Murphy Oil (MUR) 10-K 28 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Jan. 31, 2014	Jun. 30, 2013
Document And Entity Information [Abstract]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Trading Symbol	'MUR	'	'
Entity Registrant Name	'MURPHY OIL CORP /DE	'	'
Entity Central Index Key	'0000717423	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Common Stock, Shares Outstanding	'	183,181,954	'
Entity Public Float	'	'	$9,733,180,000

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets	'		'
Cash and cash equivalents	$750,155		$947,316	[1]
Canadian government securities with maturities greater than 90 days at the date of acquisition	374,842		115,603
Accounts receivable, less allowance for doubtful accounts of $1,609 in 2013 and $6,697 in 2012	999,872		1,853,364
Inventories, at lower of cost or market	'		'
Crude oil and blend stocks	40,077		226,541
Finished products	0		266,307
Materials and supplies	254,118		259,462
Prepaid expenses	83,856		335,831
Deferred income taxes	61,991		89,040
Assets held for sale	943,732		15,119
Total current assets	3,508,643		4,108,583
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $8,540,239 in 2013 and $8,138,587 in 2012	13,481,055		13,011,606
Goodwill	40,259		43,103
Deferred charges and other assets	98,123		151,183
Assets held for sale	381,404		208,168
Total assets	17,509,484		17,522,643
Current liabilities	'		'
Current maturities of long-term debt	26,249		46
Accounts payable	2,158,485		2,803,268
Income taxes payable	222,930		219,847
Other taxes payable	7,059		172,962
Other accrued liabilities	170,168		162,876
Deferred income taxes	0		2,611
Liabilities associated with assets held for sale	639,140		47,471
Total current liabilities	3,224,031		3,409,081
Long-term debt, including capital lease obligation in 2013	2,936,563		2,245,201
Deferred income taxes	1,466,100		1,544,336
Asset retirement obligations	852,488		724,273
Deferred credits and other liabilities	339,028		516,540
Liabilities associated with assets held for sale	95,544		141,177
Stockholders' equity	'		'
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued	0		0
Common Stock, par $1.00, authorized 450,000,000 shares at December 31, 2013 and 2012, issued 194,920,155 shares at December 31, 2013 and 194,616,470 shares at December 31, 2012	194,920		194,616
Capital in excess of par value	902,633		873,934
Retained earnings	8,058,792		7,717,389
Accumulated other comprehensive income	172,119	[2]	408,901	[2]
Treasury stock	-732,734		-252,805
Total stockholders' equity	8,595,730		8,942,035
Total liabilities and stockholders' equity	$17,509,484		$17,522,643
[1]	Reclassified to conform to current presentation.
[2]	All amounts are presented net of income taxes.

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
Statement Of Financial Position [Abstract]	'	'
Accounts receivable, allowance for doubtful accounts	$1,609	$6,697
Property, plant and equipment, accumulated depreciation, depletion and amortization	$8,540,239	$8,138,587
Cumulative Preferred Stock, par	$100	$100
Cumulative Preferred Stock, authorized	400,000	400,000
Cumulative Preferred Stock, issued	'	'
Common Stock, par	$1	$1
Common Stock, authorized	450,000,000	450,000,000
Common Stock, issued	194,920,155	194,616,470

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Revenues	'		'		'
Sales and other operating revenues	$5,312,686		$4,608,563	[1]	$4,222,520	[1]
Gain (loss) on sale of assets	-87		66	[1]	23,143	[1]
Interest and other income	77,490		10,973	[1]	33,019	[1]
Total revenues	5,390,089		4,619,602	[1]	4,278,682	[1]
Costs and Expenses	'		'		'
Operating expenses	1,340,143		1,114,748	[1]	1,010,121	[1]
Exploration expenses, including undeveloped lease amortization	502,215		380,924	[1]	489,346	[1]
Selling and general expenses	379,167		249,532	[1]	208,819	[1]
Depreciation, depletion and amortization	1,553,394		1,253,095	[1]	964,725	[1]
Impairment of properties	21,587	[2]	200,000	[1],[2]	368,600	[1],[2]
Accretion of asset retirement obligations	48,996		38,361	[1],[3]	33,847	[1]
Redetermination of Terra Nova working interest	0		0	[1]	-5,351	[1],[2]
Interest expense	124,423		54,105	[1]	55,831	[1]
Interest capitalized	-52,523		-39,173	[1]	-15,131	[1]
Total costs and expenses	3,917,402		3,251,592	[1]	3,110,807	[1]
Income from continuing operations before income taxes	1,472,687		1,368,010	[1]	1,167,875	[1]
Income tax expense	584,550		561,516	[1]	628,677	[1]
Income from continuing operations	888,137		806,494	[1]	539,198	[1]
Income from discontinued operations, net of income taxes	235,336		164,382	[1]	333,504	[1]
Net Income	$1,123,473		$970,876	[1]	$872,702	[1]
Income per Common Share - Basic	'		'		'
Income from continuing operations	$4.73		$4.16	[1]	$2.79	[1]
Income from discontinued operations	$1.25		$0.85	[1]	$1.72	[1]
Net Income - Basic	$5.98		$5.01	[1]	$4.51	[1]
Income per Common Share - Diluted	'		'		'
Income from continuing operations	$4.69		$4.14	[1]	$2.77	[1]
Income from discontinued operations	$1.25		$0.85	[1]	$1.72	[1]
Net Income - Diluted	$5.94		$4.99	[1]	$4.49	[1]
Average Common shares outstanding - basic	187,921,062		193,902,335	[1]	193,409,621	[1]
Average Common shares outstanding - diluted	189,271,398		194,668,737	[1]	194,512,402	[1]
[1]	Reclassified to conform to current presentation.
[2]	Results exclude corporate overhead, interest and discontinued operations.
[3]	Includes $980 reclassified to discontinued operations associated with U.S. downstream operations.

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Statement Of Income And Comprehensive Income [Abstract]	'		'		'
Net income	$1,123,473		$970,876	[1]	$872,702	[1]
Other comprehensive income (loss), net of tax	'		'		'
Net gain (loss) from foreign currency translation	-308,300		117,331		-91,247
Retirement and postretirement benefit plan adjustments	69,583		-17,650		-30,909
Deferred loss on interest rate hedges:	'		'		'
Increase in deferred loss associated with contract revaluation and settlement	0		-2,407		-16,852
Amount of loss reclassified to interest expense in consolidated statements of income	1,935		1,207		0
Net other comprehensive income (loss)	-236,782	[2]	98,481		-139,008
Comprehensive Income	$886,691		$1,069,357		$733,694
[1]	Reclassified to conform to current presentation.
[2]	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, 2013		Dec. 31, 2012		Dec. 31, 2011
Operating Activities	'		'		'
Net income	$1,123,473		$970,876	[1]	$872,702	[1]
Adjustments to reconcile net income to net cash provided by operating activities	'		'		'
Income from discontinued operations	-235,336		-164,382	[1]	-333,504	[1]
Depreciation, depletion and amortization	1,553,394		1,253,095	[1]	964,725	[1]
Impairment of long-lived assets	21,587	[2]	200,000	[1],[2]	368,600	[1],[2]
Amortization of deferred major repair costs	8,464		7,065	[1]	7,568	[1]
Expenditures for asset retirements	-51,647		-40,434	[1]	-21,490	[1]
Dry hole costs	262,876		181,924	[1]	250,954	[1]
Amortization of undeveloped leases	66,891		129,750	[1]	118,211	[1]
Accretion of asset retirement obligations	48,996		38,361	[1],[3]	33,847	[1]
Deferred and noncurrent income tax charges	158,108		342,718	[1]	133,841	[1]
Pretax (gains) losses from disposition of assets	87		-66	[1]	-23,143	[1]
Net decrease (increase) in noncash operating working capital	266,329		-168,180	[1]	-760,036	[1]
Other operating activities - net	-12,527		160,653	[1]	76,609	[1]
Net cash provided by continuing operations	3,210,695		2,911,380	[1]	1,688,884	[1]
Net cash provided by discontinued operations	427,792		144,901	[1]	456,501	[1]
Net cash provided by operating activities	3,638,487		3,056,281	[1]	2,145,385	[1]
Investing Activities	'		'		'
Property additions and dry hole costs	-3,590,344	[4]	-3,541,724	[1],[4]	-2,433,088	[1],[4]
Proceeds from sale of property, plant and equipment	1,650		99	[1]	27,382	[1]
Expenditures for major repairs	-7,757		-10,832	[1]	-5,068	[1]
Purchase of investment securities	-923,497	[5]	-1,619,308	[1],[5]	-1,689,087	[1],[5]
Proceeds from maturity of investment securities	664,258	[5]	2,035,798	[1],[5]	1,773,552	[1],[5]
Other investing activities - net	8,048		11,085	[1]	8,000	[1]
Investing activities of discontinued operations:	'		'		'
Sales proceeds	282,205		0	[1]	950,010	[1]
Other	-165,742		-192,540	[1]	-246,055	[1]
Net cash required by investing activities	-3,731,179		-3,317,422	[1]	-1,614,354	[1]
Financing Activities	'		'		'
Additions to long-term debt	350,000	[4]	1,995,467	[1],[4]	0	[1],[4]
Repayments of debt	0		-350,000	[1]	-340,041	[1]
Purchase of treasury stock	-500,000		-250,000	[1]	0	[1]
Proceeds from exercise of stock options and employee stock purchase plans	3,409		12,324	[1]	15,551	[1]
Excess tax benefits related to exercise of stock options	844		2,647	[1]	4,838	[1]
Withholding tax on stock-based incentive awards	-16,727		-3,341	[1]	-8,014	[1]
Issue cost of debt	-3,317		-6,959	[1]	-7,905	[1]
Cash dividends paid	-235,108		-714,429	[1]	-212,752	[1]
Cash included in current assets held for sale	-301,302		0	[1]	0	[1]
Separation of retail business:	'		'		'
Cash distributed to Murphy Oil by Murphy USA	650,000		0	[1]	0	[1]
Cash held and retained by Murphy USA upon separation	-55,506		0	[1]	0	[1]
Net cash provided (required) by financing activities	-107,707		685,709	[1]	-548,323	[1]
Effect of exchange rate changes on cash and cash equivalents	3,238		8,875	[1]	-4,660	[1]
Net increase (decrease) in cash and cash equivalents	-197,161		433,443	[1]	-21,952	[1]
Cash and cash equivalents, beginning	947,316	[1]	513,873	[1]	535,825	[1]
Cash and cash equivalents, ending	$750,155		$947,316	[1]	$513,873	[1]
[1]	Reclassified to conform to current presentation.
[2]	Results exclude corporate overhead, interest and discontinued operations.
[3]	Includes $980 reclassified to discontinued operations associated with U.S. downstream operations.
[4]	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.
[5]	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
Maturity of Canadian government securities	'90 days
Non-cash asset and long-term obligation	$357,991
Minimum [Member]	'
Maturity of Canadian government securities	'90 days

CONSOLIDATED_STATEMENTS_OF_STO

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (USD $)	Total		Cumulative Preferred Stock - par $100, authorized 400,000 shares, none issued	Common Stock - par $1.00, authorized 450,000,000 shares at December 31, 2013, 2012 and 2011, issued 0 shares at December 31, 2013, 194,616,470 shares at December 31, 2012 and 193,909,200 shares at December 31, 2011	Capital in Excess of Par Value	Retained Earnings	Accumulated Other Comprehensive Income	Treasury Stock
In Thousands
Balance at beginning of period at Dec. 31, 2010	'		$0	$193,294	$767,762	$6,800,992	$449,428	($11,926)
Distribution of common stock of Murphy USA Inc. to shareholders	0		'	'	'	'	'	'
Exercise of stock options	'		'	615	21,774	'	'	'
Foreign currency translation gains (losses), net of income taxes	-91,247		'	'	'	'	-91,247	'
Purchase of treasury shares	'		'	'	'	'	'	0
Net income for the year	872,702	[1]	'	'	'	872,702	'	'
Restricted stock transactions and other	'		'	'	-15,119	'	'	'
Retirement and postretirement benefit plan adjustments, net of income taxes	-30,909		'	'	'	'	-30,909	'
Cash dividends - $1.25 per share in 2013, $3.675 per share in 2012 and $1.10 per share in 2011	'		'	'	'	-212,752	'	'
Stock-based compensation	'		'	'	42,492	'	'	'
Change in deferred loss on interest rate hedges, net of income taxes	-16,852		'	'	'	'	-16,852	'
Sale of stock under employee stock purchase plans	'		'	'	1,065	'	'	870
Awarded restricted stock	'		'	0	'	'	'	6,208
Balance at end of period at Dec. 31, 2011	8,778,397		0	193,909	817,974	7,460,942	310,420	-4,848
Distribution of common stock of Murphy USA Inc. to shareholders	0		'	'	'	'	'	'
Exercise of stock options	'		'	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	[1]	'	'	'	970,876	'	'
Restricted stock transactions and other	'		'	'	-5,257	'	'	'
Retirement and postretirement benefit plan adjustments, net of income taxes	-17,650		'	'	'	'	-17,650	'
Cash dividends - $1.25 per share in 2013, $3.675 per share in 2012 and $1.10 per share in 2011	'		'	'	'	-714,429	'	'
Stock-based compensation	'		'	'	46,584	'	'	'
Change in deferred loss on interest rate hedges, net of income taxes	-2,407		'	'	'	'	-1,200	'
Sale of stock under employee stock purchase plans	'		'	'	1,916	'	'	2,043
Awarded restricted stock	'		'	224	'	'	'	0
Balance at end of period at Dec. 31, 2012	8,942,035		0	194,616	873,934	7,717,389	408,901	-252,805
Distribution of common stock of Murphy USA Inc. to shareholders	-546,962		'	'	'	'	'	'
Exercise of stock options	'		'	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 and other	'		'	'	-28,339	'	'	'
Retirement and postretirement benefit plan adjustments, net of income taxes	69,583		'	'	'	'	69,583	'
Cash dividends - $1.25 per share in 2013, $3.675 per share in 2012 and $1.10 per share in 2011	'		'	'	'	-235,108	'	'
Stock-based compensation	'		'	'	56,622	'	'	'
Change in deferred loss on interest rate hedges, net of income taxes	0		'	'	'	'	1,935	'
Sale of stock under employee stock purchase plans	'		'	'	-147	'	'	1,015
Awarded restricted stock	'		'	0	'	'	'	19,056
Balance at end of period at Dec. 31, 2013	$8,595,730		$0	$194,920	$902,633	$8,058,792	$172,119	($732,734)
[1]	Reclassified to conform to current presentation.

CONSOLIDATED_STATEMENTS_OF_STO1

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) (USD $)	3 Months Ended			12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
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	'	'		'	'		'
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	194,920,155	194,616,470		194,920,155	194,616,470		193,909,200
Cash dividends, per share	$0.31	$2.81	[1]	$1.25	$3.67	[1]	$1.10
Balance at end of year, shares of Common Stock	11,513,642	3,975,153		11,513,642	3,975,153		185,992
[1]	Includes special dividend of $2.50 per Common share paid on December 3, 2012.

Significant_Accounting_Policie

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
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. Murphy owns one petroleum refinery in the United Kingdom and markets petroleum products in that country under various brand names and to unbranded wholesale customers. The Company has announced its intention to sell the U.K. refining and marketing assets. On August 30, 2013, the Company completed the spin-off of Murphy USA Inc. (MUSA) to its shareholders. MUSA formerly was the Company’s U.S. downstream 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 all its United Kingdom oil and natural gas producing assets during 2013. In 2011, the Company sold two U.S. petroleum refineries and certain associated marketing assets. 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. For consolidated subsidiaries that are less than wholly owned, the noncontrolling interest is reflected in the balance sheet as a component of Stockholders’ Equity. 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 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, 2013 and 2012, the liabilities for natural gas balancing were immaterial.
	Refined products sold at retail are recorded when the customer takes delivery at the pump. Title transfer for bulk motor fuel products generally occurs at pipeline custody points or upon truck loading at product terminals. Merchandise revenues are recorded at the point of sale.
	The Company enters into buy/sell and similar arrangements when crude oil and other petroleum products are held at one location but are needed at a different location. The Company often pays or receives funds related to the buy/sell arrangement based on location or quality differences. The Company accounts for such transactions on a net basis in its Consolidated Statement of Income.
	TAXES COLLECTED FROM CUSTOMERS AND REMITTED TO GOVERNMENT AUTHORITIES – Excise and other taxes collected on sales of refined products and remitted to governmental agencies are excluded from revenues and costs and expenses in the Consolidated Statement of Income.
	CASH EQUIVALENTS – Short-term investments, which include government securities and other instruments with government securities as collateral, that 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, 2013, the Company owned Canadian government securities with maturities greater than 90 days at date of acquisition that had a carrying value of $374,842,000. 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, 2013, the Company’s accounts receivable primarily consisted of amounts owed to the Company by customers for sales of crude oil and natural gas. In 2012 this balance included receivables for oil and gas sales and amounts owed for refined products sold under varying credit arrangements in the U.S. and U.K. 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 – Crude oil and blend stocks inventories include unsold crude oil production in 2013 and 2012, and in 2012 also included Milford Haven refinery feedstocks. 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. Refinery inventories of crude oil and other feedstocks and certain finished product inventories are valued at the lower of cost, generally applied on a last-in, first-out (LIFO) basis, or market. Merchandise inventory held for resale at retail marketing stations in 2012 was generally carried at average cost and was included in Finished products inventories. Materials and supplies inventories are valued at the lower of average cost or estimated value and generally consist of tubulars and other drilling equipment and additionally at year-end 2012 it included spare parts for refinery operations. Cash collected upon the sale of inventory to customers is classified as an operating activity in the Consolidated Statement of Cash Flows.
	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. The Milford Haven, Wales refinery, certain marketing facilities and certain natural gas processing facilities are depreciated primarily using the composite straight-line method with depreciable lives ranging from 14 to 25 years. Gasoline stations and other properties are depreciated over 3 to 20 years by individual unit on the straight-line method. Gains and losses on asset disposals or retirements are included in income as a separate component of revenues. Property and equipment of U.K. refining and marketing operations are no longer depreciated following the recognition of these assets as held for sale in late 2013.
	Turnarounds for major processing units at the Milford Haven, Wales refinery are scheduled at four to five year intervals. 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 Milford Haven and 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 Operating Expenses for Syncrude and through results of discontinued operation for the Milford Haven refinery. Also in 2014, amortization of deferred turnaround costs will cease for the U.K. downstream operations that are held for sale. All other maintenance and repairs are expensed as incurred. Renewals and betterments are capitalized. A major turnaround occurred in 2010 at the Milford Haven, Wales refinery.
	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. The change in the carrying value of goodwill during 2013 was primarily caused by a change in the foreign currency translation rate between years. Based on its assessment of the fair value of its Canadian conventional oil and natural gas operations, the Company believes the recorded value of goodwill is not impaired at December 31, 2013. Should a future assessment indicate that goodwill is not fully recoverable, an impairment charge to write down the carrying value of goodwill would be required.
	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 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 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 in earnings. When the income effect of the underlying cash flow hedged item is recognized in the Consolidated Statement of Income, the fair value of the associated cash flow hedge is reclassified from other comprehensive income into earnings. The ineffective portion of the change in fair value of a cash flow hedge 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 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 CRSU, and the period-end price of the Company’s common stock for phantom units. When SAR are exercised and when CRSU and phantom units expire, the Company adjusts previously recorded expense to the final amounts paid out in cash for these awards.
	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.
	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, 2013
Accounting Changes And Error Corrections [Abstract]	'
New Accounting Principles and Recent Accounting Pronouncements	'
	Note B – New Accounting Principles and Recent Accounting Pronouncements
	Accounting Principles Adopted
	In February 2013, the Financial Accounting Standards Board (FASB) issued an accounting standards update that requires additional disclosures for reclassification adjustments from accumulated other comprehensive income (AOCI). These additional disclosures include changes in AOCI balances by component and significant items reclassified out of AOCI. These disclosures must be presented either on the face of the affected financial statement or in the notes to the financial statements. The disclosures are effective for Murphy Oil beginning in the first quarter of 2013 and are to be provided on a prospective basis. These disclosures are presented in Note O.
	In December 2011, the FASB issued an accounting standards update that requires enhanced disclosures about financial instruments and derivative instruments that are either offset in the balance sheet or are subject to an enforceable master netting arrangement or similar agreement. The guidance was effective for all interim and annual periods beginning on or after January 1, 2013. These disclosures are presented in Note P.

Discontinued_Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2013
Discontinued Operations And Disposal Groups [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. These funds were raised from the proceeds of $500,000,000 secured notes issued by Murphy Oil USA, Inc. plus $150,000,000 borrowed under credit facilities entered into by MUSA and Murphy Oil USA, Inc. in connection with the separation. 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
	Additionally, the Company completed the sale of all of its U.K. oil and natural gas production assets during 2013. The Company recognized an after-tax gain of $216,147,000 on sale of these U.K. oil and gas assets during 2013. The results of the operations have also been reported as discontinued operations for all periods presented in these consolidated financial statements.
	The Company has previously announced its intention to sell its U.K. refining and marketing operations. Beginning in 2013, the Company has accounted for the U.K. downstream business as discontinued operations for all periods presented, including a reclassification of all the prior years’ operating results for this business to discontinued operations. The U.K. downstream operations were formerly reported as a separate segment within the Company’s refining and marketing business. The sale process continues in 2014.
	The following table presents the carrying value of the major categories of assets and liabilities of discontinued operations reflected on the Company’s consolidated balance sheets at December 31, 2013 and 2012:
	(Millions of dollars)	2013		2012
	Current assets
	Held for sale assets of U.K. downstream operations:
	Cash	$	301,302		0
	Accounts receivable		302,059		0
	Inventories		254,240		0
	Other		86,131		0
	Held for sale assets of U.K. oil and gas operations		0		15,119
	Total current assets held for sale	$	943,732		15,119
	Non-current assets
	Held for sale assets of U.K. downstream operations:
	Property, plant and equipment, net	$	360,347		0
	Other		21,057		0
	Held for sale assets of U.K. oil and gas operations:
	Property, plant and equipment		0		205,746
	Other		0		2,422
	Total non-current assets held for sale	$	381,404		208,168
	Current liabilities
	Current liabilities associated with held for sale properties of U.K. downstream operations:
	Accounts payable	$	637,432		0
	Other		1,708		0
	Current liabilities associated with held for sale properties of U.K. oil and gas operations:
	Accounts payable		0		27,578
	Income taxes payable		0		19,893
	Total current liabilities associated with assets held for sale	$	639,140		47,471
	Non-current liabilities
	Non-current liabilities associated with held for sale properties of U.K. downstream operations:
	Deferred income taxes payable	$	68,096		0
	Deferred credits and other liabilities		27,448		0
	Non-current liabilities associated with held for sale properties of U.K. oil and gas operations:
	Deferred income taxes payable		0		87,893
	Asset retirement obligations		0		53,284
	Total non-current liabilities associated with assets held for sale	$	95,544		141,177
	As described above, the Company separated its U.S. downstream operations in 2013. The major categories of assets and liabilities for MUSA were included in the Company’s consolidated balance sheet at December 31, 2012 as follows:
	(Millions of dollars)	2012
	Current assets
	Accounts receivable	$	525,936
	Inventories		217,393
	Other current assets		8,685
	Total current assets	$	752,014
	Non-current assets
	Property, plant and equipment, net	$	1,163,748
	Other assets		498
	Total non-current assets	$	1,164,246
	Current liabilities
	Accounts payable	$	612,755
	Income taxes payable		16,851
	Other taxes payable		65,349
	Other current liabilities		38,798
	Total current liabilities	$	733,753
	Non-current liabilities
	Long-term debt	$	1,123
Deferred income taxes		89,946
Asset retirement obligations		15,401
Deferred credits and other liabilities		87,600
Total non-current liabilities	$	194,070
In 2013, the Company wrote down its net investment in the held for sale U.K. refining and marketing assets by $73,000,000. This charge has been included in discontinued operations for 2013. The write down was based on an assessment of the fair value of these assets based on the status of the ongoing sale process.
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. In July 2011, the United Kingdom enacted a supplemental tax rate increase for oil and gas companies effective retroactive to March 2011. The total U.K. tax rate increased from 50% to 62% for oil and gas companies. The supplemental tax rate change reduced income from discontinued operations by $14,461,000 for 2011.
On September 30, 2011, the Company sold the Superior, Wisconsin refinery and related assets for $214,000,000, plus certain capital expenditures between July 25, 2011, and the date of closing and the fair value of all associated hydrocarbon inventories at these locations. On October 1, 2011, the Company sold its Meraux, Louisiana refinery and related assets for $325,000,000, plus the fair value of associated hydrocarbon inventories. The Company has accounted for the results of the Superior, Wisconsin and Meraux, Louisiana refineries and associated marketing assets as discontinued operations. The after-tax gain in 2011 from disposal of the two refineries netted to $18,724,000, made up of a gain on the Superior refinery (including associated inventories) of $77,585,000 and a loss on the Meraux refinery (including associated inventories) of $58,861,000. The gain on disposal in 2011 was based on refinery selling prices, plus the sale of all associated inventories at fair value, which was significantly above the last-in, first-out cost method. The net gain on sale of the refineries included an after-tax benefit of $179,152,000 from liquidation of inventories formerly carried primarily under the last-in, first-out cost method. The U.S. refineries sold were formerly reported in the U.S. manufacturing segment.
The results of operations associated with all discontinued operations are presented in the following table.
(Thousands of dollars)	2013		2012		2011
Revenues	$	17,586,236		24,156,748		27,310,300
Income from operations before income taxes	$	119,984		330,048		571,339
Gain on sale before income taxes		130,991		0		12,684
Total income from discontinued operations before taxes		250,975		330,048		584,023
Provision for income taxes		15,639		165,666		250,519
Income from discontinued operations	$	235,336		164,382		333,504

Property_Plant_and_Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2013
Property Plant And Equipment [Abstract]	'
Property, Plant and Equipment	'
	Note D – Property, Plant and Equipment
		December 31, 2013						December 31, 2012
	(Thousands of dollars)	Cost			Net			Cost			Net
	Exploration and production1	$	21,932,119			13,433,468	2		18,408,904			11,294,933	2
	Refining and marketing		0			0			2,619,844			1,661,081
	Corporate and other		89,175			47,587			121,445			55,592
		$	22,021,294			13,481,055			21,150,193			13,011,606
	1         Includes mineral rights as follows:	$	1,007,920			489,578			1,051,153			556,399
	2         Includes $48,691 in 2013 and $26,611 in 2012 related to administrative assets and support equipment.
	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, 2013, 2012 and 2011, the Company had total capitalized drilling costs pending the determination of proved reserves of $393,030,000, $445,697,000 and $556,412,000, respectively. The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 2013.
	(Thousands of dollars)	2013			2012			2011
	Beginning balance at January 1	$	445,697			556,412			497,765
	Additions to capitalized exploratory well costs pending the determination of proved reserves		57,716			135,849			86,035
	Reclassifications to proved properties based on the determination of proved reserves		(93,936	)		(165,377	)		0
	Capitalized exploratory well costs charged to expense		(16,447	)		(81,187	)		(27,388	)
	Ending balance at December 31	$	393,030			445,697			556,412
	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.
		2013									2012							2011
	(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	$	69,757		11		5
	One to two years		60,787			7			1			18,335			2		3		143,611		15		3
	Two to three years		0			0			0			83,314			9		4		101,696		9		2
	Three years or more		275,744			22			7			284,215			26		6		241,348		33		6
		$	393,030			32			9		$	445,697			44		15	$	556,412		68		16
	Of the $336,531,000 of exploratory well costs capitalized more than one year at December 31, 2013, $213,802,000 is in Malaysia, $116,123,000 is in the U.S. and $6,606,000 is in Brunei. In Malaysia either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. 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 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. The capitalized well costs expensed in 2011 related to exploration costs offshore Republic of the Congo and Brunei. The costs in Republic of the Congo were written off following an impairment charge at the nearby Azurite field, and the Brunei costs were written off based on unsuccessful wells drilled in the area in late 2011.
	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. An impairment charge of $368,600,000 was recorded in 2011 to reduce the carrying value of the Azurite field to fair value. The Company determined that a downward revision of proved oil reserves for Azurite was necessary at year-end 2011 following an extensive study of the declining well production at the field. It was determined that the remaining reserves, including risked estimated probable and possible reserves, would not allow for recovery of the Company’s net investment in the Azurite field. Fair value was determined each year at Azurite 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.
	The Company has announced that its Board of Directors had approved plans to exit the U.K. refining and marketing business. These operations are presented as discontinued operations in Note C. The sale process for the U.K. downstream assets continues in 2014.

Financing_Arrangements

Financing Arrangements	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Financing Arrangements	'
	Note E – Financing Arrangements
	At December 31, 2013, 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, 2013. 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, 2013, the Company had borrowings of $350,000,000 under this committed facility. At December 31, 2013, the Company also had uncommitted credit lines that had estimated total borrowing capacity of approximately $345,000,000. No borrowings were outstanding under these uncommitted credit lines at December 31, 2013. 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, 2013
Debt Disclosure [Abstract]	'
Long-term Debt	'
	Note F – Long-term Debt
		December 31
	(Thousands of dollars)	2013			2012
	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, 2013		350,000			0
	Other, 6%, due through 2028		0			1,169
	Total notes payable		2,600,000			2,251,169
	Unamortized discount on notes payable		(5,439	)		(5,922	)
	Total notes payable, net of unamortized discount		2,594,561			2,245,247
	Capitalized lease obligation, due through June 2028		368,251			0
	Total debt including current maturities		2,962,812			2,245,247
	Current maturities		(26,249	)		(46	)
	Total long-term debt	$	2,936,563			2,245,201
	Long-term debt amounts repayable over each of the next five years and thereafter are as follows: $26,249,000 in 2014, $17,921,000 in 2015, $18,819,000 in 2016, $919,700,000 in 2017, $20,752,000 in 2018 and $1,959,371,000 thereafter.
	The capitalized lease obligation included in the above table is associated with production facilities at the Kakap field, offshore Sarawak, Malaysia. The facilities are utilized by the Company under a 25 year lease that extends through 2038.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligations	'
	Note G – Asset Retirement Obligations
	The asset retirement obligations liabilities (ARO) recognized by the Company at December 31, 2013 and 2012 are related to the estimated costs to dismantle and abandon its producing oil and gas properties and related equipment.
	The Company has not recorded an ARO for its refining and marketing assets in the U.K. because sufficient information is presently not available to estimate a range of potential settlement dates for the obligation. These assets are held for sale at December 31, 2013. If these assets are not sold as anticipated, the ARO obligation will be initially recognized in the period in which sufficient information exists to estimate the liability.
	A reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligation for 2013 and 2012 is shown in the following table.
	(Thousands of dollars)		2013			2012
	Balance at beginning of year		$	751,583			615,545
	Accretion expense			48,996			39,341	1
	Liabilities incurred			172,048			184,439
	Revision of previous estimates			(4,856	)		10,468
	Liabilities settled			(51,647	)		(40,434	)
	Liabilities assumed by Murphy USA Inc. upon separation			(15,401	)		0
	U.K. oil and gas asset obligations reclassified to liabilities associated with assets held for sale in 2012			0			(64,355	)
	Changes due to translation of foreign currencies			(20,720	)		6,579
	Balance at end of year			880,003			751,583
	Current portion of liability at end of year2			(27,515	)		(27,310	)
	Noncurrent portion of liability at end of year		$	852,488			724,273
		1	Includes $980 reclassified to discontinued operations associated with U.S. downstream operations.
		2	Included in Other Accrued Liabilities on the Consolidated Balance Sheet.
	The estimation of future ARO is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that may be required in future periods due to the availability of additional information such as: prices for oil field services, technological changes, governmental requirements and other factors.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	Note H – Income Taxes
	The components of income from continuing operations before income taxes for each of the three years ended December 31, 2013 and income tax expense attributable thereto were as follows.
	(Thousands of dollars)	2013			2012			2011
	Income (loss) from continuing operations before income taxes
	United States	$	(5,810	)		54,275			72,038
	Foreign		1,478,497			1,313,735			1,095,837
		$	1,472,687			1,368,010			1,167,875
	Income tax expense (benefit)
	Federal – Current	$	(56,790	)		(256,931	)		6,050
	– Deferred		65,883			177,325			15,633
			9,093			(79,606	)		21,683
	State		7,141			8,104			5,609
	Foreign – Current		477,715			472,701			471,960
	– Deferred		90,601			160,317			129,425
			568,316			633,018			601,385
	Total	$	584,550			561,516			628,677
	Income tax benefits attributable to employee stock option transactions of $7,435,000 in 2013, $5,920,000 in 2012 and $8,775,000 in 2011 were included in Capital in Excess of Par Value within Stockholders’ Equity in the Consolidated Balance Sheets.
	The following table reconciles income taxes based on the U.S. statutory tax rate to the Company’s income tax expense.
	(Thousands of dollars)	2013			2012			2011
	Income tax expense based on the U.S. statutory tax rate	$	515,440			478,804			408,756
	Foreign income subject to foreign taxes at a rate different than the U.S. statutory rate		31,752			7,710			(10,682	)
	State income taxes, net of federal benefit		4,642			5,268			3,646
	U.S. tax benefit on certain foreign upstream investments		(133,526	)		(108,077	)		0
	Increase in deferred tax asset valuation allowance related to other foreign exploration expenditures		129,588			87,558			102,714
	Impairment or abandonment of Azurite field with no tax benefit		35,475			70,000			129,010
	Malaysian tax benefits on prior year costs in Block P		0			0			(25,573	)
	Other, net		1,179			20,253			20,806
	Total	$	584,550			561,516			628,677
	An analysis of the Company’s deferred tax assets and deferred tax liabilities at December 31, 2013 and 2012 showing the tax effects of significant temporary differences follows.
	(Thousands of dollars)	2013			2012
	Deferred tax assets
	Property and leasehold costs	$	708,947			658,588
	Liabilities for dismantlements		79,111			78,100
	Postretirement and other employee benefits		175,446			197,912
	Alternative minimum tax		49,536			37,253
	Foreign tax credit carryforwards		19,896			18,594
	Other deferred tax assets		23,352			32,500
	Total gross deferred tax assets		1,056,288			1,022,947
	Less valuation allowance		(633,735	)		(523,966	)
	Net deferred tax assets		422,553			498,981
	Deferred tax liabilities
	Property, plant and equipment		(747,561	)		(808,311	)
	Accumulated depreciation, depletion and amortization		(1,040,251	)		(1,077,867	)
	Other deferred tax liabilities		(38,849	)		(70,710	)
	Total gross deferred tax liabilities		(1,826,661	)		(1,956,888	)
	Net deferred tax liabilities	$	(1,404,108	)		(1,457,907	)
	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 2022. The valuation allowance increased $109,769,000 in 2013, with these changes primarily offsetting the change in certain deferred tax assets. Any subsequent reductions of the valuation allowance will 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 and certain other foreign subsidiaries because such earnings are considered indefinitely invested in foreign countries. As of December 31, 2013, undistributed earnings of the Company’s subsidiaries considered indefinitely invested were approximately $6,677,000,000. 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 $651,000,000. The Company does not consider undistributed earnings from certain other international operations to be indefinitely invested; 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 invested, under present law, it would incur a 5% withholding tax on any monies repatriated from Canada to the United States.
	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, 2013 is shown in the following table.
	(Thousands of dollars)	2013			2012			2011
	Balance at January 1	$	16,611			18,857			23,196
	Additions for tax positions related to current year		2,486			1,258			1,294
	Settlements due to lapse of time		(12,731	)		(3,504	)		(5,633	)
	Balance at December 31	$	6,366			16,611			18,857
	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, 2013 and 2012 for interest and penalties of $146,000 and $975,000, respectively, associated with uncertain tax positions. Income tax expense for the years ended December 31, 2013, 2012 and 2011 included net benefits for interest and penalties of $829,000, $1,000 and $34,000, 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 2014 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 2014.
	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, 2013, the earliest years remaining open for audit and/or settlement in the Company’s major taxing jurisdictions are as follows: United States – 2010; Canada – 2007; United Kingdom – 2011; and Malaysia – 2006.

Incentive_Plans

Incentive Plans	12 Months Ended
	Dec. 31, 2013
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'
Incentive Plans	'
	Note I – 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 7,135,000 shares remained available for grant under the 2012 Long-Term Plan at December 31, 2013. The Company also has a 2013 Stock Plan for Non-Employee Directors (Director Plan) that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.
	The Company generally expects to issue treasury shares to satisfy future stock option exercises and vesting of restricted stock and restricted stock units.
	Amounts recognized in the financial statements with respect to share-based plans are shown in the following table.
	(Thousands of dollars)	2013			2012			2011
	Compensation charged against income before income tax benefit	$	66,976			46,694			43,272
	Related income tax benefit recognized in income		19,321			14,443			14,396
	As of December 31, 2013, there was $59,505,000 in compensation costs to be expensed over approximately the next two years related to unvested share-based compensation arrangements granted by the Company. Cash received from options exercised under all share-based payment arrangements for the years ended December 31, 2013, 2012 and 2011 was $2,395,000, $10,375,000 and $13,251,000, respectively. Total income tax benefits realized from tax deductions related to stock option exercises under share-based payment arrangements were $7,435,000, $5,920,000 and $8,775,000 for the years ended December 31, 2013, 2012 and 2011, respectively.
	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. Under the Director Plan, one-third of each grant is exercisable after each of the first three years.
	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.
		2013		2012	2011
	Fair value per option grant	$15.81 – $20.62		$12.37 – $17.74	$20.34
	Assumptions
	Dividend yield	2.10% – 2.30%		1.80% – 2.27%	1.80%
	Expected volatility	34.00% – 36.00%		39.00% – 39.62%	37.00%
	Risk-free interest rate	0.96% – 2.00%		0.55% – 0.77%	2.10%
	Expected life	5.25 yrs. – 6.50 yrs.		4.00 yrs. – 5.20 yrs.	5.10 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, 2010		5,302,384		$	48.83
	Granted at FMV		1,397,312			67.64
	Exercised		(974,500	)		39.3
	Forfeited		(290,968	)		52.73
	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			56.8
	Exercisable at December 31, 2010		2,499,610		$	45.07
	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
	Additional information about stock options outstanding at December 31, 2013 is shown below.
		Options Outstanding									Options Exercisable
	Range of Exercise	No.			Avg. Life			Aggregate			No. of			Avg. Life		Aggregate
	Prices per Option	of Options			Remaining			Intrinsic			Options			Remaining		Intrinsic
					in Years			Value						in Years		Value
	$37.44 to $39.02		658,782			3.1		$	17,677,000			406,939			1.4	$	11,165,000
	$43.88 to $51.63		2,233,621			4.5			34,786,000			832,631			2.4		16,224,000
	$54.21 to $63.46		3,114,182			4.6			21,288,000			1,195,752			2.4		4,500,000
			6,006,585			4.4		$	73,751,000			2,435,322			2.2	$	31,889,000
	The total intrinsic value of options exercised during 2013, 2012 and 2011 was $25,284,000, $17,197,000 and $28,145,000, 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 tables above 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 tables above 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.
	Stock Appreciation Rights (SAR) – SAR may be granted in conjunction with or independent of stock options. During 2013 the Committee granted SAR with terms similar to stock options granted in 2013. Upon exercise of SAR, the intrinsic value will be settled, net of applicable income tax withholdings, in cash rather than with Common shares. The initial fair value of these SAR were equivalent to stock options granted, but the fair value of these liability-type awards are adjusted quarterly based on changes in the key assumptions and the change in price of Murphy Oil shares. The liability was calculated at a price of $64.88 per SAR unit at December 31, 2013. None of these SARs are exercisable at December 31, 2013. At the time of the Murphy USA Inc. spin-off, the number of outstanding SAR and the exercise price of these SAR were adjusted in a manner similar to stock options as described above. Changes in SAR outstanding beginning in 2013 are presented in the following table.
		Number			Average
		of SAR			Exercise
					Price
	Outstanding at December 31, 2012		0
	Granted		851,000		$	54.21
	Forfeited		(68,712	)
	Surrendered in connection with separation of Murphy USA Inc.		(73,000	)
	Murphy USA Inc. spin-off adjustment		78,824
Outstanding at December 31, 2013		788,112		$	54.21
PERFORMANCE-BASED RESTRICTED STOCK UNITS AND CASH-SETTLED RESTRICTED STOCK UNITS – Restricted stock units (RSU) 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, shares under performance-based grants 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, RSU 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 RSU prior to their settlement.
In 2013, the Committee granted both equity-settled and cash-settled performance-based restricted stock units to certain employees. The terms of the cash-settled awards are similar to other performance-based restricted stock awards, except that they are to be settled, net of applicable tax withholdings, in cash rather than Common shares if performance targets are met. The initial fair value of these cash-settled awards are equivalent to other awards settled in shares, however, the cash-settled awards are considered to be liability awards and the fair value thereon is adjusted quarterly based on changes in the key assumptions and the price of Murphy Oil’s Common stock.
Upon the separation of Murphy USA Inc. on August 30, 2013, adjustments to outstanding performance-based restricted stock units were made to the number of units outstanding to preserve the economic value of these equity-settled and cash-settled awards.
Changes in performance-based RSU outstanding for each of the last three years are presented in the following table.
	Equity-Settled									Cash-Settled
	Restricted Stock Units									Restricted Stock Units
(Number of share units)	2013			2012			2011			2013
Balance at beginning of year		1,426,238			1,174,492			1,023,492			0
Granted		521,776			653,355			521,423			93,200
Awarded		(380,150	)		(260,175	)		(309,656	)		0
Forfeited		(39,573	)		(141,434	)		(60,767	)		(9,924	)
Surrendered in connection with separation of Murphy USA Inc.		(116,568	)		0			0			(6,800	)
Murphy USA Inc. spin-off adjustment		148,569			0			0			8,380
Balance at end of year		1,560,292			1,426,238			1,174,492			84,856
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 2013, 2012 and 2011 are presented in the following table.
	2013		2012	2011
Fair value per share at grant date	$39.50 – $68.01		$54.90 – $63.64	$38.94 – $64.89
Assumptions
Expected volatility	31.00% – 32.00%		37.00%	51.00%
Risk-free interest rate	0.41% – 0.62%		0.30%	1.04%
Stock beta	0.907 – 0.908		0.913	1.006
Expected life	3.00 yrs.		3.00 yrs.	3.00 yrs.
TIME-LAPSE RESTRICTED STOCK UNITS – Restricted stock units (RSU) have been granted to the Company’s Non-Employee Directors under the Directors 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 $60.30 per share and $69.67 per share in 2013, $59.33 per share in 2012 and $52.66 per share in 2011. To retain economic value at the time of spin-off of Murphy USA Inc., the number of time-lapse restricted stock units was increased by 10.7% for each unit outstanding on August 30, 2013.
Changes in time-lapse restricted stock units outstanding for each of the last three years are presented in the following table.
(Number of share units)	2013			2012			2011
Balance at beginning of year		98,477			116,724			166,173
Granted		38,184			42,256			32,711
Vested and issued		(34,696	)		(44,980	)		(82,160	)
Forfeited		0			(15,523	)		0
Murphy USA Inc. spin-off adjustment		10,916			0			0
Balance at end of year		112,881			98,477			116,724
PHANTOM UNITS – Phantom units have been granted to certain Company employees during 2012 and 2013. These awards will be settled in cash generally after three year terms based on the average of the high and low price for the Company’s Common stock on the maturity dates. To retain economic value at the time of spin-off of Murphy USA Inc., phantom unit awards were increased by 10.7% for each unit outstanding on August 30, 2013. Total expense related to these phantom awards was $2,063,000 in 2013 and $305,000 in 2012.
PERFORMANCE UNITS – The Company also awarded performance units in 2011 through 2013 to certain U.S. retail marketing employees under the 2012 Long-Term Plan and 2007 Long-Term Plan. The performance units were to be paid in cash and awards are computed at between 0% and 200% of targeted amounts based on achievement of U.S. retail financial performance over the three-year term of the award. These performance units were all settled and paid in connection with the separation of Murphy USA Inc. No performance units remain outstanding at December 31, 2013. Total expense related to these awards was $2,062,000 in 2013, $2,665,000 in 2012 and $871,000 in 2011.
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 16,020 shares at an average price of $54.14 per share in 2013, 24,418 shares at an average price of $48.54 per share in 2012 and 28,555 shares at an average price of $55.28 per share in 2011. At December 31, 2013, 286,941 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 $143,000 in 2013, $272,000 in 2012 and $328,000 in 2011. The fair value per share issued under the ESPP was approximately $6.72, $7.30 and $8.60 for the years ended December 31, 2013, 2012 and 2011, respectively.
SAVINGS-RELATED SHARE OPTION PLAN (SOP) – One of the Company’s U.K. subsidiaries formerly provided a plan that allowed shares of the Company’s Common stock to be purchased by eligible employees using payroll withholdings. An eligible employee could have elected to withhold from £5 to £250 per month to purchase shares of Company stock at a price equal to 90% of the fair value of the stock as of the date of grant. The SOP plan had a term of three years and employee withholdings were fixed over the life of the plan. At the end of the term of the SOP plan an employee received interest on withholdings and had six months to either use all or part of the withholdings plus credited interest to purchase shares of Company stock or receive a repayment of withholdings plus credited interest. The SOP expired in 2012. Compensation costs related to the SOP plan were estimated based on the value of the 10% discount and the fair value of the option that allowed the employee to receive a repayment of withholdings plus credited interest. The fair value per share of the SOP plans with holding periods that ended in April 2011 and May 2012 were $23.77 and $22.85, respectively. Total expense associated with this plan was nil in 2013, $110,000 in 2012 and $538,000 in 2011.
CASH 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 $53,250,000, $32,417,000 and $33,035,000 was recorded in 2013, 2012 and 2011, respectively, for these plans.

Employee_and_Retiree_Benefit_P

Employee and Retiree Benefit Plans	12 Months Ended
	Dec. 31, 2013
Compensation And Retirement Disclosure [Abstract]	'
Employee and Retiree Benefit Plans	'
	Note J – 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. 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 plan 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 year-end 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, 2013 and 2012 and a statement of the funded status as of December 31, 2013 and 2012.
			Pension						Other
			Benefits						Postretirement
									Benefits
	(Thousands of dollars)		2013			2012			2013			2012
	Change in benefit obligation
	Obligation at January 1		$	721,531			629,568			124,134			114,962
	Service cost			26,346			23,500			4,566			3,958
	Interest cost			30,903			29,869			5,189			5,174
	Plan amendments			1,989			0			0			0
	Participant contributions			21			30			1,376			1,035
	Actuarial loss (gain)			(9,876	)		55,479			(8,324	)		4,686
	Medicare Part D subsidy			0			0			384			432
	Exchange rate changes			1,852			7,125			(36	)		14
	Benefits paid			(38,745	)		(30,217	)		(5,211	)		(6,127	)
	Special termination benefits			849			6,177			0			0
	Curtailments			(26,463	)		0			(15,077	)		0
	Obligation assumed by MUSA at separation			(1,153	)		0			0			0
	Obligation at December 31			707,254			721,531			107,001			124,134
	Change in plan assets
	Fair value of plan assets at January 1			463,546			404,350			0			0
	Actual return on plan assets			61,932			41,674			0			0
	Employer contributions			46,726			42,207			3,451			4,660
	Participant contributions			21			30			1,376			1,035
	Medicare Part D subsidy			0			0			384			432
	Exchange rate changes			1,594			6,289			0			0
	Benefits paid			(38,745	)		(30,217	)		(5,211	)		(6,127	)
	Other			(1,966	)		(787	)		0			0
	Fair value of plan assets at December 31			533,108			463,546			0			0
	Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
	Deferred charges and other assets			10,254			9,679			0			0
	Other accrued liabilities			(5,565	)		(5,556	)		(5,920	)		(5,646	)
	Deferred credits and other liabilities			(158,589	)		(262,108	)		(101,081	)		(118,488	)
	Liabilities associated with assets held for sale			(20,246	)		0			0			0
	Funded status and net plan liability recognized at December 31		$	(174,146	)		(257,985	)		(107,001	)		(124,134	)
	At December 31, 2013, amounts included in accumulated other comprehensive income (AOCI), 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		$	(150,682	)		(13,815	)
	Prior service (cost) credit			(3,559	)		372
	Transitional asset (liability)			517			0
			$	(153,724	)		(13,443	)
	Amounts included in AOCI at December 31, 2013 that are expected to be amortized into net periodic benefit expense during 2014 are shown in the following table.
	(Thousands of dollars)		Pension			Other
			Benefits			Postretirement
						Benefits
	Net actuarial loss		$	(8,190	)		(242	)
	Prior service (cost) credit			(951	)		82
	Transitional asset (liability)			517			0
			$	(8,624	)		(160	)
	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)		2013			2012			2013			2012			2013			2012
	Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets		$	571,217			587,318			520,610			523,773			502,308			431,788
	Unfunded nonqualified and directors’ plans where accumulated benefit obligation exceeds fair value of plan assets			115,492			112,135			102,198			98,498			0			0
	Unfunded other postretirement plans			107,001			124,134			107,001			124,134			0			0
	The table that follows provides the components of net periodic benefit expense for each of the three years ended December 31, 2013.
		Pension Benefits									Other
											Postretirement Benefits
(Thousands of dollars)		2013			2012			2011			2013			2012			2011
Service cost		$	26,346			23,500			22,406			4,566			3,958			4,547
Interest cost			30,903			29,869			30,785			5,189			5,174			6,141
Expected return on plan assets			(28,974	)		(25,826	)		(25,919	)		0			0			0
Amortization of prior service cost (credit)			1,006			1,254			1,314			(143	)		(173	)		(240	)
Amortization of transitional (asset) liability			(514	)		(529	)		(536	)		8			8			8
Recognized actuarial loss			17,338			16,389			12,484			1,484			1,317			2,329
			46,105			44,657			40,534			11,104			10,284			12,785
Termination benefits expense			849			6,177			695			0			0			0
Curtailment expense (benefit)			1,365			0			1,036			(442	)		0			(605	)
Net periodic benefit expense		$	48,319			50,834			42,265			10,662			10,284			12,180
Termination and curtailment expenses in 2013 primarily related to plan amendments made at the time of separation of Murphy USA Inc. The increase in net periodic pension benefit expense in 2012 compared to 2011 was primarily related to expense recognized in 2012 for enhanced retirement benefits provided to a former executive officer. Termination and curtailment expenses in 2011 related to sale of two U.S. petroleum refineries during that year. The reduction in the net periodic benefit expense for other postretirement plans in 2012 was due to no further service costs and lower other costs associated with postretirement benefits for the Meraux and Superior refineries sold in 2011.
The preceding tables in this note include the following amounts related to foreign benefit plans.
		Pension						Other
		Benefits						Postretirement
								Benefits
(Thousands of dollars)		2013			2012			2013			2012
Benefit obligation at December 31		$	211,799			184,550			541			525
Fair value of plan assets at December 31			188,575			164,111			0			0
Net plan liabilities recognized			23,224			20,439			541			525
Net periodic benefit expense			12,622			11,022			92			88
The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2013 and 2012 and net periodic benefit expense for 2013 and 2012.
		Benefit Obligations												Net Periodic Benefit Expense
		Pension						Other						Pension						Other
		Benefits						Postretirement						Benefits						Postretirement
								Benefits												Benefits
		31-Dec						31-Dec						Year						Year
		2013			2012			2013			2012			2013			2012			2013			2012
Discount rate			4.78	%		4.24	%		4.91	%		4.18	%		4.23	%		4.8	%		4.18	%		4.87	%
Expected return on plan assets			6.24	%		6.2	%		0	%		0	%		6.24	%		6.2	%		0	%		0	%
Rate of compensation increase			4.14	%		4.13	%		0	%		0	%		4.12	%		4.1	%		0	%		0	%
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
2014		$	32,822			6,746
2015			33,459			6,971
2016			33,723			7,148
2017			34,455			7,303
2018			35,383			7,500
2019-2023			194,717			41,148
For purposes of measuring postretirement benefit obligations at December 31, 2013, the future annual rates of increase in the cost of health care were assumed to be 7.4% for 2014 decreasing each year to an ultimate rate of 5.0% in 2020 and thereafter.
Assumed health care cost trend rates have a significant effect on the expense and obligation reported for the postretirement benefit plan. A 1% change in assumed health care cost trend rates would have the following effects.
(Thousands of dollars)		1% Increase			1% Decrease
Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 2013		$	2,011			(1,551	)
Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2013			14,331			(11,812	)
During 2013, the Company made contributions of $30,570,000 to its domestic defined benefit pension plans, $16,156,000 to its foreign defined benefit pension plans, $3,412,000 to its domestic postretirement benefits plan and $39,000 to its foreign postretirement benefits plan. The Company currently expects during 2014 to make contributions of $27,133,000 to its domestic defined benefit pension plans, $21,977,000 to its foreign defined benefit pension plans, $5,883,000 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, 2013, 2012 and 2011 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 two funded domestic qualified retirement plans. The Statement specifies that all assets will be held in a Master 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, 2013 and 2012 are presented in the following table.
		December 31,
		2013			2012
Equity securities			68.4	%		62.9	%
Fixed income securities			30.7			36.1
Cash equivalents			0.9			1
			100	%		100	%
The Company’s weighted average expected return on plan assets was 6.24% in 2013 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 6.24% expected return was based on an expected average future equity securities return of 8.40% and a fixed income securities return of 3.90% and is net of average expected investment expenses of 0.45%. Over the last 10 years, the return on funded retirement plan assets has averaged 6.93%.
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
		December  31, 2013			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			0			0
U.S. small/midcap			37,149			37,149			0			0
Hedged funds and other alternative strategies			32,788			0			0			32,788
International commingled trust fund			77,041			0			77,041			0
Emerging market commingled equity fund			9,654			0			9,654			0
Fixed income securities:
U.S. fixed income			72,240			0			72,240			0
International commingled trust fund			14,865			0			14,865			0
Emerging market mutual fund			8,549			0			8,549			0
Cash and equivalents			2,992			2,992			0			0
Total Domestic Plans			344,533			129,396			182,349			32,788
Foreign Plans
Equity securities funds			99,085			0			99,085			0
Fixed income securities funds			57,030			0			57,030			0
Diversified pooled fund			30,800			0			30,800			0
Cash and equivalents			1,660			1,660			0			0
Total Foreign Plans			188,575			1,660			186,915			0
Total		$	533,108			131,056			369,264			32,788
At December 31, 2012, 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
		December 31,  2012			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		$	83,392			83,392			0			0
U.S. small/midcap			20,894			20,894			0			0
Hedged funds and other alternative strategies			14,654			0			0			14,654	*
International commingled trust fund			62,111			0			62,111			0
Emerging market commingled equity fund			9,535			0			9,535			0
Fixed income securities:
U.S. fixed income			80,203			0			80,203			0
International commingled trust fund			15,179			0			15,179			0
Emerging market mutual fund			10,060			0			10,060			0
Cash and equivalents			3,407			3,407			0			0
Total Domestic Plans			299,435			107,693			177,088			14,654
Foreign Plans
Equity securities funds			79,233			0			79,233			0
Fixed income securities funds			51,777			0			51,777			0
Diversified pooled fund			31,758			0			31,758			0
Cash and equivalents			1,343			1,343			0			0
Total Foreign Plans			164,111			1,343			162,768			0
Total		$	463,546			109,036			339,856			14,654
*	Reclassified to Level 3 to conform to current presentation.
The definition of levels within the fair value hierarchy in the tables above is included in Note P.
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. U.S. long/short equity securities are valued monthly based on a pro-rata share of value. 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. 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. The domestic plan commingled trusts have waiting periods for withdrawals ranging from 6 to 30 days. Hedged funds and other alternative strategies funds consist of one investment which permits withdrawals semi-annually and another investment which has a three year lock-up period and a 95 day notice following the lock-up period. 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, 2011		$	13,860
Actual return on plan assets:
Relating to assets held at the reporting date			794
Relating to assets sold during the period			0
Purchases, sales and settlements			0
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			0
Purchases, sales and settlements			15,000
Total at December 31, 2013		$	32,788
THRIFT PLANS – Most full-time employees of the Company may participate in thrift or 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%. A U.K. savings plan allows eligible employees to allot a portion of their base pay to purchase Company Common stock at market value. Such employee allotments are matched by the Company. Amounts charged to expense for these U.S. and U.K. plans were $13,839,000 in 2013, $12,594,000 in 2012 and $10,725,000 in 2011.

Financial_Instruments_and_Risk

Financial Instruments and Risk Management

12 Months Ended

Dec. 31, 2013

Derivative Instruments And Hedging Activities Disclosure [Abstract]

'

Financial Instruments and Risk Management

'

Note K – 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. As described below, 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 until the anticipated transactions occur.

Commodity Purchase Price Risks – The Company is subject to commodity price risk related to crude oil it will produce and sell in 2014. The Company has entered into a series of West Texas Intermediate (WTI) crude oil price swap financial contracts to hedge a portion of its Eagle Ford Shale production from January 2014 through September 2014. Under these contracts, which mature monthly, the Company will pay the average monthly price in effect and will receive the fixed contract prices. WTI open contracts at December 31, 2013 were as follows:

Volumes

Dates

(barrels per day)

Swap Prices

January – March 2014

20,000

$

98.47 per barrel

April – June 2014

20,000

$

96.48 per barrel

July – September 2014

7,000

$

95.24 per barrel

The fair value of these open commodity derivative contracts was a net asset of $716,000 at December 31, 2013. At year-end 2012, the Company was party to corn and related products derivative contracts related to formerly owned ethanol production facilities that had a fair value equal to a net asset of $2,941,000.

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, 2013 and 2012, short-term derivative instruments were outstanding in Canada for approximately $32,300,000 and $154,000,000, respectively, to manage the currency risk associated with 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 2012. The fair values of open foreign currency derivative contracts were liabilities of $26,000 at December 31, 2013 and $1,031,000 at December 31, 2012.

At December 31, 2013 and 2012, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

December 31, 2013

December 31, 2012

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

$

1,970

—

—

Accounts

$

3,043

Accounts

$

102

Receivable

Receivable

Payable

Foreign exchange

—

—

Accounts

$

1,038

—

—

Accounts

$

1,031

Payable

Payable

For the years ended December 31, 2013 and 2012, 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, 2013

Year Ended December 31, 2012

(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

$

2,104

—

—

Operating Revenues

Commodity

Discontinued

(1,604

)

Discontinued

$

(38,283

)

Operations

Operations

Foreign exchange

Interest and Other

(5,162

)

Interest and Other

14,156

Income (Loss)

Income (Loss)

$

(4,662

)

$

(24,127

)

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 to be 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 2013 and 2012, $2,963,000 and $1,852,000 of the deferred loss on the interest rate swaps was charged to interest expense in the Consolidated Statement of Income. There was no Income Statement impact in 2011 associated with accounting for these interest rate derivative contracts. The remaining loss deferred on these matured contracts at December 31, 2013 was $24,815,000, which is recorded, net of income taxes of $8,698,000, in Accumulated Other Comprehensive Income 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 2014.

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 sale of petroleum products to a large number of customers in the United Kingdom. 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, 2013
Equity [Abstract]	'
Stockholders' Equity	'
	Note L – 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.
	On October 16, 2012, the Company announced authorization of a share buyback program of up to $1.0 billion. The 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. On October 2, 2013, the Company’s Board of Directors extended the share repurchase program through April 15, 2014. Through December 31, 2013, the Company has paid $750,000,000 to repurchase shares of Common stock, and has acquired a total of 11,722,969 shares of Common stock under this buyback program. The shares acquired have been carried as Treasury Stock in the Consolidated Balance Sheet. See also Note U – Subsequent Events.

Earnings_per_Share

Earnings per Share	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Earnings per Share	'
	Note M – 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, 2013. No difference existed between net income used in computing basic and diluted income per Common share for these years.
	(Weighted-average shares outstanding)	2013		2012		2011
	Basic method		187,921,062		193,902,335		193,409,621
	Dilutive stock options		1,350,336		766,402		1,102,781
	Diluted method		189,271,398		194,668,737		194,512,402
	The following table reflects certain options to purchase shares of common stock that were outstanding during the three years ended December 31, 2013, but were not included in the computation of diluted EPS above because the incremental shares from assumed conversion were antidilutive.
		2013		2012		2011
	Antidilutive stock options excluded from diluted shares		1,026,900		3,329,689		1,823,564
	Weighted average price of these options	$	54.54	$	64.72	$	69.46

Other_Financial_Information

Other Financial Information	12 Months Ended
	Dec. 31, 2013
Organization Consolidation And Presentation Of Financial Statements [Abstract]	'
Other Financial Information	'
	Note N – Other Financial Information
	INVENTORIES – Inventories accounted for under the LIFO method totaled $318,628,000 and $262,160,000 at December 31, 2013 and 2012, respectively, and these amounts were $268,608,000 and $571,227,000 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 Sheet at December 31, 2013. Significant inventory reductions occurred in 2013 and 2011 associated with the separation of the U.S. retail marketing operations and sale of the two U.S. refineries. The reduction in inventories associated with the U.S. retail marketing separation had no impact on the Company’s Consolidated Statement of Income in 2013. The impact of liquidating inventories associated with the sale of the two U.S. refineries, which was mostly derived from fair value exceeding the LIFO carrying value, increased pretax income from discontinued operations by $296,185,000 in 2011.
	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 $73,732,000 in 2013, $5,092,000 in 2012 and $22,131,000 in 2011.
	CASH FLOW DISCLOSURES – Cash income taxes paid were $457,006,000, $566,999,000 and $938,944,000 in 2013, 2012 and 2011, respectively. Interest paid, net of amounts capitalized, was $60,501,000, $9,501,000 and $38,120,000 in 2013, 2012 and 2011, respectively.
	Noncash operating working capital (increased) decreased during each of the three years ended December 31, 2013 as shown in the following table.
	(Thousands of dollars)	2013			2012			2011
	Accounts receivable	$	224,281			(382,137	)		90,608
	Inventories		14,166			(94,907	)		(67,560	)
	Prepaid expenses		195,013			(245,881	)		9,908
	Deferred income tax assets		15,510			(7,218	)		15,914
	Accounts payable and accrued liabilities		(176,543	)		534,353			(535,788	)
	Current income tax liabilities		(6,098	)		27,610			(273,118	)
	Net (increase) decrease in noncash operating working capital	$	266,329			(168,180	)		(760,036	)

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Accumulated Other Comprehensive Income	'
	Note O – Accumulated Other Comprehensive Income
	The components of Accumulated Other Comprehensive Income (AOCI) on the Consolidated Balance Sheets at December 31, 2013 and December 31, 2012 and the changes during 2013 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
	Components of other comprehensive income (loss):
	Before reclassifications to income			(240,300	)		59,145			0			(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
	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 are included in the computation of net periodic benefit expense. Related income taxes of $8,132 are included in Income tax expense.
	4	Reclassifications before taxes of $2,963 are included in Interest expense. Related income taxes of $1,028 for the year ended December 31, 2013 are included in Income tax expense.
	At December 31, 2013, the net foreign currency translation gain of $305,192,000 was primarily related to exploration and production operations in Canada.

Assets_and_Liabilities_Measure

Assets and Liabilities Measured at Fair Value	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Assets and Liabilities Measured at Fair Value	'
	Note P – 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, 2013 and 2012 are presented in the following table.
					Fair Value Measurements at Reporting Date Using
	(Thousands of dollars)	Fair Value at			Quoted Prices			Significant			Significant
		December 31, 2013			in Active Markets			Other  Observable			Unobservable
					for Identical			Inputs			Inputs
					Assets (Liabilities)			(Level 2)			(Level 3)
					(Level 1)
	Assets
	Commodity derivative contracts	$	1,970			0			1,970			0
	Liabilities
	Nonqualified employee savings plan	$	(13,267	)		(13,267	)		0			0
	Foreign currency exchange derivative contracts		(1,038	)		0			(1,038	)		0
	Total	$	(14,305	)		(13,267	)		(1,038	)		0
					Fair Value Measurements at Reporting Date Using
	(Thousands of dollars)	Fair Value at			Quoted Prices			Significant			Significant
		December 31, 2012			in Active Markets			Other  Observable			Unobservable
					for Identical			Input			Inputs
					Assets (Liabilities)			(Level 2)			(Level 3)
					(Level 1)
	Assets
	Commodity derivative contracts	$	3,043			0			3,043			0
	Liabilities
	Nonqualified employee savings plan	$	(10,293	)		(10,293	)		0			0
	Foreign currency exchange derivative contracts		(1,031	)		0			(1,031	)		0
	Commodity derivative contracts		(102	)		0			(102	)		0
	Total	$	(11,426	)		(10,293	)		(1,133	)		0
	The fair value of West Texas Intermediate (WTI) crude oil contracts was based on active market quotes for WTI crude oil. The fair value of foreign exchange derivative contracts was based on market quotes for similar contracts at the balance sheet date. The fair value of commodity derivative contracts for corn and wet and dried distillers grain in 2012 was determined based on market quotes for No. 2 yellow corn. 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 and changes in fair value of corn and distillers grain is recorded in Income from Discontinued Operations. 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, 2013. At December 31, 2012 derivative assets and liabilities which had offsetting positions are presented in the following tables.
	(Thousands of dollars)	Gross Amounts			Gross Amounts			Net Amounts of
		of Recognized			Offset in the			Assets Presented
		Assets			Consolidated			in the Consolidated
					Balance Sheet			Balance  Sheet
	At December 31, 2012
	Commodity derivatives	$	3,111			(2,169	)		942
	(Thousands of dollars)	Gross Amounts			Gross Amounts			Net Amounts of
		of Recognized			Offset in the			Liabilities Presented
		Liabilities			Consolidated			in the Consolidated
					Balance Sheet			Balance  Sheet
	At December 31, 2012
	Commodity derivatives	$	2,271			(2,169	)		102
	All commodity derivatives noted in the above table at December 31, 2012 were corn-based contracts associated with the Company’s two former U.S. ethanol plants. Net derivative assets in the table above are included in Accounts Receivable on the Consolidated Balance Sheet at December 31, 2012; likewise, net derivative liabilities in the above table are included in Accounts Payable and Accrued Liabilities on the 2012 Consolidated Balance Sheet. Separate derivative agreements existed for each of the ethanol plants. These contracts permitted net settlement and the Company generally availed itself of this right to settle net.
	The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 2013 and 2012. 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,
		2013						2012
	(Thousands of dollars)	Carrying			Fair			Carrying			Fair
		Amount			Value			Amount			Value
	Financial assets (liabilities):
	Canadian government securities with maturities greater than 90 days at the date of acquisition	$	374,842			375,623			115,603			115,802
	Current and long-term debt		(2,962,812	)		(2,822,827	)		(2,245,247	)		(2,357,972	)

Commitments

Commitments	12 Months Ended
	Dec. 31, 2013
Commitments And Contingencies Disclosure [Abstract]	'
Commitments	'
	Note Q – 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 and Azurite oil fields, production facilities at the Thunder Hawk and West Patricia fields, and certain motor fuel stations in the U.K. During each of the next five years, expected future rental payments under all operating leases are approximately $259,365,000 in 2014, $185,957,000 in 2015, $134,754,000 in 2016, $117,555,000 in 2017 and $113,585,000 in 2018. Rental expense for noncancellable operating leases, including contingent payments when applicable, was $192,482,000 in 2013, $178,292,000 in 2012 and $185,016,000 in 2011. 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 F.
	The Company has entered into contracts to hire various drilling rigs and associated equipment for periods beyond December 31, 2013. These rigs will primarily be utilized for drilling operations in the Gulf of Mexico, onshore U.S. and Canada, and offshore Malaysia, Cameroon and Australia. Future commitments under these contracts, all of which expire by 2016, total $1,302,284,000. 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 2023. Future required minimum monthly payments for the next five years are $57,787,000 in 2014, $35,157,000 in 2015, $23,439,000 in 2016, $17,961,000 in 2017 and $12,792,000 in 2018. Under certain circumstances, the Company is required to pay additional amounts depending on the actual hydrocarbon quantities processed under the agreement. Costs incurred under these arrangements were $40,254,000 in 2013, $19,733,000 in 2012 and $24,791,000 in 2011.
	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 eight payments have been made through January 2014. 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 $805,000 in 2013, $1,063,000 in 2012 and $1,317,000 in 2011.
	Commitments for capital expenditures were approximately $1,837,394,000 at December 31, 2013, including $706,889,000 for field development and future work commitments in Malaysia, $561,410,000 for work in the Eagle Ford Shale, $184,840,000 for costs to develop deepwater Gulf of Mexico fields, and $78,851,000, $78,000,000 and $76,150,000 for future work commitments offshore Cameroon, Equatorial Guinea and Vietnam, respectively.

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments And Contingencies Disclosure [Abstract]	'
Contingencies	'
	Note R – 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. 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) currently considers the Company to be a Potentially Responsible Party (PRP) at one Superfund site. The Company has thus far been unable to ascertain any association with the Superfund site based on its research of the facts associated with the site, and the Company has notified the EPA accordingly. Based on currently available information, the Company believes that it has no responsibility at this Superfund site. Accordingly, the Company has not recorded a liability for remedial costs at the Superfund site at December 31, 2013. The potential total cost to all parties to perform necessary remedial work at the site may be substantial. If proven to be responsible, the Company could be required to bear a pro rata share of costs attributable to nonparticipating PRPs or could be assigned additional responsibility for remediation at the site. 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.
	With the spin-off of Murphy’s U.S. retail marketing business in 2013, the newly formed public company, Murphy USA Inc., has retained any environmental exposure associated with U.S. marketing operations. Murphy Oil has assigned its potential liability for one other Superfund site to Murphy USA Inc., and this company has accepted any potential responsibility for this site.
	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.
	OTHER MATTERS – In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide financial guarantees or letters of credit that may be drawn upon if the Company fails to perform under those contracts. At December 31, 2013, the Company had contingent liabilities of $129,866,000 on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to the letters of credit because it is believed that the likelihood of having these drawn is remote.

Terra_Nova_Working_Interest_Re

Terra Nova Working Interest Redetermination	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Terra Nova Working Interest Redetermination	'
	Note S – Terra Nova Working Interest Redetermination
	The joint agreement between the owners of the Terra Nova field, offshore Eastern Canada, required a one-time redetermination of working interests based on an analysis of reservoir quality among fault separated areas where varying ownership interests existed. Under the redetermination, which was essentially completed in 2010, the Company’s working interest at Terra Nova was reduced from its original 12.0% to 10.475% effective in January 2011. The Company made a cash settlement payment to certain Terra Nova partners in January 2011 to equalize all partners’ interest in the field since about February 2005 related to the Company’s working interest reduction. Based on the final settlement paid in 2011, the Company recorded a pretax benefit of $5,351,000 in 2011 due to the ultimate cost of the redetermination settlement being less than originally recorded. The benefit has been reflected as Redetermination of Terra Nova Working Interest in the 2011 Consolidated Statement of Income.

Common_Stock_Issued_and_Outsta

Common Stock Issued and Outstanding	12 Months Ended
	Dec. 31, 2013
Text Block [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, 2013 is shown below.
	(Number of shares outstanding)		2013			2012			2011
	At beginning of year			190,641,317			193,723,208			192,836,008
	Stock options exercised*			303,685			482,974			615,674
	Employee stock purchase and thrift plans			16,020			78,389			33,390
	Restricted stock awards, net of forfeitures			300,910			224,296			238,136
	Treasury shares purchased			(7,855,419	)		(3,867,550	)		0
	At end of year			183,406,513			190,641,317			193,723,208
		*	Shares issued upon exercise of stock options are less than the amount reflected in Note I due to withholdings for statutory income taxes owed upon exercise.

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2013
Subsequent Events [Abstract]	'
Subsequent Events	'
	Note U – Subsequent Events
	On February 5, 2014, the Company entered into a variable term, capped accelerated share repurchase (ASR) transaction with a major financial institution to repurchase a total of $250,000,000 of the Company’s Common stock. Through February 28, 2014, the Company has received 4,018,000 shares under the ASR. The total number of shares to be repurchased under the ASR will be determined by references to the Rule 10b-18 volume-weighted price of the Company’s Common stock, less a fixed discount. The ASR is expected to be completed within three months of the transaction. Also on February 5, 2014, the Company’s Board of Directors declared a quarterly dividend of $0.3125 per share payable on March 3, 2014 to shareholders of record on February 18, 2014.

Business_Segments

Business Segments	12 Months Ended
	Dec. 31, 2013
Segment Reporting [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, Republic of the Congo 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 has announced an intention to sell its U.K. refining and marketing operations. The Company carries the assets and liabilities of the U.K. business as held for sale at December 31, 2013, and the associated results of operations are reported as discontinued operations for all periods presented.
	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. In 2011, the Company sold its two U.S. oil refineries. All 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 2013, sales to Phillips 66 and affiliated companies represented approximately 17% of the Company’s total sales revenue, and sales to Shell Oil and its affiliates represented approximately 14% of total sales revenue. In 2012, Shell Oil, BP and Petronas represented approximately 17%, 13% and 12%, respectively, of consolidated sales. In 2011, Shell Oil, BP and Petronas represented approximately 16%, 15% and 11%, 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		Republic			Other			Total
			States								of the
											Congo
	Year ended December 31, 2013
	Segment income (loss)		$	435.4			180.8			786.4		(9.0	)		(364.8	)		1,028.80
	Revenues from external customers			1,803.80			1,144.70			2,280.50		83.5			0.1			5,312.60
	Interest income			0			0			0		0			0			0
	Interest expense, net of capitalization			0			0			0		0			0			0
	Income tax expense (benefit)			241.6			57.8			477.7		(109.9	)		(10.9	)		656.3
	Significant noncash charges (credits)
	Depreciation, depletion, amortization			576.3			374.6			588.2		0.2			4.3			1,543.60
	Accretion of asset retirement obligations			13.5			16.2			15		4.3			0			49
	Amortization of undeveloped leases			30.3			21			0		0			15.6			66.9
	Impairment of long-lived assets			0			21.6			0		0			0			21.6
	Deferred and noncurrent income taxes			99.6			26.1			48.1		0			0			173.8
	Additions to property, plant, equipment			1,785.90			334.5			1,323.40		(5.7	)		70.5			3,508.60
	Total assets at year-end			4,530.00			4,087.80			6,121.00		51.6			128.8			14,919.20
	Year ended December 31, 2012
	Segment income (loss)		$	168			208.1			894.2		(241.1	)		(124.2	)		905
	Revenues from external customers			1,038.00			1,084.30			2,428.10		57.6			0.1			4,608.10
	Interest income			0			0			0		0			0			0
	Interest expense, net of capitalization			0			0			0		0			0			0
	Income tax expense (benefit)			99.8			65.1			544.7		(64.5	)		(40.1	)		605
	Significant noncash charges (credits)
	Depreciation, depletion, amortization			330.2			345.8			532.1		33.9			2.4			1,244.40
	Accretion of asset retirement obligations			11.4			13.6			12.5		0.9			0			38.4
	Amortization of undeveloped leases			71.6			29.3			0		0			28.9			129.8
	Impairment of long-lived assets			0			0			0		200			0			200
	Deferred and noncurrent income taxes			231			72.3			73.3		(0.3	)		(1.2	)		375.1
	Additions to property, plant, equipment			1,615.90			887.2			1,426.70		(20.7	)		24.7			3,933.80
	Total assets at year-end			3,625.90			4,477.70			4,811.50		112.2			75.6			13,102.90
	Year ended December 31, 2011
	Segment income (loss)		$	152.7			328			812.7		(385.3	)		(293.9	)		614.2
	Revenues from external customers			737.7			1,288.60	*		2,045.60		148.8			24.6			4,245.30
	Interest income			0			0			0		0			0			0
	Interest expense, net of capitalization			0			0			0		0			0			0
	Income tax expense (benefit)			86.5			135.5			434.9		16.4			7.5			680.8
	Significant noncash charges (credits)
	Depreciation, depletion, amortization			183			326			357.3		87.8			1.9			956
	Accretion of asset retirement obligations			9.9			12.5			10.6		0.5			0.3			33.8
	Amortization of undeveloped leases			62.2			28.8			0		0			27.2			118.2
	Impairment of long-lived assets			0			0			0		368.6			0			368.6
	Deferred and noncurrent income taxes			54.2			39.6			84.6		(0.9	)		(0.1	)		177.4
	Additions to property, plant, equipment			696.6			885.2			694.8		79.6			20.6			2,376.80
	Total assets at year-end			2,227.60			3,746.80			3,826.90		257.5			74.1			10,132.90
	Geographic Information		Certain Long-Lived Assets at December 31
	(Millions of dollars)		United			Canada			Malaysia		United			Republic			Other		Total
			States								Kingdom			of the
														Congo
	2013		$	4,267.90			3,834.90			5,301.70		0.4			0			76.6		13,481.50
	2012			4,177.40			4,190.50			4,101.20		703.2			5.9			39.2		13,217.40
	2011			2,953.10			3,493.40			3,154.80		694.7			133.7			52.2		10,481.90
	*	Reclassified to conform to current presentation.
	Segment Information (Continued)
	(Millions of dollars)		Corporate			Discontinued			Consolidated
			and			Operations
Other
Year ended December 31, 2013
Segment income (loss)		$	(140.6	)		235.3			1,123.50
Revenues from external customers			77.5			0			5,390.10
Interest income			3.9			0			3.9
Interest expense, net of capitalization			71.9			0			71.9
Income tax expense (benefit)			(71.7	)		0			584.6
Significant noncash charges (credits)
Depreciation, depletion, amortization			9.8			0			1,553.40
Accretion of asset retirement obligations			0			0			49
Amortization of undeveloped leases			0			0			66.9
Impairment of long-lived assets			0			0			21.6
Deferred and noncurrent income taxes			(15.7	)		0			158.1
Additions to property, plant, equipment			15.5			8.1			3,532.20
Total assets at year-end			1,265.20			1,325.10			17,509.50
Year ended December 31, 2012
Segment income (loss)		$	(98.5	)		164.4			970.9
Revenues from external customers			11.5			0			4,619.60
Interest income			6.5			0			6.5
Interest expense, net of capitalization			14.9			0			14.9
Income tax expense (benefit)			(43.5	)		0			561.5
Significant noncash charges (credits)
Depreciation, depletion, amortization			8.7			0			1,253.10
Accretion of asset retirement obligations			0			0			38.4
Amortization of undeveloped leases			0			0			129.8
Impairment of long-lived assets			0			0			200
Deferred and noncurrent income taxes			(32.3	)		0			342.8
Additions to property, plant, equipment			8.2			191.8			4,133.80
Total assets at year-end			1,009.60			3,410.10			17,522.60
Year ended December 31, 2011
Segment income (loss)		$	(75.0	)		333.5			872.7
Revenues from external customers			33.4			0			4,278.70
Interest income			10.1			0			10.1
Interest expense, net of capitalization			40.7			0			40.7
Income tax expense (benefit)			(52.1	)		0			628.7
Significant noncash charges (credits)
Depreciation, depletion, amortization			8.7			0			964.7
Accretion of asset retirement obligations			0			0			33.8
Amortization of undeveloped leases			0			0			118.2
Impairment of long-lived assets			0			0			368.6
Deferred and noncurrent income taxes			(43.6	)		0			133.8
Additions to property, plant, equipment			5.3			190.1			2,572.20
Total assets at year-end			790.8			3,214.40			14,138.10
Geographic Information		Revenues from External Customers for the Year
(Millions of dollars)		United			Canada			Malaysia		Republic			Other			Total
		States								of the
										Congo
2013		$	1,798.50			1,150.20			2,337.50		83.5			20.4			5,390.10
2012			1,038.10			1,088.40			2,415.60		57.6			19.9			4,619.60
2011			741.8			1,293.40			2,063.00		148.8			31.7			4,278.70

SUPPLEMENTAL_OIL_AND_GAS_INFOR

SUPPLEMENTAL OIL AND GAS INFORMATION	12 Months Ended
	Dec. 31, 2013
Text Block [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 four of the schedules.
	SCHEDULE 1 – SUMMARY OF PROVED OIL RESERVES AND SCHEDULE 2 – SUMMARY OF PROVED NATURAL GAS RESERVES – Reserves of crude oil, condensate, natural gas liquids, natural gas and synthetic oil 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 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 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.
	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. Proved oil reserves shown in Schedule 1 include insignificant volumes of natural gas liquids.
	Oil and natural gas reserves in Malaysia are associated with production sharing contracts for Blocks SK 309/311 and K. Malaysia reserves include oil and gas to be received for both cost recovery and profit provisions under the contracts. Oil and natural gas proved reserves associated with the production sharing contracts in Malaysia totaled 125.1 million barrels and 405.8 billion cubic feet, respectively, at December 31, 2013. Approximately 74.9 billion cubic feet of natural gas proved reserves in Malaysia relate to fields in Block K for which the Company expects to receive sale proceeds of approximately $0.24 per thousand cubic feet.
	SCHEDULE 4 – 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 5 – 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 5 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, 2013.

Summary_of_Proved_Oil_Reserves

Summary of Proved Oil Reserves Based on Average Prices	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Summary of Proved Oil Reserves Based on Average Prices	'
	Schedule 1 – Summary of Proved Oil Reserves Based on Average Prices for 2010 – 2013
			Total			Total –						United			Canada						Malaysia			United			Republic
						by product						States												Kingdom			of the
																											Congo
	(Millions of barrels)		All			Oil			Synthetic			Oil			Oil			Synthetic			Oil			Oil			Oil
			Products						Oil									Oil
	Proved developed and
	undeveloped oil reserves:
	December 31, 2010			308			178.8			129.2			26.6			32.8			129.2			98.4			10.9			10.1
	Revisions of previous estimates			21.2			16			5.2			2.4			3.1			5.2			8.4			8.1			(6.0	)
	Improved recovery			14.2			14.2			0			0			0			0			10.7			3.5			0
	Extensions and discoveries			43.9			43.9			0			32.6			6.7			0			4.6			0			0
	Production			(37.6	)		(32.7	)		(4.9	)		(6.3	)		(6.0	)		(4.9	)		(17.7	)		(0.9	)		(1.8	)
	December 31, 2011			349.7			220.2			129.5			55.3			36.6			129.5			104.4			21.6			2.3
	Revisions of previous estimates			2.6			7.9			(5.3	)		13			(3.4	)		(5.3	)		(0.4	)		0.3			(1.6	)
	Improved recovery			7.2			7.2			0			0			0			0			7.2			0			0
	Extensions and discoveries			84			84			0			77.3			2.9			0			3.8			0			0
	Purchases of properties			12.5			12.5			0			6.5			6			0			0			0			0
	Production			(41.2	)		(36.1	)		(5.1	)		(9.5	)		(5.3	)		(5.1	)		(19.3	)		(1.3	)		(0.7	)
	December 31, 2012			414.8			295.7			119.1			142.6			36.8			119.1			95.7			20.6			0
	Revisions of previous estimates			43.1			40.5			2.6			28.7			8.4			2.6			3.4			0			0
	Improved recovery			27.4			27.4			0			0			0			0			27.4			0			0
	Extensions and discoveries			79.6			79.6			0			61.1			0.3			0			18.2			0			0
	Sales of properties			(20.4	)		(20.4	)		0			0			0			0			0			(20.4	)		0
	Production			(48.9	)		(44.2	)		(4.7	)		(17.7	)		(6.7	)		(4.7	)		(19.6	)		(0.2	)		(0.0	)
	December 31, 2013			495.6			378.6			117			214.7			38.8			117			125.1			0			0
	Proved developed oil reserves:
	December 31, 2010			248.3			129.2			119.1			15.8			28.6			119.1			66.5			10.9			7.4
	December 31, 2011			238.5			118			120.5			20.8			32.6			120.5			57.2			5.1			2.3
	December 31, 2012			267.7			148.6			119.1			48			29.5			119.1			67			4.1			0
	December 31, 2013			304.1			187.1			117			88.9			31.6			117			66.6			0			0
	Proved undeveloped oil reserves:
	December 31, 2010			59.7			49.6			10.1			10.8			4.2			10.1			31.9			0			2.7
	December 31, 2011			111.2			102.2			9			34.5			4			9			47.2			16.5			0
	December 31, 2012			147.1			147.1			0			94.6			7.3			0			28.7			16.5			0
	December 31, 2013			191.5			191.5			0			125.8			7.2			0			58.5			0			0
	Note:	All oil reserves included in the table above are from consolidated subsidiaries and proportionately consolidated joint ventures. The Company has no proved oil reserves attributable to investees accounted for by the equity method.
	2013 Comments for Proved Oil Reserves Changes
	Revisions of previous estimates – The positive revision for proved oil reserves in 2013 in the U.S. was attributable to better well performance in the Eagle Ford Shale area in South Texas, coupled with 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 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.
	2012 Comments for Proved Oil Reserves Changes
	Revisions of previous estimates – A positive proved oil reserves revision in 2012 in the U.S. were 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 Republic of the Congo 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 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 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.
	2011 Comments for Proved Oil Reserves Changes
	Revisions of previous estimates – Positive proved oil reserve revisions in the U.S. in 2011 were primarily associated with better production at the Medusa field in the Gulf of Mexico. Positive revisions for Canada conventional operations were mostly attributable to better well performance at the Hibernia field, offshore Eastern Canada. Synthetic oil operations had positive reserve revisions due to a change in royalty rate. Positive revisions in Malaysia were primarily at the Kikeh field caused by production performance. Positive revisions in the U.K. were associated with the Schiehallion field due to redevelopment by its owners. The negative revision in reserves in Republic of the Congo was attributable to poor production results for wells in the Azurite field.
	Improved recovery – The improved recovery in Malaysia in 2011 was primarily at Kikeh due to improved waterflood response in certain reservoir sands. U.K. reserves were at Schiehallion due to additional wells that permit better waterflood recovery.
	Extensions and discoveries – The U.S. and Canadian reserves in 2011 related to the Eagle Ford Shale area and the Seal heavy oil area, respectively, where extensive drilling occurred during the year and many undeveloped locations will be drilled in upcoming years. The majority of Malaysia reserves related to the Block K Siakap North field, which was sanctioned for development by the government and Company in 2011.

Summary_of_Proved_Natural_Gas_

Summary of Proved Natural Gas Reserves Based on Average Prices	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Summary of Proved Natural Gas Reserves Based on Average Prices	'
	Schedule 2 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2010 – 2013
	(Billions of cubic feet)		Total			United			Canada			Malaysia			United
						States									Kingdom
	Proved developed and undeveloped natural gas reserves:
	December 31, 2010			883.1			90.8			326.9			434			31.4
	Revisions of previous estimates			12.6			(6.3	)		59.4			(32.5	)		(8.0	)
	Improved recovery			13.8			0			0			14.8			(1.0	)
	Extensions and discoveries			363.5			31.1			321.5			10.9			0
	Production			(166.9	)		(17.2	)		(68.9	)		(79.4	)		(1.4	)
	December 31, 2011			1,106.10			98.4			638.9			347.8			21
	Revisions of previous estimates			20.2			16.5			(37.2	)		41.4			(0.5	)
	Improved recovery			7.2			0			0			7.2			0
	Extensions and discoveries			173.5			107.2			25.8			40.5			0
	Purchases of properties			9.4			7			2.4			0			0
	Production			(179.4	)		(19.4	)		(79.5	)		(79.3	)		(1.2	)
	December 31, 2012			1,137.00			209.7			550.4			357.6			19.3
	Revisions of previous estimates			33.7			(38.6	)		34			38.3			0
	Improved recovery			3.2			0			0			3.2			0
	Extensions and discoveries			153.4			33.3			42.5			77.6			0
	Sales of properties			(19.0	)		0			0			0			(19.0	)
	Production			(154.7	)		(19.4	)		(64.1	)		(70.9	)		(0.3	)
	December 31, 2013			1,153.60			185			562.8			405.8			0
	Proved developed natural gas reserves:
	December 31, 2010			586			67			210.1			277.5			31.4
	December 31, 2011			711.6			58.2			427.1			210.5			15.8
	December 31, 2012			706			78.8			415.8			197.3			14.1
	December 31, 2013			786.2			112.6			384			289.6			0
	Proved undeveloped natural gas reserves:
	December 31, 2010			297.1			23.8			116.8			156.5			0
	December 31, 2011			394.5			40.2			211.8			137.3			5.2
	December 31, 2012			431			130.9			134.6			160.3			5.2
	December 31, 2013			367.4			72.4			178.8			116.2			0
	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.
	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 conversion of proved wet gas reserves to proved residual gas 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.
	2011 Comments for Proved Natural Gas Reserves Changes
	Revisions of previous estimates – Proved natural gas reserves in the U.S. had negative revisions in 2011 due to well performance being less than expected in early wells drilled in the gas-prone regions of the Eagle Ford Shale. Positive revisions in Canada were primarily at the Tupper and Tupper West areas based on better than anticipated well performance. Negative revisions in Malaysia in 2011 were primarily due to higher sales prices which effectively reduced the entitlement percentage for future production at Sarawak gas fields. Negative revisions in the U.K. were essentially caused by revised estimate of gas-cap volumes at the Mungo/Monan field.
	Improved recovery – The improved recovery in Malaysia in 2011 was primarily at Kikeh due to improved waterflood response in certain reservoir sands. The U.K. reserves were at Schiehallion due to additional wells that permit better waterflood recovery.
	Extensions and discoveries – The U.S. reserves related to the Eagle Ford Shale area where extensive drilling occurred in 2011 and many undeveloped locations will be drilled in upcoming years. Canada reserves primarily related to Tupper West and Tupper areas in British Columbia mostly due to substantial drilling programs in 2011 and extensions for additional undeveloped locations which are planned to be drilled in upcoming years. Malaysia reserves include a combination of a Sarawak gas field, where three new sand reservoirs were found to be productive and were completed, and the Block K Siakap North field, which was sanctioned for development by the government and Company in 2011.

Costs_Incurred_in_Oil_and_Gas_

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities	'
	Schedule 3 – Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
	(Millions of dollars)		United			Canada		Malaysia			United			Republic			Other		Total
			States								Kingdom1			of the
														Congo
	Year Ended December 31, 2013
	Property acquisition costs
	Unproved		$	32.4			0		0			0			0			3.2		35.6
	Proved			13.2			0		0			0			0			0		13.2
	Total acquisition costs			45.6			0		0			0			0			3.2		48.8
	Exploration costs2			112.4			21.8		14.9			0			0.1			344.5		493.7
	Development costs2			1,773.20			351.6		1,787.70	3		8.1			0			19		3,939.60
	Total costs incurred			1,931.20			373.4		1,802.60			8.1			0.1			366.7		4,482.10
	Charged to expense
	Dry hole expense			46.1			32.1		20.7			0			5.6			158.4		262.9
	Geophysical and other costs			29.1			0.7		4.6			0			0.2			137.8		172.4
	Total charged to expense			75.2			32.8		25.3			0			5.8			296.2		435.3
	Property additions		$	1,856.00			340.6		1,777.30			8.1			(5.7	)		70.5		4,046.80
	Year Ended December 31, 2012
	Property acquisition costs
	Unproved		$	107.7			14.6		0			0			0			10.2		132.5
	Proved			69.1			242.4		0			0			0			0		311.5
	Total acquisition costs			176.8			257		0			0			0			10.2		444
	Exploration costs2			174.5			57		68.8			(1.0	)		51.1			97.6		448
	Development costs2			1,352.70			664.5		1,433.70			46.6			22.6			1.6		3,521.70
	Total costs incurred			1,704.00			978.5		1,502.50			45.6			73.7			109.4		4,413.70
	Charged to expense
	Dry hole expense			32.3			8		26.1			(0.8	)		76.2			39.3		181.1
	Geophysical and other costs			19.6			2.5		1.1			(0.2	)		0.6			45.4		69
	Total charged to expense			51.9			10.5		27.2			(1.0	)		76.8			84.7		250.1
	Property additions		$	1,652.10			968		1,475.30			46.6			(3.1	)		24.7		4,163.60
	Year Ended December 31, 2011
	Property acquisition costs
	Unproved		$	233.8			18.5		0			0			0			27		279.3
	Proved			0			0		0			0			23.5			0		23.5
	Total acquisition costs			233.8			18.5		0			0			23.5			27		302.8
	Exploration costs2			253.2			76		0.7			0.5			0.5			231.6		562.5
	Development costs2			263.9			871.9		705.5			30.5			78.7			3.8		1,954.30
	Total costs incurred			750.9			966.4		706.2			31			102.7			262.4		2,819.60
	Charged to expense
	Dry hole expense			0.6			50.6		0.1			0			18.1			181.6		251
	Geophysical and other costs			35.9			10.2		11			0.5			2.9			60.2		120.7
	Total charged to expense			36.5			60.8		11.1			0.5			21			241.8		371.7
	Property additions		$	714.4			905.6		695.1			30.5			81.7			20.6		2,447.90
	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        Includes non-cash asset retirement costs as follows:
	2013
	Exploration costs		$	0			0.2		0			0			0			0		0.2
	Development costs			70.1			5.9		95.9			0			0			0		171.9
			$	70.1			6.1		95.9			0			0			0		172.1
	2012
	Exploration costs		$	(1.7	)		0.1		0			0			0			0		(1.6	)
	Development costs			37.9			80.7		48.6			(11.5	)		17.6			0		173.3
			$	36.2			80.8		48.6			(11.5	)		17.6			0		171.7
	2011
	Exploration costs		$	2			0.3		0			0			0			0		2.3
	Development costs			15.8			20.1		0.3			10.8			2.1			0		49.1
			$	17.8			20.4		0.3			10.8			2.1			0		51.4
	3	Includes property cost associated with non-cash capital lease of $358.0 million at the Kakap field.

Results_of_Operations_for_Oil_

Results of Operations for Oil and Gas Producing Activities	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Results of Operations for Oil and Gas Producing Activities	'
	Schedule 4 – Results of Operations for Oil and Gas Producing Activities*
					Canada								Republic
													of the
	(Millions of dollars)		United		Conven-			Synthetic		Malaysia			Congo			Other			Total
			States		tional
	Year Ended December 31, 2013
	Revenues
	Crude oil and natural gas liquids – Sales to unaffiliated enterprises		$	1,724.70		507.2			441		1,875.00			83.6			0			4,631.50
	Natural gas – Sales to unaffiliated enterprises			72.7		198.1			0		404			0			0			674.8
	Total oil and gas revenues			1,797.40		705.3			441		2,279.00			83.6			0			5,306.30
	Other operating revenues			6.4		(1.9	)		0.3		1.5			(0.1	)		0.1			6.3
	Total revenues			1,803.80		703.4			441.3		2,280.50			83.5			0.1			5,312.60
	Costs and expenses
	Production expenses			351.1		185.5			228.2		384.4			191			0			1,340.20
	Exploration costs charged to expense			75.2		32.8			0		25.3			5.8			296.2			435.3
	Undeveloped lease amortization			30.3		21			0		0			0			15.6			66.9
	Depreciation, depletion and amortization			576.3		319.2			55.4		588.2			0.2			4.3			1,543.60
	Accretion of asset retirement obligations			13.5		5.9			10.3		15			4.3			0			49
	Impairment of properties			0		21.6			0		0			0			0			21.6
	Selling and general expenses			80.4		25.3			0.9		3.5			1.1			59.7			170.9
	Total costs and expenses			1,126.80		611.3			294.8		1,016.40			202.4			375.8			3,627.50
				677		92.1			146.5		1,264.10			(118.9	)		(375.7	)		1,685.10
	Income tax expense (benefit)			241.6		19.9			37.9		477.7			(109.9	)		(10.9	)		656.3
	Results of operations		$	435.4		72.2			108.6		786.4			(9.0	)		(364.8	)		1,028.80
	Year Ended December 31, 2012
	Revenues
	Crude oil and natural gas liquids – Sales to unaffiliated enterprises		$	976.1		411.7			463.1		1,946.00			57.6			0			3,854.50
	Natural gas – Sales to unaffiliated enterprises			54.2		209.8			0		481.1			0			0			745.1
	Total oil and gas revenues			1,030.30		621.5			463.1		2,427.10			57.6			0			4,599.60
	Other operating revenues			7.7		(0.9	)		0.6		1			0			0.1			8.5
	Total revenues			1,038.00		620.6			463.7		2,428.10			57.6			0.1			4,608.10
	Costs and expenses
	Production expenses			252.4		167.2			224.1		422.7			48.4			0			1,114.80
	Exploration costs charged to expense			51.9		10.5			0		27.2			76.8			84.7			251.1
	Undeveloped lease amortization			71.6		29.3			0		0			0			28.9			129.8
	Depreciation, depletion and amortization			330.2		290.5			55.3		532.1			33.9			2.4			1,244.40
	Accretion of asset retirement obligations			11.4		5.1			8.5		12.5			0.9			0			38.4
	Impairment of properties			0		0			0		0			200			0			200
	Selling and general expenses			52.7		19.7			0.9		(5.3	)		3.2			48.4			119.6
	Total costs and expenses			770.2		522.3			288.8		989.2			363.2			164.4			3,098.10
				267.8		98.3			174.9		1,438.90			(305.6	)		(164.3	)		1,510.00
	Income tax expense (benefit)			99.8		25.1			40		544.7			(64.5	)		(40.1	)		605
	Results of operations		$	168		73.2			134.9		894.2			(241.1	)		(124.2	)		905
	*	Results exclude corporate overhead, interest and discontinued operations.
	(Millions of dollars)		United		Canada					Malaysia			Republic			Other			Total
			States										of the
						Conven-			Synthetic				Congo
						tional
	Year Ended December 31, 2011
	Revenues
	Crude oil and natural gas liquids –
	Sales to unaffiliated enterprises		$	648.8		459.2			410.2		1,583.00			148.8			0			3,250.00
	Transfers to consolidated operations			0		46.4			96.4		0			0			0			142.8
	Natural gas – Sales to unaffiliated enterprises			71.1		280.2			0		461.3			0			0			812.6
	Total oil and gas revenues			719.9		785.8			506.6		2,044.30			148.8			0			4,205.40
	Other operating revenues			17.8		(3.8	)		0		1.3			0			24.6			39.9
	Total revenues			737.7		782			506.6		2,045.60			148.8			24.6			4,245.30
	Costs and expenses
	Production expenses			164.8		151.2			236.1		420.6			37.6			0			1,010.30
	Exploration costs charged to expense			36.5		60.8			0		11.1			21			241.8			371.2
	Undeveloped lease amortization			62.2		28.8			0		0			0			27.2			118.2
	Depreciation, depletion and amortization			183		273.9			52.1		357.3			87.8			1.9			956
	Accretion of asset retirement obligations			9.9		4.9			7.6		10.6			0.5			0.3			33.8
Impairment of properties			0		0			0		0			368.6			0			368.6
Terra Nova working interest redetermination			0		(5.4	)		0		0			0			0			(5.4	)
Selling and general expenses			42.1		14.2			0.9		(1.6	)		2.2			39.8			97.6
Total costs and expenses			498.5		528.4			296.7		798			517.7			311			2,950.30
			239.2		253.6			209.9		1,247.60			(368.9	)		(286.4	)		1,295.00
Income tax expense			86.5		79.7			55.8		434.9			16.4			7.5			680.8
Results of operations		$	152.7		173.9			154.1		812.7			(385.3	)		(293.9	)		614.2
*	Results exclude corporate overhead, interest and discontinued operations.

Standardized_Measure_of_Discou

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves	'
	Schedule 5 – Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
	(Millions of dollars)	United			Canada			Malaysia			United			Republic			Total
		States									Kingdom			of the
														Congo
	December 31, 2013
	Future cash inflows	$	20,638.60			16,112.90			13,399.00			0			0			50,150.50
	Future development costs		(3,833.9	)		(1,882.3	)		(1,445.3	)		0			0			(7,161.5	)
	Future production costs		(5,244.7	)		(7,073.0	)		(4,490.4	)		0			0			(16,808.1	)
	Future income taxes		(3,368.3	)		(1,472.8	)		(1,855.1	)		0			0			(6,696.2	)
	Future net cash flows		8,191.70			5,684.80			5,608.20			0			0			19,484.70
	10% annual discount for estimated timing of cash flows		(4,020.2	)		(2,999.1	)		(1,620.7	)		0			0			(8,640.0	)
	Standardized measure of discounted future net cash flows	$	4,171.50			2,685.70			3,987.50			0			0			10,844.70
	December 31, 2012
	Future cash inflows	$	15,547.50			15,511.60			10,354.90			2,395.20			0			43,809.20
	Future development costs		(3,731.6	)		(1,815.2	)		(966.9	)		(273.2	)		0			(6,786.9	)
	Future production costs		(3,466.6	)		(7,336.4	)		(3,143.4	)		(738.3	)		0			(14,684.7	)
	Future income taxes		(2,527.6	)		(1,714.9	)		(1,675.9	)		(872.7	)		0			(6,791.1	)
	Future net cash flows		5,821.70			4,645.10			4,568.70			511			0			15,546.50
	10% annual discount for estimated timing of cash flows		(2,862.1	)		(2,876.5	)		(1,322.9	)		(372.2	)		0			(7,433.7	)
	Standardized measure of discounted future net cash flows	$	2,959.60			1,768.60			3,245.80			138.8			0			8,112.80
	December 31, 2011
	Future cash inflows	$	6,105.40			18,835.50			11,037.50			2,509.50			248.6			38,736.50
	Future development costs		(1,283.5	)		(1,929.5	)		(1,559.8	)		(356.2	)		(0.0	)		(5,129.0	)
	Future production costs		(1,417.9	)		(7,199.7	)		(3,087.8	)		(763.0	)		(183.8	)		(12,652.2	)
	Future income taxes		(807.2	)		(2,806.8	)		(2,129.7	)		(869.0	)		(39.7	)		(6,652.4	)
	Future net cash flows		2,596.80			6,899.50			4,260.20			521.3			25.1			14,302.90
	10% annual discount for estimatedtiming of cash flows		(912.0	)		(3,658.7	)		(1,507.4	)		(304.4	)		2.8			(6,379.7	)
	Standardized measure of discounted future net cash flows	$	1,684.80			3,240.80			2,752.80			216.9			27.9			7,923.20
	Following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown.
	(Millions of dollars)	2013			2012			2011
	Net changes in prices and production costs	$	267.8			(2,461.1	)		3,743.40
	Net changes in development costs		(3,456.8	)		(3,860.1	)		(4,113.9	)
	Sales and transfers of oil and gas produced, net of production costs		(3,972.4	)		(3,493.3	)		(3,273.5	)
	Net change due to extensions and discoveries		4,608.90			4,466.30			3,300.90
	Net change due to purchases and sales of proved reserves		(135.6	)		347.4			0
	Development costs incurred		3,326.80			3,299.00			1,881.50
	Accretion of discount		1,109.30			1,153.50			827.7
	Revisions of previous quantity estimates		1,646.00			728.1			892.5
	Net change in income taxes		(662.1	)		9.8			(1,029.4	)
	Net increase		2,731.90			189.6			2,229.20
	Standardized measure at January 1		8,112.80			7,923.20			5,694.00
	Standardized measure at December 31	$	10,844.70			8,112.80			7,923.20

Capitalized_Costs_Relating_to_

Capitalized Costs Relating to Oil and Gas Producing Activities	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Capitalized Costs Relating to Oil and Gas Producing Activities	'
	Schedule 6 – Capitalized Costs Relating to Oil and Gas Producing Activities
	(Millions of dollars)		United			Canada			Malaysia			United			Republic			Other			Subtotal			Synthetic			Total
			States									Kingdom			of the									Oil –
															Congo									Canada
	December 31, 2013
	Unproved oil and gas properties		$	723.6			475.9			233.5			0			6.1			158.9			1,598.00			0			1,598.00
	Proved oil and gas properties			5,816.90			4,529.90			7,636.60			0			737.8			0			18,721.20			1,493.50			20,214.70
	Gross capitalized costs			6,540.50			5,005.80			7,870.10			0			743.9			158.9			20,319.20			1,493.50			21,812.70
	Accumulated depreciation, depletion and amortization
	Unproved oil and gas properties			(178.1	)		(248.5	)		(0.0	)		0			(6.1	)		(85.6	)		(518.3	)		(0.0	)		(518.3	)
	Proved oil and gas properties			(2,171.1	)		(2,006.8	)		(2,576.4	)		(0.0	)		(737.8	)		0			(7,492.1	)		(417.6	)		(7,909.7	)
	Net capitalized costs		$	4,191.30			2,750.50			5,293.70			0			0			73.3			12,308.80			1,075.90			13,384.70
	December 31, 2012
	Unproved oil and gas properties		$	750			510.9			837			0			11.8			107.4			2,217.10			0			2,217.10
	Proved oil and gas properties			3,972.10			4,697.80			5,260.70			603.2			737.8			0			15,271.60			1,435.60			16,707.20
	Gross capitalized costs			4,722.10			5,208.70			6,097.70			603.2			749.6			107.4			17,488.70			1,435.60			18,924.30
	Accumulated depreciation, depletion and amortization
	Unproved oil and gas properties			(183.8	)		(244.3	)		(0.0	)		(0.0	)		(6.1	)		(70.0	)		(504.2	)		(0.0	)		(504.2	)
	Proved oil and gas properties			(1,590.6	)		(1,828.8	)		(2,001.8	)		(397.5	)		(737.8	)		(0.0	)		(6,556.5	)		(389.6	)		(6,946.1	)
	Net capitalized costs		$	2,947.70			3,135.60			4,095.90			205.7			5.7			37.4			10,428.00			1,046.00			11,474.00
	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_INFORMA

SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED)	'
	MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
	SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED)
	(Millions of dollars except per share amounts)		First		Second		Third		Fourth			Year
			Quarter		Quarter		Quarter		Quarter
	Year Ended December 31, 2013
	Sales and other operating revenues		$	1,298.90		1,315.60		1,366.50		1,331.70			5,312.70
	Income from continuing operations before income taxes			360		454.2		463.7		194.8			1,472.70
	Income from continuing operations			182.7		259.9		265		180.5			888.1
	Net income			360.6		402.7		284.8		75.4			1,123.50
	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		0.4			5.94
	Cash dividend per Common share			0.3125		0.3125		0.3125		0.3125			1.25
	Market price of Common Stock1
	High			63.81		66.09		71.84		65.55			71.84
	Low			59.33		59.98		59.8		59.93			59.33
	Year Ended December 31, 2012
	Sales and other operating revenues		$	1,149.80		1,078.00		1,083.70		1,297.10			4,608.60
	Income from continuing operations before income taxes			471.6		357		338.9		200.5			1,368.00
	Income from continuing operations			285.6		210.9		186.1		123.9			806.5
	Net income			290.1		295.4		226.7		158.7			970.9
	Income from continuing operations per Common share
	Basic			1.48		1.09		0.96		0.64			4.16
	Diluted			1.47		1.08		0.95		0.64			4.14
	Net income per Common share
	Basic			1.5		1.52		1.17		0.82			5.01
	Diluted			1.49		1.52		1.16		0.82			4.99
	Cash dividend per Common share			0.275		0.275		0.3125		2.8125	2		3.675	2
	Market price of Common Stock1
	High			64.76		57.12		56.24		63.74			64.76
	Low			55.82		43.65		48.8		54.97			43.65
	1	Prices are as quoted on the New York Stock Exchange.
	2	Includes special dividend of $2.50 per Common share paid on December 3, 2012.

VALUATION_ACCOUNTS_AND_RESERVE

VALUATION ACCOUNTS AND RESERVES	12 Months Ended
	Dec. 31, 2013
Valuation And Qualifying Accounts [Abstract]	'
VALUATION ACCOUNTS AND RESERVES	'
	MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
	SCHEDULE II – VALUATION ACCOUNTS AND RESERVES
	(Millions of dollars)		Balance at		Charged		Deductions			Other*			Balance at
			January 1		(Credited)								December 31
					to Expense
	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		115.4		0			(5.7	)		633.7
	2012
	Deducted from asset accounts:
	Allowance for doubtful accounts		$	7.9		0.3		(1.5	)		0			6.7
	Deferred tax asset valuation allowance			445.8		78.2		0			0			524
	2011
	Deducted from asset accounts:
	Allowance for doubtful accounts		$	8		0.2		(0.3	)		0			7.9
	Deferred tax asset valuation allowance			305.3		140.5		0			0			445.8
	*	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, 2013
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. Murphy owns one petroleum refinery in the United Kingdom and markets petroleum products in that country under various brand names and to unbranded wholesale customers. The Company has announced its intention to sell the U.K. refining and marketing assets. On August 30, 2013, the Company completed the spin-off of Murphy USA Inc. (MUSA) to its shareholders. MUSA formerly was the Company’s U.S. downstream 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 all its United Kingdom oil and natural gas producing assets during 2013. In 2011, the Company sold two U.S. petroleum refineries and certain associated marketing assets. 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. For consolidated subsidiaries that are less than wholly owned, the noncontrolling interest is reflected in the balance sheet as a component of Stockholders’ Equity. 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 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, 2013 and 2012, the liabilities for natural gas balancing were immaterial.
	Refined products sold at retail are recorded when the customer takes delivery at the pump. Title transfer for bulk motor fuel products generally occurs at pipeline custody points or upon truck loading at product terminals. Merchandise revenues are recorded at the point of sale.
	The Company enters into buy/sell and similar arrangements when crude oil and other petroleum products are held at one location but are needed at a different location. The Company often pays or receives funds related to the buy/sell arrangement based on location or quality differences. The Company accounts for such transactions on a net basis in its Consolidated Statement of Income.
TAXES COLLECTED FROM CUSTOMERS AND REMITTED TO GOVERNMENT AUTHORITIES	'
	TAXES COLLECTED FROM CUSTOMERS AND REMITTED TO GOVERNMENT AUTHORITIES – Excise and other taxes collected on sales of refined products and remitted to governmental agencies are excluded from revenues and costs and expenses in the Consolidated Statement of Income.
CASH EQUIVALENTS	'
	CASH EQUIVALENTS – Short-term investments, which include government securities and other instruments with government securities as collateral, that 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, 2013, the Company owned Canadian government securities with maturities greater than 90 days at date of acquisition that had a carrying value of $374,842,000. These securities are readily marketable and could be quickly converted to cash if needed to meet operating cash needs in Canada.
ACCOUNTS RECEIVABLE	'
	ACCOUNTS RECEIVABLE – At December 31, 2013, the Company’s accounts receivable primarily consisted of amounts owed to the Company by customers for sales of crude oil and natural gas. In 2012 this balance included receivables for oil and gas sales and amounts owed for refined products sold under varying credit arrangements in the U.S. and U.K. 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 – Crude oil and blend stocks inventories include unsold crude oil production in 2013 and 2012, and in 2012 also included Milford Haven refinery feedstocks. 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. Refinery inventories of crude oil and other feedstocks and certain finished product inventories are valued at the lower of cost, generally applied on a last-in, first-out (LIFO) basis, or market. Merchandise inventory held for resale at retail marketing stations in 2012 was generally carried at average cost and was included in Finished products inventories. Materials and supplies inventories are valued at the lower of average cost or estimated value and generally consist of tubulars and other drilling equipment and additionally at year-end 2012 it included spare parts for refinery operations. Cash collected upon the sale of inventory to customers is classified as an operating activity in the Consolidated Statement of Cash Flows.
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. The Milford Haven, Wales refinery, certain marketing facilities and certain natural gas processing facilities are depreciated primarily using the composite straight-line method with depreciable lives ranging from 14 to 25 years. Gasoline stations and other properties are depreciated over 3 to 20 years by individual unit on the straight-line method. Gains and losses on asset disposals or retirements are included in income as a separate component of revenues. Property and equipment of U.K. refining and marketing operations are no longer depreciated following the recognition of these assets as held for sale in late 2013.
	Turnarounds for major processing units at the Milford Haven, Wales refinery are scheduled at four to five year intervals. 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 Milford Haven and 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 Operating Expenses for Syncrude and through results of discontinued operation for the Milford Haven refinery. Also in 2014, amortization of deferred turnaround costs will cease for the U.K. downstream operations that are held for sale. All other maintenance and repairs are expensed as incurred. Renewals and betterments are capitalized. A major turnaround occurred in 2010 at the Milford Haven, Wales refinery.
CAPITALIZED INTEREST	'
	CAPITALIZED INTEREST – Interest associated with borrowings from third parties is capitalized on significant oil and gas development projects when the expected development period extends for one year or more. Interest capitalized is credited in the Consolidated 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. The change in the carrying value of goodwill during 2013 was primarily caused by a change in the foreign currency translation rate between years. Based on its assessment of the fair value of its Canadian conventional oil and natural gas operations, the Company believes the recorded value of goodwill is not impaired at December 31, 2013. Should a future assessment indicate that goodwill is not fully recoverable, an impairment charge to write down the carrying value of goodwill would be required.
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 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 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 in earnings. When the income effect of the underlying cash flow hedged item is recognized in the Consolidated Statement of Income, the fair value of the associated cash flow hedge is reclassified from other comprehensive income into earnings. The ineffective portion of the change in fair value of a cash flow hedge 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 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 CRSU, and the period-end price of the Company’s common stock for phantom units. When SAR are exercised and when CRSU and phantom units expire, the Company adjusts previously recorded expense to the final amounts paid out in cash for these awards.
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.
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, 2013
Discontinued Operations And Disposal Groups [Abstract]	'
Assets and Liabilities Presented in Consolidated Balance Sheets as Held for Sale	'
	The following table presents the carrying value of the major categories of assets and liabilities of discontinued operations reflected on the Company’s consolidated balance sheets at December 31, 2013 and 2012:
	(Millions of dollars)	2013		2012
	Current assets
	Held for sale assets of U.K. downstream operations:
	Cash	$	301,302		0
	Accounts receivable		302,059		0
	Inventories		254,240		0
	Other		86,131		0
	Held for sale assets of U.K. oil and gas operations		0		15,119
	Total current assets held for sale	$	943,732		15,119
	Non-current assets
	Held for sale assets of U.K. downstream operations:
	Property, plant and equipment, net	$	360,347		0
	Other		21,057		0
	Held for sale assets of U.K. oil and gas operations:
	Property, plant and equipment		0		205,746
	Other		0		2,422
	Total non-current assets held for sale	$	381,404		208,168
	Current liabilities
	Current liabilities associated with held for sale properties of U.K. downstream operations:
	Accounts payable	$	637,432		0
	Other		1,708		0
	Current liabilities associated with held for sale properties of U.K. oil and gas operations:
	Accounts payable		0		27,578
	Income taxes payable		0		19,893
	Total current liabilities associated with assets held for sale	$	639,140		47,471
	Non-current liabilities
	Non-current liabilities associated with held for sale properties of U.K. downstream operations:
	Deferred income taxes payable	$	68,096		0
	Deferred credits and other liabilities		27,448		0
	Non-current liabilities associated with held for sale properties of U.K. oil and gas operations:
	Deferred income taxes payable		0		87,893
	Asset retirement obligations		0		53,284
	Total non-current liabilities associated with assets held for sale	$	95,544		141,177
Major Categories of Assets and Liabilities for MUSA Included in Consolidated Balance Sheet	'
	The major categories of assets and liabilities for MUSA were included in the Company’s consolidated balance sheet at December 31, 2012 as follows:
	(Millions of dollars)	2012
	Current assets
	Accounts receivable	$	525,936
	Inventories		217,393
	Other current assets		8,685
	Total current assets	$	752,014
	Non-current assets
	Property, plant and equipment, net	$	1,163,748
	Other assets		498
	Total non-current assets	$	1,164,246
	Current liabilities
	Accounts payable	$	612,755
	Income taxes payable		16,851
	Other taxes payable		65,349
	Other current liabilities		38,798
	Total current liabilities	$	733,753
	Non-current liabilities
	Long-term debt	$	1,123
	Deferred income taxes		89,946
	Asset retirement obligations		15,401
	Deferred credits and other liabilities		87,600
	Total non-current liabilities	$	194,070
Results of Operations Associated with Discontinued Operations	'
	The results of operations associated with all discontinued operations are presented in the following table.
	(Thousands of dollars)	2013		2012		2011
	Revenues	$	17,586,236		24,156,748		27,310,300
	Income from operations before income taxes	$	119,984		330,048		571,339
	Gain on sale before income taxes		130,991		0		12,684
	Total income from discontinued operations before taxes		250,975		330,048		584,023
	Provision for income taxes		15,639		165,666		250,519
	Income from discontinued operations	$	235,336		164,382		333,504

Property_Plant_and_Equipment_T

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Property Plant And Equipment [Abstract]	'
Property, Plant and Equipment	'
		December 31, 2013						December 31, 2012
	(Thousands of dollars)	Cost			Net			Cost			Net
	Exploration and production1	$	21,932,119			13,433,468	2		18,408,904			11,294,933	2
	Refining and marketing		0			0			2,619,844			1,661,081
	Corporate and other		89,175			47,587			121,445			55,592
		$	22,021,294			13,481,055			21,150,193			13,011,606
	1         Includes mineral rights as follows:	$	1,007,920			489,578			1,051,153			556,399
	2         Includes $48,691 in 2013 and $26,611 in 2012 related to administrative assets and support equipment.
Net Changes in Capitalized Exploratory Well Costs	'
	The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 2013.
	(Thousands of dollars)	2013			2012			2011
	Beginning balance at January 1	$	445,697			556,412			497,765
	Additions to capitalized exploratory well costs pending the determination of proved reserves		57,716			135,849			86,035
	Reclassifications to proved properties based on the determination of proved reserves		(93,936	)		(165,377	)		0
	Capitalized exploratory well costs charged to expense		(16,447	)		(81,187	)		(27,388	)
	Ending balance at December 31	$	393,030			445,697			556,412
Aging of Capitalized Exploratory Well Costs	'
	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.
		2013									2012							2011
	(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	$	69,757		11		5
	One to two years		60,787			7			1			18,335			2		3		143,611		15		3
	Two to three years		0			0			0			83,314			9		4		101,696		9		2
	Three years or more		275,744			22			7			284,215			26		6		241,348		33		6
		$	393,030			32			9		$	445,697			44		15	$	556,412		68		16

Longterm_Debt_Tables

Long-term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Long-term Debt	'
		December 31
	(Thousands of dollars)	2013			2012
	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, 2013		350,000			0
	Other, 6%, due through 2028		0			1,169
	Total notes payable		2,600,000			2,251,169
	Unamortized discount on notes payable		(5,439	)		(5,922	)
	Total notes payable, net of unamortized discount		2,594,561			2,245,247
	Capitalized lease obligation, due through June 2028		368,251			0
	Total debt including current maturities		2,962,812			2,245,247
	Current maturities		(26,249	)		(46	)
	Total long-term debt	$	2,936,563			2,245,201

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Reconciliation of Beginning and Ending Aggregate Carrying Amount of Asset Retirement Obligation	'
	A reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligation for 2013 and 2012 is shown in the following table.
	(Thousands of dollars)		2013			2012
	Balance at beginning of year		$	751,583			615,545
	Accretion expense			48,996			39,341	1
	Liabilities incurred			172,048			184,439
	Revision of previous estimates			(4,856	)		10,468
	Liabilities settled			(51,647	)		(40,434	)
	Liabilities assumed by Murphy USA Inc. upon separation			(15,401	)		0
	U.K. oil and gas asset obligations reclassified to liabilities associated with assets held for sale in 2012			0			(64,355	)
	Changes due to translation of foreign currencies			(20,720	)		6,579
	Balance at end of year			880,003			751,583
	Current portion of liability at end of year2			(27,515	)		(27,310	)
	Noncurrent portion of liability at end of year		$	852,488			724,273
		1	Includes $980 reclassified to discontinued operations associated with U.S. downstream operations.
		2	Included in Other Accrued Liabilities on the Consolidated Balance Sheet.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Components of Income from Continuing Operations Before Income Taxes and Income Tax Expense	'
	The components of income from continuing operations before income taxes for each of the three years ended December 31, 2013 and income tax expense attributable thereto were as follows.
	(Thousands of dollars)	2013			2012			2011
	Income (loss) from continuing operations before income taxes
	United States	$	(5,810	)		54,275			72,038
	Foreign		1,478,497			1,313,735			1,095,837
		$	1,472,687			1,368,010			1,167,875
	Income tax expense (benefit)
	Federal – Current	$	(56,790	)		(256,931	)		6,050
	– Deferred		65,883			177,325			15,633
			9,093			(79,606	)		21,683
	State		7,141			8,104			5,609
	Foreign – Current		477,715			472,701			471,960
	– Deferred		90,601			160,317			129,425
			568,316			633,018			601,385
	Total	$	584,550			561,516			628,677
Reconciliation of Income Taxes Based on U.S. Statutory Tax Rate to Income Tax Expense	'
	The following table reconciles income taxes based on the U.S. statutory tax rate to the Company’s income tax expense.
	(Thousands of dollars)	2013			2012			2011
	Income tax expense based on the U.S. statutory tax rate	$	515,440			478,804			408,756
	Foreign income subject to foreign taxes at a rate different than the U.S. statutory rate		31,752			7,710			(10,682	)
	State income taxes, net of federal benefit		4,642			5,268			3,646
	U.S. tax benefit on certain foreign upstream investments		(133,526	)		(108,077	)		0
	Increase in deferred tax asset valuation allowance related to other foreign exploration expenditures		129,588			87,558			102,714
	Impairment or abandonment of Azurite field with no tax benefit		35,475			70,000			129,010
	Malaysian tax benefits on prior year costs in Block P		0			0			(25,573	)
	Other, net		1,179			20,253			20,806
	Total	$	584,550			561,516			628,677
Analysis of Deferred Tax Assets and Deferred Tax Liabilities Showing Tax Effects of Significant Temporary Differences	'
	An analysis of the Company’s deferred tax assets and deferred tax liabilities at December 31, 2013 and 2012 showing the tax effects of significant temporary differences follows.
	(Thousands of dollars)	2013			2012
	Deferred tax assets
	Property and leasehold costs	$	708,947			658,588
	Liabilities for dismantlements		79,111			78,100
	Postretirement and other employee benefits		175,446			197,912
	Alternative minimum tax		49,536			37,253
	Foreign tax credit carryforwards		19,896			18,594
	Other deferred tax assets		23,352			32,500
	Total gross deferred tax assets		1,056,288			1,022,947
	Less valuation allowance		(633,735	)		(523,966	)
	Net deferred tax assets		422,553			498,981
	Deferred tax liabilities
	Property, plant and equipment		(747,561	)		(808,311	)
	Accumulated depreciation, depletion and amortization		(1,040,251	)		(1,077,867	)
	Other deferred tax liabilities		(38,849	)		(70,710	)
	Total gross deferred tax liabilities		(1,826,661	)		(1,956,888	)
	Net deferred tax liabilities	$	(1,404,108	)		(1,457,907	)
Reconciliation of Beginning and Ending Amount of Consolidated Liability for Unrecognized Income Tax Benefits	'
	A reconciliation of the beginning and ending amount of the consolidated liability for unrecognized income tax benefits during the three years ended December 31, 2013 is shown in the following table.
	(Thousands of dollars)	2013			2012			2011
	Balance at January 1	$	16,611			18,857			23,196
	Additions for tax positions related to current year		2,486			1,258			1,294
	Settlements due to lapse of time		(12,731	)		(3,504	)		(5,633	)
	Balance at December 31	$	6,366			16,611			18,857

Incentive_Plans_Tables

Incentive Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'
Share-Based Plans, Amounts Recognized	'
	Amounts recognized in the financial statements with respect to share-based plans are shown in the following table.
	(Thousands of dollars)	2013			2012			2011
	Compensation charged against income before income tax benefit	$	66,976			46,694			43,272
	Related income tax benefit recognized in income		19,321			14,443			14,396
Fair Value of Option Award Estimated on Date of Grant using Black-Scholes Pricing Model	'
	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.
		2013		2012	2011
	Fair value per option grant	$15.81 – $20.62		$12.37 – $17.74	$20.34
	Assumptions
	Dividend yield	2.10% – 2.30%		1.80% – 2.27%	1.80%
	Expected volatility	34.00% – 36.00%		39.00% – 39.62%	37.00%
	Risk-free interest rate	0.96% – 2.00%		0.55% – 0.77%	2.10%
	Expected life	5.25 yrs. – 6.50 yrs.		4.00 yrs. – 5.20 yrs.	5.10 yrs.
Changes in Stock Options Outstanding	'
	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, 2010		5,302,384		$	48.83
	Granted at FMV		1,397,312			67.64
	Exercised		(974,500	)		39.3
	Forfeited		(290,968	)		52.73
	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			56.8
	Exercisable at December 31, 2010		2,499,610		$	45.07
	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
Additional Information about Stock Options Outstanding	'
	Additional information about stock options outstanding at December 31, 2013 is shown below.
		Options Outstanding									Options Exercisable
	Range of Exercise	No.			Avg. Life			Aggregate			No. of			Avg. Life		Aggregate
	Prices per Option	of Options			Remaining			Intrinsic			Options			Remaining		Intrinsic
					in Years			Value						in Years		Value
	$37.44 to $39.02		658,782			3.1		$	17,677,000			406,939			1.4	$	11,165,000
	$43.88 to $51.63		2,233,621			4.5			34,786,000			832,631			2.4		16,224,000
	$54.21 to $63.46		3,114,182			4.6			21,288,000			1,195,752			2.4		4,500,000
			6,006,585			4.4		$	73,751,000			2,435,322			2.2	$	31,889,000
Changes in SAR Outstanding	'
	Changes in SAR outstanding beginning in 2013 are presented in the following table.
		Number			Average
		of SAR			Exercise
					Price
	Outstanding at December 31, 2012		0
	Granted		851,000		$	54.21
	Forfeited		(68,712	)
	Surrendered in connection with separation of Murphy USA Inc.		(73,000	)
	Murphy USA Inc. spin-off adjustment		78,824
	Outstanding at December 31, 2013		788,112		$	54.21
Changes in Performance-Based RSU Outstanding	'
	Changes in performance-based RSU outstanding for each of the last three years are presented in the following table.
		Equity-Settled									Cash-Settled
		Restricted Stock Units									Restricted Stock Units
	(Number of share units)	2013			2012			2011			2013
	Balance at beginning of year		1,426,238			1,174,492			1,023,492			0
	Granted		521,776			653,355			521,423			93,200
	Awarded		(380,150	)		(260,175	)		(309,656	)		0
	Forfeited		(39,573	)		(141,434	)		(60,767	)		(9,924	)
	Surrendered in connection with separation of Murphy USA Inc.		(116,568	)		0			0			(6,800	)
	Murphy USA Inc. spin-off adjustment		148,569			0			0			8,380
	Balance at end of year		1,560,292			1,426,238			1,174,492			84,856
Assumptions used in Valuation of Performance Awards Granted	'
	The assumptions used in the valuation of the performance awards granted in 2013, 2012 and 2011 are presented in the following table.
		2013		2012	2011
	Fair value per share at grant date	$39.50 – $68.01		$54.90 – $63.64	$38.94 – $64.89
	Assumptions
	Expected volatility	31.00% – 32.00%		37.00%	51.00%
	Risk-free interest rate	0.41% – 0.62%		0.30%	1.04%
	Stock beta	0.907 – 0.908		0.913	1.006
	Expected life	3.00 yrs.		3.00 yrs.	3.00 yrs.
Changes in Time-Lapse Restricted Stock and Restricted Stock Units Outstanding	'
	Changes in time-lapse restricted stock units outstanding for each of the last three years are presented in the following table.
	(Number of share units)	2013			2012			2011
	Balance at beginning of year		98,477			116,724			166,173
	Granted		38,184			42,256			32,711
	Vested and issued		(34,696	)		(44,980	)		(82,160	)
	Forfeited		0			(15,523	)		0
	Murphy USA Inc. spin-off adjustment		10,916			0			0
	Balance at end of year		112,881			98,477			116,724

Employee_and_Retiree_Benefit_P1

Employee and Retiree Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Amounts Included in Accumulated Other Comprehensive Income Not Recognized in Net Periodic Benefit Expense	'
	At December 31, 2013, amounts included in accumulated other comprehensive income (AOCI), 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		$	(150,682	)		(13,815	)
	Prior service (cost) credit			(3,559	)		372
	Transitional asset (liability)			517			0
			$	(153,724	)		(13,443	)
Amounts Included in Accumulated Other Comprehensive Income Expected to be Amortization into Net Periodic Benefit Expense	'
	Amounts included in AOCI at December 31, 2013 that are expected to be amortized into net periodic benefit expense during 2014 are shown in the following table.
	(Thousands of dollars)		Pension			Other
			Benefits			Postretirement
						Benefits
	Net actuarial loss		$	(8,190	)		(242	)
	Prior service (cost) credit			(951	)		82
	Transitional asset (liability)			517			0
			$	(8,624	)		(160	)
Projected Benefit Obligations, Accumulated Benefit Obligations and Fair Value of Plan Assets for Plans where Accumulated Benefit Obligation Exceeded Fair Value of Plan Assets	'
	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)		2013			2012			2013			2012			2013			2012
	Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets		$	571,217			587,318			520,610			523,773			502,308			431,788
	Unfunded nonqualified and directors’ plans where accumulated benefit obligation exceeds fair value of plan assets			115,492			112,135			102,198			98,498			0			0
	Unfunded other postretirement plans			107,001			124,134			107,001			124,134			0			0
Components of Net Periodic Benefit Expense	'
	The table that follows provides the components of net periodic benefit expense for each of the three years ended December 31, 2013.
			Pension Benefits									Other
												Postretirement Benefits
	(Thousands of dollars)		2013			2012			2011			2013			2012			2011
	Service cost		$	26,346			23,500			22,406			4,566			3,958			4,547
	Interest cost			30,903			29,869			30,785			5,189			5,174			6,141
	Expected return on plan assets			(28,974	)		(25,826	)		(25,919	)		0			0			0
	Amortization of prior service cost (credit)			1,006			1,254			1,314			(143	)		(173	)		(240	)
	Amortization of transitional (asset) liability			(514	)		(529	)		(536	)		8			8			8
	Recognized actuarial loss			17,338			16,389			12,484			1,484			1,317			2,329
				46,105			44,657			40,534			11,104			10,284			12,785
	Termination benefits expense			849			6,177			695			0			0			0
	Curtailment expense (benefit)			1,365			0			1,036			(442	)		0			(605	)
	Net periodic benefit expense		$	48,319			50,834			42,265			10,662			10,284			12,180
Weighted-Average Assumptions used in Measurement of Benefit Obligations and Net Periodic Benefit Expense	'
	The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2013 and 2012 and net periodic benefit expense for 2013 and 2012.
			Benefit Obligations												Net Periodic Benefit Expense
			Pension						Other						Pension						Other
			Benefits						Postretirement						Benefits						Postretirement
									Benefits												Benefits
			31-Dec						31-Dec						Year						Year
			2013			2012			2013			2012			2013			2012			2013			2012
	Discount rate			4.78	%		4.24	%		4.91	%		4.18	%		4.23	%		4.8	%		4.18	%		4.87	%
	Expected return on plan assets			6.24	%		6.2	%		0	%		0	%		6.24	%		6.2	%		0	%		0	%
	Rate of compensation increase			4.14	%		4.13	%		0	%		0	%		4.12	%		4.1	%		0	%		0	%
Benefit Payments Reflecting Expected Future Service as Appropriate which are Expected to be Paid in Future Years from Assets of Plans or by 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
	2014		$	32,822			6,746
	2015			33,459			6,971
	2016			33,723			7,148
	2017			34,455			7,303
	2018			35,383			7,500
	2019-2023			194,717			41,148
One Percent Change in Assumed Health Care Cost Trend Rates	'
	A 1% change in assumed health care cost trend rates would have the following effects.
	(Thousands of dollars)		1% Increase			1% Decrease
	Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 2013		$	2,011			(1,551	)
	Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2013			14,331			(11,812	)
Effects of Fair Value Measurements Using Significant Unobservable Inputs on Changes in Level 3 Plan Assets	'
	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, 2011		$	13,860
	Actual return on plan assets:
	Relating to assets held at the reporting date			794
	Relating to assets sold during the period			0
	Purchases, sales and settlements			0
	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			0
	Purchases, sales and settlements			15,000
	Total at December 31, 2013		$	32,788
Domestic Plans [Member]	'
Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status	'
	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, 2013 and 2012 and a statement of the funded status as of December 31, 2013 and 2012.
			Pension						Other
			Benefits						Postretirement
									Benefits
	(Thousands of dollars)		2013			2012			2013			2012
	Change in benefit obligation
	Obligation at January 1		$	721,531			629,568			124,134			114,962
	Service cost			26,346			23,500			4,566			3,958
	Interest cost			30,903			29,869			5,189			5,174
	Plan amendments			1,989			0			0			0
	Participant contributions			21			30			1,376			1,035
	Actuarial loss (gain)			(9,876	)		55,479			(8,324	)		4,686
	Medicare Part D subsidy			0			0			384			432
	Exchange rate changes			1,852			7,125			(36	)		14
	Benefits paid			(38,745	)		(30,217	)		(5,211	)		(6,127	)
	Special termination benefits			849			6,177			0			0
	Curtailments			(26,463	)		0			(15,077	)		0
	Obligation assumed by MUSA at separation			(1,153	)		0			0			0
	Obligation at December 31			707,254			721,531			107,001			124,134
	Change in plan assets
	Fair value of plan assets at January 1			463,546			404,350			0			0
	Actual return on plan assets			61,932			41,674			0			0
	Employer contributions			46,726			42,207			3,451			4,660
	Participant contributions			21			30			1,376			1,035
	Medicare Part D subsidy			0			0			384			432
	Exchange rate changes			1,594			6,289			0			0
	Benefits paid			(38,745	)		(30,217	)		(5,211	)		(6,127	)
	Other			(1,966	)		(787	)		0			0
	Fair value of plan assets at December 31			533,108			463,546			0			0
	Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
	Deferred charges and other assets			10,254			9,679			0			0
	Other accrued liabilities			(5,565	)		(5,556	)		(5,920	)		(5,646	)
	Deferred credits and other liabilities			(158,589	)		(262,108	)		(101,081	)		(118,488	)
	Liabilities associated with assets held for sale			(20,246	)		0			0			0
	Funded status and net plan liability recognized at December 31		$	(174,146	)		(257,985	)		(107,001	)		(124,134	)
Foreign Plans [Member]	'
Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status	'
	The preceding tables in this note include the following amounts related to foreign benefit plans.
			Pension						Other
			Benefits						Postretirement
									Benefits
	(Thousands of dollars)		2013			2012			2013			2012
	Benefit obligation at December 31		$	211,799			184,550			541			525
	Fair value of plan assets at December 31			188,575			164,111			0			0
	Net plan liabilities recognized			23,224			20,439			541			525
	Net periodic benefit expense			12,622			11,022			92			88
Other Postretirement Benefits [Member]	'
Asset Allocation for Benefit Plans	'
	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
			December  31, 2013			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			0			0
	U.S. small/midcap			37,149			37,149			0			0
	Hedged funds and other alternative strategies			32,788			0			0			32,788
	International commingled trust fund			77,041			0			77,041			0
	Emerging market commingled equity fund			9,654			0			9,654			0
	Fixed income securities:
	U.S. fixed income			72,240			0			72,240			0
	International commingled trust fund			14,865			0			14,865			0
	Emerging market mutual fund			8,549			0			8,549			0
	Cash and equivalents			2,992			2,992			0			0
	Total Domestic Plans			344,533			129,396			182,349			32,788
	Foreign Plans
	Equity securities funds			99,085			0			99,085			0
	Fixed income securities funds			57,030			0			57,030			0
	Diversified pooled fund			30,800			0			30,800			0
	Cash and equivalents			1,660			1,660			0			0
	Total Foreign Plans			188,575			1,660			186,915			0
	Total		$	533,108			131,056			369,264			32,788
	At December 31, 2012, 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
			December 31,  2012			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		$	83,392			83,392			0			0
	U.S. small/midcap			20,894			20,894			0			0
	Hedged funds and other alternative strategies			14,654			0			0			14,654	*
	International commingled trust fund			62,111			0			62,111			0
	Emerging market commingled equity fund			9,535			0			9,535			0
	Fixed income securities:
	U.S. fixed income			80,203			0			80,203			0
	International commingled trust fund			15,179			0			15,179			0
	Emerging market mutual fund			10,060			0			10,060			0
	Cash and equivalents			3,407			3,407			0			0
	Total Domestic Plans			299,435			107,693			177,088			14,654
	Foreign Plans
	Equity securities funds			79,233			0			79,233			0
	Fixed income securities funds			51,777			0			51,777			0
	Diversified pooled fund			31,758			0			31,758			0
	Cash and equivalents			1,343			1,343			0			0
	Total Foreign Plans			164,111			1,343			162,768			0
	Total		$	463,546			109,036			339,856			14,654
	*	Reclassified to Level 3 to conform to current presentation.
Funded Defined Benefit Pension Plans [Member]	'
Asset Allocation for Benefit Plans	'
	The weighted average asset allocation for the Company’s funded pension benefit plans at December 31, 2013 and 2012 are presented in the following table.
			December 31,
			2013			2012
	Equity securities			68.4	%		62.9	%
	Fixed income securities			30.7			36.1
	Cash equivalents			0.9			1
				100	%		100	%

Financial_Instruments_and_Risk1

Financial Instruments and Risk Management (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instruments And Hedging Activities Disclosure [Abstract]

'

WTI Open Contracts

'

WTI open contracts at December 31, 2013 were as follows:

Volumes

Dates

(barrels per day)

Swap Prices

January – March 2014

20,000

$

98.47 per barrel

April – June 2014

20,000

$

96.48 per barrel

July – September 2014

7,000

$

95.24 per barrel

Fair Value of Derivative Instruments Not Designated as Hedging Instruments

'

At December 31, 2013 and 2012, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

December 31, 2013

December 31, 2012

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

$

1,970

—

—

Accounts

$

3,043

Accounts

$

102

Receivable

Receivable

Payable

Foreign exchange

—

—

Accounts

$

1,038

—

—

Accounts

$

1,031

Payable

Payable

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

'

For the years ended December 31, 2013 and 2012, 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, 2013

Year Ended December 31, 2012

(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

2,104

—

—

Operating Revenues

Commodity

Discontinued

$

(1,604

)

Discontinued

$

(38,283

)

Operations

Operations

Foreign exchange

Interest and Other

(5,162

)

Interest and Other

14,156

Income (Loss)

Income (Loss)

$

(4,662

)

$

(24,127

)

Earnings_per_Share_Tables

Earnings per Share (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Weighted-Average Shares Outstanding for Computation of Basic and Diluted Income Per Common 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, 2013. No difference existed between net income used in computing basic and diluted income per Common share for these years.
	(Weighted-average shares outstanding)	2013		2012		2011
	Basic method		187,921,062		193,902,335		193,409,621
	Dilutive stock options		1,350,336		766,402		1,102,781
	Diluted method		189,271,398		194,668,737		194,512,402
Anti Dilutive Securities Not Included in Computation of Diluted EPS	'
	The following table reflects certain options to purchase shares of common stock that were outstanding during the three years ended December 31, 2013, but were not included in the computation of diluted EPS above because the incremental shares from assumed conversion were antidilutive.
		2013		2012		2011
	Antidilutive stock options excluded from diluted shares		1,026,900		3,329,689		1,823,564
	Weighted average price of these options	$	54.54	$	64.72	$	69.46

Other_Financial_Information_Ta

Other Financial Information (Tables)	12 Months Ended
	Dec. 31, 2013
Organization Consolidation And Presentation Of Financial Statements [Abstract]	'
Noncash Operating Working Capital (Increased) Decreased	'
	Noncash operating working capital (increased) decreased during each of the three years ended December 31, 2013 as shown in the following table.
	(Thousands of dollars)	2013			2012			2011
	Accounts receivable	$	224,281			(382,137	)		90,608
	Inventories		14,166			(94,907	)		(67,560	)
	Prepaid expenses		195,013			(245,881	)		9,908
	Deferred income tax assets		15,510			(7,218	)		15,914
	Accounts payable and accrued liabilities		(176,543	)		534,353			(535,788	)
	Current income tax liabilities		(6,098	)		27,610			(273,118	)
	Net (increase) decrease in noncash operating working capital	$	266,329			(168,180	)		(760,036	)

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Components of Accumulated Other Comprehensive Income	'
	The components of Accumulated Other Comprehensive Income (AOCI) on the Consolidated Balance Sheets at December 31, 2013 and December 31, 2012 and the changes during 2013 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
	Components of other comprehensive income (loss):
	Before reclassifications to income			(240,300	)		59,145			0			(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
	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 are included in the computation of net periodic benefit expense. Related income taxes of $8,132 are included in Income tax expense.
	4	Reclassifications before taxes of $2,963 are included in Interest expense. Related income taxes of $1,028 for the year ended December 31, 2013 are included in Income tax expense.

Assets_and_Liabilities_Measure1

Assets and Liabilities Measured at Fair Value (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements of Assets and Liabilities	'
	The fair value measurements for these assets and liabilities at December 31, 2013 and 2012 are presented in the following table.
					Fair Value Measurements at Reporting Date Using
	(Thousands of dollars)	Fair Value at			Quoted Prices			Significant			Significant
		December 31, 2013			in Active Markets			Other  Observable			Unobservable
					for Identical			Inputs			Inputs
					Assets (Liabilities)			(Level 2)			(Level 3)
					(Level 1)
	Assets
	Commodity derivative contracts	$	1,970			0			1,970			0
	Liabilities
	Nonqualified employee savings plan	$	(13,267	)		(13,267	)		0			0
	Foreign currency exchange derivative contracts		(1,038	)		0			(1,038	)		0
	Total	$	(14,305	)		(13,267	)		(1,038	)		0
					Fair Value Measurements at Reporting Date Using
	(Thousands of dollars)	Fair Value at			Quoted Prices			Significant			Significant
		December 31, 2012			in Active Markets			Other  Observable			Unobservable
					for Identical			Input			Inputs
					Assets (Liabilities)			(Level 2)			(Level 3)
					(Level 1)
	Assets
	Commodity derivative contracts	$	3,043			0			3,043			0
	Liabilities
	Nonqualified employee savings plan	$	(10,293	)		(10,293	)		0			0
	Foreign currency exchange derivative contracts		(1,031	)		0			(1,031	)		0
	Commodity derivative contracts		(102	)		0			(102	)		0
	Total	$	(11,426	)		(10,293	)		(1,133	)		0
Offsetting of Assets and Liabilities Related to Derivative Contracts	'
	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, 2013. At December 31, 2012 derivative assets and liabilities which had offsetting positions are presented in the following tables.
	(Thousands of dollars)	Gross Amounts			Gross Amounts			Net Amounts of
		of Recognized			Offset in the			Assets Presented
		Assets			Consolidated			in the Consolidated
					Balance Sheet			Balance  Sheet
	At December 31, 2012
	Commodity derivatives	$	3,111			(2,169	)		942
	(Thousands of dollars)	Gross Amounts			Gross Amounts			Net Amounts of
		of Recognized			Offset in the			Liabilities Presented
		Liabilities			Consolidated			in the Consolidated
					Balance Sheet			Balance  Sheet
	At December 31, 2012
	Commodity derivatives	$	2,271			(2,169	)		102
Carrying Amounts and Estimated Fair Values of Financial Instruments	'
	The fair value of these, which represents fees associated with obtaining the instruments, was nominal.
		At December 31,
		2013						2012
	(Thousands of dollars)	Carrying			Fair			Carrying			Fair
		Amount			Value			Amount			Value
	Financial assets (liabilities):
	Canadian government securities with maturities greater than 90 days at the date of acquisition	$	374,842			375,623			115,603			115,802
	Current and long-term debt		(2,962,812	)		(2,822,827	)		(2,245,247	)		(2,357,972	)

Common_Stock_Issued_and_Outsta1

Common Stock Issued and Outstanding (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Activity in Number of Shares of Common Stock Issued and Outstanding	'
	Activity in the number of shares of Common Stock issued and outstanding for the three years ended December 31, 2013 is shown below.
	(Number of shares outstanding)		2013			2012			2011
	At beginning of year			190,641,317			193,723,208			192,836,008
	Stock options exercised*			303,685			482,974			615,674
	Employee stock purchase and thrift plans			16,020			78,389			33,390
	Restricted stock awards, net of forfeitures			300,910			224,296			238,136
	Treasury shares purchased			(7,855,419	)		(3,867,550	)		0
	At end of year			183,406,513			190,641,317			193,723,208
		*	Shares issued upon exercise of stock options are less than the amount reflected in Note I due to withholdings for statutory income taxes owed upon exercise.

Business_Segments_Tables

Business Segments (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Segment Information	'
	Segment Information		Exploration and Production
	(Millions of dollars)		United			Canada			Malaysia		Republic			Other			Total
			States								of the
											Congo
	Year ended December 31, 2013
	Segment income (loss)		$	435.4			180.8			786.4		(9.0	)		(364.8	)		1,028.80
	Revenues from external customers			1,803.80			1,144.70			2,280.50		83.5			0.1			5,312.60
	Interest income			0			0			0		0			0			0
	Interest expense, net of capitalization			0			0			0		0			0			0
	Income tax expense (benefit)			241.6			57.8			477.7		(109.9	)		(10.9	)		656.3
	Significant noncash charges (credits)
	Depreciation, depletion, amortization			576.3			374.6			588.2		0.2			4.3			1,543.60
	Accretion of asset retirement obligations			13.5			16.2			15		4.3			0			49
	Amortization of undeveloped leases			30.3			21			0		0			15.6			66.9
	Impairment of long-lived assets			0			21.6			0		0			0			21.6
	Deferred and noncurrent income taxes			99.6			26.1			48.1		0			0			173.8
	Additions to property, plant, equipment			1,785.90			334.5			1,323.40		(5.7	)		70.5			3,508.60
	Total assets at year-end			4,530.00			4,087.80			6,121.00		51.6			128.8			14,919.20
	Year ended December 31, 2012
	Segment income (loss)		$	168			208.1			894.2		(241.1	)		(124.2	)		905
	Revenues from external customers			1,038.00			1,084.30			2,428.10		57.6			0.1			4,608.10
	Interest income			0			0			0		0			0			0
	Interest expense, net of capitalization			0			0			0		0			0			0
	Income tax expense (benefit)			99.8			65.1			544.7		(64.5	)		(40.1	)		605
	Significant noncash charges (credits)
	Depreciation, depletion, amortization			330.2			345.8			532.1		33.9			2.4			1,244.40
	Accretion of asset retirement obligations			11.4			13.6			12.5		0.9			0			38.4
	Amortization of undeveloped leases			71.6			29.3			0		0			28.9			129.8
	Impairment of long-lived assets			0			0			0		200			0			200
	Deferred and noncurrent income taxes			231			72.3			73.3		(0.3	)		(1.2	)		375.1
	Additions to property, plant, equipment			1,615.90			887.2			1,426.70		(20.7	)		24.7			3,933.80
	Total assets at year-end			3,625.90			4,477.70			4,811.50		112.2			75.6			13,102.90
	Year ended December 31, 2011
	Segment income (loss)		$	152.7			328			812.7		(385.3	)		(293.9	)		614.2
	Revenues from external customers			737.7			1,288.60	*		2,045.60		148.8			24.6			4,245.30
	Interest income			0			0			0		0			0			0
	Interest expense, net of capitalization			0			0			0		0			0			0
	Income tax expense (benefit)			86.5			135.5			434.9		16.4			7.5			680.8
	Significant noncash charges (credits)
	Depreciation, depletion, amortization			183			326			357.3		87.8			1.9			956
	Accretion of asset retirement obligations			9.9			12.5			10.6		0.5			0.3			33.8
	Amortization of undeveloped leases			62.2			28.8			0		0			27.2			118.2
	Impairment of long-lived assets			0			0			0		368.6			0			368.6
	Deferred and noncurrent income taxes			54.2			39.6			84.6		(0.9	)		(0.1	)		177.4
	Additions to property, plant, equipment			696.6			885.2			694.8		79.6			20.6			2,376.80
	Total assets at year-end			2,227.60			3,746.80			3,826.90		257.5			74.1			10,132.90
	*	Reclassified to conform to current presentation.
	(Millions of dollars)		Corporate			Discontinued			Consolidated
			and			Operations
			Other
	Year ended December 31, 2013
	Segment income (loss)		$	(140.6	)		235.3			1,123.50
	Revenues from external customers			77.5			0			5,390.10
	Interest income			3.9			0			3.9
	Interest expense, net of capitalization			71.9			0			71.9
	Income tax expense (benefit)			(71.7	)		0			584.6
	Significant noncash charges (credits)
	Depreciation, depletion, amortization			9.8			0			1,553.40
	Accretion of asset retirement obligations			0			0			49
	Amortization of undeveloped leases			0			0			66.9
	Impairment of long-lived assets			0			0			21.6
	Deferred and noncurrent income taxes			(15.7	)		0			158.1
	Additions to property, plant, equipment			15.5			8.1			3,532.20
Total assets at year-end			1,265.20			1,325.10			17,509.50
Year ended December 31, 2012
Segment income (loss)		$	(98.5	)		164.4			970.9
Revenues from external customers			11.5			0			4,619.60
Interest income			6.5			0			6.5
Interest expense, net of capitalization			14.9			0			14.9
Income tax expense (benefit)			(43.5	)		0			561.5
Significant noncash charges (credits)
Depreciation, depletion, amortization			8.7			0			1,253.10
Accretion of asset retirement obligations			0			0			38.4
Amortization of undeveloped leases			0			0			129.8
Impairment of long-lived assets			0			0			200
Deferred and noncurrent income taxes			(32.3	)		0			342.8
Additions to property, plant, equipment			8.2			191.8			4,133.80
Total assets at year-end			1,009.60			3,410.10			17,522.60
Year ended December 31, 2011
Segment income (loss)		$	(75.0	)		333.5			872.7
Revenues from external customers			33.4			0			4,278.70
Interest income			10.1			0			10.1
Interest expense, net of capitalization			40.7			0			40.7
Income tax expense (benefit)			(52.1	)		0			628.7
Significant noncash charges (credits)
Depreciation, depletion, amortization			8.7			0			964.7
Accretion of asset retirement obligations			0			0			33.8
Amortization of undeveloped leases			0			0			118.2
Impairment of long-lived assets			0			0			368.6
Deferred and noncurrent income taxes			(43.6	)		0			133.8
Additions to property, plant, equipment			5.3			190.1			2,572.20
Total assets at year-end			790.8			3,214.40			14,138.10
Geographic Information on Certain Long-Lived Assets	'
	Geographic Information		Certain Long-Lived Assets at December 31
	(Millions of dollars)		United			Canada			Malaysia		United			Republic			Other		Total
			States								Kingdom			of the
														Congo
	2013		$	4,267.90			3,834.90			5,301.70		0.4			0			76.6		13,481.50
	2012			4,177.40			4,190.50			4,101.20		703.2			5.9			39.2		13,217.40
	2011			2,953.10			3,493.40			3,154.80		694.7			133.7			52.2		10,481.90
Geographic Information on Revenues from External Customers	'
	Geographic Information		Revenues from External Customers for the Year
	(Millions of dollars)		United			Canada			Malaysia		Republic			Other			Total
			States								of the
											Congo
	2013		$	1,798.50			1,150.20			2,337.50		83.5			20.4			5,390.10
	2012			1,038.10			1,088.40			2,415.60		57.6			19.9			4,619.60
	2011			741.8			1,293.40			2,063.00		148.8			31.7			4,278.70

Significant_Accounting_Policie2

Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Significant Accounting Policies [Line Items]	'	'
Canadian government securities with maturities greater than 90 days at the date of acquisition	$374,842	$115,603
Maturity of Canadian government securities	'90 days	'
Stock Options [Member]	'	'
Significant Accounting Policies [Line Items]	'	'
Stock-based compensation, fair value assumption model	'Black-Scholes 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	'
Restricted Stock and Restricted Stock Units [Member]	'	'
Significant Accounting Policies [Line Items]	'	'
Stock-based compensation, vesting period	'3 years	'
Minimum [Member]	'	'
Significant Accounting Policies [Line Items]	'	'
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] | Stock Options [Member]	'	'
Significant Accounting Policies [Line Items]	'	'
Stock-based compensation, vesting period	'3 years	'
Refining [Member] | Minimum [Member]	'	'
Significant Accounting Policies [Line Items]	'	'
Depreciable lives, straight-line method	'14 years	'
Turnarounds for major processing units	'4 years	'
Refining [Member] | Maximum [Member]	'	'
Significant Accounting Policies [Line Items]	'	'
Depreciable lives, straight-line method	'25 years	'
Turnarounds for major processing units	'5 years	'
Gasoline stations and other properties [Member] | Minimum [Member]	'	'
Significant Accounting Policies [Line Items]	'	'
Depreciable lives, straight-line method	'3 years	'
Gasoline stations and other properties [Member] | Maximum [Member]	'	'
Significant Accounting Policies [Line Items]	'	'
Depreciable lives, straight-line method	'20 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	'

Discontinued_Operations_Additi

Discontinued Operations - Additional Information (Detail) (USD $)

1 Months Ended

6 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

Sep. 30, 2011

Mar. 31, 2011

Feb. 28, 2011

Dec. 31, 2012

Jun. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2013

Aug. 30, 2013

Aug. 30, 2013

Sep. 30, 2011

Sep. 30, 2011

Dec. 31, 2013

OilRefinery

Ethanol Plant in Hereford, Texas [Member]

Oil and Gas Properties [Member]

Murphy USA Inc [Member]

Murphy Oil USA Inc [Member]

Superior Refinery [Member]

Meraux Refinery [Member]

U.K refining and marketing assets [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 distributed

'

'

'

'

'

$650,000,000

$0

[1]

$0

[1]

'

'

'

$650,000,000

'

'

'

Fund raised from proceeds of secured notes

'

'

'

'

'

'

'

'

'

'

'

500,000,000

'

'

'

Borrowed funds under credit facility

'

'

'

'

'

'

'

'

'

'

'

150,000,000

'

'

'

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.

'

'

'

'

'

'

'

'

'

After tax gain on sale of oil and natural gas production

'

'

'

'

'

'

'

'

'

216,147,000

'

'

'

'

'

Impairment charges of Investment

'

'

'

'

'

'

'

'

60,988,000

'

'

'

'

'

73,000,000

United Kingdom, corporation tax rate, tax relief on oil and gas decommissioning costs

'

'

'

50.00%

62.00%

'

'

'

'

'

'

'

'

'

'

United Kingdom, increase in tax expense of discontinued operations

'

'

'

'

'

'

5,523,000

14,461,000

'

'

'

'

'

'

'

United Kingdom, supplemental tax rate for oil and gas companies

'

62.00%

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from sales of assets

'

'

'

'

'

1,650,000

99,000

[1]

27,382,000

[1]

'

'

'

'

214,000,000

325,000,000

'

Number of Refineries for disposal

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain (loss) on disposal of refineries, net of tax

18,724,000

'

'

'

'

'

'

'

'

'

'

'

77,585,000

58,861,000

'

Gain (loss) on liquidation of inventories

'

'

'

'

'

'

'

'

'

'

'

'

'

$179,152,000

'

[1]

Reclassified to conform to current presentation.

Discontinued_Operations_Assets

Discontinued Operations - Assets and Liabilities Presented in Consolidated Balance Sheets as Held for Sale (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'
Accounts receivable	$999,872	$1,853,364
Held for sale assets of U.K. oil and gas operations	943,732	15,119
Property, plant and equipment	13,481,055	13,011,606
Other	98,123	151,183
Total non-current assets held for sale	381,404	208,168
Accounts payable	2,158,485	2,803,268
Income taxes payable	222,930	219,847
Total current liabilities associated with assets held for sale	639,140	47,471
Deferred income taxes payable	1,466,100	1,544,336
Deferred credits and other liabilities	339,028	516,540
Asset retirement obligations	852,488	724,273
Total non-current liabilities associated with assets held for sale	95,544	141,177
U.K. downstream operations [Member]	'	'
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'
Cash	301,302	0
Accounts receivable	302,059	0
Inventories	254,240	0
Other	86,131	0
Property, plant and equipment	360,347	0
Other	21,057	0
Accounts payable	637,432	0
Other	1,708	0
Deferred income taxes payable	68,096	0
Deferred credits and other liabilities	27,448	0
U.K. oil and gas operations [Member]	'	'
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'
Held for sale assets of U.K. oil and gas operations	0	15,119
Property, plant and equipment	0	205,746
Other	0	2,422
Accounts payable	0	27,578
Income taxes payable	0	19,893
Deferred income taxes payable	0	87,893
Asset retirement obligations	$0	$53,284

Discontinued_Operations_Major_

Discontinued Operations - Major Categories of Assets and Liabilities for MUSA Included in Consolidated Balance Sheet (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013
In Thousands, unless otherwise specified			Murphy USA Inc [Member]
Current assets	'	'	'
Accounts receivable	$999,872	$1,853,364	$525,936
Inventories	'	'	217,393
Other current assets	'	'	8,685
Total current assets	3,508,643	4,108,583	752,014
Non-current assets	'	'	'
Property, plant and equipment, Net	13,481,055	13,011,606	1,163,748
Other assets	98,123	151,183	498
Total non-current assets	'	'	1,164,246
Current liabilities	'	'	'
Accounts payable	2,158,485	2,803,268	612,755
Income taxes payable	222,930	219,847	16,851
Other taxes payable	'	'	65,349
Other current liabilities	'	'	38,798
Total current liabilities	3,224,031	3,409,081	733,753
Non-current liabilities	'	'	'
Long-term debt	2,936,563	2,245,201	1,123
Deferred income taxes	1,466,100	1,544,336	89,946
Asset retirement obligations	852,488	724,273	15,401
Deferred credits and other liabilities	339,028	516,540	87,600
Total non-current liabilities	'	'	$194,070

Results_of_Operations_Associat

Results of Operations Associated with Discontinued Operations (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
Discontinued Operations And Disposal Groups [Abstract]	'	'		'
Revenues	$17,586,236	$24,156,748		$27,310,300
Income from operations before income taxes	119,984	330,048		571,339
Gain on sale before income taxes	130,991	0		12,684
Total income from discontinued operations before taxes	250,975	330,048		584,023
Provision for income taxes	15,639	165,666		250,519
Income from discontinued operations	$235,336	$164,382	[1]	$333,504	[1]
[1]	Reclassified to conform to current presentation.

Property_Plant_and_Equipment_D

Property Plant and Equipment (Detail) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Property, Plant and Equipment [Line Items]	'		'
Property, plant and equipment, Cost	$22,021,294		$21,150,193
Property, plant and equipment, Net	13,481,055		13,011,606
Exploration and Production Equipment [Member]	'		'
Property, Plant and Equipment [Line Items]	'		'
Property, plant and equipment, Cost	21,932,119	[1]	18,408,904	[1]
Property, plant and equipment, Net	13,433,468	[1],[2]	11,294,933	[1],[2]
Refining and Marketing [Member]	'		'
Property, Plant and Equipment [Line Items]	'		'
Property, plant and equipment, Cost	0		2,619,844
Property, plant and equipment, Net	0		1,661,081
Corporate and Other [Member]	'		'
Property, Plant and Equipment [Line Items]	'		'
Property, plant and equipment, Cost	89,175		121,445
Property, plant and equipment, Net	47,587		55,592
Mineral Rights [Member]	'		'
Property, Plant and Equipment [Line Items]	'		'
Property, plant and equipment, Cost	1,007,920		1,051,153
Property, plant and equipment, Net	$489,578		$556,399
[1]	Includes mineral rights as follows:
[2]	Includes $48,691 in 2013 and $26,611 in 2012 related to administrative assets and support equipment.

Property_Plant_and_Equipment_P

Property Plant and Equipment (Parenthetical) (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, Net	$13,481,055	$13,011,606
Administrative assets and support equipment [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, Net	$48,691	$26,611

Property_Plant_and_Equipment_A

Property, Plant and Equipment - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]	'		'		'		'
Total capitalized exploratory well costs	$393,030,000		$445,697,000		$556,412,000		$497,765,000
Exploratory well costs capitalized more than one year	336,531,000		'		'		'
Impairment of long-lived assets	21,587,000	[1]	200,000,000	[1],[2]	368,600,000	[1],[2]	'
Malaysia [Member]	'		'		'		'
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]	'		'		'		'
Exploratory well costs capitalized more than one year	213,802,000		'		'		'
United States [Member]	'		'		'		'
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]	'		'		'		'
Exploratory well costs capitalized more than one year	116,123,000		'		'		'
Brunei	'		'		'		'
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]	'		'		'		'
Exploratory well costs capitalized more than one year	$6,606,000		'		'		'
[1]	Results exclude corporate overhead, interest and discontinued operations.
[2]	Reclassified to conform to current presentation.

Net_Changes_in_Capitalized_Exp

Net Changes in Capitalized Exploratory Well Costs (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]	'	'	'
Beginning balance at January 1	$445,697	$556,412	$497,765
Additions to capitalized exploratory well costs pending the determination of proved reserves	57,716	135,849	86,035
Reclassifications to proved properties based on the determination of proved reserves	-93,936	-165,377	0
Capitalized exploratory well costs charged to expense	-16,447	-81,187	-27,388
Ending balance at December 31	$393,030	$445,697	$556,412

Aging_of_Capitalized_Explorato

Aging of Capitalized Exploratory Well Costs (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
	Well	Well	Well
	Project	Project	Project
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]	'	'	'	'
Amount	$393,030	$445,697	$556,412	$497,765
No. of Wells	32	44	68	'
No. of Projects	9	15	16	'
Zero to one year [Member]	'	'	'	'
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]	'	'	'	'
Amount	56,499	59,833	69,757	'
No. of Wells	3	7	11	'
No. of Projects	1	2	5	'
One to two years [Member]	'	'	'	'
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]	'	'	'	'
Amount	60,787	18,335	143,611	'
No. of Wells	7	2	15	'
No. of Projects	1	3	3	'
Two to three years [Member]	'	'	'	'
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]	'	'	'	'
Amount	0	83,314	101,696	'
No. of Wells	0	9	9	'
No. of Projects	0	4	2	'
Three years or more [Member]	'	'	'	'
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]	'	'	'	'
Amount	$275,744	$284,215	$241,348	'
No. of Wells	22	26	33	'
No. of Projects	7	6	6	'

Financing_Arrangements_Additio

Financing Arrangements - Additional Information (Detail) (USD $)	1 Months Ended	12 Months Ended
	31-May-13	Dec. 31, 2013
Line of Credit Facility [Line Items]	'	'
Credit facility maximum borrowing capacity	$1,500,000,000	$2,000,000,000
Credit facility, maturity date	30-Jun-16	30-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 borrowing capacity	'	350,000,000
Uncommitted Credit Facility [Member]	'	'
Line of Credit Facility [Line Items]	'	'
Credit facility maximum borrowing capacity	'	$345,000,000

Long_term_debt_Detail

Long term debt (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Debt Instrument [Line Items]	'	'
Total notes payable	$2,600,000	$2,251,169
Unamortized discount on notes payable	-5,439	-5,922
Total notes payable, net of unamortized discount	2,594,561	2,245,247
Capitalized lease obligation	368,251	0
Total debt including current maturities	2,962,812	2,245,247
Current maturities	-26,249	-46
Total long-term debt	2,936,563	2,245,201
2.50% notes, due 2017 [Member]	'	'
Debt Instrument [Line Items]	'	'
Notes payable	550,000	550,000
3.70% notes, due 2022 [Member]	'	'
Debt Instrument [Line Items]	'	'
Notes payable	600,000	600,000
4.00% notes, due 2022 [Member]	'	'
Debt Instrument [Line Items]	'	'
Notes payable	500,000	500,000
7.05% notes, due 2029 [Member]	'	'
Debt Instrument [Line Items]	'	'
Notes payable	250,000	250,000
5.125% notes, due 2042 [Member]	'	'
Debt Instrument [Line Items]	'	'
Notes payable	350,000	350,000
Notes payable to banks, 1.4375% at December 31, 2013 [Member]	'	'
Debt Instrument [Line Items]	'	'
Notes payable	350,000	0
Other, 6%, due through 2028 [Member]	'	'
Debt Instrument [Line Items]	'	'
Notes payable	$0	$1,169

Long_term_debt_Parenthetical_D

Long term debt (Parenthetical) (Detail)	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]	'	'
Capitalized lease due date	'2028	'2028
2.50% notes, due 2017 [Member]	'	'
Debt Instrument [Line Items]	'	'
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, 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, 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, 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, stated interest rate	5.13%	5.13%
Notes payable, due date	'2042	'2042
Notes payable to banks, 1.4375% at December 31, 2013 [Member]	'	'
Debt Instrument [Line Items]	'	'
Notes payable, stated interest rate	1.44%	1.44%
Other, 6%, due through 2028 [Member]	'	'
Debt Instrument [Line Items]	'	'
Notes payable, stated interest rate	6.00%	6.00%
Notes payable, due date	'2028	'2028

Long_term_debt_Additional_Info

Long term debt - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Future maturities of long term debt in 2014	$26,249,000
Future maturities of long term debt in 2015	17,921,000
Future maturities of long term debt in 2016	18,819,000
Future maturities of long term debt in 2017	919,700,000
Future maturities of long term debt in 2018	20,752,000
Thereafter	$1,959,371,000
Term of capital lease	'25 years
Lease expiration year	'2038

Reconciliation_of_Beginning_an

Reconciliation of Beginning and Ending Aggregate Carrying Amount of Asset Retirement Obligation (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Asset Retirement Obligation Disclosure [Abstract]	'		'		'
Balance at beginning of year	$751,583		$615,545		'
Accretion expense	48,996		38,361	[1],[2]	33,847	[1]
Liabilities incurred	172,048		184,439		'
Revision of previous estimates	-4,856		10,468		'
Liabilities settled	-51,647		-40,434		'
Liabilities assumed by Murphy USA Inc. upon separation	-15,401		0		'
U.K. oil and gas asset obligations reclassified to liabilities associated with assets held for sale in 2012	0		-64,355		'
Changes due to translation of foreign currencies	-20,720		6,579		'
Balance at end of year	880,003		751,583		615,545
Current portion of liability at end of year	-27,515	[3]	-27,310	[3]	'
Noncurrent portion of liability at end of year	$852,488		$724,273		'
[1]	Reclassified to conform to current presentation.
[2]	Includes $980 reclassified to discontinued operations associated with U.S. downstream operations.
[3]	Included in Other Accrued Liabilities on the Consolidated Balance Sheet.

Reconciliation_of_Beginning_an1

Reconciliation of Beginning and Ending Aggregate Carrying Amount of Asset Retirement Obligation (Parenthetical) (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
Reconciliation of Changes in Asset Retirement Obligations [Line Items]	'	'		'
Accretion of asset retirement obligations	$48,996	$38,361	[1],[2]	$33,847	[1]
Murphy USA Inc [Member]	'	'		'
Reconciliation of Changes in Asset Retirement Obligations [Line Items]	'	'		'
Accretion of asset retirement obligations	'	$980		'
[1]	Reclassified to conform to current presentation.
[2]	Includes $980 reclassified to discontinued operations associated with U.S. downstream operations.

Components_of_Income_from_Cont

Components of Income from Continuing Operations Before Income Taxes and Income Tax Expense (Detail) (USD $)

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Income (loss) from continuing operations before income taxes

'

'

'

'

'

'

'

'

'

'

'

United States

'

'

'

'

'

'

'

'

($5,810)

$54,275

$72,038

Foreign

'

'

'

'

'

'

'

'

1,478,497

1,313,735

1,095,837

Income from continuing operations before income taxes

194,800

463,700

454,200

360,000

200,500

338,900

357,000

471,600

1,472,687

1,368,010

[1]

1,167,875

[1]

Income tax expense (benefit)

'

'

'

'

'

'

'

'

'

'

'

Federal - Current

'

'

'

'

'

'

'

'

-56,790

-256,931

6,050

Federal - Deferred

'

'

'

'

'

'

'

'

65,883

177,325

15,633

Federal Income Tax Expense (Benefit), Continuing Operations, Total

'

'

'

'

'

'

'

'

9,093

-79,606

21,683

State

'

'

'

'

'

'

'

'

7,141

8,104

5,609

Foreign - Current

'

'

'

'

'

'

'

'

477,715

472,701

471,960

Foreign - Deferred

'

'

'

'

'

'

'

'

90,601

160,317

129,425

Foreign Income Tax Expense (Benefit), Continuing Operations, Total

'

'

'

'

'

'

'

'

568,316

633,018

601,385

Total

'

'

'

'

'

'

'

'

$584,550

$561,516

[1]

$628,677

[1]

[1]

Reclassified to conform to current presentation.

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Examination [Line Items]	'	'	'
Income tax benefits attributable to employee stock option transactions	$7,435,000	$5,920,000	$8,775,000
Increase in deferred tax asset valuation allowance	109,769,000	'	'
Undistributed earnings of subsidiaries considered indefinitely invested	6,677,000,000	'	'
Unrecognized deferred tax liability	651,000,000	'	'
Withholding tax on any monies repatriated from Canada to the U.S.	5.00%	'	'
Other recorded liabilities for interest and penalties	146,000	975,000	'
Income tax expense, (charges) net benefits for interest and penalties	829,000	1,000	34,000
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	'2010	'	'
Canada [Member]	'	'	'
Income Tax Examination [Line Items]	'	'	'
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions	'2007	'	'
United Kingdom [Member]	'	'	'
Income Tax Examination [Line Items]	'	'	'
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions	'2011	'	'
Malaysia [Member]	'	'	'
Income Tax Examination [Line Items]	'	'	'
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions	'2006	'	'
Minimum [Member]	'	'	'
Income Tax Examination [Line Items]	'	'	'
Income tax rate realized up on ultimate settlement	50.00%	'	'
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	'2022	'	'

Reconciliation_of_Income_Taxes

Reconciliation of Income Taxes Based on U.S. Statutory Tax Rate to Income Tax Expense (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'		'
Income tax expense based on the U.S. statutory tax rate	$515,440	$478,804		$408,756
Foreign income subject to foreign taxes at a rate different than the U.S. statutory rate	31,752	7,710		-10,682
State income taxes, net of federal benefit	4,642	5,268		3,646
U.S. tax benefit on certain foreign upstream investments	-133,526	-108,077		0
Increase in deferred tax asset valuation allowance related to other foreign exploration expenditures	129,588	87,558		102,714
Impairment or abandonment of Azurite field with no tax benefit	35,475	70,000		129,010
Malaysian tax benefits on prior year costs in Block P	0	0		-25,573
Other, net	1,179	20,253		20,806
Total	$584,550	$561,516	[1]	$628,677	[1]
[1]	Reclassified to conform to current presentation.

Analysis_of_Deferred_Tax_Asset

Analysis of Deferred Tax Assets and Deferred Tax Liabilities Showing Tax Effects of Significant Temporary Differences (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Deferred tax assets	'	'
Property and leasehold costs	$708,947	$658,588
Liabilities for dismantlements	79,111	78,100
Postretirement and other employee benefits	175,446	197,912
Alternative minimum tax	49,536	37,253
Foreign tax credit carryforwards	19,896	18,594
Other deferred tax assets	23,352	32,500
Total gross deferred tax assets	1,056,288	1,022,947
Less valuation allowance	-633,735	-523,966
Net deferred tax assets	422,553	498,981
Deferred tax liabilities	'	'
Property, plant and equipment	-747,561	-808,311
Accumulated depreciation, depletion and amortization	-1,040,251	-1,077,867
Other deferred tax liabilities	-38,849	-70,710
Total gross deferred tax liabilities	-1,826,661	-1,956,888
Net deferred tax liabilities	($1,404,108)	($1,457,907)

Reconciliation_of_Beginning_an2

Reconciliation of Beginning and Ending Amount of Consolidated Liability for Unrecognized Income Tax Benefits (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'	'
Beginning balance	$16,611	$18,857	$23,196
Additions for tax positions related to current year	2,486	1,258	1,294
Settlements due to lapse of time	-12,731	-3,504	-5,633
Ending balance	$6,366	$16,611	$18,857

Incentive_Plans_Additional_Inf

Incentive Plans - Additional Information (Detail)

1 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

Feb. 28, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Aug. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Aug. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

USD ($)

USD ($)

USD ($)

USD ($)

Maximum [Member]

2012 Long-Term Plan [Member]

2012 Long-Term Plan and the 2007 Long-Term Plan [Member]

Director Plan [Member]

Stock Options [Member]

Stock Options [Member]

Stock Options [Member]

Stock Options [Member]

Time-Lapse Restricted Stock and Restricted Stock Units [Member]

Time-Lapse Restricted Stock and Restricted Stock Units [Member]

Time-Lapse Restricted Stock and Restricted Stock Units [Member]

Phantom Units [Member]

Phantom Units [Member]

Phantom Units [Member]

Performance Based Restricted Stock [Member]

Performance Based Restricted Stock [Member]

Performance Based Restricted Stock [Member]

Performance Based Restricted Stock [Member]

Performance Based Restricted Stock [Member]

Performance Based Restricted Stock [Member]

Performance Based Restricted Stock [Member]

Employee Stock Purchase Plan (ESPP) [Member]

Employee Stock Purchase Plan (ESPP) [Member]

Employee Stock Purchase Plan (ESPP) [Member]

Savings Related Share Option Plan (SOP) [Member]

Savings Related Share Option Plan (SOP) [Member]

Savings Related Share Option Plan (SOP) [Member]

Savings Related Share Option Plan (SOP) [Member]

Savings Related Share Option Plan (SOP) [Member]

Savings Related Share Option Plan (SOP) [Member]

Savings Related Share Option Plan (SOP) [Member]

Performance Units [Member]

Performance Units [Member]

Performance Units [Member]

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

Maximum [Member]

Maximum [Member]

Maximum [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

Maximum [Member]

Minimum [Member]

SOP plans with holding periods ending in April 2011 [Member]

SOP plans with holding periods ending in May 2012 [Member]

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

GBP (£)

GBP (£)

USD ($)

USD ($)

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

980,000

'

'

'

'

'

'

'

'

'

'

'

'

Maximum number of shares available for issuance, annual rate

'

'

'

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of shares remained available

'

'

'

'

'

'

7,135,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

286,941

'

'

'

'

'

'

'

'

'

'

'

'

Unvested share-based compensation arrangements, compensation costs to be expensed

'

$59,505,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

3,409,000

12,324,000

[1]

15,551,000

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Income tax benefits realized for the tax deductions from option exercises

'

7,435,000

5,920,000

8,775,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Option granted to date, term of years

'

'

'

'

'

'7 years

'

'7 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Employee stock purchase plan, 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 three years.

'Under the Director Plan, one-third of each grant is exercisable after each of the first three years.

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock-based compensation, fair value assumption model

'

'

'

'

'

'

'

'

'

'Black-Scholes pricing model

'

'

'

'

'

'

'

'

'

'Monte Carlo valuation model

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total intrinsic value of options exercised

'

25,284,000

17,197,000

28,145,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Price at which liability calculated

'

$64.88

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Granted restricted stock, valuation

'

'

'

'

'

'

'

'

'

'

'

'

'

$69.67

$59.33

$52.66

'

'

'

'

$68.01

$63.64

$64.89

$39.50

$54.90

$38.94

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage increase in number of outstanding stock units

'

'

'

'

'

'

'

'

'

'

'

'

'

10.70%

'

'

'

'

10.70%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Compensation expenses

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,063,000

305,000

'

'

'

'

'

'

'

'

143,000

272,000

328,000

0

110,000

538,000

'

'

'

'

2,062,000

2,665,000

871,000

Percentage of targeted amounts paid in cash and awards based on achievement, minimum

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.00%

0.00%

0.00%

Percentage of targeted amounts paid in cash and awards based on achievement, maximum

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

200.00%

200.00%

200.00%

Performance units outstanding

'

6,006,585

'

'

'

'

'

'

'

6,006,585

5,907,359

5,434,228

5,302,384

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

'

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%

'

'

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 June 30, 2017.

'

'

'

'

'

'

'

'

'

'

'

'

Employee stock purchases, shares

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

16,020

24,418

28,555

'

'

'

'

'

'

'

'

'

'

Employee stock purchases, per share

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$54.14

$48.54

$55.28

'

'

'

'

'

'

'

'

'

'

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

'

'

'Compensation costs related to the SOP plan were estimated based on the value of the 10% discount and the fair value of the option that allowed the employee to receive a repayment of withholdings plus credited interest.

'

'

'

'

'

'

'

'

'

Fair value per share issued under ESPP

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$6.72

$7.30

$8.60

'

'

'

'

'

'

'

'

'

'

Monthly salary that can be withhold by eligible employee for stock purchase

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

250

5

'

'

'

'

'

Fair value per share of SOP plans

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$23.77

$22.85

'

'

'

Compensation expense for incentive plans

'

$53,250,000

$32,417,000

$33,035,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

[1]

Reclassified to conform to current presentation.

ShareBased_Plans_Amounts_Recog

Share-Based Plans, Amounts Recognized (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'	'	'
Compensation charged against income before tax benefit	$66,976	$46,694	$43,272
Related income tax benefit recognized in income	$19,321	$14,443	$14,396

Fair_Value_of_Option_Award_Est

Fair Value of Option Award Estimated on Date of Grant using Black-Scholes Pricing Model (Detail) (Stock Options [Member], USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012
		Minimum [Member]	Minimum [Member]	Maximum [Member]	Maximum [Member]
Share based Compensation Arrangement by Share based Payment Award, Fair Value Assumptions, Method Used [Line Items]	'	'	'	'	'
Fair value per option grant	$20.34	$15.81	$12.37	$20.62	$17.74
Assumptions	'	'	'	'	'
Dividend yield	1.80%	2.10%	1.80%	2.30%	2.27%
Expected volatility	37.00%	34.00%	39.00%	36.00%	39.62%
Risk-free interest rate	2.10%	0.96%	0.55%	2.00%	0.77%
Expected life	'5 years 1 month 6 days	'5 years 3 months	'4 years	'6 years 6 months	'5 years 2 months 12 days

Changes_in_Stock_Options_Outst

Changes in Stock Options Outstanding (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Number of Shares	'		'		'		'
Exercised	-303,685	[1]	-482,974	[1]	-615,674	[1]	'
Outstanding at end of year	6,006,585		'		'		'
Exercisable at end of year	2,435,322		'		'		'
Stock Options [Member]	'		'		'		'
Number of Shares	'		'		'		'
Outstanding at beginning of year	5,907,359		5,434,228		5,302,384		'
Granted at FMV	1,320,176		1,870,500		1,397,312		'
Exercised	-1,335,355		-823,855		-974,500		'
Forfeited	-228,576		-573,514		-290,968		'
Murphy USA Inc. spin-off adjustment	615,917		'		'		'
Outstanding at end of year	6,006,585		5,907,359		5,434,228		'
Exercisable at end of year	2,435,322		2,474,636		2,319,735		2,499,610
Average Exercise Price	'		'		'		'
Outstanding at beginning of year	$55.17		$55.17		$48.83		'
Granted at FMV	$55.26		$57.96		$67.64		'
Exercised	$45.84		$38.37		$39.30		'
Forfeited	$58.01		$60.43		$52.73		'
Surrendered in connection with separation of Murphy USA Inc.	$55.99		'		'		'
Murphy USA Inc. spin-off adjustment	$52.09		'		'		'
Outstanding at end of year	$56.80		$55.17		$55.17		'
Exercisable at end of year	$51.79		$54.43		$51.14		$45.07
Stock Options [Member] | Spin [Member]	'		'		'		'
Number of Shares	'		'		'		'
Forfeited	-272,936		'		'		'
[1]	Shares issued upon exercise of stock options are less than the amount reflected in Note I due to withholdings for statutory income taxes owed upon exercise.

Additional_Information_about_S

Additional Information about Stock options Outstanding (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Outstanding at end of year	6,006,585
Options Outstanding, Avg. Life in Years	'4 years 4 months 24 days
Options Outstanding, Aggregate Intrinsic Value	$73,751,000
Exercisable at end of year	2,435,322
Options Exercisable, Avg. Life in year	'2 years 2 months 12 days
Options Exercisable, Aggregate Intrinsic Value	31,889,000
Range of Exercise Prices per Option $ 0 to $ 0 [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
Outstanding at end of year	658,782
Options Outstanding, Avg. Life in Years	'3 years 1 month 6 days
Options Outstanding, Aggregate Intrinsic Value	17,677,000
Exercisable at end of year	406,939
Options Exercisable, Avg. Life in year	'1 year 4 months 24 days
Options Exercisable, Aggregate Intrinsic Value	11,165,000
Range of Exercise Prices per Option $ 0 to $ 0 [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
Outstanding at end of year	2,233,621
Options Outstanding, Avg. Life in Years	'4 years 6 months
Options Outstanding, Aggregate Intrinsic Value	34,786,000
Exercisable at end of year	832,631
Options Exercisable, Avg. Life in year	'2 years 4 months 24 days
Options Exercisable, Aggregate Intrinsic Value	16,224,000
Range of Exercise Prices per Option $ 0 to $ 0 [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
Outstanding at end of year	3,114,182
Options Outstanding, Avg. Life in Years	'4 years 7 months 6 days
Options Outstanding, Aggregate Intrinsic Value	21,288,000
Exercisable at end of year	1,195,752
Options Exercisable, Avg. Life in year	'2 years 4 months 24 days
Options Exercisable, Aggregate Intrinsic Value	$4,500,000

Changes_in_SAR_Outstanding_Det

Changes in SAR Outstanding (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Outstanding at end of year	6,006,585
Stock Appreciation Rights (SAR) [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Outstanding at beginning of year	0
Number of SAR, Granted	851,000
Number of SAR, Forfeited	-68,712
Number of SAR, Murphy USA Inc. spin-off adjustment	78,824
Outstanding at end of year	788,112
Forfeited	'
Surrendered in connection with separation of Murphy USA Inc.	'
Murphy USA Inc. spin-off adjustment	'
Outstanding at end of year	$54.21
Forfeited	'
Surrendered in connection with separation of Murphy USA Inc.	'
Murphy USA Inc. spin-off adjustment	'
Stock Appreciation Rights (SAR) [Member] | Spin [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Number of SAR, Forfeited	-73,000

Changes_in_PerformanceBased_RS

Changes in Performance-Based RSU Outstanding (Detail) (Performance Based Restricted Stock [Member])	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity-Settled Restricted Stock Units [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Balance at beginning of year	1,426,238	1,174,492	1,023,492
Granted	521,776	653,355	521,423
Awarded	-380,150	-260,175	-309,656
Forfeited	-39,573	-141,434	-60,767
Surrendered in connection with separation of Murphy USA Inc.	-116,568	0	0
Murphy USA Inc. spin-off adjustment	148,569	0	0
Balance at end of year	1,560,292	1,426,238	1,174,492
Cash-Settled Restricted Stock Units [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Balance at beginning of year	0	'	'
Granted	93,200	'	'
Awarded	0	'	'
Forfeited	-9,924	'	'
Surrendered in connection with separation of Murphy USA Inc.	-6,800	'	'
Murphy USA Inc. spin-off adjustment	8,380	'	'
Balance at end of year	84,856	'	'

Assumptions_used_in_Valuation_

Assumptions used in Valuation Performance Awards Granted (Detail) (Performance Based Restricted Stock [Member], USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Assumptions	'	'	'
Expected volatility	'	37.00%	51.00%
Risk-free interest rate	'	0.30%	1.04%
Stock beta	'	0.913	1.006
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]	'	'	'
Fair value per share at grant date	39.5	54.9	38.94
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]	'	'	'
Fair value per share at grant date	68.01	63.64	64.89
Assumptions	'	'	'
Expected volatility	32.00%	'	'
Risk-free interest rate	0.62%	'	'
Stock beta	0.908	'	'

Changes_in_TimeLapse_Restricte

Changes in Time-Lapse Restricted Stock and Restricted Stock Units Outstanding (Detail) (Restricted Stock and Restricted Stock Units [Member])	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	98,477	116,724	166,173
Granted	38,184	42,256	32,711
Vested and issued	-34,696	-44,980	-82,160
Forfeited	0	-15,523	0
Murphy USA Inc. spin-off adjustment	10,916	0	0
Balance at end of year	112,881	98,477	116,724

Plans_Benefit_Obligations_and_

Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Change in plan assets	'	'	'
Fair value of plan assets, Ending Balance	$533,108,000	$463,546,000	'
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31	'	'	'
Liabilities associated with assets held for sale	-639,140,000	-47,471,000	'
Pension Benefits [Member]	'	'	'
Change in benefit obligation	'	'	'
Obligations, Beginning Balance	721,531,000	629,568,000	'
Service cost	26,346,000	23,500,000	22,406,000
Interest cost	30,903,000	29,869,000	30,785,000
Plan amendments	1,989,000	0	'
Participant contributions	21,000	30,000	'
Actuarial loss (gain)	-9,876,000	55,479,000	'
Medicare Part D subsidy, Change in benefit obligation	0	0	'
Exchange rate changes	1,852,000	7,125,000	'
Benefits paid	-38,745,000	-30,217,000	'
Special termination benefits	849,000	6,177,000	'
Curtailments	-26,463,000	0	'
Obligation assumed by MUSA at separation	-1,153,000	0	'
Obligations, Ending Balance	707,254,000	721,531,000	629,568,000
Change in plan assets	'	'	'
Fair value of plan assets, Beginning Balance	463,546,000	404,350,000	'
Actual return on plan assets	61,932,000	41,674,000	'
Employer contributions	46,726,000	42,207,000	'
Participant contributions	21,000	30,000	'
Medicare Part D subsidy, Fair value of plan assets	0	0	'
Exchange rate changes	1,594,000	6,289,000	'
Benefits paid	-38,745,000	-30,217,000	'
Other	-1,966,000	-787,000	'
Fair value of plan assets, Ending Balance	533,108,000	463,546,000	404,350,000
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31	'	'	'
Deferred charges and other assets	10,254,000	9,679,000	'
Other accrued liabilities	-5,565,000	-5,556,000	'
Deferred credits and other liabilities	-158,589,000	-262,108,000	'
Liabilities associated with assets held for sale	-20,246,000	0	'
Funded status and net plan liability recognized at the end of the period	-174,146,000	-257,985,000	'
Other Postretirement Benefits [Member]	'	'	'
Change in benefit obligation	'	'	'
Obligations, Beginning Balance	124,134,000	114,962,000	'
Service cost	4,566,000	3,958,000	4,547,000
Interest cost	5,189,000	5,174,000	6,141,000
Plan amendments	0	0	'
Participant contributions	1,376,000	1,035,000	'
Actuarial loss (gain)	-8,324,000	4,686,000	'
Medicare Part D subsidy, Change in benefit obligation	384,000	432,000	'
Exchange rate changes	-36,000	14,000	'
Benefits paid	-5,211,000	-6,127,000	'
Special termination benefits	0	0	'
Curtailments	-15,077,000	0	'
Obligation assumed by MUSA at separation	0	0	'
Obligations, Ending Balance	107,001,000	124,134,000	114,962,000
Change in plan assets	'	'	'
Fair value of plan assets, Beginning Balance	0	0	'
Actual return on plan assets	0	0	'
Employer contributions	3,451,000	4,660,000	'
Participant contributions	1,376,000	1,035,000	'
Medicare Part D subsidy, Fair value of plan assets	384,000	432,000	'
Exchange rate changes	0	0	'
Benefits paid	-5,211,000	-6,127,000	'
Other	0	0	'
Fair value of plan assets, Ending Balance	0	0	0
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31	'	'	'
Deferred charges and other assets	0	0	'
Other accrued liabilities	-5,920,000	-5,646,000	'
Deferred credits and other liabilities	-101,081,000	-118,488,000	'
Liabilities associated with assets held for sale	0	0	'
Funded status and net plan liability recognized at the end of the period	($107,001,000)	($124,134,000)	'

Amounts_Included_in_Accumulate

Amounts Included in Accumulated Other Comprehensive Income Not Recognized in Net Periodic Benefit Expense (Detail) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Pension Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Net actuarial loss	($150,682)
Prior service (cost) credit	-3,559
Transitional asset (liability)	517
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax, Total	-153,724
Other Postretirement Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Net actuarial loss	-13,815
Prior service (cost) credit	372
Transitional asset (liability)	0
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax, Total	($13,443)

Amounts_Included_in_Accumulate1

Amounts Included in Accumulated Other Comprehensive Income Expected to be Amortization into Net Periodic Benefit Expense (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Pension Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Net actuarial loss	($8,190)
Prior service (cost) credit	-951
Transitional asset (liability)	517
Defined Benefit Plan, Amount to be Amortized from Accumulated Other Comprehensive Income (Loss) Next Fiscal Year, Total	-8,624
Other Postretirement Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Net actuarial loss	-242
Prior service (cost) credit	82
Transitional asset (liability)	0
Defined Benefit Plan, Amount to be Amortized from Accumulated Other Comprehensive Income (Loss) Next Fiscal Year, Total	($160)

Projected_Benefit_Obligations_

Projected Benefit Obligations, Accumulated Benefit Obligations and Fair Value of Plan Assets for Plans where Accumulated Benefit Obligation Exceeded Fair Value of Plan Assets (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
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	$571,217	$587,318
Plans where accumulated benefit obligation exceeds fair value of plan assets, Aggregate accumulated benefit Obligation	520,610	523,773
Plans where accumulated benefit obligation exceeds fair value of plan assets, Aggregate fair value of plan assets	502,308	431,788
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	115,492	112,135
Plans where accumulated benefit obligation exceeds fair value of plan assets, Aggregate accumulated benefit Obligation	102,198	98,498
Plans where accumulated benefit obligation exceeds fair value of plan assets, Aggregate fair value of plan assets	0	0
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	107,001	124,134
Plans where accumulated benefit obligation exceeds fair value of plan assets, Aggregate accumulated benefit Obligation	107,001	124,134
Plans where accumulated benefit obligation exceeds fair value of plan assets, Aggregate fair value of plan assets	$0	$0

Components_of_Net_Periodic_Ben

Components of Net Periodic Benefit Expense (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Service cost	$26,346	$23,500	$22,406
Interest cost	30,903	29,869	30,785
Expected return on plan assets	-28,974	-25,826	-25,919
Amortization of prior service cost (credit)	1,006	1,254	1,314
Amortization of transitional (asset) liability	-514	-529	-536
Recognized actuarial loss	17,338	16,389	12,484
Defined Benefit Plan, Gross Periodic Benefit Cost, Total	46,105	44,657	40,534
Termination benefits expense	849	6,177	695
Curtailment expense (benefit)	1,365	0	1,036
Net periodic benefit expense	48,319	50,834	42,265
Other Postretirement Benefits [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Service cost	4,566	3,958	4,547
Interest cost	5,189	5,174	6,141
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	-143	-173	-240
Amortization of transitional (asset) liability	8	8	8
Recognized actuarial loss	1,484	1,317	2,329
Defined Benefit Plan, Gross Periodic Benefit Cost, Total	11,104	10,284	12,785
Termination benefits expense	0	0	0
Curtailment expense (benefit)	-442	0	-605
Net periodic benefit expense	$10,662	$10,284	$12,180

Amount_Related_to_Foreign_Bene

Amount Related to Foreign Benefit Plans (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair value of plan assets, Ending Balance	$533,108	$463,546
Foreign Defined Benefit Pension Plans [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Benefit obligation, Ending Balance	211,799	184,550
Fair value of plan assets, Ending Balance	188,575	164,111
Net plan liabilities recognized	23,224	20,439
Net periodic benefit expense	12,622	11,022
Foreign Other Postretirement Benefit Plans [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Benefit obligation, Ending Balance	541	525
Fair value of plan assets, Ending Balance	0	0
Net plan liabilities recognized	541	525
Net periodic benefit expense	$92	$88

WeightedAverage_Assumptions_us

Weighted-Average Assumptions used in Measurement of Benefit Obligations and Net Periodic Benefit Expense (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]	'	'
Expected return on plan assets	6.24%	'
Expected return on plan assets	6.24%	'
Pension Benefits [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Benefit Obligation, Discount rate	4.78%	4.24%
Expected return on plan assets	6.24%	6.20%
Benefit Obligation, Rate of compensation increase	4.14%	4.13%
Net periodic benefit expense, Discount rate	4.23%	4.80%
Expected return on plan assets	6.24%	6.20%
Net periodic benefit expense, Rate of compensation increase	4.12%	4.10%
Other Postretirement Benefits [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Benefit Obligation, Discount rate	4.91%	4.18%
Expected return on plan assets	0.00%	0.00%
Benefit Obligation, Rate of compensation increase	0.00%	0.00%
Net periodic benefit expense, Discount rate	4.18%	4.87%
Expected return on plan assets	0.00%	0.00%
Net periodic benefit expense, Rate of compensation increase	0.00%	0.00%

Benefit_Payments_Reflected_Exp

Benefit Payments, Reflected Expected Future Service as Appropriate which are Expected to be Paid in Future Years from Assets of Plans or by Company (Detail) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Pension Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
2014	$32,822
2015	33,459
2016	33,723
2017	34,455
2018	35,383
2019-2023	194,717
Other Postretirement Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
2014	6,746
2015	6,971
2016	7,148
2017	7,303
2018	7,500
2019-2023	$41,148

Employee_and_Retiree_Benefit_P2

Employee and Retiree Benefit Plans - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension and Other Postretirement Benefits Disclosure [Line Items]	'	'	'
Future annual rate of increase in cost of health care for 2013 to measure postretirement benefit obligations	7.40%	'	'
Ultimate rate of health care cost in 2020 and thereafter	5.00%	'	'
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) eliminates 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) eliminates 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.	'	'
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	6.24%	'	'
Domestic plan, investment lock up period	'3 years	'	'
Domestic plan, investment notice period	'95 days	'	'
Amounts charged to expense for U.S. and U.K. plans	13,839,000	12,594,000	10,725,000
Defined benefit plan, percentage of employer's matching contribution	6.00%	6.00%	6.00%
Foreign Other Postretirement Benefit Plans [Member]	'	'	'
Pension and Other Postretirement Benefits Disclosure [Line Items]	'	'	'
Contributions to benefit plans	39,000	'	'
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	3,412,000	'	'
Expected benefit plan contributions to be made during next year	5,883,000	'	'
Funded Retirement Plan [Member]	'	'	'
Pension and Other Postretirement Benefits Disclosure [Line Items]	'	'	'
Weighted average expected return on plan asset	6.93%	'	'
Domestic defined benefit pension plans [Member]	'	'	'
Pension and Other Postretirement Benefits Disclosure [Line Items]	'	'	'
Contributions to benefit plans	30,570,000	'	'
Expected benefit plan contributions to be made during next year	27,133,000	'	'
Foreign Defined Benefit Pension Plans [Member]	'	'	'
Pension and Other Postretirement Benefits Disclosure [Line Items]	'	'	'
Contributions to benefit plans	16,156,000	'	'
Expected benefit plan contributions to be made during next year	$21,977,000	'	'
United Kingdom [Member]	'	'	'
Pension and Other Postretirement Benefits Disclosure [Line Items]	'	'	'
Percentage fixed income allocation	95.00%	'	'
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	'	'
Asset performance compared to a benchmark return, percent targeted to outperform the benchmark over three years	0.75%	'	'
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%	'	'
Maximum [Member] | United Kingdom [Member]	'	'	'
Pension and Other Postretirement Benefits Disclosure [Line Items]	'	'	'
Maximum percentage of income investment in securities	5.00%	'	'
Commingled trust fund [Member] | Maximum [Member] | Domestic postretirement benefits plan [Member]	'	'	'
Pension and Other Postretirement Benefits Disclosure [Line Items]	'	'	'
Domestic plan, commingled trusts waiting periods for withdrawals (in days)	'30 days	'	'
Commingled trust fund [Member] | Minimum [Member] | Domestic postretirement benefits plan [Member]	'	'	'
Pension and Other Postretirement Benefits Disclosure [Line Items]	'	'	'
Domestic plan, commingled trusts waiting periods for withdrawals (in days)	'6 days	'	'
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%	'	'
Basis used to determine expected return on plan asset, percentage of expected return (expense)	8.40%	'	'
Equity securities [Member] | United Kingdom [Member] | Foreign Other Postretirement Benefit Plans [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	'	'	'
Weighted average expected return on plan asset	3.90%	'	'
Basis used to determine expected return on plan asset, percentage of expected return (expense)	0.45%	'	'
Fixed Income Securities [Member] | United Kingdom [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	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] | Foreign Other Postretirement Benefit Plans [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%	'	'

One_Percent_Change_in_Assumed_

One Percent Change in Assumed Health Care Cost Trend Rates (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Compensation And Retirement Disclosure [Abstract]	'
Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 2013	$2,011
Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2013	14,331
A 1% decrease effect on total service and interest cost components of net periodic postretirement benefit expense	-1,551
A 1% decrease effect on the health care component of the accumulated postretirement benefit obligation	($11,812)

Weighted_Average_Asset_Allocat

Weighted Average Asset Allocation for Company's Funded Pension Benefit Plans (Detail) (Funded Defined Benefit Pension Plans [Member])	Dec. 31, 2013	Dec. 31, 2012
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	68.40%	62.90%
Fixed income securities [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Weighted average asset allocation	30.70%	36.10%
Cash equivalents [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Weighted average asset allocation	0.90%	1.00%

Fair_Value_Measurements_of_Ret

Fair Value Measurements of Retirement Plan Assets within Fair Value of Hierarchy (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	$533,108	$463,546
Domestic Plans [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	344,533	299,435
Domestic Plans [Member] | Equity securities [Member] | US core equity [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	89,255	83,392
Domestic Plans [Member] | Equity securities [Member] | U.S. small/midcap [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	37,149	20,894
Domestic Plans [Member] | Equity securities [Member] | Hedged funds and other alternative strategies [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	32,788	14,654
Domestic Plans [Member] | Equity securities [Member] | International [Member] | Commingled trust fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	77,041	62,111
Domestic Plans [Member] | Equity securities [Member] | Emerging market [Member] | Commingled equity fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	9,654	9,535
Domestic Plans [Member] | Fixed income securities [Member] | U.S. fixed income [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	72,240	80,203
Domestic Plans [Member] | Fixed income securities [Member] | International [Member] | Commingled trust fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	14,865	15,179
Domestic Plans [Member] | Fixed income securities [Member] | Emerging market [Member] | Mutual fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	8,549	10,060
Domestic Plans [Member] | Cash and Cash Equivalents [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	2,992	3,407
Foreign Plans [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	188,575	164,111
Foreign Plans [Member] | Cash and Cash Equivalents [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	1,660	1,343
Foreign Plans [Member] | Equity securities funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	99,085	79,233
Foreign Plans [Member] | Fixed income securities funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	57,030	51,777
Foreign Plans [Member] | Diversified pooled fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	30,800	31,758
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	131,056	109,036
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	129,396	107,693
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	89,255	83,392
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	37,149	20,894
Quoted Prices in Active Markets for Identical Assets (Level 1) [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	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Plans [Member] | Equity securities [Member] | International [Member] | Commingled trust fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Plans [Member] | Equity securities [Member] | Emerging market [Member] | Commingled equity fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Plans [Member] | Fixed income securities [Member] | U.S. fixed income [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Plans [Member] | Fixed income securities [Member] | International [Member] | Commingled trust fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Plans [Member] | Fixed income securities [Member] | Emerging market [Member] | Mutual fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
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	2,992	3,407
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	1,660	1,343
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	1,660	1,343
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign Plans [Member] | Equity securities funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign Plans [Member] | Fixed income securities funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign Plans [Member] | Diversified pooled fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Significant Other Observable Inputs (Level 2) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	369,264	339,856
Significant Other Observable Inputs (Level 2) [Member] | Domestic Plans [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	182,349	177,088
Significant Other Observable Inputs (Level 2) [Member] | Domestic Plans [Member] | Equity securities [Member] | US core equity [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Significant Other Observable Inputs (Level 2) [Member] | Domestic Plans [Member] | Equity securities [Member] | U.S. small/midcap [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
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	0	0
Significant Other Observable Inputs (Level 2) [Member] | Domestic Plans [Member] | Equity securities [Member] | International [Member] | Commingled trust fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	77,041	62,111
Significant Other Observable Inputs (Level 2) [Member] | Domestic Plans [Member] | Equity securities [Member] | Emerging market [Member] | Commingled equity fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	9,654	9,535
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	72,240	80,203
Significant Other Observable Inputs (Level 2) [Member] | Domestic Plans [Member] | Fixed income securities [Member] | International [Member] | Commingled trust fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	14,865	15,179
Significant Other Observable Inputs (Level 2) [Member] | Domestic Plans [Member] | Fixed income securities [Member] | Emerging market [Member] | Mutual fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	8,549	10,060
Significant Other Observable Inputs (Level 2) [Member] | Domestic Plans [Member] | Cash and Cash Equivalents [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Significant Other Observable Inputs (Level 2) [Member] | Foreign Plans [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	186,915	162,768
Significant Other Observable Inputs (Level 2) [Member] | Foreign Plans [Member] | Cash and Cash Equivalents [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
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	99,085	79,233
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	57,030	51,777
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	30,800	31,758
Significant Unobservable Inputs (Level 3) [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	32,788	14,654
Significant Unobservable Inputs (Level 3) [Member] | Domestic Plans [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	32,788	14,654
Significant Unobservable Inputs (Level 3) [Member] | Domestic Plans [Member] | Equity securities [Member] | US core equity [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) [Member] | Domestic Plans [Member] | Equity securities [Member] | U.S. small/midcap [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
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	32,788	14,654
Significant Unobservable Inputs (Level 3) [Member] | Domestic Plans [Member] | Equity securities [Member] | International [Member] | Commingled trust fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) [Member] | Domestic Plans [Member] | Equity securities [Member] | Emerging market [Member] | Commingled equity fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) [Member] | Domestic Plans [Member] | Fixed income securities [Member] | U.S. fixed income [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) [Member] | Domestic Plans [Member] | Fixed income securities [Member] | International [Member] | Commingled trust fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) [Member] | Domestic Plans [Member] | Fixed income securities [Member] | Emerging market [Member] | Mutual fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) [Member] | Domestic Plans [Member] | Cash and Cash Equivalents [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) [Member] | Foreign Plans [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) [Member] | Foreign Plans [Member] | Cash and Cash Equivalents [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) [Member] | Foreign Plans [Member] | Equity securities funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) [Member] | Foreign Plans [Member] | Fixed income securities funds [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) [Member] | Foreign Plans [Member] | Diversified pooled fund [Member]	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Fair Value of Plan Assets	$0	$0

Effects_of_Fair_Value_Measurem

Effects of Fair Value Measurements Using Significant Unobservable Inputs on Changes in Level 3 Plan Assets (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Insurance [Abstract]	'	'
Beginning Balance	$14,654	$13,860
Actual return on plan assets:	'	'
Relating to assets held at the reporting date	3,134	794
Relating to assets sold during the period	0	0
Purchases, sales and settlements	15,000	0
Ending Balance	$32,788	$14,654

WTI_Open_Contracts_Detail

WTI Open Contracts (Detail)	Dec. 31, 2013
	bbl
January to March 2014 [Member]	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Number of barrels	20,000
Natural gas deliveries contract average price per thousand cubic feet	98.47
April to June 2014 [Member]	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Number of barrels	20,000
Natural gas deliveries contract average price per thousand cubic feet	96.48
July to September 2014 [Member]	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'
Number of barrels	7,000
Natural gas deliveries contract average price per thousand cubic feet	95.24

Financial_Instruments_and_Risk2

Financial Instruments and Risk Management - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'	'		'
Maturities of notes payable	$0	$350,000,000	[1]	$340,041,000	[1]
Deferred loss charged to income	2,963,000	1,852,000		'
Scenario, Forecast [Member]	'	'		'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'	'		'
Interest expense due to deferred loss on interest rate swaps expected during 2014	2,963,000	'		'
Commodity derivative contracts [Member] | Other Assets [Member]	'	'		'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'	'		'
Fair value of commodity derivative contracts	716,000	2,941,000		'
Commodity derivative contracts [Member] | Other Liabilities [Member]	'	'		'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'	'		'
Fair values of foreign currency derivative contracts	26,000,000	1,031,000,000		'
Foreign exchange derivative contract [Member] | Currency, U.S. Dollar | Canada [Member]	'	'		'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'	'		'
Foreign currency short-term derivative instruments	32,300,000	154,000,000		'
Interest Rate Swap [Member]	'	'		'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'	'		'
Loss deferred for fair value of interest rate derivative contracts, net of tax	24,815,000	'		'
Loss deferred for fair value of interest rate derivative contracts	$8,698,000	'		'
[1]	Reclassified to conform to current presentation.

Fair_Value_of_Derivative_Instr

Fair Value of Derivative Instruments Not Designated as Hedging Instruments (Detail) (Nondesignated [Member], Accounts Receivable [Member], USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Commodity derivative contracts [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Asset Derivatives	$1,970	$3,043
Liability Derivatives	'	102
Foreign exchange derivative contract [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Asset Derivatives	'	'
Liability Derivatives	$1,038	$1,031

Recognized_Gains_and_Losses_fo

Recognized Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments (Detail) (Nondesignated [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Amount of Gain (Loss) Recognized in Income on Derivative	($4,662)	($24,127)
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	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	-38,283
Foreign exchange derivative contract [Member] | Interest and other income [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Amount of Gain (Loss) Recognized in Income on Derivative	($5,162)	$14,156

Stockholders_Equity_Additional

Stockholder's Equity - Additional Information (Detail) (USD $)	0 Months Ended	1 Months Ended	12 Months Ended	0 Months Ended
	Dec. 03, 2012	Dec. 31, 2013	Dec. 31, 2013	Oct. 16, 2012
				Maximum [Member]
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	'	'	'	1,000,000,000
Shares repurchased, value	'	'	$750,000,000	'
Shares repurchased, shares	'	'	11,722,969	'

WeightedAverage_Shares_Outstan

Weighted-Average Shares Outstanding for Computation of Basic and Diluted Income Per Common Share (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
Earnings Per Share [Abstract]	'	'		'
Basic method	187,921,062	193,902,335	[1]	193,409,621	[1]
Dilutive stock options	1,350,336	766,402		1,102,781
Diluted method	189,271,398	194,668,737	[1]	194,512,402	[1]
[1]	Reclassified to conform to current presentation.

Anti_Dilutive_Securities_Not_I

Anti Dilutive Securities Not Included in Computation of Diluted EPS (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Earnings Per Share [Abstract]	'	'	'
Antidilutive stock options excluded from diluted shares	1,026,900	3,329,689	1,823,564
Weighted average price of these options	$54.54	$64.72	$69.46

Other_Financial_Information_Ad

Other Financial Information - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]	'	'	'
Inventories accounted for under the LIFO method	$318,628,000	$262,160,000	'
Decrease amount of inventory that would have been valued using the FIFO method	268,608,000	571,227,000	'
Increased pretax income from discontinued operation derived from fair value exceeding the LIFO carrying value	'	'	296,185,000
Net gains (losses) from foreign currency transactions	73,732,000	5,092,000	22,131,000
Income taxes paid	457,006,000	566,999,000	938,944,000
Interest paid, net of amounts capitalized	$60,501,000	$9,501,000	$38,120,000

Noncash_Operating_Working_Capi

Noncash Operating Working Capital (Increased) Decreased (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]	'	'	'
Accounts receivable	$224,281	($382,137)	$90,608
Inventories	14,166	-94,907	-67,560
Prepaid expenses	195,013	-245,881	9,908
Deferred income tax assets	15,510	-7,218	15,914
Accounts payable and accrued liabilities	-176,543	534,353	-535,788
Current income tax liabilities	-6,098	27,610	-273,118
Net (increase) decrease in noncash operating working capital	$266,329	($168,180)	($760,036)

Components_of_Accumulated_Othe

Components of Accumulated Other Comprehensive Income (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Accumulated Other Comprehensive Income (Loss) [Line Items]	'		'		'
Beginning Balance	$408,901	[1]	'		'
Before reclassifications to income	-181,155	[1]	'		'
Reclassifications to income	55,627	[1]	'		'
Net other comprehensive income (loss)	-236,782	[1]	98,481		-139,008
Ending Balance	172,119	[1]	408,901	[1]	'
Foreign Currency Translation Gains (Losses) [Member]	'		'		'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'		'		'
Beginning Balance	613,492	[1]	'		'
Before reclassifications to income	-240,300	[1]	'		'
Reclassifications to income	-68,000	[1],[2]	'		'
Net other comprehensive income (loss)	-308,300	[1]	'		'
Ending Balance	305,192	[1]	'		'
Retirement and Postretirement Benefit Plan Adjustments [Member]	'		'		'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'		'		'
Beginning Balance	-186,539	[1]	'		'
Before reclassifications to income	59,145	[1]	'		'
Reclassifications to income	10,438	[1],[3]	'		'
Net other comprehensive income (loss)	69,583	[1]	'		'
Ending Balance	-116,956	[1]	'		'
Deferred Loss On Interest Rate Derivative Hedges [Member]	'		'		'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'		'		'
Beginning Balance	-18,052	[1]	'		'
Before reclassifications to income	0	[1]	'		'
Reclassifications to income	1,935	[1],[4]	'		'
Net other comprehensive income (loss)	1,935	[1]	'		'
Ending Balance	($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 are included in the computation of net periodic benefit expense. Related income taxes of $8,132 are included in Income tax expense.
[4]	Reclassifications before taxes of $2,963 are included in Interest expense. Related income taxes of $1,028 for the year ended December 31, 2013 are included in Income tax expense.

Components_of_Accumulated_Othe1

Components of Accumulated Other Comprehensive Income (Parenthetical) (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]	'
Reclassifications before taxes, included in net periodic benefit expense	$18,570
Reclassifications income tax, included in net periodic benefit expense	8,132
Reclassifications before taxes, included in interest expense	2,963
Reclassifications income tax, included in interest expense	$1,028

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Income - Additional Information (Detail) (USD $)	Dec. 31, 2013
Accumulated Other Comprehensive Income Loss Net Of Tax [Abstract]	'
Foreign currency translation gains (losses), net of tax	$305,192,000

Fair_Value_of_Assets_and_Liabi

Fair Value of Assets and Liabilities (Detail) (Fair Value, Measurements, Recurring [Member], USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Derivative liabilities	($14,305)	($11,426)
Commodity derivative contracts [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Derivative assets	1,970	3,043
Derivative liabilities	'	-102
Nonqualified employee savings plans [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Derivative liabilities	-13,267	-10,293
Foreign exchange derivative contract [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Derivative liabilities	-1,038	-1,031
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Derivative liabilities	-13,267	-10,293
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Commodity derivative contracts [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Derivative assets	0	0
Derivative liabilities	'	0
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Nonqualified employee savings plans [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Derivative liabilities	-13,267	-10,293
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign exchange derivative contract [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Derivative liabilities	0	0
Significant Other Observable Inputs (Level 2) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Derivative liabilities	-1,038	-1,133
Significant Other Observable Inputs (Level 2) [Member] | Commodity derivative contracts [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Derivative assets	1,970	3,043
Derivative liabilities	'	-102
Significant Other Observable Inputs (Level 2) [Member] | Nonqualified employee savings plans [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Derivative liabilities	0	0
Significant Other Observable Inputs (Level 2) [Member] | Foreign exchange derivative contract [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Derivative liabilities	-1,038	-1,031
Significant Unobservable Inputs (Level 3) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Derivative liabilities	0	0
Significant Unobservable Inputs (Level 3) [Member] | Commodity derivative contracts [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Derivative assets	0	0
Derivative liabilities	'	0
Significant Unobservable Inputs (Level 3) [Member] | Nonqualified employee savings plans [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Derivative liabilities	0	0
Significant Unobservable Inputs (Level 3) [Member] | Foreign exchange derivative contract [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]	'	'
Derivative liabilities	$0	$0

Offsetting_of_Assets_and_Liabi

Offsetting of Assets and Liabilities Related to Derivative Contracts (Detail) (Commodity derivatives [Member], USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Commodity derivatives [Member]	'	'
Derivative Financial Instruments [Line Items]	'	'
Gross Amounts of Recognized Assets	$3,111	'
Gross Amounts of Recognized Liabilities	'	2,271
Gross Amounts Offset in the Consolidated Balance Sheet	-2,169	-2,169
Net Amounts of Assets Presented in the Consolidated Balance Sheet	942	'
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet	'	$102

Carrying_Amounts_and_Estimated

Carrying Amounts and Estimated Fair Values of Financial Instruments (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Financial assets (liabilities), Carrying value	'	'
Canadian government securities with maturities greater than 90 days at the date of acquisition	$374,842	$115,603
Current and long-term debt	2,962,812	2,245,247
Financial assets (liabilities):	'	'
Canadian government securities with maturities greater than 90 days at the date of acquisition	375,623	115,802
Current and long-term debt	($2,822,827)	($2,357,972)

Commitments_Additional_Informa

Commitments - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2006
Commitments and Contingencies Disclosure [Line Items]	'	'	'	'
Operating lease rental payments due in 2014	$259,365,000	'	'	'
Operating lease rental payments due in 2015	185,957,000	'	'	'
Operating lease rental payments due in 2016	134,754,000	'	'	'
Operating lease rental payments due in 2017	117,555,000	'	'	'
Operating lease rental payments due in 2018	113,585,000	'	'	'
Rental expenses for non-cancellable lease, including contingent payments	192,482,000	178,292,000	185,016,000	'
Commitments for capital expenditures	1,837,394,000	'	'	'
Malaysia [Member]	'	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'	'
Commitments for capital expenditures	706,889,000	'	'	'
Gulf of Mexico [Member]	'	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'	'
Commitments for capital expenditures	184,840,000	'	'	'
Eagle Ford Shale [Member]	'	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'	'
Commitments for capital expenditures	561,410,000	'	'	'
Cameroon	'	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'	'
Commitments for capital expenditures	78,851,000	'	'	'
Vietnam	'	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'	'
Commitments for capital expenditures	76,150,000	'	'	'
Equatorial Guinea	'	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'	'
Commitments for capital expenditures	78,000,000	'	'	'
Drilling Rigs And Associated Equipment [Member]	'	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'	'
Future commitments	1,302,284,000	'	'	'
Processing Production Handling and Transportation Services [Member]	'	'	'	'
Commitments and Contingencies Disclosure [Line Items]	'	'	'	'
Operating lease rental payments due in 2014	57,787,000	'	'	'
Operating lease rental payments due in 2015	35,157,000	'	'	'
Operating lease rental payments due in 2016	23,439,000	'	'	'
Operating lease rental payments due in 2017	17,961,000	'	'	'
Operating lease rental payments due in 2018	12,792,000	'	'	'
Processing and transportation charges	40,254,000	19,733,000	24,791,000	'
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	$805,000	$1,063,000	$1,317,000	'

Contingencies_Additional_Infor

Contingencies - Additional Information (Detail) (USD $)	Dec. 31, 2013
	Location
Commitments and Contingencies Disclosure [Line Items]	'
Superfund site company is considered to be Potentially Responsible Party (PRP)	1
Letter of Credit [Member]	'
Commitments and Contingencies Disclosure [Line Items]	'
Contingent liabilities	129,866,000

Terra_Nova_Working_Interest_Re1

Terra Nova Working Interest Redetermination - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011		Jan. 31, 2011	Dec. 31, 2010
Commitments And Contingencies Disclosure [Abstract]	'	'		'		'	'
Joint agreement ownership interest	'	'		'		10.48%	12.00%
Redetermination of Terra Nova working interest	$0	$0	[1]	($5,351)	[1],[2]	'	'
[1]	Reclassified to conform to current presentation.
[2]	Results exclude corporate overhead, interest and discontinued operations.

Activity_in_Number_of_Shares_o

Activity in Number of Shares of Common Stock Issued and Outstanding (Detail)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Equity [Abstract]	'		'		'
At beginning of year	190,641,317		193,723,208		192,836,008
Stock options exercised	303,685	[1]	482,974	[1]	615,674	[1]
Employee stock purchase and thrift plans	16,020		78,389		33,390
Restricted stock awards, net of forfeitures	300,910		224,296		238,136
Treasury shares purchased	-7,855,419		-3,867,550		0
At end of year	183,406,513		190,641,317		193,723,208
[1]	Shares issued upon exercise of stock options are less than the amount reflected in Note I due to withholdings for statutory income taxes owed upon exercise.

Subsequent_Events_Additional_I

Subsequent Events - Additional Information (Detail) (USD $)	1 Months Ended	12 Months Ended	0 Months Ended	1 Months Ended
	Dec. 31, 2013	Dec. 31, 2013	Feb. 05, 2014	Feb. 28, 2014
		Accelerated Share Repurchase (ASR) [Member]	Subsequent Event [Member]	Subsequent Event [Member]
			Accelerated Share Repurchase (ASR) [Member]	Accelerated Share Repurchase (ASR) [Member]
Subsequent Event [Line Items]	'	'	'	'
Shares repurchased, value	'	'	$250,000,000	'
Shares repurchased, shares	'	'	'	4,018,000
Quarterly dividend declared, per share	'	'	$0.31	'
Dividend payable date	'	3-Mar-14	'	'
Dividend payable record date	16-Nov-12	18-Feb-14	'	'

Business_Segments_Additional_I

Business Segments - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012	Dec. 31, 2011
	OilRefinery	Phillips 66 and Affiliated Companies [Member]	Shell Oil and Affiliates [Member]	Shell Oil [Member]	Shell Oil [Member]	BP [Member]	BP [Member]	Petronas [Member]	Petronas [Member]
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'
Number of oil refineries sold	2	'	'	'	'	'	'	'	'
Percentage of net sales revenue in oil and natural gas production	'	17.00%	14.00%	17.00%	16.00%	13.00%	15.00%	12.00%	11.00%

Segment_Information_Detail

Segment Information (Detail) (USD $)

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Segment income (loss)

$75,400,000

$284,800,000

$402,700,000

$360,600,000

$158,700,000

$226,700,000

$295,400,000

$290,100,000

$1,123,473,000

$970,876,000

[1]

$872,702,000

[1]

Revenues from external customers

'

'

'

'

'

'

'

'

5,390,089,000

4,619,602,000

[1]

4,278,682,000

[1]

Interest income

'

'

'

'

'

'

'

'

3,900,000

6,500,000

10,100,000

Interest expense, net of capitalization

'

'

'

'

'

'

'

'

71,900,000

14,900,000

40,700,000

Income tax expense (benefit)

'

'

'

'

'

'

'

'

584,550,000

561,516,000

[1]

628,677,000

[1]

Significant noncash charges (credits)

'

'

'

'

'

'

'

'

'

'

'

Depreciation, depletion, amortization

'

'

'

'

'

'

'

'

1,553,394,000

1,253,095,000

[1]

964,725,000

[1]

Accretion of asset retirement obligations

'

'

'

'

'

'

'

'

48,996,000

38,361,000

[1],[2]

33,847,000

[1]

Amortization of undeveloped leases

'

'

'

'

'

'

'

'

66,891,000

129,750,000

[1]

118,211,000

[1]

Impairment of long-lived assets

'

'

'

'

'

'

'

'

21,587,000

[3]

200,000,000

[1],[3]

368,600,000

[1],[3]

Deferred and noncurrent income taxes

'

'

'

'

'

'

'

'

158,100,000

342,800,000

133,800,000

Additions to property, plant, equipment

'

'

'

'

'

'

'

'

3,532,200,000

4,133,800,000

2,572,200,000

Total assets at year-end

17,509,484,000

'

'

'

17,522,643,000

'

'

'

17,509,484,000

17,522,643,000

14,138,100,000

External Customer [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

5,390,100,000

4,619,600,000

'

United States [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

1,798,500,000

1,038,100,000

741,800,000

Canada [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

1,150,200,000

1,088,400,000

1,293,400,000

Malaysia [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

2,337,500,000

2,415,600,000

2,063,000,000

Republic of the Congo [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

83,500,000

57,600,000

148,800,000

Other [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

20,400,000

19,900,000

31,700,000

Discontinued Operations [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Segment income (loss)

'

'

'

'

'

'

'

'

235,300,000

164,400,000

333,500,000

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 long-lived assets

'

'

'

'

'

'

'

'

0

0

0

Deferred and noncurrent income taxes

'

'

'

'

'

'

'

'

0

0

0

Additions to property, plant, equipment

'

'

'

'

'

'

'

'

8,100,000

191,800,000

190,100,000

Total assets at year-end

1,325,100,000

'

'

'

3,410,100,000

'

'

'

1,325,100,000

3,410,100,000

3,214,400,000

Discontinued Operations [Member] | External Customer [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

0

0

'

Operating Segments [Member] | External Customer [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

'

'

4,278,700,000

Operating Segments [Member] | Discontinued Operations [Member] | External Customer [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

'

'

0

Exploration and production [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Segment income (loss)

'

'

'

'

'

'

'

'

1,028,800,000

905,000,000

614,200,000

Interest income

'

'

'

'

'

'

'

'

0

0

0

Interest expense, net of capitalization

'

'

'

'

'

'

'

'

0

0

0

Income tax expense (benefit)

'

'

'

'

'

'

'

'

656,300,000

605,000,000

680,800,000

Significant noncash charges (credits)

'

'

'

'

'

'

'

'

'

'

'

Depreciation, depletion, amortization

'

'

'

'

'

'

'

'

1,543,600,000

1,244,400,000

956,000,000

Accretion of asset retirement obligations

'

'

'

'

'

'

'

'

49,000,000

38,400,000

33,800,000

Amortization of undeveloped leases

'

'

'

'

'

'

'

'

66,900,000

129,800,000

118,200,000

Impairment of long-lived assets

'

'

'

'

'

'

'

'

21,600,000

200,000,000

368,600,000

Deferred and noncurrent income taxes

'

'

'

'

'

'

'

'

173,800,000

375,100,000

177,400,000

Additions to property, plant, equipment

'

'

'

'

'

'

'

'

3,508,600,000

3,933,800,000

2,376,800,000

Total assets at year-end

14,919,200,000

'

'

'

13,102,900,000

'

'

'

14,919,200,000

13,102,900,000

10,132,900,000

Exploration and production [Member] | External Customer [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

5,312,600,000

4,608,100,000

'

Exploration and production [Member] | United States [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Segment income (loss)

'

'

'

'

'

'

'

'

435,400,000

168,000,000

152,700,000

Interest income

'

'

'

'

'

'

'

'

0

0

0

Interest expense, net of capitalization

'

'

'

'

'

'

'

'

0

0

0

Income tax expense (benefit)

'

'

'

'

'

'

'

'

241,600,000

99,800,000

86,500,000

Significant noncash charges (credits)

'

'

'

'

'

'

'

'

'

'

'

Depreciation, depletion, amortization

'

'

'

'

'

'

'

'

576,300,000

330,200,000

183,000,000

Accretion of asset retirement obligations

'

'

'

'

'

'

'

'

13,500,000

11,400,000

9,900,000

Amortization of undeveloped leases

'

'

'

'

'

'

'

'

30,300,000

71,600,000

62,200,000

Impairment of long-lived assets

'

'

'

'

'

'

'

'

0

0

0

Deferred and noncurrent income taxes

'

'

'

'

'

'

'

'

99,600,000

231,000,000

54,200,000

Additions to property, plant, equipment

'

'

'

'

'

'

'

'

1,785,900,000

1,615,900,000

696,600,000

Total assets at year-end

4,530,000,000

'

'

'

3,625,900,000

'

'

'

4,530,000,000

3,625,900,000

2,227,600,000

Exploration and production [Member] | United States [Member] | External Customer [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

1,803,800,000

1,038,000,000

'

Exploration and production [Member] | Canada [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Segment income (loss)

'

'

'

'

'

'

'

'

180,800,000

208,100,000

328,000,000

Interest income

'

'

'

'

'

'

'

'

0

0

0

Interest expense, net of capitalization

'

'

'

'

'

'

'

'

0

0

0

Income tax expense (benefit)

'

'

'

'

'

'

'

'

57,800,000

65,100,000

135,500,000

Significant noncash charges (credits)

'

'

'

'

'

'

'

'

'

'

'

Depreciation, depletion, amortization

'

'

'

'

'

'

'

'

374,600,000

345,800,000

326,000,000

Accretion of asset retirement obligations

'

'

'

'

'

'

'

'

16,200,000

13,600,000

12,500,000

Amortization of undeveloped leases

'

'

'

'

'

'

'

'

21,000,000

29,300,000

28,800,000

Impairment of long-lived assets

'

'

'

'

'

'

'

'

21,600,000

0

0

Deferred and noncurrent income taxes

'

'

'

'

'

'

'

'

26,100,000

72,300,000

39,600,000

Additions to property, plant, equipment

'

'

'

'

'

'

'

'

334,500,000

887,200,000

885,200,000

Total assets at year-end

4,087,800,000

'

'

'

4,477,700,000

'

'

'

4,087,800,000

4,477,700,000

3,746,800,000

Exploration and production [Member] | Canada [Member] | External Customer [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

1,144,700,000

1,084,300,000

'

Exploration and production [Member] | Malaysia [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Segment income (loss)

'

'

'

'

'

'

'

'

786,400,000

894,200,000

812,700,000

Interest income

'

'

'

'

'

'

'

'

0

0

0

Interest expense, net of capitalization

'

'

'

'

'

'

'

'

0

0

0

Income tax expense (benefit)

'

'

'

'

'

'

'

'

477,700,000

544,700,000

434,900,000

Significant noncash charges (credits)

'

'

'

'

'

'

'

'

'

'

'

Depreciation, depletion, amortization

'

'

'

'

'

'

'

'

588,200,000

532,100,000

357,300,000

Accretion of asset retirement obligations

'

'

'

'

'

'

'

'

15,000,000

12,500,000

10,600,000

Amortization of undeveloped leases

'

'

'

'

'

'

'

'

0

0

0

Impairment of long-lived assets

'

'

'

'

'

'

'

'

0

0

0

Deferred and noncurrent income taxes

'

'

'

'

'

'

'

'

48,100,000

73,300,000

84,600,000

Additions to property, plant, equipment

'

'

'

'

'

'

'

'

1,323,400,000

1,426,700,000

694,800,000

Total assets at year-end

6,121,000,000

'

'

'

4,811,500,000

'

'

'

6,121,000,000

4,811,500,000

3,826,900,000

Exploration and production [Member] | Malaysia [Member] | External Customer [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

2,280,500,000

2,428,100,000

'

Exploration and production [Member] | Republic of the Congo [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Segment income (loss)

'

'

'

'

'

'

'

'

-9,000,000

-241,100,000

-385,300,000

Interest income

'

'

'

'

'

'

'

'

0

0

0

Interest expense, net of capitalization

'

'

'

'

'

'

'

'

0

0

0

Income tax expense (benefit)

'

'

'

'

'

'

'

'

-109,900,000

-64,500,000

16,400,000

Significant noncash charges (credits)

'

'

'

'

'

'

'

'

'

'

'

Depreciation, depletion, amortization

'

'

'

'

'

'

'

'

200,000

33,900,000

87,800,000

Accretion of asset retirement obligations

'

'

'

'

'

'

'

'

4,300,000

900,000

500,000

Amortization of undeveloped leases

'

'

'

'

'

'

'

'

0

0

0

Impairment of long-lived assets

'

'

'

'

'

'

'

'

0

200,000,000

368,600,000

Deferred and noncurrent income taxes

'

'

'

'

'

'

'

'

0

-300,000

-900,000

Additions to property, plant, equipment

'

'

'

'

'

'

'

'

-5,700,000

-20,700,000

79,600,000

Total assets at year-end

51,600,000

'

'

'

112,200,000

'

'

'

51,600,000

112,200,000

257,500,000

Exploration and production [Member] | Republic of the Congo [Member] | External Customer [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

83,500,000

57,600,000

'

Exploration and production [Member] | Other [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Segment income (loss)

'

'

'

'

'

'

'

'

-364,800,000

-124,200,000

-293,900,000

Interest income

'

'

'

'

'

'

'

'

0

0

0

Interest expense, net of capitalization

'

'

'

'

'

'

'

'

0

0

0

Income tax expense (benefit)

'

'

'

'

'

'

'

'

-10,900,000

-40,100,000

7,500,000

Significant noncash charges (credits)

'

'

'

'

'

'

'

'

'

'

'

Depreciation, depletion, amortization

'

'

'

'

'

'

'

'

4,300,000

2,400,000

1,900,000

Accretion of asset retirement obligations

'

'

'

'

'

'

'

'

0

0

300,000

Amortization of undeveloped leases

'

'

'

'

'

'

'

'

15,600,000

28,900,000

27,200,000

Impairment of long-lived assets

'

'

'

'

'

'

'

'

0

0

0

Deferred and noncurrent income taxes

'

'

'

'

'

'

'

'

0

-1,200,000

-100,000

Additions to property, plant, equipment

'

'

'

'

'

'

'

'

70,500,000

24,700,000

20,600,000

Total assets at year-end

128,800,000

'

'

'

75,600,000

'

'

'

128,800,000

75,600,000

74,100,000

Exploration and production [Member] | Other [Member] | External Customer [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

100,000

100,000

'

Exploration and production [Member] | Operating Segments [Member] | External Customer [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

'

'

4,245,300,000

Exploration and production [Member] | Operating Segments [Member] | United States [Member] | External Customer [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

'

'

737,700,000

Exploration and production [Member] | Operating Segments [Member] | Canada [Member] | External Customer [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

'

'

1,288,600,000

[1]

Exploration and production [Member] | Operating Segments [Member] | Malaysia [Member] | External Customer [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

'

'

2,045,600,000

Exploration and production [Member] | Operating Segments [Member] | Republic of the Congo [Member] | External Customer [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

'

'

148,800,000

Exploration and production [Member] | Operating Segments [Member] | Other [Member] | External Customer [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

'

'

24,600,000

Corporate and Other [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Segment income (loss)

'

'

'

'

'

'

'

'

-140,600,000

-98,500,000

-75,000,000

Interest income

'

'

'

'

'

'

'

'

3,900,000

6,500,000

10,100,000

Interest expense, net of capitalization

'

'

'

'

'

'

'

'

71,900,000

14,900,000

40,700,000

Income tax expense (benefit)

'

'

'

'

'

'

'

'

-71,700,000

-43,500,000

-52,100,000

Significant noncash charges (credits)

'

'

'

'

'

'

'

'

'

'

'

Depreciation, depletion, amortization

'

'

'

'

'

'

'

'

9,800,000

8,700,000

8,700,000

Accretion of asset retirement obligations

'

'

'

'

'

'

'

'

0

0

0

Amortization of undeveloped leases

'

'

'

'

'

'

'

'

0

0

0

Impairment of long-lived assets

'

'

'

'

'

'

'

'

0

0

0

Deferred and noncurrent income taxes

'

'

'

'

'

'

'

'

-15,700,000

-32,300,000

-43,600,000

Additions to property, plant, equipment

'

'

'

'

'

'

'

'

15,500,000

8,200,000

5,300,000

Total assets at year-end

1,265,200,000

'

'

'

1,009,600,000

'

'

'

1,265,200,000

1,009,600,000

790,800,000

Corporate and Other [Member] | External Customer [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

77,500,000

11,500,000

'

Corporate and Other [Member] | Operating Segments [Member] | External Customer [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues from external customers

'

'

'

'

'

'

'

'

'

'

$33,400,000

[1]

Reclassified to conform to current presentation.

[2]

Includes $980 reclassified to discontinued operations associated with U.S. downstream operations.

[3]

Results exclude corporate overhead, interest and discontinued operations.

Geographic_Information_on_Cert

Geographic Information on Certain Long-Lived Assets (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Revenues from External Customers and Long-Lived Assets [Line Items]	'	'	'
Certain Long-Lived Assets	$13,481.50	$13,217.40	$10,481.90
United States [Member]	'	'	'
Revenues from External Customers and Long-Lived Assets [Line Items]	'	'	'
Certain Long-Lived Assets	4,267.90	4,177.40	2,953.10
Canada [Member]	'	'	'
Revenues from External Customers and Long-Lived Assets [Line Items]	'	'	'
Certain Long-Lived Assets	3,834.90	4,190.50	3,493.40
Malaysia [Member]	'	'	'
Revenues from External Customers and Long-Lived Assets [Line Items]	'	'	'
Certain Long-Lived Assets	5,301.70	4,101.20	3,154.80
United Kingdom [Member]	'	'	'
Revenues from External Customers and Long-Lived Assets [Line Items]	'	'	'
Certain Long-Lived Assets	0.4	703.2	694.7
Republic of the Congo [Member]	'	'	'
Revenues from External Customers and Long-Lived Assets [Line Items]	'	'	'
Certain Long-Lived Assets	0	5.9	133.7
Other [Member]	'	'	'
Revenues from External Customers and Long-Lived Assets [Line Items]	'	'	'
Certain Long-Lived Assets	$76.60	$39.20	$52.20

Geographic_Information_on_Reve

Geographic Information on Revenues from External Customers (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
Revenues from External Customers and Long-Lived Assets [Line Items]	'	'		'
Revenues from external customers	$5,390,089	$4,619,602	[1]	$4,278,682	[1]
United States [Member]	'	'		'
Revenues from External Customers and Long-Lived Assets [Line Items]	'	'		'
Revenues from external customers	1,798,500	1,038,100		741,800
Canada [Member]	'	'		'
Revenues from External Customers and Long-Lived Assets [Line Items]	'	'		'
Revenues from external customers	1,150,200	1,088,400		1,293,400
Malaysia [Member]	'	'		'
Revenues from External Customers and Long-Lived Assets [Line Items]	'	'		'
Revenues from external customers	2,337,500	2,415,600		2,063,000
Republic of the Congo [Member]	'	'		'
Revenues from External Customers and Long-Lived Assets [Line Items]	'	'		'
Revenues from external customers	83,500	57,600		148,800
Other [Member]	'	'		'
Revenues from External Customers and Long-Lived Assets [Line Items]	'	'		'
Revenues from external customers	$20,400	$19,900		$31,700
[1]	Reclassified to conform to current presentation.

Recovered_Sheet1

Supplemental Oil and Gas Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013
	Mg
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 500 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	125.1
Malaysia [Member] | Natural Gas Reserves [Member]	'
Reserve Quantities [Line Items]	'
Oil and natural gas reserves associated with the production sharing contracts	405.8
Malaysia [Member] | Natural Gas Reserves [Member] | Kikeh Field [Member]	'
Reserve Quantities [Line Items]	'
Oil and natural gas reserves associated with the production sharing contracts	74.9

Summary_of_Proved_Oil_Reserves1

Summary of Proved Oil Reserves Based on Average Prices (Detail) (Oil Reserves [Member])	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
	bbl	bbl	bbl	bbl
Proved developed and undeveloped oil reserves:	'	'	'	'
Proved developed and undeveloped reserves, Beginning Balance	414,800,000	349,700,000	308,000,000	'
Revisions of previous estimates	43,100,000	2,600,000	21,200,000	'
Improved recovery	27,400,000	7,200,000	14,200,000	'
Extensions and discoveries	79,600,000	84,000,000	43,900,000	'
Sales of properties	-20,400,000	'	'	'
Purchases of properties	'	12,500,000	'	'
Production	-48,900,000	-41,200,000	-37,600,000	'
Proved developed and undeveloped reserves, Ending Balance	495,600,000	414,800,000	349,700,000	'
Proved developed reserves	304,100,000	267,700,000	238,500,000	248,300,000
Proved undeveloped reserves	191,500,000	147,100,000	111,200,000	59,700,000
Crude Oil [Member]	'	'	'	'
Proved developed and undeveloped oil reserves:	'	'	'	'
Proved developed and undeveloped reserves, Beginning Balance	295,700,000	220,200,000	178,800,000	'
Revisions of previous estimates	40,500,000	7,900,000	16,000,000	'
Improved recovery	27,400,000	7,200,000	14,200,000	'
Extensions and discoveries	79,600,000	84,000,000	43,900,000	'
Sales of properties	-20,400,000	'	'	'
Purchases of properties	'	12,500,000	'	'
Production	-44,200,000	-36,100,000	-32,700,000	'
Proved developed and undeveloped reserves, Ending Balance	378,600,000	295,700,000	220,200,000	'
Proved developed reserves	187,100,000	148,600,000	118,000,000	129,200,000
Proved undeveloped reserves	191,500,000	147,100,000	102,200,000	49,600,000
Synthetic Oil [Member]	'	'	'	'
Proved developed and undeveloped oil reserves:	'	'	'	'
Proved developed and undeveloped reserves, Beginning Balance	119,100,000	129,500,000	129,200,000	'
Revisions of previous estimates	2,600,000	-5,300,000	5,200,000	'
Improved recovery	0	0	0	'
Extensions and discoveries	0	0	0	'
Sales of properties	0	'	'	'
Purchases of properties	'	0	'	'
Production	-4,700,000	-5,100,000	-4,900,000	'
Proved developed and undeveloped reserves, Ending Balance	117,000,000	119,100,000	129,500,000	'
Proved developed reserves	117,000,000	119,100,000	120,500,000	119,100,000
Proved undeveloped reserves	0	0	9,000,000	10,100,000
United States [Member] | Crude Oil [Member]	'	'	'	'
Proved developed and undeveloped oil reserves:	'	'	'	'
Proved developed and undeveloped reserves, Beginning Balance	142,600,000	55,300,000	26,600,000	'
Revisions of previous estimates	28,700,000	13,000,000	2,400,000	'
Improved recovery	0	0	0	'
Extensions and discoveries	61,100,000	77,300,000	32,600,000	'
Sales of properties	0	'	'	'
Purchases of properties	'	6,500,000	'	'
Production	-17,700,000	-9,500,000	-6,300,000	'
Proved developed and undeveloped reserves, Ending Balance	214,700,000	142,600,000	55,300,000	'
Proved developed reserves	88,900,000	48,000,000	20,800,000	15,800,000
Proved undeveloped reserves	125,800,000	94,600,000	34,500,000	10,800,000
Canada [Member] | Crude Oil [Member]	'	'	'	'
Proved developed and undeveloped oil reserves:	'	'	'	'
Proved developed and undeveloped reserves, Beginning Balance	36,800,000	36,600,000	32,800,000	'
Revisions of previous estimates	8,400,000	-3,400,000	3,100,000	'
Improved recovery	0	0	0	'
Extensions and discoveries	300,000	2,900,000	6,700,000	'
Sales of properties	0	'	'	'
Purchases of properties	'	6,000,000	'	'
Production	-6,700,000	-5,300,000	-6,000,000	'
Proved developed and undeveloped reserves, Ending Balance	38,800,000	36,800,000	36,600,000	'
Proved developed reserves	31,600,000	29,500,000	32,600,000	28,600,000
Proved undeveloped reserves	7,200,000	7,300,000	4,000,000	4,200,000
Canada [Member] | Synthetic Oil [Member]	'	'	'	'
Proved developed and undeveloped oil reserves:	'	'	'	'
Proved developed and undeveloped reserves, Beginning Balance	119,100,000	129,500,000	129,200,000	'
Revisions of previous estimates	2,600,000	-5,300,000	5,200,000	'
Improved recovery	0	0	0	'
Extensions and discoveries	0	0	0	'
Sales of properties	0	'	'	'
Purchases of properties	'	0	'	'
Production	-4,700,000	-5,100,000	-4,900,000	'
Proved developed and undeveloped reserves, Ending Balance	117,000,000	119,100,000	129,500,000	'
Proved developed reserves	117,000,000	119,100,000	120,500,000	119,100,000
Proved undeveloped reserves	0	0	9,000,000	10,100,000
Malaysia [Member] | Crude Oil [Member]	'	'	'	'
Proved developed and undeveloped oil reserves:	'	'	'	'
Proved developed and undeveloped reserves, Beginning Balance	95,700,000	104,400,000	98,400,000	'
Revisions of previous estimates	3,400,000	-400,000	8,400,000	'
Improved recovery	27,400,000	7,200,000	10,700,000	'
Extensions and discoveries	18,200,000	3,800,000	4,600,000	'
Sales of properties	0	'	'	'
Purchases of properties	'	0	'	'
Production	-19,600,000	-19,300,000	-17,700,000	'
Proved developed and undeveloped reserves, Ending Balance	125,100,000	95,700,000	104,400,000	'
Proved developed reserves	66,600,000	67,000,000	57,200,000	66,500,000
Proved undeveloped reserves	58,500,000	28,700,000	47,200,000	31,900,000
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	10,900,000	'
Revisions of previous estimates	0	300,000	8,100,000	'
Improved recovery	0	0	3,500,000	'
Extensions and discoveries	0	0	0	'
Sales of properties	-20,400,000	'	'	'
Purchases of properties	'	0	'	'
Production	-200,000	-1,300,000	-900,000	'
Proved developed and undeveloped reserves, Ending Balance	0	20,600,000	21,600,000	'
Proved developed reserves	0	4,100,000	5,100,000	10,900,000
Proved undeveloped reserves	0	16,500,000	16,500,000	0
Republic of the Congo [Member] | Crude Oil [Member]	'	'	'	'
Proved developed and undeveloped oil reserves:	'	'	'	'
Proved developed and undeveloped reserves, Beginning Balance	0	2,300,000	10,100,000	'
Revisions of previous estimates	0	-1,600,000	-6,000,000	'
Improved recovery	0	0	0	'
Extensions and discoveries	0	0	0	'
Sales of properties	0	'	'	'
Purchases of properties	'	0	'	'
Production	0	-700,000	-1,800,000	'
Proved developed and undeveloped reserves, Ending Balance	0	0	2,300,000	'
Proved developed reserves	0	0	2,300,000	7,400,000
Proved undeveloped reserves	0	0	0	2,700,000

Summary_of_Proved_Natural_Gas_1

Summary of Proved Natural Gas Reserves Based on Average Prices (Detail) (Natural Gas Reserves [Member])	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
	ft3	ft3	ft3	ft3
Proved developed and undeveloped natural gas reserves	'	'	'	'
Proved developed and undeveloped reserves, Beginning Balance	1,137,000,000,000	1,106,100,000,000	883,100,000,000	'
Revisions of previous estimates	33,700,000,000	20,200,000,000	12,600,000,000	'
Improved recovery	3,200,000,000	7,200,000,000	13,800,000,000	'
Extensions and discoveries	153,400,000,000	173,500,000,000	363,500,000,000	'
Sales of properties	-19,000,000,000	'	'	'
Purchases of properties	'	9,400,000,000	'	'
Production	-154,700,000,000	-179,400,000,000	-166,900,000,000	'
Proved developed and undeveloped reserves, Ending Balance	1,153,600,000,000	1,137,000,000,000	1,106,100,000,000	'
Proved developed reserve	786,200,000,000	706,000,000,000	711,600,000,000	586,000,000,000
Proved undeveloped reserves	367,400,000,000	431,000,000,000	394,500,000,000	297,100,000,000
United States [Member]	'	'	'	'
Proved developed and undeveloped natural gas reserves	'	'	'	'
Proved developed and undeveloped reserves, Beginning Balance	209,700,000,000	98,400,000,000	90,800,000,000	'
Revisions of previous estimates	-38,600,000,000	16,500,000,000	-6,300,000,000	'
Improved recovery	0	0	0	'
Extensions and discoveries	33,300,000,000	107,200,000,000	31,100,000,000	'
Sales of properties	0	'	'	'
Purchases of properties	'	7,000,000,000	'	'
Production	-19,400,000,000	-19,400,000,000	-17,200,000,000	'
Proved developed and undeveloped reserves, Ending Balance	185,000,000,000	209,700,000,000	98,400,000,000	'
Proved developed reserve	112,600,000,000	78,800,000,000	58,200,000,000	67,000,000,000
Proved undeveloped reserves	72,400,000,000	130,900,000,000	40,200,000,000	23,800,000,000
Canada [Member]	'	'	'	'
Proved developed and undeveloped natural gas reserves	'	'	'	'
Proved developed and undeveloped reserves, Beginning Balance	550,400,000,000	638,900,000,000	326,900,000,000	'
Revisions of previous estimates	34,000,000,000	-37,200,000,000	59,400,000,000	'
Improved recovery	0	0	0	'
Extensions and discoveries	42,500,000,000	25,800,000,000	321,500,000,000	'
Sales of properties	0	'	'	'
Purchases of properties	'	2,400,000,000	'	'
Production	-64,100,000,000	-79,500,000,000	-68,900,000,000	'
Proved developed and undeveloped reserves, Ending Balance	562,800,000,000	550,400,000,000	638,900,000,000	'
Proved developed reserve	384,000,000,000	415,800,000,000	427,100,000,000	210,100,000,000
Proved undeveloped reserves	178,800,000,000	134,600,000,000	211,800,000,000	116,800,000,000
Malaysia [Member]	'	'	'	'
Proved developed and undeveloped natural gas reserves	'	'	'	'
Proved developed and undeveloped reserves, Beginning Balance	357,600,000,000	347,800,000,000	434,000,000,000	'
Revisions of previous estimates	38,300,000,000	41,400,000,000	-32,500,000,000	'
Improved recovery	3,200,000,000	7,200,000,000	14,800,000,000	'
Extensions and discoveries	77,600,000,000	40,500,000,000	10,900,000,000	'
Sales of properties	0	'	'	'
Purchases of properties	'	0	'	'
Production	-70,900,000,000	-79,300,000,000	-79,400,000,000	'
Proved developed and undeveloped reserves, Ending Balance	405,800,000,000	357,600,000,000	347,800,000,000	'
Proved developed reserve	289,600,000,000	197,300,000,000	210,500,000,000	277,500,000,000
Proved undeveloped reserves	116,200,000,000	160,300,000,000	137,300,000,000	156,500,000,000
United Kingdom [Member]	'	'	'	'
Proved developed and undeveloped natural gas reserves	'	'	'	'
Proved developed and undeveloped reserves, Beginning Balance	19,300,000,000	21,000,000,000	31,400,000,000	'
Revisions of previous estimates	0	-500,000,000	-8,000,000,000	'
Improved recovery	0	0	-1,000,000,000	'
Extensions and discoveries	0	0	0	'
Sales of properties	-19,000,000,000	'	'	'
Purchases of properties	'	0	'	'
Production	-300,000,000	-1,200,000,000	-1,400,000,000	'
Proved developed and undeveloped reserves, Ending Balance	0	19,300,000,000	21,000,000,000	'
Proved developed reserve	0	14,100,000,000	15,800,000,000	31,400,000,000
Proved undeveloped reserves	0	5,200,000,000	5,200,000,000	0

Cost_Incurred_in_Oil_and_Gas_P

Cost Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Property acquisition costs	'		'		'
Unproved	$35,600,000		$132,500,000		$279,300,000
Proved	13,200,000		311,500,000		23,500,000
Total acquisition costs	48,800,000		444,000,000		302,800,000
Exploration costs	493,700,000	[1]	448,000,000	[1]	562,500,000	[1]
Development costs	3,939,600,000	[1]	3,521,700,000	[1]	1,954,300,000	[1]
Total Costs	4,482,100,000		4,413,700,000		2,819,600,000
Charged to expense	'		'		'
Dry hole expense	262,876,000		181,924,000	[2]	250,954,000	[2]
Geophysical and other costs	172,400,000		69,000,000		120,700,000
Total charged to expense	435,300,000		250,100,000		371,700,000
Property additions	4,046,800,000		4,163,600,000		2,447,900,000
United States [Member]	'		'		'
Property acquisition costs	'		'		'
Unproved	32,400,000		107,700,000		233,800,000
Proved	13,200,000		69,100,000		0
Total acquisition costs	45,600,000		176,800,000		233,800,000
Exploration costs	112,400,000	[1]	174,500,000	[1]	253,200,000	[1]
Development costs	1,773,200,000	[1]	1,352,700,000	[1]	263,900,000	[1]
Total Costs	1,931,200,000		1,704,000,000		750,900,000
Charged to expense	'		'		'
Dry hole expense	46,100,000		32,300,000		600,000
Geophysical and other costs	29,100,000		19,600,000		35,900,000
Total charged to expense	75,200,000		51,900,000		36,500,000
Property additions	1,856,000,000		1,652,100,000		714,400,000
Canada [Member]	'		'		'
Property acquisition costs	'		'		'
Unproved	0		14,600,000		18,500,000
Proved	0		242,400,000		0
Total acquisition costs	0		257,000,000		18,500,000
Exploration costs	21,800,000	[1]	57,000,000	[1]	76,000,000	[1]
Development costs	351,600,000	[1]	664,500,000	[1]	871,900,000	[1]
Total Costs	373,400,000		978,500,000		966,400,000
Charged to expense	'		'		'
Dry hole expense	32,100,000		8,000,000		50,600,000
Geophysical and other costs	700,000		2,500,000		10,200,000
Total charged to expense	32,800,000		10,500,000		60,800,000
Property additions	340,600,000		968,000,000		905,600,000
Malaysia [Member]	'		'		'
Property acquisition costs	'		'		'
Unproved	0		0		0
Proved	0		0		0
Total acquisition costs	0		0		0
Exploration costs	14,900,000	[1]	68,800,000	[1]	700,000	[1]
Development costs	1,787,700,000	[1],[3]	1,433,700,000	[1]	705,500,000	[1]
Total Costs	1,802,600,000		1,502,500,000		706,200,000
Charged to expense	'		'		'
Dry hole expense	20,700,000		26,100,000		100,000
Geophysical and other costs	4,600,000		1,100,000		11,000,000
Total charged to expense	25,300,000		27,200,000		11,100,000
Property additions	1,777,300,000		1,475,300,000		695,100,000
United Kingdom [Member]	'		'		'
Property acquisition costs	'		'		'
Unproved	0	[4]	0	[4]	0	[4]
Proved	0	[4]	0	[4]	0	[4]
Total acquisition costs	0	[4]	0	[4]	0	[4]
Exploration costs	0	[1],[4]	-1,000,000	[1],[4]	500,000	[1],[4]
Development costs	8,100,000	[1],[4]	46,600,000	[1],[4]	30,500,000	[1],[4]
Total Costs	8,100,000	[4]	45,600,000	[4]	31,000,000	[4]
Charged to expense	'		'		'
Dry hole expense	0	[4]	-800,000	[4]	0	[4]
Geophysical and other costs	0	[4]	-200,000	[4]	500,000	[4]
Total charged to expense	0	[4]	-1,000,000	[4]	500,000	[4]
Property additions	8,100,000	[4]	46,600,000	[4]	30,500,000	[4]
Republic of the Congo [Member]	'		'		'
Property acquisition costs	'		'		'
Unproved	0		0		0
Proved	0		0		23,500,000
Total acquisition costs	0		0		23,500,000
Exploration costs	100,000	[1]	51,100,000	[1]	500,000	[1]
Development costs	0	[1]	22,600,000	[1]	78,700,000	[1]
Total Costs	100,000		73,700,000		102,700,000
Charged to expense	'		'		'
Dry hole expense	5,600,000		76,200,000		18,100,000
Geophysical and other costs	200,000		600,000		2,900,000
Total charged to expense	5,800,000		76,800,000		21,000,000
Property additions	-5,700,000		-3,100,000		81,700,000
Other Regions [Member]	'		'		'
Property acquisition costs	'		'		'
Unproved	3,200,000		10,200,000		27,000,000
Proved	0		0		0
Total acquisition costs	3,200,000		10,200,000		27,000,000
Exploration costs	344,500,000	[1]	97,600,000	[1]	231,600,000	[1]
Development costs	19,000,000	[1]	1,600,000	[1]	3,800,000	[1]
Total Costs	366,700,000		109,400,000		262,400,000
Charged to expense	'		'		'
Dry hole expense	158,400,000		39,300,000		181,600,000
Geophysical and other costs	137,800,000		45,400,000		60,200,000
Total charged to expense	296,200,000		84,700,000		241,800,000
Property additions	$70,500,000		$24,700,000		$20,600,000
[1]	Includes non-cash asset retirement costs as follows: 2013 Exploration costs $ 0.0 0.2 0.0 0.0 0.0 0.0 0.2 Development costs 70.1 5.9 95.9 0.0 0.0 0.0 171.9 $ 70.1 6.1 95.9 0.0 0.0 0.0 172.1 2012 Exploration costs $ (1.7 ) 0.1 0.0 0.0 0.0 0.0 (1.6 ) Development costs 37.9 80.7 48.6 (11.5 ) 17.6 0.0 173.3 $ 36.2 80.8 48.6 (11.5 ) 17.6 0.0 171.7 2011 Exploration costs $ 2.0 0.3 0.0 0.0 0.0 0.0 2.3 Development costs 15.8 20.1 0.3 10.8 2.1 0.0 49.1 $ 17.8 20.4 0.3 10.8 2.1 0.0 51.4
[2]	Reclassified to conform to current presentation.
[3]	Includes property cost associated with non-cash capital lease of $358.0 million at the Kakap field.
[4]	The Company has accounted for U.K. operations as discontinued operations due to the sale of these operations in the first half of 2013.

Cost_Incurred_in_Oil_and_Gas_P1

Cost Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Parenthetical) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Exploration costs	$493.70	[1]	$448	[1]	$562.50	[1]
Development costs	3,939.60	[1]	3,521.70	[1]	1,954.30	[1]
Total Costs	4,482.10		4,413.70		2,819.60
United States [Member]	'		'		'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Exploration costs	112.4	[1]	174.5	[1]	253.2	[1]
Development costs	1,773.20	[1]	1,352.70	[1]	263.9	[1]
Total Costs	1,931.20		1,704		750.9
Canada [Member]	'		'		'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Exploration costs	21.8	[1]	57	[1]	76	[1]
Development costs	351.6	[1]	664.5	[1]	871.9	[1]
Total Costs	373.4		978.5		966.4
Malaysia [Member]	'		'		'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Exploration costs	14.9	[1]	68.8	[1]	0.7	[1]
Development costs	1,787.70	[1],[2]	1,433.70	[1]	705.5	[1]
Total Costs	1,802.60		1,502.50		706.2
Non-cash capital lease obligation	358		'		'
United Kingdom [Member]	'		'		'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Exploration costs	0	[1],[3]	-1	[1],[3]	0.5	[1],[3]
Development costs	8.1	[1],[3]	46.6	[1],[3]	30.5	[1],[3]
Total Costs	8.1	[3]	45.6	[3]	31	[3]
Republic of the Congo [Member]	'		'		'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Exploration costs	0.1	[1]	51.1	[1]	0.5	[1]
Development costs	0	[1]	22.6	[1]	78.7	[1]
Total Costs	0.1		73.7		102.7
Other Regions [Member]	'		'		'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Exploration costs	344.5	[1]	97.6	[1]	231.6	[1]
Development costs	19	[1]	1.6	[1]	3.8	[1]
Total Costs	366.7		109.4		262.4
Asset Retirement Obligation Costs [Member]	'		'		'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Exploration costs	0.2		-1.6		2.3
Development costs	171.9		173.3		49.1
Total Costs	172.1		171.7		51.4
Asset Retirement Obligation Costs [Member] | United States [Member]	'		'		'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Exploration costs	0		-1.7		2
Development costs	70.1		37.9		15.8
Total Costs	70.1		36.2		17.8
Asset Retirement Obligation Costs [Member] | Canada [Member]	'		'		'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Exploration costs	0.2		0.1		0.3
Development costs	5.9		80.7		20.1
Total Costs	6.1		80.8		20.4
Asset Retirement Obligation Costs [Member] | Malaysia [Member]	'		'		'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Exploration costs	0		0		0
Development costs	95.9		48.6		0.3
Total Costs	95.9		48.6		0.3
Asset Retirement Obligation Costs [Member] | United Kingdom [Member]	'		'		'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Exploration costs	0		0		0
Development costs	0		-11.5		10.8
Total Costs	0		-11.5		10.8
Asset Retirement Obligation Costs [Member] | Republic of the Congo [Member]	'		'		'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Exploration costs	0		0		0
Development costs	0		17.6		2.1
Total Costs	0		17.6		2.1
Asset Retirement Obligation Costs [Member] | Other Regions [Member]	'		'		'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'		'		'
Exploration costs	0		0		0
Development costs	0		0		0
Total Costs	$0		$0		$0
[1]	Includes non-cash asset retirement costs as follows: 2013 Exploration costs $ 0.0 0.2 0.0 0.0 0.0 0.0 0.2 Development costs 70.1 5.9 95.9 0.0 0.0 0.0 171.9 $ 70.1 6.1 95.9 0.0 0.0 0.0 172.1 2012 Exploration costs $ (1.7 ) 0.1 0.0 0.0 0.0 0.0 (1.6 ) Development costs 37.9 80.7 48.6 (11.5 ) 17.6 0.0 173.3 $ 36.2 80.8 48.6 (11.5 ) 17.6 0.0 171.7 2011 Exploration costs $ 2.0 0.3 0.0 0.0 0.0 0.0 2.3 Development costs 15.8 20.1 0.3 10.8 2.1 0.0 49.1 $ 17.8 20.4 0.3 10.8 2.1 0.0 51.4
[2]	Includes property cost 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 half of 2013.

Results_of_Operations_for_Oil_1

Results of Operations for Oil and Gas Producing Activities (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Revenues	'		'		'
Total oil and gas revenues	$5,306,300,000	[1]	$4,599,600,000	[1]	$4,205,400,000	[1]
Other operating revenues	6,300,000	[1]	8,500,000	[1]	39,900,000	[1]
Total revenues	5,312,600,000	[1]	4,608,100,000	[1]	4,245,300,000	[1]
Costs and expenses	'		'		'
Production expenses	1,340,200,000	[1]	1,114,800,000	[1]	1,010,300,000	[1]
Exploration costs charged to expense	435,300,000	[1]	251,100,000	[1]	371,200,000	[1]
Undeveloped lease amortization	66,900,000	[1]	129,800,000	[1]	118,200,000	[1]
Depreciation, depletion and amortization	1,543,600,000	[1]	1,244,400,000	[1]	956,000,000	[1]
Accretion of asset retirement obligations	49,000,000	[1]	38,400,000	[1]	33,800,000	[1]
Impairment of properties	21,587,000	[1]	200,000,000	[1],[2]	368,600,000	[1],[2]
Terra Nova working interest redetermination	0		0	[2]	-5,351,000	[1],[2]
Selling and general expenses	170,900,000	[1]	119,600,000	[1]	97,600,000	[1]
Total costs and expenses	3,627,500,000	[1]	3,098,100,000	[1]	2,950,300,000	[1]
Results of Operations, Income before Income Taxes	1,685,100,000	[1]	1,510,000,000	[1]	1,295,000,000	[1]
Income tax expense	656,300,000	[1]	605,000,000	[1]	680,800,000	[1]
Results of operations	1,028,800,000	[1]	905,000,000	[1]	614,200,000	[1]
Crude Oil and Natural Gas Liquids [Member]	'		'		'
Revenues	'		'		'
Sales to unaffiliated enterprises	4,631,500,000	[1]	3,854,500,000	[1]	3,392,800,000	[1]
Transfers to consolidated operations	'		'		142,800,000	[1]
Natural Gas [Member]	'		'		'
Revenues	'		'		'
Sales to unaffiliated enterprises	674,800,000	[1]	745,100,000	[1]	812,600,000	[1]
United States [Member] | Oil Reserves [Member]	'		'		'
Revenues	'		'		'
Total oil and gas revenues	1,797,400,000	[1]	1,030,300,000	[1]	719,900,000	[1]
Other operating revenues	6,400,000	[1]	7,700,000	[1]	17,800,000	[1]
Total revenues	1,803,800,000	[1]	1,038,000,000	[1]	737,700,000	[1]
Costs and expenses	'		'		'
Production expenses	351,100,000	[1]	252,400,000	[1]	164,800,000	[1]
Exploration costs charged to expense	75,200,000	[1]	51,900,000	[1]	36,500,000	[1]
Undeveloped lease amortization	30,300,000	[1]	71,600,000	[1]	62,200,000	[1]
Depreciation, depletion and amortization	576,300,000	[1]	330,200,000	[1]	183,000,000	[1]
Accretion of asset retirement obligations	13,500,000	[1]	11,400,000	[1]	9,900,000	[1]
Impairment of properties	0	[1]	0	[1]	0	[1]
Terra Nova working interest redetermination	'		'		0	[1]
Selling and general expenses	80,400,000	[1]	52,700,000	[1]	42,100,000	[1]
Total costs and expenses	1,126,800,000	[1]	770,200,000	[1]	498,500,000	[1]
Results of Operations, Income before Income Taxes	677,000,000	[1]	267,800,000	[1]	239,200,000	[1]
Income tax expense	241,600,000	[1]	99,800,000	[1]	86,500,000	[1]
Results of operations	435,400,000	[1]	168,000,000	[1]	152,700,000	[1]
United States [Member] | Crude Oil and Natural Gas Liquids [Member] | Oil Reserves [Member]	'		'		'
Revenues	'		'		'
Sales to unaffiliated enterprises	1,724,700,000	[1]	976,100,000	[1]	648,800,000	[1]
Transfers to consolidated operations	'		'		0	[1]
United States [Member] | Natural Gas [Member] | Oil Reserves [Member]	'		'		'
Revenues	'		'		'
Sales to unaffiliated enterprises	72,700,000	[1]	54,200,000	[1]	71,100,000	[1]
Canada [Member] | Conventional [Member]	'		'		'
Revenues	'		'		'
Total oil and gas revenues	705,300,000	[1]	621,500,000	[1]	785,800,000	[1]
Other operating revenues	-1,900,000	[1]	-900,000	[1]	-3,800,000	[1]
Total revenues	703,400,000	[1]	620,600,000	[1]	782,000,000	[1]
Costs and expenses	'		'		'
Production expenses	185,500,000	[1]	167,200,000	[1]	151,200,000	[1]
Exploration costs charged to expense	32,800,000	[1]	10,500,000	[1]	60,800,000	[1]
Undeveloped lease amortization	21,000,000	[1]	29,300,000	[1]	28,800,000	[1]
Depreciation, depletion and amortization	319,200,000	[1]	290,500,000	[1]	273,900,000	[1]
Accretion of asset retirement obligations	5,900,000	[1]	5,100,000	[1]	4,900,000	[1]
Impairment of properties	21,587,000	[1]	0	[1]	0	[1]
Terra Nova working interest redetermination	'		'		-5,400,000	[1]
Selling and general expenses	25,300,000	[1]	19,700,000	[1]	14,200,000	[1]
Total costs and expenses	611,300,000	[1]	522,300,000	[1]	528,400,000	[1]
Results of Operations, Income before Income Taxes	92,100,000	[1]	98,300,000	[1]	253,600,000	[1]
Income tax expense	19,900,000	[1]	25,100,000	[1]	79,700,000	[1]
Results of operations	72,200,000	[1]	73,200,000	[1]	173,900,000	[1]
Canada [Member] | Synthetic Oil [Member]	'		'		'
Revenues	'		'		'
Total oil and gas revenues	441,000,000	[1]	463,100,000	[1]	506,600,000	[1]
Other operating revenues	300,000	[1]	600,000	[1]	0	[1]
Total revenues	441,300,000	[1]	463,700,000	[1]	506,600,000	[1]
Costs and expenses	'		'		'
Production expenses	228,200,000	[1]	224,100,000	[1]	236,100,000	[1]
Exploration costs charged to expense	0	[1]	0	[1]	0	[1]
Undeveloped lease amortization	0	[1]	0	[1]	0	[1]
Depreciation, depletion and amortization	55,400,000	[1]	55,300,000	[1]	52,100,000	[1]
Accretion of asset retirement obligations	10,300,000	[1]	8,500,000	[1]	7,600,000	[1]
Impairment of properties	0	[1]	0	[1]	0	[1]
Terra Nova working interest redetermination	'		'		0	[1]
Selling and general expenses	900,000	[1]	900,000	[1]	900,000	[1]
Total costs and expenses	294,800,000	[1]	288,800,000	[1]	296,700,000	[1]
Results of Operations, Income before Income Taxes	146,500,000	[1]	174,900,000	[1]	209,900,000	[1]
Income tax expense	37,900,000	[1]	40,000,000	[1]	55,800,000	[1]
Results of operations	108,600,000	[1]	134,900,000	[1]	154,100,000	[1]
Canada [Member] | Crude Oil and Natural Gas Liquids [Member] | Conventional [Member]	'		'		'
Revenues	'		'		'
Sales to unaffiliated enterprises	507,200,000	[1]	411,700,000	[1]	505,600,000	[1],[2]
Transfers to consolidated operations	'		'		46,400,000	[1]
Canada [Member] | Crude Oil and Natural Gas Liquids [Member] | Synthetic Oil [Member]	'		'		'
Revenues	'		'		'
Sales to unaffiliated enterprises	441,000,000	[1]	463,100,000	[1]	506,600,000	[1],[2]
Transfers to consolidated operations	'		'		96,400,000	[1]
Canada [Member] | Natural Gas [Member] | Conventional [Member]	'		'		'
Revenues	'		'		'
Sales to unaffiliated enterprises	198,100,000	[1]	209,800,000	[1]	280,200,000	[1]
Canada [Member] | Natural Gas [Member] | Synthetic Oil [Member]	'		'		'
Revenues	'		'		'
Sales to unaffiliated enterprises	0	[1]	0	[1]	0	[1]
Malaysia [Member] | Oil Reserves [Member]	'		'		'
Revenues	'		'		'
Total oil and gas revenues	2,279,000,000	[1]	2,427,100,000	[1]	2,044,300,000	[1]
Other operating revenues	1,500,000	[1]	1,000,000	[1]	1,300,000	[1]
Total revenues	2,280,500,000	[1]	2,428,100,000	[1]	2,045,600,000	[1]
Costs and expenses	'		'		'
Production expenses	384,400,000	[1]	422,700,000	[1]	420,600,000	[1]
Exploration costs charged to expense	25,300,000	[1]	27,200,000	[1]	11,100,000	[1]
Undeveloped lease amortization	0	[1]	0	[1]	0	[1]
Depreciation, depletion and amortization	588,200,000	[1]	532,100,000	[1]	357,300,000	[1]
Accretion of asset retirement obligations	15,000,000	[1]	12,500,000	[1]	10,600,000	[1]
Impairment of properties	0	[1]	0	[1]	0	[1]
Terra Nova working interest redetermination	'		'		0	[1]
Selling and general expenses	3,500,000	[1]	-5,300,000	[1]	-1,600,000	[1]
Total costs and expenses	1,016,400,000	[1]	989,200,000	[1]	798,000,000	[1]
Results of Operations, Income before Income Taxes	1,264,100,000	[1]	1,438,900,000	[1]	1,247,600,000	[1]
Income tax expense	477,700,000	[1]	544,700,000	[1]	434,900,000	[1]
Results of operations	786,400,000	[1]	894,200,000	[1]	812,700,000	[1]
Malaysia [Member] | Crude Oil and Natural Gas Liquids [Member] | Oil Reserves [Member]	'		'		'
Revenues	'		'		'
Sales to unaffiliated enterprises	1,875,000,000	[1]	1,946,000,000	[1]	1,583,000,000	[1]
Transfers to consolidated operations	'		'		0	[1]
Malaysia [Member] | Natural Gas [Member] | Oil Reserves [Member]	'		'		'
Revenues	'		'		'
Sales to unaffiliated enterprises	404,000,000	[1]	481,100,000	[1]	461,300,000	[1]
Republic of the Congo [Member] | Oil Reserves [Member]	'		'		'
Revenues	'		'		'
Total oil and gas revenues	83,600,000	[1]	57,600,000	[1]	148,800,000	[1]
Other operating revenues	-100,000	[1]	0	[1]	0	[1]
Total revenues	83,500,000	[1]	57,600,000	[1]	148,800,000	[1]
Costs and expenses	'		'		'
Production expenses	191,000,000	[1]	48,400,000	[1]	37,600,000	[1]
Exploration costs charged to expense	5,800,000	[1]	76,800,000	[1]	21,000,000	[1]
Undeveloped lease amortization	0	[1]	0	[1]	0	[1]
Depreciation, depletion and amortization	200,000	[1]	33,900,000	[1]	87,800,000	[1]
Accretion of asset retirement obligations	4,300,000	[1]	900,000	[1]	500,000	[1]
Impairment of properties	0	[1]	200,000,000	[1]	368,600,000	[1]
Terra Nova working interest redetermination	'		'		0	[1]
Selling and general expenses	1,100,000	[1]	3,200,000	[1]	2,200,000	[1]
Total costs and expenses	202,400,000	[1]	363,200,000	[1]	517,700,000	[1]
Results of Operations, Income before Income Taxes	-118,900,000	[1]	-305,600,000	[1]	-368,900,000	[1]
Income tax expense	-109,900,000	[1]	-64,500,000	[1]	16,400,000	[1]
Results of operations	-9,000,000	[1]	-241,100,000	[1]	-385,300,000	[1]
Republic of the Congo [Member] | Crude Oil and Natural Gas Liquids [Member] | Oil Reserves [Member]	'		'		'
Revenues	'		'		'
Sales to unaffiliated enterprises	83,600,000	[1]	57,600,000	[1]	148,800,000	[1]
Transfers to consolidated operations	'		'		0	[1]
Republic of the Congo [Member] | Natural Gas [Member] | Oil Reserves [Member]	'		'		'
Revenues	'		'		'
Sales to unaffiliated enterprises	0	[1]	0	[1]	0	[1]
Other Regions [Member] | Oil Reserves [Member]	'		'		'
Revenues	'		'		'
Total oil and gas revenues	0	[1]	0	[1]	0	[1]
Other operating revenues	100,000	[1]	100,000	[1]	24,600,000	[1]
Total revenues	100,000	[1]	100,000	[1]	24,600,000	[1]
Costs and expenses	'		'		'
Production expenses	0	[1]	0	[1]	0	[1]
Exploration costs charged to expense	296,200,000	[1]	84,700,000	[1]	241,800,000	[1]
Undeveloped lease amortization	15,600,000	[1]	28,900,000	[1]	27,200,000	[1]
Depreciation, depletion and amortization	4,300,000	[1]	2,400,000	[1]	1,900,000	[1]
Accretion of asset retirement obligations	0	[1]	0	[1]	300,000	[1]
Impairment of properties	0	[1]	0	[1]	0	[1]
Terra Nova working interest redetermination	'		'		0	[1]
Selling and general expenses	59,700,000	[1]	48,400,000	[1]	39,800,000	[1]
Total costs and expenses	375,800,000	[1]	164,400,000	[1]	311,000,000	[1]
Results of Operations, Income before Income Taxes	-375,700,000	[1]	-164,300,000	[1]	-286,400,000	[1]
Income tax expense	-10,900,000	[1]	-40,100,000	[1]	7,500,000	[1]
Results of operations	-364,800,000	[1]	-124,200,000	[1]	-293,900,000	[1]
Other Regions [Member] | Crude Oil and Natural Gas Liquids [Member] | Oil Reserves [Member]	'		'		'
Revenues	'		'		'
Sales to unaffiliated enterprises	0	[1]	0	[1]	0	[1]
Transfers to consolidated operations	'		'		0	[1]
Other Regions [Member] | Natural Gas [Member] | Oil Reserves [Member]	'		'		'
Revenues	'		'		'
Sales to unaffiliated enterprises	$0	[1]	$0	[1]	$0	[1]
[1]	Results exclude corporate overhead, interest and discontinued operations.
[2]	Reclassified to conform to current presentation.

Standardized_Measure_of_Discou1

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future cash inflows	$50,150.50	$43,809.20	$38,736.50
Future development costs	-7,161.50	-6,786.90	-5,129
Future production costs	-16,808.10	-14,684.70	-12,652.20
Future income taxes	-6,696.20	-6,791.10	-6,652.40
Future net cash flows	19,484.70	15,546.50	14,302.90
10% annual discount for estimated timing of cash flows	-8,640	-7,433.70	-6,379.70
Standardized measure of discounted future net cash flows	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	20,638.60	15,547.50	6,105.40
Future development costs	-3,833.90	-3,731.60	-1,283.50
Future production costs	-5,244.70	-3,466.60	-1,417.90
Future income taxes	-3,368.30	-2,527.60	-807.2
Future net cash flows	8,191.70	5,821.70	2,596.80
10% annual discount for estimated timing of cash flows	-4,020.20	-2,862.10	-912
Standardized measure of discounted future net cash flows	4,171.50	2,959.60	1,684.80
Canada [Member]	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future cash inflows	16,112.90	15,511.60	18,835.50
Future development costs	-1,882.30	-1,815.20	-1,929.50
Future production costs	-7,073	-7,336.40	-7,199.70
Future income taxes	-1,472.80	-1,714.90	-2,806.80
Future net cash flows	5,684.80	4,645.10	6,899.50
10% annual discount for estimated timing of cash flows	-2,999.10	-2,876.50	-3,658.70
Standardized measure of discounted future net cash flows	2,685.70	1,768.60	3,240.80
Malaysia [Member]	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future cash inflows	13,399	10,354.90	11,037.50
Future development costs	-1,445.30	-966.9	-1,559.80
Future production costs	-4,490.40	-3,143.40	-3,087.80
Future income taxes	-1,855.10	-1,675.90	-2,129.70
Future net cash flows	5,608.20	4,568.70	4,260.20
10% annual discount for estimated timing of cash flows	-1,620.70	-1,322.90	-1,507.40
Standardized measure of discounted future net cash flows	3,987.50	3,245.80	2,752.80
United Kingdom [Member]	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future cash inflows	0	2,395.20	2,509.50
Future development costs	0	-273.2	-356.2
Future production costs	0	-738.3	-763
Future income taxes	0	-872.7	-869
Future net cash flows	0	511	521.3
10% annual discount for estimated timing of cash flows	0	-372.2	-304.4
Standardized measure of discounted future net cash flows	0	138.8	216.9
Republic of the Congo [Member]	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future cash inflows	0	0	248.6
Future development costs	0	0	0
Future production costs	0	0	-183.8
Future income taxes	0	0	-39.7
Future net cash flows	0	0	25.1
10% annual discount for estimated timing of cash flows	0	0	2.8
Standardized measure of discounted future net cash flows	$0	$0	$27.90

Principal_Sources_of_Changes_i

Principal Sources of Changes in Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Net changes in prices and production costs	$267.80	($2,461.10)	$3,743.40
Net changes in development costs	-3,456.80	-3,860.10	-4,113.90
Sales and transfers of oil and gas produced, net of production costs	-3,972.40	-3,493.30	-3,273.50
Net change due to extensions and discoveries	4,608.90	4,466.30	3,300.90
Net change due to purchases and sales of proved reserves	-135.6	347.4	0
Development costs incurred	3,326.80	3,299	1,881.50
Accretion of discount	1,109.30	1,153.50	827.7
Revisions of previous quantity estimates	1,646	728.1	892.5
Net change in income taxes	-662.1	9.8	-1,029.40
Net increase	2,731.90	189.6	2,229.20
Standardized measure	10,844.70	8,112.80	7,923.20
Beginning of Period [Member]	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Standardized measure	8,112.80	7,923.20	5,694
End of Period [Member]	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Standardized measure	$10,844.70	$8,112.80	$7,923.20

Capitalized_Costs_Relating_to_1

Capitalized Costs Relating to Oil and Gas Producing Activities (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'
Unproved oil and gas properties	$1,598	$2,217.10
Proved oil and gas properties	20,214.70	16,707.20
Gross capitalized costs	21,812.70	18,924.30
Accumulated depreciation, depletion and amortization	'	'
Unproved oil and gas properties	-518.3	-504.2
Proved oil and gas properties	-7,909.70	-6,946.10
Net capitalized costs	13,384.70	11,474
Oil Reserves [Member]	'	'
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'
Unproved oil and gas properties	1,598	2,217.10
Proved oil and gas properties	18,721.20	15,271.60
Gross capitalized costs	20,319.20	17,488.70
Accumulated depreciation, depletion and amortization	'	'
Unproved oil and gas properties	-518.3	-504.2
Proved oil and gas properties	-7,492.10	-6,556.50
Net capitalized costs	12,308.80	10,428
United States [Member] | Oil Reserves [Member]	'	'
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'
Unproved oil and gas properties	723.6	750
Proved oil and gas properties	5,816.90	3,972.10
Gross capitalized costs	6,540.50	4,722.10
Accumulated depreciation, depletion and amortization	'	'
Unproved oil and gas properties	-178.1	-183.8
Proved oil and gas properties	-2,171.10	-1,590.60
Net capitalized costs	4,191.30	2,947.70
Canada [Member] | Oil Reserves [Member]	'	'
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'
Unproved oil and gas properties	475.9	510.9
Proved oil and gas properties	4,529.90	4,697.80
Gross capitalized costs	5,005.80	5,208.70
Accumulated depreciation, depletion and amortization	'	'
Unproved oil and gas properties	-248.5	-244.3
Proved oil and gas properties	-2,006.80	-1,828.80
Net capitalized costs	2,750.50	3,135.60
Canada [Member] | Synthetic Oil [Member]	'	'
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'
Unproved oil and gas properties	0	0
Proved oil and gas properties	1,493.50	1,435.60
Gross capitalized costs	1,493.50	1,435.60
Accumulated depreciation, depletion and amortization	'	'
Unproved oil and gas properties	0	0
Proved oil and gas properties	-417.6	-389.6
Net capitalized costs	1,075.90	1,046
Malaysia [Member] | Oil Reserves [Member]	'	'
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'
Unproved oil and gas properties	233.5	837
Proved oil and gas properties	7,636.60	5,260.70
Gross capitalized costs	7,870.10	6,097.70
Accumulated depreciation, depletion and amortization	'	'
Unproved oil and gas properties	0	0
Proved oil and gas properties	-2,576.40	-2,001.80
Net capitalized costs	5,293.70	4,095.90
United Kingdom [Member] | Oil Reserves [Member]	'	'
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'
Unproved oil and gas properties	0	0
Proved oil and gas properties	0	603.2
Gross capitalized costs	0	603.2
Accumulated depreciation, depletion and amortization	'	'
Unproved oil and gas properties	0	0
Proved oil and gas properties	0	-397.5
Net capitalized costs	0	205.7
Republic of the Congo [Member] | Oil Reserves [Member]	'	'
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'
Unproved oil and gas properties	6.1	11.8
Proved oil and gas properties	737.8	737.8
Gross capitalized costs	743.9	749.6
Accumulated depreciation, depletion and amortization	'	'
Unproved oil and gas properties	-6.1	-6.1
Proved oil and gas properties	-737.8	-737.8
Net capitalized costs	0	5.7
Other Regions [Member] | Oil Reserves [Member]	'	'
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'
Unproved oil and gas properties	158.9	107.4
Proved oil and gas properties	0	0
Gross capitalized costs	158.9	107.4
Accumulated depreciation, depletion and amortization	'	'
Unproved oil and gas properties	-85.6	-70
Proved oil and gas properties	0	0
Net capitalized costs	$73.30	$37.40

Recovered_Sheet2

Supplemental Quarterly Information (Detail) (USD $)	3 Months Ended																12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]	'		'		'		'		'		'		'		'		'		'		'
Sales and other operating revenues	$1,331,700		$1,366,500		$1,315,600		$1,298,900		$1,297,100		$1,083,700		$1,078,000		$1,149,800		$5,312,686		$4,608,563	[1]	$4,222,520	[1]
Income from continuing operations before income taxes	194,800		463,700		454,200		360,000		200,500		338,900		357,000		471,600		1,472,687		1,368,010	[1]	1,167,875	[1]
Income from continuing operations	180,500		265,000		259,900		182,700		123,900		186,100		210,900		285,600		888,137		806,494	[1]	539,198	[1]
Net income	$75,400		$284,800		$402,700		$360,600		$158,700		$226,700		$295,400		$290,100		$1,123,473		$970,876	[1]	$872,702	[1]
Income from continuing operations per Common share	'		'		'		'		'		'		'		'		'		'		'
Basic	$0.98		$1.42		$1.38		$0.96		$0.64		$0.96		$1.09		$1.48		$4.73		$4.16	[1]	$2.79	[1]
Diluted	$0.96		$1.41		$1.37		$0.95		$0.64		$0.95		$1.08		$1.47		$4.69		$4.14	[1]	$2.77	[1]
Net income per Common share	'		'		'		'		'		'		'		'		'		'		'
Basic	$0.41		$1.52		$2.13		$1.89		$0.82		$1.17		$1.52		$1.50		$5.98		$5.01	[1]	$4.51	[1]
Diluted	$0.40		$1.51		$2.12		$1.88		$0.82		$1.16		$1.52		$1.49		$5.94		$4.99	[1]	$4.49	[1]
Cash dividend per Common share	$0.31		$0.31		$0.31		$0.31		$2.81	[2]	$0.31		$0.28		$0.28		$1.25		$3.67	[2]	$1.10
Market price of Common Stock	'		'		'		'		'		'		'		'		'		'		'
High	$65.55	[3]	$71.84	[3]	$66.09	[3]	$63.81	[3]	$63.74	[3]	$56.24	[3]	$57.12	[3]	$64.76	[3]	$71.84	[3]	$64.76	[3]	'
Low	$59.93	[3]	$59.80	[3]	$59.98	[3]	$59.33	[3]	$54.97	[3]	$48.80	[3]	$43.65	[3]	$55.82	[3]	$59.33	[3]	$43.65	[3]	'
[1]	Reclassified to conform to current presentation.
[2]	Includes special dividend of $2.50 per Common share paid on December 3, 2012.
[3]	Prices are as quoted on the New York Stock Exchange.

Supplemental_Quarterly_Informa1

Supplemental Quarterly Information (Parenthetical) (Detail) (USD $)	1 Months Ended
	Dec. 31, 2012
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]	'
Special dividend per Common share paid	$2.50

Recovered_Sheet3

Valuation Accounts and Reserves (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Allowance for Doubtful Accounts [Member]	'		'		'
Valuation and Qualifying Accounts Disclosure [Line Items]	'		'		'
Beginning balance	$6.70		$7.90		$8
Charged (Credited) to Expense	0.4		0.3		0.2
Deductions	-0.4		-1.5		-0.3
Other	-5.1	[1]	0	[1]	0	[1]
Ending Balance	1.6		6.7		7.9
Deferred tax asset valuation allowance [Member]	'		'		'
Valuation and Qualifying Accounts Disclosure [Line Items]	'		'		'
Beginning balance	524		445.8		305.3
Charged (Credited) to Expense	115.4		78.2		140.5
Deductions	0		0		0
Other	-5.7	[1]	0	[1]	0	[1]
Ending Balance	$633.70		$524		$445.80
[1]	Amounts in 2013 primarily arose due to separation of Murphy USA Inc. and presentation of U.K. downstream operations as assets held for sale.