Murphy Oil (MUR) 10-K 26 Feb 10 2009 FY Annual report Financial data

Statement Of Income Alternative

Statement Of Income Alternative (USD $)
In Thousands, except Share data	12 Months Ended Dec. 31, 2009	12 Months Ended Dec. 31, 2008	12 Months Ended Dec. 31, 2007
Revenues
Sales and other operating revenues	$18,918,181	$27,360,625	$18,297,637
Gain (loss) on sale of assets	3,709	133,717	(365)
Interest and other income (loss)	90,502	(62,011)	15,692
Total revenues	19,012,392	27,432,331	18,312,964
Costs and Expenses
Crude oil and product purchases	14,547,589	21,649,742	14,882,618
Operating expenses	1,621,854	1,657,427	1,277,858
Exploration expenses, including undeveloped lease amortization	265,172	344,406	202,808
Selling and general expenses	242,266	228,490	228,316
Depreciation, depletion and amortization	919,055	667,265	450,624
Impairment of properties	5,240	0	40,708
Accretion of asset retirement obligations	26,154	24,484	16,244
Redetermination of Terra Nova working interest	83,498	0	0
Interest expense	53,005	73,611	74,665
Interest capitalized	(28,614)	(31,459)	(49,881)
Total costs and expenses	17,735,219	24,613,966	17,123,960
Income from continuing operations before income taxes	1,277,173	2,818,365	1,189,004
Income tax expense	536,656	1,073,616	449,924
Income from continuing operations	740,517	1,744,749	739,080
Income (loss) from discontinued operations, net of income taxes	97,104	(4,763)	27,449
Net Income	$837,621	$1,739,986	$766,529
Income per Common Share - Basic
Income from continuing operations	3.88	9.2	3.93
Income (loss) from discontinued operations	0.51	-0.02	0.15
Net Income - Basic	4.39	9.18	4.08
Income per Common Share - Diluted
Income from continuing operations	3.85	9.08	3.87
Income (loss) from discontinued operations	0.5	-0.02	0.14
Net Income - Diluted	4.35	9.06	4.01
Average Common shares outstanding - basic	190,767,077	189,608,846	188,027,557
Average Common shares outstanding - diluted	192,468,450	192,133,672	191,140,737

Statement Of Financial Position

Statement Of Financial Position Classified (USD $)
In Thousands	Dec. 31, 2009	Dec. 31, 2008
Current assets
Cash and cash equivalents	$301,144	$666,110
Canadian government securities with maturities greater than 90 days at the date of acquisition	779,025	420,340
Accounts receivable, less allowance for doubtful accounts of $7,761 in 2009 and $7,303 in 2008	1,463,297	1,033,996
Inventories, at lower of cost or market
Crude oil and blend stocks	128,936	98,217
Finished products	384,250	315,340
Materials and supplies	220,796	190,616
Prepaid expenses	83,218	92,544
Deferred income taxes	15,029	29,801
Total current assets	3,375,695	2,846,964
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $4,714,826 in 2009 and $3,824,393 in 2008	9,065,088	7,727,718
Goodwill	40,652	37,370
Deferred charges and other assets	274,924	537,046
Total assets	12,756,359	11,149,098
Current liabilities
Current maturities of long-term debt	38	2,572
Accounts payable	1,539,523	1,174,623
Income taxes payable	387,164	451,372
Other taxes payable	165,934	152,038
Other accrued liabilities	88,949	107,541
Total current liabilities	2,181,608	1,888,146
Long-term debt	1,353,183	1,026,222
Deferred income taxes	1,018,767	878,131
Asset retirement obligations	476,938	435,589
Deferred credits and other liabilities	379,837	642,065
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, 2009 and 2008, issued 191,797,600 shares at December 31, 2009 and 191,248,941 shares at December 31, 2008	191,798	191,249
Capital in excess of par value	680,509	631,859
Retained earnings	6,204,316	5,557,483
Accumulated other comprehensive income (loss)	287,187	(87,697)
Treasury stock	(17,784)	(13,949)
Total stockholders' equity	7,346,026	6,278,945
Total liabilities and stockholders' equity	$12,756,359	$11,149,098

1_Statement Of Financial Positi

Statement Of Financial Position Classified (Parenthetical) (USD $)
In Thousands, except Share data	Dec. 31, 2009	Dec. 31, 2008
Accounts receivable, allowance for doubtful accounts	$7,761	$7,303
Property, plant and equipment, accumulated depreciation, depletion and amortization	$4,714,826	$3,824,393
Cumulative Preferred Stock, par	$100	$100
Cumulative Preferred Stock, authorized	400,000	400,000
Cumulative Preferred Stock, issued	0	0
Common Stock, par	$1	$1
Common Stock, authorized	450,000,000	450,000,000
Common Stock, issued	191,797,600	191,248,941

Statement Of Cash Flows Indirec

Statement Of Cash Flows Indirect (USD $)
In Thousands	12 Months Ended Dec. 31, 2009		12 Months Ended Dec. 31, 2008		12 Months Ended Dec. 31, 2007
Operating Activities
Net income	$837,621		$1,739,986		$766,529
(Income) loss from discontinued operations	(97,104)		4,763		(27,449)
Income from continuing operations	740,517		1,744,749		739,080
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Depreciation, depletion and amortization	919,055		667,265		450,624
Impairment of long-lived assets	5,240		0		40,708
Amortization of deferred major repair costs	26,103		27,294		22,107
Expenditures for asset retirements	(48,694)		(9,240)		(13,039)
Dry hole costs	125,244		129,459		66,797
Amortization of undeveloped leases	83,213		112,052		33,215
Accretion of asset retirement obligations	26,154		24,484		16,244
Deferred and noncurrent income tax charges	97,213		233,076		102,507
Pretax (gains) losses from disposition of assets	(3,709)		(133,717)		365
Net decrease (increase) in noncash operating working capital	(194,690)		93,710		145,454
Other operating activities - net	90,001		35,304		69,441
Net cash provided by continuing operations	1,865,647		2,924,436		1,673,503
Net cash provided (required) by discontinued operations	(1,014)		115,476		66,917
Net cash provided by operating activities	1,864,633		3,039,912		1,740,420
Investing Activities
Property additions and dry hole costs	(1,978,598)		(2,179,011)		(1,908,803)
Proceeds from sale of property, plant and equipment	1,616		361,961		21,636
Expenditures for major repairs	(30,253)		(57,604)		(14,649)
Purchase of investment securities	(2,531,515)	[2]	(1,043,473)	[2]	0	[2]
Proceeds from maturity of investment securities	2,172,830	[2]	623,133	[2]	0	[2]
Other investing activities - net	(34,050)		(21,256)		4,011
Investing activities of discontinued operations
Sales proceeds	78,908		0		0
Other	(845)		(6,949)		(40,416)
Net cash required by investing activities	(2,331,907)		(2,323,199)		(2,286,513)
Financing Activities
Additions to long-term debt	243,500		0		686,194
Reductions of long-term debt	0		(487,612)		(825)
Reductions of nonrecourse debt of a subsidiary	(2,572)	[1]	(5,235)	[1]	(4,903)	[1]
Proceeds from exercise of stock options and employee stock purchase plans	12,746		29,687		41,624
Excess tax benefits related to exercise of stock options	4,143		20,288		30,805
Cash dividends paid	(190,788)		(166,501)		(127,353)
Other financing activities - net	0		0		(760)
Net cash provided (required) by financing activities	67,029		(609,373)		624,782
Effect of exchange rate changes on cash and cash equivalents	35,279		(114,937)		51,628
Net increase (decrease) in cash and cash equivalents	(364,966)		(7,597)		130,317
Cash and cash equivalents at January 1	666,110		673,707		543,390
Cash and cash equivalents at December 31	301,144		666,110		673,707
Milford Haven refinery
Investing activities of discontinued operations
Acquisition of business	0		0		(348,292)
Hankinson ethanol plant
Investing activities of discontinued operations
Acquisition of business	($10,000)	[1]	$0	[1]	$0	[1]
[1]Excludes nonrecourse seller financing of $82 million related to the Company's acquisition of an ethanol plant in 2009.
[2]Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.

2_Statement Of Cash Flows Indir

Statement Of Cash Flows Indirect (Parenthetical) (USD $)
In Millions	12 Months Ended Dec. 31, 2009	12 Months Ended Dec. 31, 2008	12 Months Ended Dec. 31, 2007
Acquisition of Hankinson ethanol plant, nonrecourse seller financing	($82)	$0	$0

Statement Of Shareholders Equit

Statement Of Shareholders Equity And Other Comprehensive Income (USD $)
In Thousands			Capital in Excess of Par Value	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Treasury Stock	Total
Balance at beginning of period at Dec. 31, 2006	$0	$187,692	$454,860	$3,349,832	$131,999	($3,110)
Exercise of stock options		2,281	63,702
Cumulative effect of changes in accounting principles				(5,010)	1,345
Restricted stock transactions and other			3,794
Foreign currency translation gains (losses), net of income taxes					204,266		204,266
Net income for the year				766,529			766,529
Amortization, forfeitures and other			23,784
Retirement and postretirement benefit plan adjustments, net of income taxes					14,155		14,155
Cash dividends - $1.00 per share in 2009, $0.875 per share in 2008 and $0.675 per share in 2007				(127,353)
Sale of stock under employee stock purchase plans			1,045			982
Awarded restricted stock, net of forfeitures						(4,619)
Balance at end of period at Dec. 31, 2007	0	189,973	547,185	3,983,998	351,765	(6,747)	5,066,174
Exercise of stock options		1,276	45,839
Cumulative effect of changes in accounting principles				0	0
Restricted stock transactions and other			7,089
Foreign currency translation gains (losses), net of income taxes					(383,021)		(383,021)
Net income for the year				1,739,986			1,739,986
Amortization, forfeitures and other			30,811
Retirement and postretirement benefit plan adjustments, net of income taxes					(56,441)		(56,441)
Cash dividends - $1.00 per share in 2009, $0.875 per share in 2008 and $0.675 per share in 2007				(166,501)
Sale of stock under employee stock purchase plans			935			515
Awarded restricted stock, net of forfeitures						(7,717)
Balance at end of period at Dec. 31, 2008	0	191,249	631,859	5,557,483	(87,697)	(13,949)	6,278,945
Exercise of stock options		549	17,244
Cumulative effect of changes in accounting principles				0	0
Restricted stock transactions and other			2,473
Foreign currency translation gains (losses), net of income taxes					375,951		375,951
Net income for the year				837,621			837,621
Amortization, forfeitures and other			27,976
Retirement and postretirement benefit plan adjustments, net of income taxes					(1,067)		(1,067)
Cash dividends - $1.00 per share in 2009, $0.875 per share in 2008 and $0.675 per share in 2007				(190,788)
Sale of stock under employee stock purchase plans			957			1,604
Awarded restricted stock, net of forfeitures						(5,439)
Balance at end of period at Dec. 31, 2009	$0	$191,798	$680,509	$6,204,316	$287,187	($17,784)	$7,346,026

3_Statement Of Shareholders Equ

Statement Of Shareholders Equity And Other Comprehensive Income (Parenthetical) (USD $)
	Retained Earnings	Treasury Stock
Cash dividends, per share	0.675
Balance at end of year, shares of Common Stock		258,821
Cash dividends, per share	0.875
Balance at end of year, shares of Common Stock		535,135
Cash dividends, per share	$1
Balance at end of year, shares of Common Stock		682,222

Statement Of Other Comprehensiv

Statement Of Other Comprehensive Income (USD $)
In Thousands	12 Months Ended Dec. 31, 2009	12 Months Ended Dec. 31, 2008	12 Months Ended Dec. 31, 2007
Net income	$837,621	$1,739,986	$766,529
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation	375,951	(383,021)	204,266
Retirement and postretirement plan adjustments	(1,067)	(56,441)	14,155
Other comprehensive income (loss)	374,884	(439,462)	218,421
Comprehensive Income	$1,212,505	$1,300,524	$984,950

Significant Accounting Policies

Significant Accounting Policies
	12 Months Ended Dec. 31, 2009 USD / shares
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/or natural gas in the United States, Canada, the United Kingdom, Malaysia and Republic of the Congo and conducts oil and natural gas exploration activities worldwide. The Company has an interest in a Canadian synthetic oil operation, owns two petroleum refineries and one ethanol production facility in the United States and one refinery in the United Kingdom. Murphy markets petroleum products under various brand names and to unbranded wholesale customers in the United States and United Kingdom. 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. Title transfers for crude oil, natural gas and bulk refined products generally occur at pipeline custody points or when a tanker lifting has occurred. Refined products sold at retail are recorded when the customer takes delivery at the pump. Merchandise revenues are recorded at the point of sale. 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. Gas imbalances occur when the Companys actual sales 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 December31, 2009 and 2008, the liabilities for natural gas balancing were immaterial. 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-

New Accounting Principles and R

New Accounting Principles and Recent Accounting Pronouncements
	12 Months Ended Dec. 31, 2009 USD / shares
New Accounting Principles and Recent Accounting Pronouncements	Note B New Accounting Principles and Recent Accounting Pronouncements New Accounting Principles Adopted The Company adopted new accounting guidance issued by the Financial Accounting Standards Board (FASB) for noncontrolling interests in consolidated financial statements effective January1, 2009. This guidance is to be applied prospectively, except for presentation and disclosure requirements which are applied retrospectively. This guidance required noncontrolling interests to be reclassified as equity, and consolidated net income and comprehensive income shall include the respective results attributable to noncontrolling interests. The adoption of this guidance did not have a significant effect on the Companys consolidated financial statements. The Company adopted new accounting guidance covering business combinations effective January1, 2009. The new guidance established principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquired business. It also established how to recognize and measure goodwill acquired in the business combination or a gain from a bargain purchase, if applicable. This guidance impacts the recognition and measurement of assets and liabilities in business combinations that occur beginning in 2009. Assets and liabilities that arose from business combinations that occurred prior to 2009 are not affected by this guidance. The adoption of this guidance did not have a significant effect on the Companys financial statements for the year ended December31, 2009. The Company is unable to predict how the application of this guidance will affect its financial statements in future periods. The Company adopted new accounting guidance which addresses disclosures about derivative instruments and hedging activities in January 2009. This guidance expands required disclosures regarding derivative instruments to include qualitative information about objectives and strategies for using derivatives, quantities disclosures about fair value amounts and gains and losses on derivative instruments, and disclosures about credit-risk related contingent features in derivative agreements. See Note L for further disclosures. In 2009, the Company adopted new accounting guidance for determining whether instruments granted in share-based payment transactions are participating securities. This guidance specifies that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings per share (EPS) calculation under the two-class method, and also requires that all prior-period EPS calculations be adjusted retrospectively. The adoption of this guidance did not have a significant impact on the Companys prior-period EPS calculations. The Company adopted new accounting guidance addressing certain equity method investment accounting considerations in January 2009, which has been applied prospectively. The guidance addresses how to ini

Discontinued Operations

Discontinued Operations
	12 Months Ended Dec. 31, 2009 USD / shares
Discontinued Operations	Note C Discontinued Operations On March12, 2009, the Company sold its operations in Ecuador for net cash proceeds of $78,900,000. The acquirer also assumed certain tax and other liabilities associated with the Ecuador properties sold. The Ecuador properties sold included 20% interests in producing Block16 and the nearby Tivacuno area. The Company recorded a gain of $103,596,000, net of income taxes of $13,961,000, from the sale of the Ecuador properties in 2009. The Company used the proceeds of the sale to pay down debt and to partially fund ongoing development projects in other areas. At the time of the sale, the Ecuador properties produced approximately 6,700 net barrels per day of heavy oil and had net proved oil reserves of approximately 4.3million barrels. Ecuador operating results prior to the sale, and the resulting gain on disposal, have been reported as discontinued operations. The consolidated financial statements for 2008 and 2007 have been reclassified to conform to this presentation. In past reports, the operating results for the Ecuador properties were primarily included in the Ecuador segment in the Oil and Gas Operating Results table; interest expense associated with the business was previously included in Corporate results. The major assets (liabilities) associated with the Ecuador properties at the time of the sale are presented in the following table. (Thousands of dollars) Current assets $ 4,214 Property, plant and equipment, net of accumulated depreciation, depletion and amortization 65,178 Other noncurrent assets 683 Assets sold $ 70,075 Current liabilities $ 105,185 Other noncurrent liabilities 35 Liabilities associated with assets sold $ 105,220 The following table reflects the results of operations, including the gain on sale, from the Ecuador properties sold in 2009. (Thousands of dollars) 2009 2008 2007 Revenues $ 125,654 80,209 126,134 Income before income tax expense, including a gain on disposal of $117,557 in 2009 109,865 188 48,228 Income tax expense 12,761 4,951 20,779

Acquisitions

Acquisitions
	12 Months Ended Dec. 31, 2009 USD / shares
Acquisitions	Note D Acquisitions A wholly-owned subsidiary of the Company purchased an ethanol plant in Hankinson, North Dakota on October1, 2009. The plant has a rated capacity to produce 110million gallons of ethanol per annum. The $92,000,000 purchase price was financed with an $82,000,000 nonrecourse loan held by former owners. The loan currently bears interest at 5.0%per year and is repayable in 2014. Revenue and expenses associated with the ethanol plant have been included in the Companys consolidated statement of income beginning on the date of acquisition. The Company has performed a preliminary allocation of the purchase price for the Hankinson plant as of October1, 2009 based on the estimated fair value of the assets acquired as presented in the following table. (Thousands of dollars) Inventory $ 2,469 Land and land improvements 11,833 Buildings and improvements 9,819 Machinery and transportation equipment 67,879 Total purchase price $ 92,000 On December1, 2007, Murphy Oils indirect wholly-owned subsidiary, Murco Petroleum Limited (Murco), acquired the remaining 70% interest in the Milford Haven, Wales, refinery in the U.K. Prior to the acquisition, Murco held an effective 30% interest in the 108,000 barrel per day refinery located in Pembrokeshire in southwest Wales. Post-acquisition, Murco owns 100% of the refinery. Murco paid cash consideration for the refinery complex, certain nearby land, the adjacent jetty, a pipeline connection to the Mainline Pipeline and spare parts. Murco also obtained the refinery workforce and primary operational systems, and purchased certain crude oil and products inventory at the time of acquisition. The total purchase price of $348,292,000 included $11,078,000 of transaction costs. Revenue and expenses associated with the 70% interest acquired have been included in the Companys consolidated statements of income beginning on December1, 2007. No goodwill was recorded associated with this acquisition as the fair value of the assets acquired exceeded the purchase price paid by the Company.

Property, Plant and Equipment

Property, Plant and Equipment
	12 Months Ended Dec. 31, 2009 USD / shares
Property, Plant and Equipment	Note E Property, Plant and Equipment December31, 2009 December31, 2008 (Thousands of dollars) Cost Net Cost Net Exploration and production1 $ 10,258,126 6,834,178 2 8,485,391 5,791,945 2 Refining 1,900,551 1,048,067 1,649,679 881,436 Marketing 1,518,349 1,120,494 1,337,223 1,008,703 Corporate and other 102,888 62,349 79,818 45,634 $ 13,779,914 9,065,088 11,552,111 7,727,718 1Includes mineral rights as follows: $ 576,543 326,382 536,884 374,646 2Includes $11,773 in 2009 and $13,983 in 2008 related to administrative assets and support equipment. In January 2008, the Company sold its interest in Berkana Energy Corporation and recorded a pretax gain of $41,950,000 ($40,161,000 after-tax). In May 2008, the Company sold its interest in the Lloydminster area properties in Western Canada for a pretax gain of $90,451,000 ($67,236,000 after-tax). In 2007, the Company entered into an agreement with Walmart Stores, Inc. to purchase parcels of property leased from Walmart for its Murphy USA retail gasoline stations. A total of 837 sites have been purchased at a cost of $305,670,000. In conjunction with purchasing these sites, the Company closed 55 stations in the U.S. and Canada in 2007. In the Consolidated Statement of Income for 2007, the Company recorded noncash impairment charges of $40,708,000 primarily for writedown of the remaining book value and associated abandonment costs related to the NorthAmerican retail gasoline station closures. 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 December31, 2009, 2008 and 2007, the Company had total capitalized drilling costs pending the determination of proved reserves of $369,862,000, $310,118,000 and $272,155,000, respectively. The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December31, 2009. (Thousands of dollars) 2009 2008 2007 Beginning balance at January1 $ 310,118 272,155 315,445 Additions to capitalized exploratory well costs pending the determination of proved reserves 119,995 44,832 6,856 Reclassifications to proved properties based on the determination of proved reserves (60,251 ) (6,869 ) (50,146 ) Capitalized exploratory well costs charged to expense or sold Ending balance at December31 $ 369,862 310,118 272,155 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 have been capitalized since the completion of drilling. 2009 2008 2007

Financing Arrangements

Financing Arrangements
	12 Months Ended Dec. 31, 2009 USD / shares
Financing Arrangements	Note F Financing Arrangements At December31, 2009, the Company had a $1,962,500,000 committed credit facility with a major banking consortium that matures in June 2012. Between June 2010 and June 2011, the capacity of the committed facility is reduced to $1,905,000,000 and between June 2011 and June 2012 the maximum facility is $1,827,500,000. At December31, 2009, the Company had borrowed $625,000,000 under this committed facility. Borrowings under this facility bear interest at prime or varying cost of fund options. Facility fees are due at varying rates on the commitment. At December31, 2009 the Company had borrowed $47,000,000 under uncommitted credit lines. If necessary, the Company could convert borrowings under these uncommitted lines to the committed long-term credit facility outstanding through 2012. 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 September 2012.

Long-term Debt

Long-term Debt
	12 Months Ended Dec. 31, 2009 USD / shares
Long-term Debt	Note G Long-term Debt December31 (Thousands of dollars) 2009 2008 Notes payable 6.375% notes, due 2012, net of unamortized discount of $269 at December31, 2009 $ 349,731 349,616 7.05% notes, due 2029, net of unamortized discount of $1,801 at December31, 2009 248,199 248,106 Notes payable to banks, 0.675% to 2.10% at December31, 2009 672,000 428,500 Other, 6%, due through 2028 1,291 Total notes payable 1,271,221 1,026,222 Nonrecourse debt of a subsidiary Loan payable to seller on ethanol plant, 5.0%, due in 2014 82,000 Loans payable to Canadian government, interest free, payable in Canadian dollars, due in 2009 2,572 Total debt including current maturities 1,353,221 1,028,794 Current maturities (38 ) (2,572 ) Total long-term debt $ 1,353,183 1,026,222 Future maturities are: $38,000 in 2010, $7,041,000 in 2011, $1,031,774,000 in 2012, $10,046,000 in 2013, $55,048,000 in 2014 and $249,274,000 thereafter. The interest-free loans from the Canadian government were used to finance expenditures for the Hibernia field. The outstanding balance was repaid in annual installments through 2009.

Asset Retirement Obligations

Asset Retirement Obligations
	12 Months Ended Dec. 31, 2009 USD / shares
Asset Retirement Obligations	Note H Asset Retirement Obligations The majority of the asset retirement obligations (ARO) recognized by the Company at December31, 2009 and 2008 related to the estimated costs to dismantle and abandon its producing oil and gas properties and related equipment. A portion of the ARO related to retail gasoline stations. The Company did not record an ARO for its refining, ethanol and certain of its marketing assets because sufficient information is presently not available to estimate a range of potential settlement dates for the obligation. These assets are consistently being upgraded and are expected to be operational into the foreseeable future. In these cases, the 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 2009 and 2008 is shown in the following table. (Thousands of dollars) 2009 2008 Balance at beginning of year $ 435,589 336,107 Accretion expense 26,154 24,484 Liabilities incurred 42,578 46,367 Revision of previous estimates (609 ) 68,245 Liabilities settled (48,694 ) (23,335 )* Changes due to translation of foreign currencies 21,920 (16,279 ) Balance at end of year $ 476,938 435,589 * Includes non-cash settlements related to sale of assets in Canada in 2008. 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, 2009 USD / shares
Income Taxes	Note I Income Taxes The components of income from continuing operations before income taxes for each of the three years ended December31, 2009 and income tax expense attributable thereto were as follows. (Thousands of dollars) 2009 2008 2007 Income from continuing operations before income taxes United States $ 302,765 476,882 415,124 Foreign 974,408 2,341,483 773,880 $ 1,277,173 2,818,365 1,189,004 Income tax expense Federal Current $ 114,037 134,759 82,033 Deferred 1,005 40,328 56,407 115,042 175,087 138,440 State 9,496 16,714 15,969 Foreign Current* 318,619 689,407 248,301 Deferred* 93,499 192,408 47,214 412,118 881,815 295,515 Total $ 536,656 1,073,616 449,924 * Included a benefit of $38,687 in 2007 for an enacted reduction in the Canadian federal tax rate. Income tax benefits attributable to employee stock option transactions of $6,035,000 in 2009, $23,964,000 in 2008 and$33,895,000 in 2007 were included in Capital in Excess of Par Value in the Consolidated Balance Sheets. The following table reconciles income taxes based on the U.S. statutory tax rate to the Companys income tax expense. (Thousands of dollars) 2009 2008 2007 Income tax expense based on the U.S. statutory tax rate $ 447,011 986,428 416,151 Foreign income subject to foreign taxes at a rate different than the U.S. statutory rate 33,395 19,823 32,021 State income taxes, net of federal benefit 6,172 10,864 10,380 Increase in deferred tax asset valuation allowance related to foreign exploration expenditures 34,431 31,535 12,533 Change in Canadian federal tax rate (38,687 ) Other, net 15,647 24,966 17,526 Total $ 536,656 1,073,616 449,924 An analysis of the Companys deferred tax assets and deferred tax liabilities at December31, 2009 and 2008 showing the tax effects of significant temporary differences follows. (Thousands of dollars) 2009 2008 Deferred tax assets Property and leasehold costs $ 344,735 261,019 Liabilities for dismantlements 91,546 87,226 Postretirement and other employee benefits 118,044 114,221 Foreign tax credit carryforwards 46,308 41,043 Other deferred tax assets 129,517 119,314 Total gross deferred tax assets 730,150 622,823 Less valuation allowance (290,168 ) (266,755 ) Net deferred tax assets 439,982 356,068 Deferred tax liabilities Property, plant and equipment (575,955 ) (430,056 ) Accumulated depreciation, depletion and amortization (668,006 ) (604,267 ) Deferred major repair costs (18,525 ) (18,142 ) Other deferred tax liabilities (181,234 ) (152

Incentive Plans

Incentive Plans
	12 Months Ended Dec. 31, 2009 USD / shares
Incentive Plans	Note J Incentive Plans Costs resulting from all share-based payment transactions are recognized as an expense in the financial statements using a fair value-based measurement method over the periods that the awards vest. At the annual meeting of shareholders on May9, 2007, two new incentive compensation plans were approved and the Employee Stock Purchase Plan was amended. The 2007 Annual Incentive Plan (2007 Annual Plan) authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and other key employees. Cash awards under the 2007 Annual Plan are determined based on the Companys actual financial and operating results as measured against the performance goals established by the Committee. The 2007 Long-Term Incentive Plan (2007 Long-Term Plan) authorizes the Committee to make grants of the Companys 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 2007 Long-Term Plan expires in 2017. A total of 6,700,000 shares are issuable during the life of the 2007 Long-Term Plan, with annual grants limited to 1% of Common shares outstanding; allowed shares not granted may be granted in future years. The Company also has a Stock Plan for Non-Employee Directors (Directors Plan) that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Companys Non-Employee Directors. The Company generally expects to issue new 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 as follows. (Thousands of dollars) 2009 2008 2007 Compensation charged against income before income tax benefit $ 28,618 25,656 22,241 Related income tax benefit recognized in income 7,860 8,628 7,778 As of December31, 2009, there was $30,507,000 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 December31, 2009, 2008 and 2007 was $12,746,000, $29,687,000 and $41,624,000, respectively. Total income tax benefits realized from tax deductions related to stock option exercises under share-based payment arrangements were $6,035,000, $23,964,000 and $33,895,000 for the years ended December31, 2009, 2008 and 2007, 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 10 years from such date. Each option granted to date under the 2007 Long-Term Plan has had a term of seven years, has been nonqualified, and has had an option price equal to FMV at date of grant.

Employee and Retiree Benefit Pl

Employee and Retiree Benefit Plans
	12 Months Ended Dec. 31, 2009 USD / shares
Employee and Retiree Benefit Plans	Note K Employee and Retiree Benefit Plans PENSION AND OTHER POSTRETIREMENT PLANS The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory. Generally accepted accounting principles require the Company to recognize in its consolidated balance sheet the overfunded or underfunded status of its defined benefit plans as an asset or liability and to recognize changes in that funded status at the balance sheet date through comprehensive income. In 2007, the Company adopted the requirement to use a December31 measurement date rather than at September30 as previously permitted. The transition to a December31 measurement date required the Company to reduce its consolidated Retained Earnings as of January1, 2007 by $4,301,000 to recognize the one-time after-tax effect of an additional three months of net periodic benefit expense for its retirement and postretirement benefit plans. The tables that follow provide a reconciliation of the changes in the plans benefit obligations and fair value of assets for the years ended December31, 2009 and 2008 and a statement of the funded status as of December31, 2009 and 2008. Pension Benefits Other PostretirementBenefits (Thousands of dollars) 2009 2008 2009 2008 Change in benefit obligation Obligation at January1 $ 441,697 446,386 87,318 80,685 Service cost 17,052 17,928 3,121 2,708 Interest cost 28,767 27,667 5,688 5,087 Plan amendments 612 2,582 Participant contributions 35 36 894 846 Actuarial (gain) loss 44,140 (1,035 ) 9,643 2,802 Medicare Part D subsidy 500 195 Exchange rate changes 11,311 (29,756 ) Benefits paid (24,561 ) (22,111 ) (5,820 ) (5,005 ) Special termination benefits 1,867 Curtailments 551 406 Obligation at December31 521,471 441,697 101,750 87,318 Change in plan assets Fair value of plan assets at January1 278,083 339,259 Actual return on plan assets 61,406 (63,312 ) Employer contributions 50,772 50,639 4,426 3,964 Participant contributions 35 36 894 846 Medicare Part D subsidy 500 195 Exchange rate changes 10,598 (26,090 ) Benefits paid (24,561 ) (22,111 ) (5,820 ) (5,005 ) Other

Financial Instruments and Risk

Financial Instruments and Risk Management
	12 Months Ended Dec. 31, 2009 USD / shares
Financial Instruments and Risk Management	Note L Financial Instruments and Risk Management DERIVATIVE INSTRUMENTS Murphy makes limited use of 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 Companys 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). To qualify for hedge accounting, the changes in the market value of a derivative instrument must historically have been, and would be expected to continue to be, highly effective at offsetting changes in the prices of the hedged item. To the extent that the change in fair value of a derivative instrument has less than perfect correlation with the change in the fair value of the hedged item, a portion of the change in fair value of the derivative instrument is considered ineffective and would normally be recorded in earnings during the affected period. Crude Oil Purchase Price Risks The Company purchases crude oil as feedstock at its U.S. and U.K. refineries and is therefore subject to commodity price risk. Short-term derivative instruments were outstanding at December31, 2008 to manage the 2009 purchase price of 1,063,000 barrels of crude oil at the Companys Superior, Wisconsin refinery. At December31, 2007 essentially offsetting short-term derivative instruments were outstanding to manage the 2008 purchase price of 403,000 barrels of crude oil at the Companys Meraux, Louisiana refinery. Total pretax charges from marking these contracts to market at the respective year-end were $1,378,000 in 2008 and $40,000 in 2007. There were no open crude oil purchase contracts at December31, 2009, but $2,296,000 was receivable from a third party at that date on a completed contract. Foreign Currency Exchange Risks The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. Short-term derivative instruments were outstanding at December31, 2009 to manage the risk of approximately $36,000,000 of U.S. dollar balances associated with the Companys Canadian operation and to manage the risk of approximately $100,000,000 equivalent of ringgit balances in the Companys Malaysian operations. The impact on consolidated income from continuing operations before taxes from marking these derivative contracts to market as of December31, 2009 was a gain of $340,000. There were no foreign currency exchange instruments outstanding at December31, 2008 and 2007. At December31, 2009, the fair value of derivative instruments not designated as hedging instruments are presented in the following table. December31, 2009 Asset Derivatives LiabilityDerivatives (Thousands of dollars) Balance Sheet Location Fair Value Balance Sheet Location Fair Value Commodity derivative contracts Ac

Earnings per Share

Earnings per Share
	12 Months Ended Dec. 31, 2009 USD / shares
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 December31, 2009. No difference existed between net income used in computing basic and diluted income per Common share for these years. (Weighted-average shares outstanding) 2009 2008 2007 Basic method 190,767,077 189,608,846 188,027,557 Dilutive stock options 1,701,373 2,524,826 3,113,180 Diluted method 192,468,450 192,133,672 191,140,737 Outstanding options to purchase shares of Common Stock were not included in the computation of diluted earnings per share in 2009 and 2008 because the incremental shares from assumed conversion were antidilutive. These included 1,793,905 shares at a weighted average share price of $56.25 in 2009 and 924,000 shares at a weighted average share price of $72.745 in 2008. There were no antidilutive options in the 2007 period.

Other Financial Information

Other Financial Information
	12 Months Ended Dec. 31, 2009 USD / shares
Other Financial Information	Note N Other Financial Information INVENTORIES Inventories accounted for under the LIFO method totaled $334,768,000 and $342,984,000 at December31, 2009 and 2008, respectively, and these amounts were $551,184,000 and $202,477,000 less than such inventories would have been valued using the FIFO method. ACCOUNTS RECEIVABLE In 2009, the Company recorded income before taxes, and a related accounts receivable, of $244,418,000 plus $42,000,000 of associated interest thereon, for an anticipated recovery of federal royalties paid in previous years on certain oil and gas properties in the Gulf of Mexico. The royalty portion of this accounts receivable was collected on February25, 2010. ACCUMULATED OTHER COMPREHENSIVE INCOME At December31, 2009 and 2008, the components of Accumulated Other Comprehensive Income (Loss) were as follows. (Thousands of dollars) 2009 2008 Foreign currency translation gains, net of tax $ 421,468 45,517 Retirement and postretirement plan liability adjustments, net of tax (134,281 ) (133,214 ) Balance at end of year $ 287,187 (87,697 ) At December31, 2009, components of the net foreign currency translation gains of $421,468,000 were gains of $395,088,000 for Canadian dollars, $22,214,000 for pounds sterling and $4,166,000 for other currencies. Net gains (losses) from foreign currency transactions, including the effects of foreign currency contracts, included in the Consolidated Statements of Income were $48,429,000 in 2009, $(105,620,000) in 2008 and $(20,637,000) in 2007. CASH FLOW DISCLOSURES Cash income taxes paid were $501,506,000, $380,602,000 and $297,274,000 in 2009, 2008 and 2007, respectively. Interest paid, net of amounts capitalized, was $21,017,000, $43,715,000 and $22,274,000 in 2009, 2008 and 2007, respectively. Noncash operating working capital (increased) decreased during each of the three years ended December31, 2009 as follows. (Thousands of dollars) 2009 2008 2007 Accounts receivable $ (402,481 ) 386,605 (445,677 ) Inventories (114,569 ) 22,474 (107,945 ) Prepaid expenses 7,209 (12,959 ) 57,089 Deferred income tax assets 14,772 56,451 (65,391 ) Accounts payable and accrued liabilities 365,257 (701,450 ) 661,599 Current income tax liabilities (64,878 ) 342,589 45,779 Net (increase) decrease in noncash operating working capital, excluding acquisition of the Milford Haven refinery in 2007 $ (194,690 ) 93,710 145,454

Assets and Liabilities Measured

Assets and Liabilities Measured at Fair Value
	12 Months Ended Dec. 31, 2009 USD / shares
Assets and Liabilities Measured at Fair Value	Note O Assets and Liabilities Measured at Fair Value As described in Note B, the Company adopted the FASBs fair value measurements rule on January1, 2008. The portion of the rule applicable to nonrecurring nonfinancial assets and liabilities was adopted by the Company on January1, 2009. The rule establishes a fair value hierarchy 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 Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheet. The fair value measurements for these assets and liabilities at December31, 2009 are presented in the following table. Fair Value at December31, 2009 FairValueMeasurementsatReportingDateUsing (Thousands of dollars) Quoted Pricesin ActiveMarkets forIdentical Assets (Liabilities) (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level3) Assets Derivative assets $ 2,636 2,636 Liabilities Nonqualified employee savings plan (5,691 ) (5,691 ) The nonqualified employee savings plan is an unfunded savings plan through which the participants seek a return via phantom investments in equity securities and/or mutual funds. Fair value of this liability was based on quoted prices for these equity securities and mutual funds. The fair value of commodity derivatives was determined based on market quotes for WTI crude and foreign currency exchange contracts at the balance sheet date. The income effect of the changes in the fair value of nonqualified employee savings plan is recorded in Selling and General Expense in the Consolidated Statement of Income. The change in fair value of commodity derivatives is recorded in Crude Oil and Product Purchases and the change in fair value of foreign currency exchange derivatives is recorded in Interest and Other Income (Loss). The carrying value of the Companys Cash and Cash Equivalents, Accounts Receivable and Accounts Payable approximates fair value. The assets of an ethanol plant acquired in 2009 were recorded at fair value based on valuation techniques including the cost and income approaches using Level 3 unobservable inputs within the fair value hierarchy. The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December31, 2009 and 2008. 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, short-term notes payable, trade accounts payable and accrued expenses, all of which had fair values approximating carrying amounts. The carrying value of Canadian government securities is determined b

Hurricane and Insurance Related

Hurricane and Insurance Related Matters
	12 Months Ended Dec. 31, 2009 USD / shares
Hurricane and Insurance Related Matters	Note P Hurricane and Insurance Related Matters The Company maintains insurance coverage related to losses of production and profits for occurrences such as storms, fires and other issues. During 2009, the Companys North American refining and marketing operations recorded a benefit of $15,398,000 for business interruption insurance relating to a fire that occurred at the Meraux, Louisiana refinery in June 2003. This business interruption settlement was included in Sales and Other Operating Revenues in the Consolidated Statement of Income for 2009. The Company also maintains certain insurance covering property damage, sudden and accidental environmental events and other hazards. In 2009, the Companys primary property insurer settled all claims for damages at the Meraux refinery and other properties caused by Hurricane Katrina, which struck the U.S. Gulf Coast in late August 2005. The insurers claims for Hurricane Katrina exceeded its maximum loss for a specific event, which ultimately limited the amount of insurance the Company received for its damages. The Companys final cash settlement from the insurer led to pretax income of $12,718,000 in 2009. This income, which was recorded in Sales and Operating Revenues in the 2009 Consolidated Statement of Income, arose because the ultimate payments received from the insurer exceeded amounts originally estimated by the insurer. In 2007, the Company recorded a $3,000,000 charge in Operating Expenses associated with Meraux property damages from Hurricane Katrina because the property insurer lowered its estimated insurance payments based on higher total estimated claims related to this event. With the final insurance settlement in 2009, the Companys refining and marketing operations ultimately received insurance proceeds of $156,919,000 related to property damages incurred as a result of Hurricane Katrina. See Note R for additional information regarding environmental and other contingencies relating to Hurricane Katrina. The Company also settled with an insurance consortium in 2009 for its claims related to a crude oil spill that occurred at the Meraux refinery after Hurricane Katrina. The settlement led to pretax income of $6,500,000 in the Consolidated Statement of Income for 2009, with $4,500,000 related to the insurance claim included in Sales and Other Operating Revenues for the North American Refining and Marketing segment and $2,000,000 of associated interest income included in Interest and Other Income for Corporate activities. At year-end 2009, the Company had not settled its claim against one insurer for legal and professional costs associated with the insurance coverage negotiation process. During early 2010, the Company agreed to accept a final settlement of $3,000,000 from the insurer for these costs.

Commitments

Commitments
	12 Months Ended Dec. 31, 2009 USD / shares
Commitments	Note Q Commitments In September 2009, the Company entered into a forward sales contract to mitigate the price risk for a portion of its 2010 natural gas sales volumes at the Tupper field in Western Canada. The contract calls for natural gas deliveries of approximately 33million cubic feet per day during 2010 at a price of Cdn$5.30 per thousand cubic feet at the AECO C sales point. The contract has been accounted for as a normal sale for accounting purposes. The Company leases land, gasoline stations, and 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 and a production facility at the Thunder Hawk field. During the next five years, expected future rental payments under all operating leases are approximately $146,784,000 in 2010, $139,490,000 in 2011, $137,362,000 in 2012, $132,035,000 in 2013 and $121,925,000 in 2014. Rental expense for noncancellable operating leases, including contingent payments when applicable, was $124,693,000 in 2009, $88,890,000 in 2008 and $61,439,000 in 2007. During the construction period for these leased assets at Azurite and Thunder Hawk, the Company was considered the proportionate owner of this equipment for accounting purposes, and therefore, recorded equivalent assets and liabilities in the Consolidated Balance Sheet prior to the commencement of the leases. Upon completion of the construction of the two pieces of equipment, the assets and liabilities of approximately $282,700,000 associated with these equipment leases were removed from the Companys Consolidated Balance Sheet through a non-cash related sale and leaseback transaction. There was no impact on net income, cash flow or stockholders equity from these sale and leaseback transactions. To assure a long-term supply of hydrogen at its Meraux, Louisiana refinery, the Company has contracted to purchase up to 35million standard cubic feet of hydrogen per day at market prices through 2021. The contract requires the payment of a base facility charge for use of the facility. Future required minimum annual payments for base facility charges for the next five years are $6,550,000 in 2010, $6,812,000 in 2011, $7,084,000 in 2012, $7,368,000 in 2013 and $7,663,000 in 2014. Base facility charges and hydrogen costs incurred in 2009, 2008 and 2007 totaled $26,888,000, $45,396,000 and $42,512,000, respectively. The Company has operating, production handling and transportation agreements providing for processing, production handling and transportation services for hydrocarbon production from certain fields in the Gulf of Mexico and Western Canada. These agreements require minimum monthly or annual payments for processing and/or transportation charges through 2018. Future required minimum monthly payments for the next five years are $9,912,000 in 2010, $17,972,000 in2011, $17,814,000 in 2012, $12,720,000 in 2013 and $15,779,000 in 2014. Under certain circumstances, the Company is required to pay additional amounts depending on the actual hydrocarbon quantities processed under the agreement. Costs incurred

Contingencies

Contingencies
	12 Months Ended Dec. 31, 2009 USD / shares
Contingencies	Note R Contingencies The Companys 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 Companys 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 Murphys 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. While some of these historical properties are in various stages of negotiation, investigation, and/or cleanup, the Company is investigating the extent of any such liability and the availability of applicable defenses and believes costs rel

Terra Nova Working Interest Red

Terra Nova Working Interest Redetermination
	12 Months Ended Dec. 31, 2009 USD / shares
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, requires a redetermination of working interests based on an analysis of reservoir quality among fault separated areas where varying ownership interests exist. The operator of Terra Nova completed the initial redetermination assessment in 2009 and the matter is the subject of arbitration before final interests are determined. The Company anticipates that its working interest at Terra Nova will be reduced from its current 12.0% to approximately 10.5%, subject to the results of the ongoing arbitration process between the operator and certain other owners. Upon completion of the arbitration process, the Company will be required to make a cash settlement payment to the Terra Nova partnership for the value of oil sold since about December 2004 related to the ultimate working interest reduction below 12.0%. The Company has recorded expense of $83,498,000 in 2009 based on the anticipated working interest reduction, with this amount reflected as Redetermination of Terra Nova Working Interest in the Consolidated Statement of Income. The Company cannot predict the final outcome of the redetermination process, which is expected to be completed by the end of 2010.

Common Stock Issued and Outstan

Common Stock Issued and Outstanding
	12 Months Ended Dec. 31, 2009 USD / shares
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 December31, 2009 is shown below. (Number of shares outstanding) 2009 2008 2007 At beginning of year 190,713,806 189,714,149 187,572,200 Stock options exercised 548,659 1,275,971 2,249,300 Employee stock purchase and thrift plans 61,575 19,755 37,679 Restricted stock awards, net of forfeitures (208,662 ) (299,334 ) (144,442 ) All other 3,265 (588 ) At end of year 191,115,378 190,713,806 189,714,149

Subsequent Events

Subsequent Events
	12 Months Ended Dec. 31, 2009 USD / shares
Subsequent Events	Note U Subsequent Events The Company has evaluated subsequent events through the date of issuance of these consolidated financial statements (February 26, 2010). In certain cases, events that occur after the balance sheet date lead to recognition and/or disclosure in the consolidated financial statements.

Business Segments

Business Segments
	12 Months Ended Dec. 31, 2009 USD / shares
Business Segments	Note V Business Segments Murphys reportable segments are organized into two major types of business activities, each subdivided into geographic areas of operations. The Companys exploration and production activity is subdivided into segments for the United States, Canada, Malaysia, the United Kingdom, 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 Companys refining and marketing segments are North America and the United Kingdom and each derives revenue mainly from the sale of petroleum products and merchandise. The Company sells gasoline in the United States at retail stations built primarily at Walmart Supercenters. The U.S. refining, ethanol and marketing businesses, and the former Canadian marketing business are included in the North American segment. In 2007, the Company exited the gasoline marketing business in Canada by closing and writing off all eight gasoline stations in that country. The Companys 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. 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. The Company had no single customer from which it derived more than 10% of its revenues. 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 page F-37, Certain Long-Lived Assets at December31 exclude investments, noncurrent receivables, deferred tax assets and goodwill and other intangible assets. Excise taxes on petroleum products of $2,069,323,000, $2,140,338,000 and $2,070,777,000 for the years 2009, 2008 and 2007, respectively, that were collected by the Company and remitted to various government entities were excluded from revenues and costs and expenses. Segment Information Exploration and Production (Millions of dollars) United States Canada Malaysia United Kingdom Republic oftheCongo Other Total Year ended December31, 2009 Segment income (loss) $ 178.0 64.8 561.9 12.6 (20.6 ) (104.9 ) 691.8 Revenues from external customers 708.6 635.2 1,526.4 61.6 16.5 2.4 2,950.7 Intersegment revenues 85.3 85.3 Interest income Interest expense, net of capitalization Income tax expense (benefit) 88.4 21.0 354.1 11.9 1.3 (.6 ) 476.1 Significant noncash charges (credits) Depreciation, depletion, amortization 246.5 199.9 304.1 12.4 11.5 1.4 775.8 Accretion of ass

Schedule 1 - Summary of Oil Res

Schedule 1 - Summary of Oil Reserves Based on Year-End Prices for 2006 - 2008 and Average Prices for 2009
	12 Months Ended Dec. 31, 2009 USD / shares
Schedule 1 - Summary of Oil Reserves Based on Year-End Prices for 2006 - 2008 and Average Prices for 2009	Schedule 1 Summary of Oil Reserves Based on Year-End Prices for 2006 - 2008 and Average Prices for 2009 Total Total by product United States Canada Malaysia United Kingdom Republic oftheCongo Ecuador All Products Synthetic Oil Oil Synthetic Oil Oil Oil Oil Oil (Millions of barrels) Oil Oil Proved developed and undeveloped reserves: December31, 2006 173.8 173.8 44.0 43.7 54.3 20.7 11.1 Revisions of previous estimates (2.5 ) (2.5 ) (8.9 ) 3.6 3.2 (.4 ) Extensions and discoveries 35.6 35.6 .9 2.2 32.5 Production (28.7 ) (28.7 ) (4.8 ) (11.3 ) (7.4 ) (1.9 ) (3.3 ) December31, 2007 178.2 178.2 31.2 38.2 82.6 18.8 7.4 Revisions of previous estimates 10.0 10.0 (1.5 ) (1.9 ) 13.3 .1 Improved recovery 18.4 18.4 18.4 Extensions and discoveries 9.5 9.5 1.0 1.1 7.4 Production (38.7 ) (38.7 ) (3.9 ) (9.3 ) (21.0 ) (1.8 ) (2.7 ) Sales of properties (3.8 ) (3.8 ) (3.8 ) December31, 2008 173.6 173.6 26.8 24.3 100.7 17.0 4.8 Synthetic reserves now presented as proved under SEC rules 131.6 131.6 131.6 Revisions of previous estimates 5.8 3.2 2.6 5.0 7.2 2.6 (4.9 ) (4.1 ) Improved recovery 31.0 31.0 31.0 Extensions and discoveries 23.9 23.9 .8 3.3 11.2 8.6 Production (48.2 ) (43.5 ) (4.7 ) (6.2 ) (7.0 ) (4.7 ) (27.9 ) (1.2 ) (.7 ) (.5 ) Sales of properties (4.3 ) (4.3 ) (4.3 ) December31, 2009 313.4 183.9 129.5 26.4 27.8 129.5 110.1 11.7 7.9 Proved developed reserves: December31, 2008 122.5 122.5 16.7 23.1 63.4 14.5 4.8 December31, 2009 270.0 150.3 119.7 18.3 26.2 119.7 90.0 11.7 4.1 Proved undeveloped reserves: December31, 2008 51.1 51.1 10.1 1.2 37.3 2.5 December31, 2009 43.4 33.6 9.8 8.1 1.6 9.8 20.1 3.8 Note: All oil reserves included in the table above are from consolidated subsidiaries and proportionately consolidated joint vent

Schedule 2 - Summary of Natural

Schedule 2 - Summary of Natural Gas Reserves Based on Year-End Prices for 2006 - 2008 and Average Prices for 2009
	12 Months Ended Dec. 31, 2009 USD / shares
Schedule 2 - Summary of Natural Gas Reserves Based on Year-End Prices for 2006 - 2008 and Average Prices for 2009	Schedule 2 Summary of Natural Gas Reserves Based on Year-End Prices for 2006 - 2008 and Average Prices for 2009 (Billions of cubic feet) Total United States Canada Malaysia United Kingdom Proved developed and undeveloped reserves: December31, 2006 531.4 148.6 20.9 337.5 24.4 Revisions of previous estimates (13.6 ) (19.1 ) 7.7 (2.2 ) Extensions and discoveries 97.3 .9 5.8 88.7 1.9 Production (24.3 ) (17.1 ) (4.5 ) (2.7 ) December31, 2007 590.8 113.3 29.9 424.0 23.6 Revisions of previous estimates (43.5 ) 1.1 .8 (45.4 ) Improved recovery 1.9 1.9 Extensions and discoveries 82.1 .8 56.0 25.3 Production (23.0 ) (17.8 ) (1.8 ) (.6 ) (2.8 ) Sales of properties (22.7 ) (22.7 ) December31, 2008 585.6 97.4 62.2 405.2 20.8 Revisions of previous estimates 77.2 9.1 (.6 ) 59.4 9.3 Improved recovery 6.9 6.9 Extensions and discoveries 153.5 2.6 83.3 67.6 Production (68.4 ) (19.8 ) (20.0 ) (27.3 ) (1.3 ) Sales of properties (.2 ) (.2 ) December31, 2009 754.6 89.3 124.7 511.8 28.8 Proved developed reserves: December31, 2008 209.2 58.8 52.0 79.5 18.9 December31, 2009 401.6 73.2 89.7 209.9 28.8 Proved undeveloped reserves: December31, 2008 376.4 38.6 10.2 325.7 1.9 December31, 2009 353.0 16.1 35.0 301.9 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.

Schedule 3 - Costs Incurred in

Schedule 3 - Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
	12 Months Ended Dec. 31, 2009 USD / shares
Schedule 3 - 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 States Canada1 Malaysia United Kingdom Republic oftheCongo Ecuador2 Other Total Year Ended December31, 2009 Property acquisition costs Unproved $ 82.4 31.0 4.7 118.1 Proved Total acquisition costs 82.4 31.0 4.7 118.1 Exploration costs3 89.7 9.9 114.4 .1 19.1 79.4 312.6 Development costs3 197.2 321.4 695.9 15.1 187.5 .8 1.2 1,419.1 Total costs incurred 369.3 362.3 810.3 15.2 206.6 .8 85.3 1,849.8 Charged to expense Dry hole expense 11.3 55.0 13.9 45.1 125.3 Geophysical and other costs 16.2 10.0 .8 .2 (3.1 ) 32.6 56.7 Total charged to expense 27.5 10.0 55.8 .2 10.8 77.7 182.0 Property additions $ 341.8 352.3 754.5 15.0 195.8 .8 7.6 1,667.8 Year Ended December31, 2008 Property acquisition costs Unproved $ 125.7 20.6 9.7 156.0 Proved Total acquisition costs 125.7 20.6 9.7 156.0 Exploration costs3 142.4 18.8 97.2 10.2 1.1 60.0 329.7 Development costs3 168.9 421.7 687.9 27.2 149.4 6.9 3.0 1,465.0 Total costs incurred 437.0 461.1 785.1 37.4 150.5 6.9 72.7 1,950.7 Charged to expense Dry hole expense 18.0 80.4 31.1 129.5 Geophysical and other costs 40.2 18.9 14.3 .5 .2 28.8 102.9 Total charged to expense 58.2 18.9 94.7 .5 .2 59.9 232.4 Property additions $ 378.8 442.2 690.4 36.9 150.3 6.9 12.8 1,718.3 Year Ended December31, 2007 Property acquisition costs Unproved $ 23.4 399.2 422.6 Proved Total acquisition costs 23.4 399.2 422.6 Exploration costs3 112.8 31.1 43.9 .8 12.5 .3 6.8 208.2 Development costs3 215.8 126.9 646.2 31.2 127.5 40.1 1.8 1,189.5

Schedule 4 - Results of Operati

Schedule 4 - Results of Operations for Oil and Gas Producing Activities
	12 Months Ended Dec. 31, 2009 USD / shares
Schedule 4 - Results of Operations for Oil and Gas Producing Activities	Schedule 4 Results of Operations for Oil and Gas Producing Activities1 (Millions of dollars) United States Canada Malaysia United Kingdom Republic oftheCongo Other Subtotal Synthetic Oil Canada Total Year Ended December31, 2009 Revenues Crude oil and natural gas liquids Sales to unaffiliated enterprises $ 374.8 310.7 1,478.4 54.7 24.5 2,243.1 258.1 2,501.2 Transfers to consolidated operations 54.9 54.9 30.4 85.3 Natural gas Sales to unaffiliated enterprises 80.6 68.6 45.4 6.4 201.0 201.0 Total oil and gas revenues 455.4 434.2 1,523.8 61.1 24.5 2,499.0 288.5 2,787.5 Other operating revenues2 253.2 (2.2 ) 2.6 .5 (8.0 ) 2.4 248.5 248.5 Total revenues 708.6 432.0 1,526.4 61.6 16.5 2.4 2,747.5 288.5 3,036.0 Costs and expenses Production expenses 101.2 97.9 248.2 19.9 15.4 482.6 171.9 654.5 Exploration costs charged to expense 27.5 10.0 55.8 .2 10.8 77.7 182.0 182.0 Undeveloped lease amortization 34.7 44.1 4.4 83.2 83.2 Depreciation, depletion and amortization 246.5 171.8 304.1 12.4 11.5 1.4 747.7 28.1 775.8 Accretion of asset retirement obligations 6.8 4.3 7.8 1.6 .1 .6 21.2 4.3 25.5 Impairment of long-lived assets 5.2 5.2 5.2 Terra Nova working interest redetermination 83.5 83.5 83.5 Selling and general expenses 20.3 18.0 (5.5 ) 3.0 (2.0 ) 23.8 57.6 .8 58.4 Total costs and expenses 442.2 429.6 610.4 37.1 35.8 107.9 1,663.0 205.1 1,868.1 266.4 2.4 916.0 24.5 (19.3 ) (105.5 ) 1,084.5 83.4 1,167.9 Income tax expense (benefits) 88.4 1.2 354.1 11.9 1.3 (.6 ) 456.3 19.8 476.1 Results of operations $ 178.0 1.2 561.9 12.6 (20.6 ) (104.9 ) 628.2 63.6 691.8 Year Ended December31, 2008 Revenues Crude oil and natural gas liquids Sales to unaffiliated enterprises $ 374.0 697.5 1,985.6 189.2 3,246.3 371.4 3,617.7 Transfers to consolidated operations 78.3 .2 78.5 88.2 166.7 Natural gas

Schedule 5 - Standardized Measu

Schedule 5 - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
	12 Months Ended Dec. 31, 2009 USD / shares
Schedule 5 - 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 States Canada1 Malaysia United Kingdom Republic oftheCongo Ecuador2 Total December31, 2009 Future cash inflows $ 1,908.1 9,571.1 7,496.1 831.2 467.7 20,274.2 Future development costs (245.7 ) (191.3 ) (726.3 ) (9.7 ) (99.7 ) (1,272.7 ) Future production and abandonment costs (523.6 ) (5,450.6 ) (1,976.1 ) (330.4 ) (176.5 ) (8,457.2 ) Future income taxes (264.8 ) (952.3 ) (1,531.3 ) (250.2 ) (83.2 ) (3,081.8 ) Future net cash flows 874.0 2,976.9 3,262.4 240.9 108.3 7,462.5 10% annual discount for estimated timing of cash flows (174.8 ) (1,521.4 ) (838.0 ) (64.7 ) (7.2 ) (2,606.1 ) Standardized measure of discounted future net cash flows $ 699.2 1,455.5 2,424.4 176.2 101.1 4,856.4 December31, 2008 Future cash inflows $ 1,722.0 999.6 5,602.3 751.0 128.5 9,203.4 Future development costs (330.0 ) (26.3 ) (924.8 ) (133.3 ) (4.8 ) (1,419.2 ) Future production and abandonment costs (495.6 ) (445.0 ) (1,078.8 ) (254.8 ) (87.4 ) (2,361.6 ) Future income taxes (217.9 ) (157.0 ) (1,336.8 ) (201.4 ) (1,913.1 ) Future net cash flows 678.5 371.3 2,261.9 161.5 36.3 3,509.5 10% annual discount for estimated timing of cash flows (146.1 ) (62.2 ) (572.3 ) (59.6 ) (4.1 ) (844.3 ) Standardized measure of discounted future net cash flows $ 532.4 309.1 1,689.6 101.9 32.2 2,665.2 December31, 2007 Future cash inflows $ 3,564.8 2,905.0 7,813.6 1,955.7 214.0 16,453.1 Future development costs (397.7 ) (19.1 ) (1,504.3 ) (73.9 ) (19.9 ) (2,014.9 ) Future production and abandonment costs (542.0 ) (901.1 ) (1,674.6 ) (436.2 ) (141.5 ) (3,695.4 ) Future income taxes (849.8 ) (434.7 ) (1,381.6 ) (738.7 ) (15.2 ) (3,420.0 ) Future net cash flows 1,775.3 1,550.1 3,253.1 706.9 37.4 7,322.8 10% annual discount for estimated timing of cash flows (489.1 ) (335.9 ) (750.5 ) (272.2 ) (3.1 ) (1,850.8 ) Standardized measure of discounted future net cash flows $ 1,286.2 1,214.2 2,502.6 434.7 34.3 5,472.0

Schedule 6 - Capitalized Costs

Schedule 6 - Capitalized Costs Relating to Oil and Gas Producing Activities
	12 Months Ended Dec. 31, 2009 USD / shares
Schedule 6 - Capitalized Costs Relating to Oil and Gas Producing Activities	Schedule 6 Capitalized Costs Relating to Oil and Gas Producing Activities (Millions of dollars) United States Canada Malaysia United Kingdom Republic of the Congo Ecuador* Other Subtotal Synthetic Oil Canada Total December31, 2009 Unproved oil and gas properties $ 427.9 467.8 254.5 9.5 21.3 19.7 1,200.7 1,200.7 Proved oil and gas properties 1,626.9 2,217.4 3,201.8 510.6 404.6 3.6 7,964.9 1,035.0 8,999.9 Gross capitalized costs 2,054.8 2,685.2 3,456.3 520.1 425.9 23.3 9,165.6 1,035.0 10,200.6 Accumulated depreciation, depletion and amortization Unproved oil and gas properties (78.8 ) (157.3 ) (6.1 ) (8.0 ) (250.2 ) (250.2 ) Proved oil and gas properties (791.1 ) (1,017.9 ) (744.5 ) (328.8 ) (20.3 ) (3.6 ) (2,906.2 ) (221.8 ) (3,128.0 ) Net capitalized costs $ 1,184.9 1,510.0 2,711.8 191.3 399.5 11.7 6,009.2 813.2 6,822.4 December31, 2008 Unproved oil and gas properties $ 313.5 405.2 198.5 9.6 230.4 13.3 1,170.5 1,170.5 Proved oil and gas properties 1,419.0 1,620.3 2,504.2 495.5 388.0 3.5 6,430.5 832.1 7,262.6 Gross capitalized costs 1,732.5 2,025.5 2,702.7 505.1 230.4 388.0 16.8 7,601.0 832.1 8,433.1 Accumulated depreciation, depletion and amortization Unproved oil and gas properties (59.3 ) (93.2 ) (6.1 ) (3.6 ) (162.2 ) (162.2 ) Proved oil and gas properties (543.7 ) (719.4 ) (430.8 ) (312.9 ) (317.3 ) (3.5 ) (2,327.6 ) (165.3 ) (2,492.9 ) Net capitalized costs $ 1,129.5 1,212.9 2,271.9 192.2 224.3 70.7 9.7 5,111.2 666.8 5,778.0 * The Company sold its Ecuador operations on March12, 2009. Note: Unproved oil and gas properties above include costs and associated accumulated amortization of properties that do not have proved reserves; these costs include mineral interests, uncompleted exploratory wells, and exploratory wells capitalized pending further evaluation.

SUPPLEMENTAL QUARTERLY INFORMAT

SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED)
	12 Months Ended Dec. 31, 2009 USD / shares
SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED)	MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED) (Millions of dollars except per share amounts) First Quarter Second Quarter Third Quarter Fourth Quarter Year Year Ended December31, 2009 Sales and other operating revenues $ 3,416.4 4,496.0 5,202.2 5,803.6 18,918.2 Income from continuing operations before income taxes 156.5 271.1 312.8 536.8 1,277.2 Income from continuing operations 71.2 160.9 188.9 319.5 740.5 Net income 171.1 158.8 188.9 318.8 837.6 Income from continuing operations per Common share Basic 0.37 0.84 0.99 1.67 3.88 Diluted 0.37 0.84 0.98 1.65 3.85 Net income per Common share Basic 0.90 0.83 0.99 1.67 4.39 Diluted 0.89 0.83 0.98 1.65 4.35 Cash dividend per Common share 0.25 0.25 0.25 0.25 1.00 Market price of Common Stock* High 51.79 60.49 61.79 64.66 64.66 Low 38.18 43.93 50.38 53.18 38.18 Year Ended December31, 2008 Sales and other operating revenues $ 6,466.7 8,249.2 8,184.7 4,460.0 27,360.6 Income from continuing operations before income taxes 656.7 968.5 919.4 273.8 2,818.4 Income from continuing operations 408.2 618.5 585.0 133.0 1,744.7 Net income 409.0 619.2 584.4 127.4 1,740.0 Income from continuing operations per Common share Basic 2.16 3.26 3.08 0.70 9.20 Diluted 2.13 3.22 3.04 0.69 9.08 Net income per Common share Basic 2.16 3.27 3.08 0.67 9.18 Diluted 2.14 3.22 3.04 0.67 9.06 Cash dividend per Common share 0.1875 0.1875 0.25 0.25 0.875 Market price of Common Stock* High 85.85 98.05 100.93 61.23 100.93 Low 69.54 83.03 60.61 37.00 37.00 * Prices are as quoted on the New York Stock Exchange.

SCHEDULE II - VALUATION ACCOUNT

SCHEDULE II - VALUATION ACCOUNTS AND RESERVES
	12 Months Ended Dec. 31, 2009 USD / shares
SCHEDULE II - VALUATION ACCOUNTS AND RESERVES	MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES SCHEDULE II VALUATION ACCOUNTS AND RESERVES (Millions of dollars) Balanceat January1 Charged (Credited) toExpense Deductions Other* Balance at December31 2009 Deducted from asset accounts: Allowance for doubtful accounts $ 7.3 .9 (.2 ) (.2 ) 7.8 Deferred tax asset valuation allowance 266.8 23.4 290.2 2008 Deducted from asset accounts: Allowance for doubtful accounts $ 7.5 .1 (.2 ) (.1 ) 7.3 Deferred tax asset valuation allowance 214.1 52.7 266.8 2007 Deducted from asset accounts: Allowance for doubtful accounts $ 10.4 .7 (3.6 ) 7.5 Deferred tax asset valuation allowance 205.8 8.3 214.1 * Amounts primarily represent changes in foreign currency exchange rates.

Document Information

Document Information
	12 Months Ended Dec. 31, 2009 USD / shares
Document Type	10-K
Amendment Flag	false
Document Period End Date	2009-12-31

Entity Information

Entity Information (USD $)
	12 Months Ended Dec. 31, 2009	Jan. 31, 2010	Jun. 30, 2009
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		191,136,278
Entity Public Float			$10,365,158,000