10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                     to                     

Commission file number 1-8590

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	71-0361522
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)
200 Peach Street, P.O. Box 7000, El Dorado, Arkansas	71731-7000
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (870) 862-6411

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock, $1.00 Par Value	New York Stock Exchange
Series A Participating Cumulative Preferred Stock Purchase Rights	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes   x    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x     No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes   x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No   x

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter (as of June 30, 2011) – $12,706,062,000.

Number of shares of Common Stock, $1.00 Par Value, outstanding at January 31, 2012 was 193,877,158.

Documents incorporated by reference:

Portions of the Registrant’s definitive Proxy Statement relating to the Annual Meeting of Stockholders on May 9, 2012 have been incorporated by reference in Part III herein.

MURPHY OIL CORPORATION

TABLE OF CONTENTS – 2011 FORM 10-K

		Page Number
	PART I
Item 1.	Business		1
Item 1A.	Risk Factors		15
Item 1B.	Unresolved Staff Comments		20
Item 2.	Properties		20
Item 3.	Legal Proceedings		21
Item 4.	(Removed and Reserved)
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		22
Item 6.	Selected Financial Data		23
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		24
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		54
Item 8.	Financial Statements and Supplementary Data		55
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		55
Item 9A.	Controls and Procedures		55
Item 9B.	Other Information		55
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance		56
Item 11.	Executive Compensation		56
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		56
Item 13.	Certain Relationships and Related Transactions, and Director Independence		56
Item 14.	Principal Accounting Fees and Services		56
	PART IV
Item 15.	Exhibits, Financial Statement Schedules		57
Signatures			60

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PART I

Item 1. BUSINESS

Summary

Murphy Oil Corporation is a worldwide oil and gas exploration and production company with retail and wholesale gasoline marketing operations in the United States and refining and marketing operations in the United Kingdom. As used in this report, the terms Murphy, Murphy Oil, we, our, its and Company may refer to Murphy Oil Corporation or any one or more of its consolidated subsidiaries.

The Company was originally incorporated in Louisiana in 1950 as Murphy Corporation. It was reincorporated in Delaware in 1964, at which time it adopted the name Murphy Oil Corporation, and was reorganized in 1983 to operate primarily as a holding company of its various businesses. Its operations are classified into two business activities: (1) “Exploration and Production” and (2) “Refining and Marketing.” For reporting purposes, Murphy’s exploration and production activities are subdivided into six geographic segments, including the United States, Canada, Malaysia, the United Kingdom, Republic of the Congo and all other countries. Murphy’s refining and marketing activities are subdivided into segments for the United States and the United Kingdom. Additionally, “Corporate” activities include interest income, interest expense, foreign exchange effects and administrative costs not allocated to the segments.

The information appearing in the 2011 Annual Report to Security Holders (2011 Annual Report) is incorporated in this Form 10-K report as Exhibit 13 and is deemed to be filed as part of this Form 10-K report as indicated under Items 1, 2 and 7.

In addition to the following information about each business activity, data about Murphy’s operations, properties and business segments, including revenues by class of products and financial information by geographic area, are provided on pages 24 through 46, F-17 and F-18, F-46 through F-52 and F-54 of this Form 10-K report and on pages 5 and 6 of the 2011 Annual Report.

At December 31, 2011, Murphy had 8,610 employees, including 3,176 full-time and 5,434 part-time.

Interested parties may obtain the Company’s public disclosures filed with the Securities and Exchange Commission (SEC), including Form 10-K, Form 10-Q, Form 8-K and other documents, by accessing the Investor Relations section of Murphy Oil Corporation’s Web site at www.murphyoilcorp.com.

Exploration and Production

The Company’s exploration and production business explores for and produces crude oil, natural gas and natural gas liquids worldwide. The Company’s exploration and production management team in Houston, Texas, directs the Company’s worldwide exploration and production activities.

During 2011, Murphy’s principal exploration and production activities were conducted in the United States by wholly owned Murphy Exploration & Production Company – USA (Murphy Expro USA), in Malaysia, Republic of the Congo, Indonesia, Suriname, Australia, Brunei and the Kurdistan region of Iraq by wholly owned Murphy Exploration & Production Company – International (Murphy Expro International) and its subsidiaries, in Western Canada and offshore Eastern Canada by wholly owned Murphy Oil Company Ltd. (MOCL) and its subsidiaries, and in the U.K. North Sea and the Atlantic Margin by wholly owned Murphy Petroleum Limited. Murphy’s crude oil and natural gas liquids production in 2011 was in the United States, Canada, Malaysia, the United Kingdom and Republic of the Congo; its natural gas was produced and sold in the United States, Canada, Malaysia and the United Kingdom. MOCL owns a 5% undivided interest in Syncrude Canada Ltd. in northern Alberta, one of the world’s largest producers of synthetic crude oil.

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Unless otherwise indicated, all references to the Company’s oil and gas production volumes and proved oil and gas reserves are net to the Company’s working interest excluding applicable royalties.

Murphy’s worldwide crude oil, condensate and natural gas liquids production in 2011 averaged 103,160 barrels per day, a decrease of 19% compared to 2010. The decrease was primarily due to lower 2011 oil production at the Kikeh field, offshore Sabah Malaysia, where several wells were shut-in for a portion of the year for well work due to sand production issues. The Company’s worldwide sales volume of natural gas averaged 457 million cubic feet (MMCF) per day in 2011, up 28% from 2010 levels. The higher natural gas sales volume in 2011 was primarily attributable to increased natural gas production in the Montney area of Western Canada, where the Company’s Tupper West area commenced gas production in early 2011 and where further development operations led to higher gas production at Tupper, and at fields offshore Sarawak Malaysia. Total worldwide 2011 production on a barrel of oil equivalent basis (six thousand cubic feet of natural gas equals one barrel of oil) was 179,388 barrels per day, a decrease of 4% compared to 2010.

Total production in 2012 is currently expected to average about 200,000 barrels of oil equivalent per day. The projected production increase of approximately 11% in 2012 is primarily related to higher natural gas production at the Tupper West area in Western Canada due to continued drilling, higher oil production at Kikeh following the well work program and additional field development operations, and higher oil and gas volumes produced in the Eagle Ford Shale area of South Texas as the Company continues to ramp-up its drilling program in the area. These volumes are expected to more than offset production declines in 2012 at other producing fields.

United States

In the United States, Murphy primarily has production of oil and/or natural gas from fields in the deepwater Gulf of Mexico, in the Eagle Ford Shale area of South Texas and onshore in South Louisiana. The Company produced approximately 17,100 barrels of oil per day and 47 million cubic feet of natural gas per day in the U.S. in 2011. These amounts represented 17% of the Company’s total worldwide oil and 10% of worldwide natural gas production volumes. During 2011, approximately 45% of total U.S. hydrocarbon production was produced at two operated Gulf of Mexico fields – Thunder Hawk and Medusa. The Company holds a 60% interest at Medusa in Mississippi Canyon Blocks 538/582, which produced total daily oil and natural gas of about 6,000 barrels and 6 MMCF, respectively, in 2011. Production from Medusa is expected to continue to decline in 2012 and should average 4,300 barrels of oil and about 4 MMCF of natural gas on a daily basis. At December 31, 2011, the Medusa field had total proved oil and natural gas reserves of approximately 5.8 million barrels and 5.9 billion cubic feet, respectively. Murphy has a 37.5% working interest in the Thunder Hawk field in Mississippi Canyon Block 734. Oil and natural gas production at Thunder Hawk averaged about 3,800 barrels of oil per day and 4 MMCF per day in 2011. Production in 2012 at Thunder Hawk is expected to average approximately 3,200 barrels of oil per day and 3 MMCF per day. The lower 2012 production at Thunder Hawk is due to well decline and a delay in performing drilling operations caused by permitting issues following the Macondo incident in 2010. Proved oil and natural gas reserves at Thunder Hawk at year-end 2011 were 3.3 million barrels and 4.0 billion cubic feet, respectively.

The Company has acquired rights to significant acreage in South Texas in the Eagle Ford Shale unconventional oil and gas play. The Company has eight active drilling rigs in the Eagle Ford in early 2012, with plans to exit 2012 with ten to twelve rigs in operation. Current plans are to drill approximately 130 wells in the play in 2012. The Company is primarily concentrating drilling efforts in the areas of the Eagle Ford where oil is the primary hydrocarbon produced. Lower natural gas price realization has caused the Company’s drilling in the gas-prone areas to be limited to acreage where drilling is necessary to retain leases. Totals for 2011 oil and natural gas production in the Eagle Ford area were approximately 3,200 barrels per day and 3.3 MMCF per day, respectively. Due to ongoing drilling and infrastructure development activities, 2012 production is expected to be approximately 12,000 barrels of oil per day and 20 billion cubic feet of natural gas per day. At December 31, 2011, the Company’s proved reserves in the Eagle Ford Shale area totaled 35.7 million barrels of oil and 38.2 billion cubic feet of natural gas. Total proved U.S. oil and natural gas reserves at December 31, 2011 were 55.3 million barrels and 98.4 billion cubic feet, respectively.

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Subsequent to the Macondo incident in April 2010, the process for obtaining drilling and other operational permits in the Gulf of Mexico has been extended significantly. The changes to the permitting process, as well as operational procedures, are expected to continue to cause delays and add more expense associated with drilling operations in the Gulf of Mexico. Therefore, the Company anticipates that its production, and likely many other companies’ production, will be adversely affected in the Gulf of Mexico during 2012 and possibly beyond because of permitting delays. The Company is unable to predict to what extent these delays and additional processes will ultimately impact its operations in the Gulf of Mexico.

Canada

In Canada, the Company owns an interest in three significant non-operated assets – the Hibernia and Terra Nova fields offshore Newfoundland in the Jeanne d’Arc Basin and Syncrude Canada Ltd. in northern Alberta. In addition, the Company owns interests in one heavy oil area, two significant natural gas areas and light oil prospective acreage in the Western Canadian Sedimentary Basin (WCSB).

Murphy has a 6.5% working interest in Hibernia, while at Terra Nova the Company’s working interest is 10.475%. The joint agreement between owners of Terra Nova required a one-time redetermination of working interests based on an analysis of reservoir quality among fault separated areas where varying ownership interests exist. The redetermination process was essentially completed in 2010 and the Company’s working interest was reduced from 12.0% to 10.475% effective January 1, 2011. The Company had recorded cumulative expense of $102.1 million through 2010 based on the anticipated settlement of the working interest reduction. The Company made a settlement payment to certain Terra Nova partners in January 2011 to equalize the value of oil sold and costs incurred since about March 2005 related to the difference between the Company’s 10.475% ultimate working interest and its original 12.0% interest. The final settlement paid was less than the Company’s original estimate and, therefore, a credit of $5.4 million was recorded to income in 2011. Oil production in 2011 was about 6,100 barrels of oil per day at Hibernia and 3,100 barrels per day at Terra Nova. Hibernia production decreased slightly in 2011 due to lower gross production and a higher royalty rate, while Terra Nova experienced well downtime and the Company’s working interest was reduced from 12.0% in 2010 to 10.475% in 2011. Oil production for 2012 at Hibernia and Terra Nova is anticipated to be approximately 5,700 barrels per day and 2,800 barrels per day, respectively. Production declines at both fields in 2012 due to anticipated downtime for extended maintenance. Total proved oil reserves at December 31, 2011 at Hibernia and Terra Nova were approximately 10.8 million barrels and 6.6 million barrels, respectively.

Murphy owns a 5% undivided interest in Syncrude Canada Ltd., a joint venture located about 25 miles north of Fort McMurray, Alberta. Syncrude utilizes its assets, which include three coking units, to extract bitumen from oil sand deposits and to upgrade this bitumen into a high-value synthetic crude oil. Production in 2011 was about 13,500 barrels of synthetic crude oil per day and is expected to average about 14,200 barrels per day in 2012. Total proved reserves for Syncrude at year-end 2011 were 129.5 million barrels.

Daily production in 2011 in the WCSB averaged about 7,300 barrels of mostly heavy oil and about 189 MMCF of natural gas. Through 2011, the Company has acquired approximately 156,000 net acres of mineral rights in the northeastern British Columbia Montney area, including Tupper and Tupper West. Natural gas production commenced at Tupper in December 2008, while Tupper West production started up in February 2011. Oil and natural gas daily production for 2012 in Western Canada, excluding Syncrude, is expected to be about 10,200 barrels and 243 MMCF, respectively. The increase in oil production in 2012 is primarily due to an ongoing drilling program in the Seal heavy oil area. The increase in natural gas volumes in 2012 is primarily due to ramp-up of production at Tupper West associated with wells added from an ongoing drilling program. The initial production rates for Tupper West wells have been significantly better than anticipated at project sanction. However, natural gas prices in North America have weakened significantly in early 2012. Should natural gas prices in Canada continue to remain weak during 2012, the Company may elect to delay its development drilling program in the Tupper and Tupper West areas. This would lead to lower natural gas production volumes in the WCSB in 2012 and possibly beyond. Total Western Canada proved oil and natural gas reserves at December 31, 2011, excluding Syncrude, were 19.2 million barrels and 633.6 billion cubic feet, respectively.

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Through 2011, the Company has acquired approximately 146,000 net acres of land in Southern Alberta that is prospective for light oil. The Company began drilling operations on this acreage in early 2011. Several wells were expensed as dry holes during 2011. One well was on production test in early 2012. Additional wells are planned throughout 2012 to test various formations.

Malaysia

In Malaysia, the Company has majority interests in six separate production sharing contracts (PSCs). The Company serves as the operator of all these areas other than the Kakap development. The production sharing contracts cover approximately 3.74 million gross acres. Murphy has an 85% interest in discoveries made in two shallow-water blocks, SK 309 and SK 311, offshore Sarawak. In January 2010, Murphy relinquished all other acreage in Blocks SK 309 and SK 311, while retaining the acreage surrounding its producing oil and gas fields as well as areas surrounding its other discoveries, where development projects are ongoing or planned in the future. About 7,100 barrels of oil per day were produced in 2011 at Block SK 309/311, with 60% at the West Patricia field and the remainder mostly associated with gas liquids produced at other Sarawak fields. Oil production in 2012 at fields in Blocks SK 309/311 is anticipated to total about 6,000 barrels of oil per day. The Company has a gas sales contract for the Sarawak area with PETRONAS, the Malaysian state-owned oil company, and has an ongoing multi-phase development plan for several natural gas discoveries on these blocks. The gas sales contract allows for gross sales volumes of up to 250 MMCF per day through 2014, with an option to extend for seven years at 250 MMCF per day or for ten years at 350 MMCF per day. Total net natural gas sales volume offshore Sarawak was about 177 MMCF per day during 2011 (gross 242 MMCF per day). Sarawak net natural gas sales volumes are anticipated to be approximately 168 MMCF per day in 2012. Total proved reserves of oil and natural gas at December 31, 2011 for Blocks SK 309/311 were 4.7 million barrels and 253.9 billion cubic feet, respectively.

The Company made a major discovery at the Kikeh field in deepwater Block K, offshore Sabah, in 2002 and added another important discovery at Kakap in 2004. Several additional discoveries have been made in Block K at other areas. In 2006, the Company relinquished a portion of Block K and was granted a 60% interest in an extension of a portion of Block K. In 2011, the Company relinquished the remainder of Block K except for the discovered fields, including Kikeh and Kakap. Total gross acreage held by the Company in Block K as of December 31, 2011 was 1.02 million acres. Production volumes at Kikeh averaged 41,500 barrels of oil per day during 2011. Kikeh oil production declined significantly in 2011 compared to the prior year due to several wells being shut down for a portion of the year due to sand and fines produced with the oil. An extensive work program was undertaken and initial results have been successful and as expected. Oil production at Kikeh is anticipated to average approximately 49,400 barrels per day for 2012 as the development program there continues. In February 2007, the Company signed a Kikeh field natural gas sales contract with PETRONAS that calls for gross sales volumes of up to 120 MMCF per day through June 2012. Gas production at Kikeh is slated to continue thereafter until the earlier of lack of available commercial quantities of Kikeh associated gas reserves or expiry of the Block K production sharing contract. Natural gas production at Kikeh began in late 2008, and 2011 production totaled approximately 40 MMCF per day in 2011. Daily gas production in 2012 at Kikeh is expected to average about 49 MMCF per day. The Kakap field in Block K is operated by another company. This field is being jointly developed with the Gumusut field owned by others. Kakap development activities continued during 2011 and first production is anticipated in late 2012 or early 2013. The Siakap North oil discovery was made in 2009; the field will be a unitized development operated by Murphy. The field is presently under development as a tie-back to the Kikeh field and first oil production is currently anticipated in 2013. Total proved reserves booked in Block K as of year-end 2011 were 99.7 million barrels of oil and 93.9 billion cubic feet of natural gas.

The Company also has an interest in deepwater Block H offshore Sabah. In early 2007, the Company announced a significant natural gas discovery at the Rotan well in Block H. In early 2008, the Company followed up Rotan with a discovery at Biris. In March 2008, the Company renewed the contract for Block H at a 60% interest while retaining 80% interest in the Rotan and Biris discoveries. In 2010 another natural gas discovery was made in

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Block H at Dolfin, and in early 2012, an additional gas discovery was made at Buluh. In 2011, the Company relinquished 30% of Block H, but retained all discovered fields. Total gross acreage held by the Company at year-end 2011 in Block H was 1.40 million acres. In early 2006, the Company added a 60% interest in a PSC covering Block P, which includes 1.05 million gross acres of the previously relinquished Block K area, offshore Sabah.

Murphy has a 75% interest in gas holding agreements for Kenarong and Pertang discoveries made in Block PM 311, located offshore peninsular Malaysia. Development options are being studied for these discoveries. Murphy relinquished its remaining interests in Block PM 311 and all of adjacent Block PM 312 in 2007.

United Kingdom

Murphy produces oil and natural gas in the United Kingdom sector of the North Sea. Total 2011 production in the U.K. amounted to about 2,400 barrels of oil per day and 4 MMCF of natural gas per day. Total 2012 daily production levels in the U.K. are anticipated to average about 3,000 barrels of oil and 5 MMCF of natural gas. In 2011, the Schiehallion partners approved a redevelopment plan comprising a subsea equipment upgrade with additional flowlines and new risers as well as a new floating production, storage and offloading vessel. The old vessel will be removed in 2013 and production is scheduled to resume through the new vessel in early 2016. Total proved reserves in the U.K. at December 31, 2011 were 21.6 million barrels of oil and 21.0 billion cubic feet of natural gas.

Republic of the Congo

The Company has interests in Production Sharing Agreements (PSA) covering two offshore blocks in Republic of the Congo – Mer Profonde Sud (MPS) and Mer Profonde Nord (MPN). The Company’s interests cover approximately 1.33 million gross acres with water depths ranging from 490 to 6,900 feet, and the Company serves as operator of both blocks. In 2005, Murphy made an oil discovery at Azurite Marine #1 in the southern block, MPS. The Company successfully followed up the Azurite discovery with other appraisal wells. First oil production occurred at the Azurite field in August 2009. Total oil production in 2011 averaged 5,000 barrels per day at Azurite for the Company’s 50% interest. Anticipated production in 2012 is 3,700 barrels per day, with the decrease caused by natural decline at producing wells. Total proved oil reserves at the Azurite field as of December 31, 2011 were 2.3 million barrels. A significant revision was made in 2011 to reduce proved oil reserves at the Azurite field. The reserve revision was necessary based on the significantly lower oil recovery from producing wells. The reserve reduction led to an impairment charge of $368.6 million during 2011. In late 2010, the Company successfully negotiated an amendment to the PSA covering the MPS block. The new terms were officially approved in February 2011 and were effective retroactive to October 1, 2010. Essentially, the amendment revised terms of the PSA that allocates additional levels of crude oil production to the accounts of the Company and its non-government partners in future periods. The Company paid a bonus to Republic of the Congo in connection with the PSA amendment. A wildcat well drilled at Titane Marine in 2010 in the MPN block found accumulations of crude oil for which appraisal plans are pending. Development options are currently being studied. Other prospects in the MPN block are being evaluated and exploration wells are being planned for 2012.

Australia

The Company holds three exploration permits in Australia and serves as operator of each. A number of exploration wells will be drilled on the permits between 2012 and 2015. A 40% interest in Block AC/P36 in the Browse Basin offshore northwestern Australia covering 1.00 million gross acres was acquired in 2007 and one unsuccessful well has been drilled. The Company expects to increase its working interest in this block to 100% in 2012. Block WA-423P, also in the Browse Basin, was acquired in November 2008. The permit covers approximately 1.43 million gross acres with the Company holding a 40% working interest. Three-dimensional seismic has been acquired and a one year extension of the permit has been granted. Block NT/P80 in the Bonaparte Basin, offshore northwestern Australia, was acquired in June 2009 and covers approximately 1.21 million gross acres. Two-dimensional seismic was acquired and processed in 2011 on this block on which the Company’s working interest is 40%.

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Indonesia

In May 2008, the Company entered into a production sharing contract in Indonesia, at a 100% interest, in the South Barito block in south Kalimantan on the island of Borneo. The block covers approximately 1.24 million gross acres. The agreement calls for relinquishment of 25% of acreage during 2012. The contract permits a six-year exploration term with an optional four-year extension. The work commitment calls for geophysical work, 2D seismic acquisition and processing, and two exploration wells. In November 2008, Murphy entered into a production sharing contract in the Semai II block offshore West Papua. The Company has a 28.3% interest in the block which covers about 835 thousand gross acres. The permit calls for a 3D seismic program and three exploration wells. The 3D seismic was acquired in 2010, while the first exploration well in the Semai II block was drilled in early 2011 and was unsuccessful. Multiple additional drilling prospects are currently being evaluated. In December 2010, Murphy entered into a production sharing contract in the Wokam II block offshore West Papua, Moluccas and Papua. Murphy has a 100% interest in the block which covers 1.22 million gross acres. The three-year work commitment calls for seismic acquisition and processing, which the Company expects to begin in 2012. In November 2011, the Company acquired a 100% interest in a production sharing contract in the Semai IV block offshore West Papua. The concession includes 873 thousand gross acres. The agreement calls for work commitments of seismic acquisition and processing. Murphy is the operator of all the Indonesian concessions.

Brunei

In late 2010, the Company entered into two production sharing agreements for properties offshore Brunei. The Company has a 5% working interest in Block CA-1 and a 30% working interest in Block CA-2. These blocks cover a significant portion of acreage formerly held by the Company in Malaysia Blocks L and M. The Malaysian Production Sharing Contracts covering Blocks L and M were terminated in early 2010. The CA-1 and CA-2 blocks cover 1.44 million and 1.49 million gross acres, respectively. The first two exploration wells in Block CA-2 and the initial well in Block CA-1 were drilled in 2011 and were unsuccessful.

Iraq

In late 2010, the Company finalized an agreement with the Kurdistan Regional Government (KRG) in Iraq to acquire an interest in the Central Dohuk block. The Company operates and holds a 50% interest in the block. The Central Dohuk block covers approximately 153 thousand gross acres and is located in the Dohuk area of the Kurdistan region in Iraq. The Company shot seismic in 2011 and plans an exploration well in 2012. In July 2011, the Company entered into an agreement with KRG to acquire a 20% non-operated interest in the Baranan block. Baranan covers approximately 178 thousand acres, and exploration plans call for seismic acquisition and the first exploration well in 2012.

Suriname

In June 2007, Murphy entered into a production sharing contract covering Block 37, offshore Suriname. Murphy operates this block and has a 100% working interest, subject to a potential reduction to 80% should the state oil company exercise its back-in option. Block 37 covers approximately 2.16 million gross acres and has water depths ranging from 160 to 1,000 feet. The contract provides for a six-year exploration period with two phases. Phase I has a four-year period that requires the acquisition of 3D seismic and the drilling of two wells. The 3D seismic was shot in late 2008 and early 2009, and interpretation of this data occurred in 2009. The first two exploration wells were drilled in late 2010 and early 2011 and were unsuccessful. Further exploration activities are presently being evaluated.

In December 2011, Murphy signed a production sharing contract with Suriname’s state oil company, Staatsolie Maatschappij Suriname N.V. (Staatsolie), whereby it acquired a 100% working interest and operatorship of Block 48 offshore Suriname. The block encompasses 794 thousand acres with water depths ranging from 1,000 to 3,000 meters. The 30-year contract is divided into an exploration period and one or more development and

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production periods, and may be extended with mutual agreement of Murphy and Staatsolie. There are three phases of the exploration period, with each divided into two-year terms, thereby allowing the Company to withdraw from the contract or enter into the next phase. Minimum work obligations vary during each exploration phase and may require either seismic data acquisition or drilling of an exploratory well. Staatsolie has the right to join in the development and production of each commercial field within the contract area with up to a 20% participation.

Cameroon

In October 2011, Murphy was granted government approval to acquire a 50% working interest and operatorship of the NTEM concession. The working interest was acquired from Sterling Cameroon Limited (Sterling) via a farm-out agreement. Sterling retained a 50% non-operated interest in the block. The NTEM block, situated in the Douala Basin offshore Cameroon, encompasses 514 thousand gross acres, with water depths ranging from 300 to 1,900 meters. The concession is currently in force majeure, pending the resolution of a border dispute with neighboring Equatorial Guinea. When force majeure is lifted, there will be 15 months of the first renewal period remaining which can be extended for a further two years under the second renewal period option in the contract. Each of the renewal periods requires a minimum work obligation involving the drilling of exploratory wells.

Ecuador

Murphy sold its 20% working interest in Block 16, Ecuador in March 2009. The Company has accounted for all Ecuador operations as discontinued operations. In October 2007, the government of Ecuador passed a law that increased its share of revenue for sales prices that exceed a base price (about $23.36 per barrel at December 31, 2008) from 50% to 99%. The government had previously enacted a 50% revenue sharing rate in April 2006. The Company initiated arbitration proceedings against the government in one international jurisdiction claiming that they did not have the right under the contract to enact the revenue sharing provision. In 2010, the arbitration panel determined that it lacked jurisdiction over the claim due to technicalities. The arbitration was refiled in 2011 under a different international jurisdiction and present activities involve selection of arbiters. The arbitration proceeding is likely to take many months to reach conclusion. The Company’s total claim in the arbitration process is approximately $118 million.

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Proved Reserves

Total proved oil and natural gas reserves as of December 31, 2011 are presented in the following table.

	Proved Reserves
	Oil		Synthetic Oil		Natural Gas
	(millions of barrels)				(billions of cubic feet)
Proved Developed Reserves:
United States		20.8		—		58.2
Canada		32.6		120.5		427.1
Malaysia		57.2		—		210.5
United Kingdom		5.1		—		15.8
Republic of the Congo		2.3		—		—
Total proved developed reserves		118.0		120.5		711.6
Proved Undeveloped Reserves:
United States		34.5		—		40.2
Canada		4.0		9.0		211.8
Malaysia		47.2		—		137.3
United Kingdom		16.5		—		5.2
Republic of the Congo		—		—		—
Total proved undeveloped reserves		102.2		9.0		394.5
Total proved reserves		220.2		129.5		1,106.1

Proved Undeveloped Reserves

Murphy’s proved undeveloped reserves at December 31, 2011 increased 67.7 million barrels of oil equivalent (MMBOE) from a year earlier. Approximately 24.8 MMBOE of proved undeveloped reserves were converted to proved developed reserves during 2011. The majority of the proved undeveloped reserves migration to the proved developed category occurred at the Tupper and Tupper West gas areas, as these areas had active development work ongoing during the year. The conversion of non-proved reserves to newly reported proved undeveloped reserves occurred at several areas including, but not limited to, the Tupper, Tupper West and Eagle Ford Shale areas and the Kikeh field. During 2011, there were 11.7 MMBOE of positive revisions for proved undeveloped reserves. The majority of proved undeveloped reserves additions associated with revisions of previous estimates were the result of development drilling and well performance at the Kikeh field in Malaysia. The Company spent $422.1 million in 2011 to convert proved undeveloped reserves to proved developed reserves. The Company expects to spend about $2.1 billion in 2012, $1.4 billion in 2013 and $520 million in 2014 to move currently undeveloped proved reserves to the developed category. The higher level of spend in 2012 is caused by significant drilling in the year at several locations, including the Kikeh field, the Eagle Ford Shale and the Tupper West area. In computing MMBOE, natural gas is converted to equivalent barrels of oil using a ratio of six thousand cubic feet (MCF) to one barrel of oil.

At December 31, 2011, proved reserves are included for several development projects that are ongoing, including natural gas developments at the Tupper West area in British Columbia and offshore Sarawak Malaysia, and an oil development at Kakap, offshore Sabah Malaysia. Total proved undeveloped reserves associated with various development projects at December 31, 2011 were approximately 177 MMBOE, which is 33% of the Company’s total proved reserves. Certain of these development projects have proved undeveloped reserves that will take more than five years to bring to production. Three such projects have significant levels of such proved undeveloped reserves. The Company operates a deepwater field in the Gulf of Mexico that has two undeveloped locations that exceed this five-year window. Total reserves associated with the two wells amount to less than 1% of the Company’s total proved reserves at year-end 2011. The development of certain of this field’s reserves stretches beyond five years due to limited well slots available on the production platform, thus making it

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necessary to wait for depletion of other wells prior to initiating further development of these two locations. The Kakap field oil development project has undeveloped proved reserves that make up less than 3% of the Company’s total proved reserves at year-end 2011. This non-operated project will take longer than five years to develop due to long lead-time equipment required to complete the development process in the deep waters offshore Sabah Malaysia. The third project that will take more than five years to develop is offshore Malaysia and makes up approximately 1% of the Company’s total proved reserves at year-end 2011. This project is an extension of the Sarawak natural gas project and should be on production in 2014 once current project production volumes decline.

Murphy Oil’s Reserves Processes and Policies

The Company employs a General Manager of Corporate Reserves (General Manager) who is independent of the Company’s oil and gas management. The General Manager reports to an Executive Vice President of Murphy Oil Corporation, who in turn reports directly to the President of the Company. The General Manager makes presentations to the Board of Directors periodically about the Company’s reserves. The General Manager reviews and discusses reserves estimates directly with the Company’s reservoir engineering staff in order to make every effort to ensure compliance with the rules and regulations of the SEC and industry. The General Manager coordinates and oversees reserves audits. These audits are performed annually and target coverage of approximately one-third of Company reserves each year. The audits are performed by the General Manager and qualified engineering staff from areas of the Company other than the area being audited. The General Manager may also utilize qualified independent reserves consultants to assist with the internal audits or to perform separate audits as considered appropriate. On occasion, the Company may use independent reserves consultants to determine its proved reserves reported in this Form 10-K. At December 31, 2011, the Company utilized Ryder Scott Company, L.P., an independent petroleum engineering company, to prepare estimated proved oil and natural gas reserves for the Eagle Ford Shale area in South Texas and the United Kingdom. The total estimated proved reserves prepared by Ryder Scott represented 16% of the Company’s total proved oil reserves and 5% of the total proved natural gas reserves as of December 31, 2011. Ryder Scott’s report, including a description of their engineer’s technical qualifications for estimating reserves, is included as Exhibit 99.6 to this Annual Report on Form 10-K.

Each significant exploration and production office maintains one or more Qualified Reserve Estimators (QRE) on staff. The QRE is responsible for estimating and evaluating reserves and other reserves information for his or her assigned area. The QRE may personally make the estimates and evaluations of reserves or may supervise and approve the estimation and evaluation thereof by others. A QRE is professionally qualified to perform these reserves estimates due to having sufficient educational background, professional training and professional experience to enable him or her to exercise prudent professional judgment. Normally, this requires a minimum of three years practical experience in petroleum engineering or petroleum production geology, with at least one year of such experience being in the estimation and evaluation of reserves, and either a bachelors or advanced degree in petroleum engineering, geology or other discipline of engineering or physical science from a college or university of recognized stature, or the equivalent thereof from an appropriate government authority or professional organization.

Larger Company offices also employ a Regional Reserves Coordinator (RRC) who supervises the local QREs. The RRC is usually a senior QRE that has the primary responsibility for coordinating and submitting reserves information to senior management.

The Company’s QREs maintain files containing pertinent data regarding each significant reservoir. Each file includes sufficient data to support the calculations or analogies used to develop the values. Examples of data included in the file, as appropriate, include: production histories; pertinent drilling and workover histories; bottom hole pressure data; volumetric, material balance, analogy or other pertinent reserve estimation data; production performance curves; narrative descriptions of the methods and logic used to determine reserves values; maps and logs; and a signed copy of the conclusion of the QRE stating, that in their opinion, the reserves

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have been calculated, reviewed, documented and reported in compliance with the regulations and guidelines contained in the reserves training manual. The Company’s reserves are maintained in an industry recognized reservoir engineering software system, which has adequate access controls to avoid the possibility of improper manipulation of data.

When reserves calculations are completed by QREs and appropriately reviewed by RRCs and the General Manager, the conclusions are reviewed and discussed with the head of the Company’s exploration and production business and other senior management as appropriate. The Company’s Controller’s department is responsible for preparing and filing reserves schedules within Form 10-K.

Murphy provides annual training to all company reserve estimators to ensure SEC requirements associated with reserve estimation and associated Form 10-K reporting are fulfilled. The training includes materials provided to each participant that outlines the latest guidance from the SEC as well as best practices for many engineering and geologic matters related to reserve estimation.

Qualifications of General Manager of Corporate Reserves

The Company believes that it has qualified employees generating oil and gas reserves. Mr. Brad Gouge serves as General Manager of Corporate Reserves after joining the Company in mid-2008. Prior to that time, Mr. Gouge was Vice President at a major petroleum engineering consulting firm. He previously was a production and then reservoir engineer with a major integrated oil company. Mr. Gouge earned a Bachelors of Science degree in Petroleum Engineering from Texas A&M University and has attended numerous industry training courses. Mr. Gouge is a registered Professional Engineer in the state of Texas and is an instructor for a Society of Petroleum Engineers (SPE) Petroleum Reserves course. He is also co-author of two papers on estimating petroleum reserves which have been published by the SPE and serves on the SPE Oil and Gas Reserves Committee (ORGC), as well as, the Joint Committee on Reserves Evaluator Training (JCORET).

More information regarding Murphy’s estimated quantities of proved oil and gas reserves for the last three years are presented by geographic area on pages F-48 and F-49 of this Form 10-K report. Murphy has not filed and is not required to file any estimates of its total proved oil or gas reserves on a recurring basis with any federal or foreign governmental regulatory authority or agency other than the U.S. Securities and Exchange Commission. Annually, Murphy reports gross reserves of properties operated in the United States to the U.S. Department of Energy; such reserves are derived from the same data from which estimated proved reserves of such properties are determined.

Crude oil, condensate and gas liquids production and sales, and natural gas sales by geographic area with weighted average sales prices for each of the seven years ended December 31, 2011 are shown on page 5 of the 2011 Annual Report. In 2011, the Company’s production of oil and natural gas represented approximately 0.1% of worldwide totals.

Production expenses for the last three years in U.S. dollars per equivalent barrel are discussed beginning on page 33 of this Form 10-K report. For purposes of these computations, natural gas sales volumes are converted to equivalent barrels of oil using a ratio of six MCF of natural gas to one barrel of oil.

Supplemental disclosures relating to oil and gas producing activities are reported on pages F-46 through F-54 of this Form 10-K report.

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At December 31, 2011, Murphy held leases, concessions, contracts or permits on developed and undeveloped acreage as shown by geographic area in the following table. Gross acres are those in which all or part of the working interest is owned by Murphy. Net acres are the portions of the gross acres attributable to Murphy’s interest.

	Developed				Undeveloped				Total
Area (Thousands of acres)	Gross		Net		Gross		Net		Gross		Net
United States – Onshore		16		12		287		234		303		246
– Gulf of Mexico		13		5		1,027		635		1,040		640
– Alaska		4		1		2		–		6		1
Total United States		33		18		1,316		869		1,349		887
Canada – Onshore, excluding oil sands		63		57		610		561		673		618
– Offshore		94		8		117		10		211		18
– Oil sands – Syncrude		96		5		160		8		256		13
Total Canada		253		70		887		579		1,140		649
Malaysia		164		136		3,580		2,194		3,744		2,330
United Kingdom		34		4		17		2		51		6
Republic of the Congo		1		–		1,332		902		1,333		902
Suriname		–		–		2,959		2,959		2,959		2,959
Australia		–		–		3,640		1,456		3,640		1,456
Indonesia		–		–		4,174		3,218		4,174		3,218
Brunei		–		–		2,934		519		2,934		519
Cameroon		–		–		514		257		514		257
Iraq		–		–		331		112		331		112
Spain		–		–		36		6		36		6
Totals		485		228		21,720		13,073		22,205		13,301

Certain acreage held by the Company will expire in the next three years. Scheduled expirations in 2012 include 36 thousand net acres in Block PM 311 in Malaysia; and 188 thousand net acres in the United States. In 2013, 485 thousand net acres expire in Block H Malaysia; 629 thousand net acres expire in Block P Malaysia; 433 thousand acres in Block 37 in Suriname; and 116 thousand net acres expire in the United States. In 2014, 447 thousand net acres expire in South Barito Indonesia; 96 thousand net acres expire in Semai II Indonesia; 405 thousand net acres expire in Semai IV Indonesia; 619 thousand net acres expire in Wokam Indonesia; 448 thousand net acres expire in Blocks MPS and MPN in Republic of the Congo; and 134 thousand net acres expire in the United States.

As used in the three tables that follow, “gross” wells are the total wells in which all or part of the working interest is owned by Murphy, and “net” wells are the total of the Company’s fractional working interests in gross wells expressed as the equivalent number of wholly owned wells.

The following table shows the number of oil and gas wells producing or capable of producing at December 31, 2011.

	Oil Wells				Gas Wells
Country	Gross		Net		Gross		Net
United States		81		43		21		12
Canada		364		266		141		141
Malaysia		32		26		34		29
United Kingdom		36		3		23		2
Republic of the Congo		6		3		–		–
Totals		519		341		219		184

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Murphy’s net wells drilled in the last three years are shown in the following table.

	United States				Canada				Malaysia				United Kingdom				Other				Totals
	Pro- ductive		Dry		Pro- ductive		Dry		Pro- ductive		Dry		Pro- ductive		Dry		Pro- ductive		Dry		Pro- ductive		Dry
2011
Exploratory		17.9		–		1.0		4.9		0.9		–		–		–		–		2.3		19.8		7.2
Development		14.3		0.8		117.5		6.0		12.8		–		–		–		0.5		–		145.1		6.8
2010
Exploratory		9.2		–		–		–		6.8		0.8		–		0.1		1.0		2.5		17.0		3.4
Development		–		–		87.0		5.0		23.6		–		–		–		2.5		–		113.1		5.0
2009
Exploratory		1.3		0.6		–		–		5.6		1.6		–		–		0.5		0.7		7.4		2.9
Development		1.1		–		42.0		3.0		17.0		–		0.4		–		0.5		–		61.0		3.0

Murphy’s drilling wells in progress at December 31, 2011 are shown below.

	Exploratory				Development				Total
Country	Gross		Net		Gross		Net		Gross		Net
United States		13		11.9		6		3.6		19		15.5
Canada		–		–		7		7.0		7		7.0
Malaysia		–		–		2		1.6		2		1.6
Totals		13		11.9		15		12.2		28		24.1

Refining and Marketing

The Company’s refining and marketing businesses are located in the United States and United Kingdom. The U.S. business primarily consists of retail marketing of petroleum products through a large chain of motor refueling stations. Most of these stations are located on or near Walmart store sites, with the remaining stations located at other high traffic sites that are near major thoroughfares. The U.S. business entered the renewable fuels business and acquired an ethanol production facility in North Dakota during 2009, and also purchased an unfinished ethanol production facility in Texas in 2010 that was completed and began operations in 2011. Additionally, the U.S. operations include refined product terminals, and a crude oil and refined products trading business. The Company sold both its U.S. petroleum refineries at Meraux, Louisiana and Superior, Wisconsin, and certain associated marketing assets in 2011. The U.K. business primarily consists of operations that refine crude oil and other feedstocks into petroleum products such as gasoline and distillates, buy and sell crude oil and refined products, and transport and market petroleum products. The Company has announced its intention to sell its U.K. refining and marketing operations.

Murphy Oil USA, Inc. (MOUSA), a wholly owned subsidiary of Murphy Oil Corporation, markets refined products through a network of retail gasoline stations and unbranded wholesale customers in a 23-state area, primarily in the Southern and Midwestern United States. Murphy’s retail stations are located in 23 states and are primarily located in the parking lots of Walmart Supercenters using the brand name Murphy USA^®. The Company’s stations also include stand-alone locations using the Murphy Express^® brand. At December 31, 2011, the Company marketed products through 1,128 Murphy owned and operated stations. Of the Company stations, 1,003 are located on parking lots of Walmart Supercenters and 125 are stand-alone Murphy Express locations. MOUSA plans to build additional retail gasoline stations at Walmart Supercenters and other stand-alone locations in 2012 and beyond.

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Below is a table that lists the states where we operate Company-owned retail sites at December 31, 2011 and the number of retail sites in each state.

State	No. of stations		State	No. of stations		State	No. of stations
Alabama		65	Kansas		1	New Mexico		6
Arkansas		60	Kentucky		37	Ohio		42
Colorado		1	Louisiana		60	Oklahoma		50
Florida		99	Michigan		23	South Carolina		44
Georgia		77	Minnesota		7	Tennessee		75
Iowa		21	Missouri		46	Texas		236
Illinois		26	Mississippi		48	Virginia		3
Indiana		32	North Carolina		69	Total		1,128

Refined products are supplied from six terminals that are wholly owned and operated by MOUSA and at numerous terminals owned by others. Three of the wholly owned terminals are supplied by marine transportation and three are supplied by pipeline. MOUSA also receives products at terminals owned by others either in exchange for deliveries from the Company’s terminals or by outright purchase.

The Company owns land underlying 899 of the stations on Walmart parking lots. No rent is payable to Walmart for the owned locations. For the remaining gasoline stations located on Walmart property that are not owned, Murphy has master agreements that allow the Company to rent land from Walmart. The master agreements contain general terms applicable to all rental sites in the United States. The terms of the agreements range from 10-15 years at each station, with Murphy holding two successive five-year extension options at each site. The agreements permit Walmart to terminate the agreements in their entirety, or only as to affected sites, at its option for the following reasons: Murphy vacates or abandons the property; Murphy improperly transfers the rights under this agreement to another party; an agreement or a premises is taken upon execution or by process of law; Murphy files a petition in bankruptcy or becomes insolvent; Murphy fails to pay its debts as they become due; Murphy fails to pay rent or other sums required to be paid within 90 days after written notice; or Murphy fails to perform in any material way as required by the agreements. Sales from the Company’s U.S. retail marketing stations represented 47.4% of consolidated Company revenues in 2011, 53.1% in 2010 and 51.4% in 2009. As the Company continues to expand the number of retail operated gasoline stations, total revenue generated by this business is expected to grow. MOUSA’s share of retail gasoline sales was approximately 2.6% of the total U.S. market during 2011.

In addition to the refined products sold at our retail gasoline stations, our stores carry a broad selection of snacks, beverages, tobacco products, and non-food merchandise. Our merchandise offer includes two private label products available at our retail stations, including an isotonic drink offered in several flavors and a private label energy drink. In 2011, we purchased more than 90% of our merchandise from a single vendor, McLane’s Company, Inc., a wholly owned subsidiary of Berkshire Hathaway, Inc. The following table shows certain information with respect to our merchandise sales for the last three years:

	2011			2010			2009
Merchandise sales (in millions)	$	2,115.6			1,969.2			1,706.3
Merchandise sales revenue per store month	$	158,144			153,530			137,623
Merchandise margin as a percentage of merchandise sales		12.8	%		13.1	%		12.5	%

In October 2009, MOUSA acquired an ethanol production facility located in Hankinson, North Dakota, to enter the renewable fuels business as a complement to our retail operations. The $92 million purchase price was primarily financed by $82 million of seller-provided nonrecourse debt. The Company chose in 2010 to pay off the nonrecourse debt early. The facility is designed to produce 110 million gallons of corn-based ethanol per year. Ethanol production in 2011 totaled 116.4 million gallons at Hankinson. The Company acquired a partially constructed ethanol production facility in Hereford, Texas, in late 2010. The Company paid $40 million for the

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facility at purchase and spent approximately $25.1 million to complete construction of the facility. The Hereford facility is designed with production capacity of 105 million gallons of corn-based ethanol per year, and commenced operation near the end of the first quarter of 2011. Total annualized ethanol production during the last six months of 2011 amounted to about 90 million gallons at Hereford. In addition to the ethanol production at each location, the Hankinson plant produces dried distillers grain with solubles (DDGS) and the Hereford plant produces wet distillers grains with solubles (WDGS), which are both sold to local farmers and other available outlets as an additional source of income. During 2011, the Company sold 358,000 tons of DDGS and 535,000 tons of WDGS.

Murphy owns an interest in a crude oil pipeline with a diameter of 24 inches that connects storage at the Louisiana Offshore Oil Port (LOOP) at Clovelly, Louisiana, to the Meraux refinery. Murphy owns a 40.1% interest in the first 22 miles of this pipeline from Clovelly to Alliance, Louisiana, and 100% of the remaining 24 miles from Alliance to Meraux. After the sale of the Meraux refinery in late 2011, the Company uses this pipeline to transport crude oil for two major companies for a throughput fee.

Murco Petroleum Limited (Murco), a wholly owned U.K. subsidiary, owns 100% interest in a refinery at Milford Haven, Pembrokeshire, Wales. The refinery is located on a 1,200 acre site owned by the Company; 750 acres are used by the refinery and the remainder is rented for agricultural use. The Milford Haven, Wales, refinery was shut down for a plant-wide turnaround in early 2010. During the downtime, the Company completed an expansion project that increased the plant’s crude oil throughput capacity from 108,000 barrels per day to 135,000 barrels per day. The refinery has consistently performed at or above nameplate capacity during 2011. Murphy has announced its intention to sell the Milford Haven refinery as well as U.K. marketing assets.

Refinery capacities at Milford Haven, Wales at December 31, 2011 are shown in the following table.

Crude capacity – barrels per stream day	135,000
Process capacity – barrels per stream day
Vacuum distillation	55,000
Catalytic cracking – fresh feed	37,000
Naphtha hydrotreating	18,300
Catalytic reforming	18,300
Distillate hydrotreating	74,000
Isomerization	11,300
Production capacity – barrels per stream day
Alkylation	6,300
Crude oil and product storage capacity – barrels	8,908,000

At the end of 2011, Murco distributed refined products in the United Kingdom from the wholly-owned Milford Haven refinery, three wholly owned terminals supplied by rail, six terminals owned by others where products are received in exchange for deliveries from the Company’s terminals and eight terminals owned by others where products are purchased for delivery. At December 31, 2011, there were 233 Company stations, 222 of which were branded MURCO with the remainder under various third party brands. The Company owns the freehold under 149 of the sites and leases the remainder. The Company also supplied 226 MURCO branded dealer stations at year-end 2011.

In 2011, Murphy owned approximately 7.5% of the refining capacity in the United Kingdom. MURCO’s fuel sales represented 2.1% of the total U.K. market share in 2011.

A statistical summary of key operating and financial indicators for each of the seven years ended December 31, 2011 are reported on page 6 of the 2011 Annual Report.

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Environmental

Murphy’s businesses are subject to various U.S. federal, state and local environmental, health and safety laws and regulations, and are also subject to similar laws and regulations in other countries in which it operates. These regulatory requirements continue to change and increase in number and complexity, and the requirements govern the manner in which the company conducts its operations and the products it sells. The Company anticipates more environmental regulations in the future in the countries where it has operations.

Further information on environmental matters and their impact on Murphy are contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 41 through 46.

Web site Access to SEC Reports

Our Internet Web site address is http://www.murphyoilcorp.com. Information contained on our Web site is not part of this report on Form 10-K.

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on our Web site, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC. Alternatively, you may access these reports at the SEC’s Web site at http://www.sec.gov.

Item 1A. RISK FACTORS

Murphy Oil’s businesses operate in highly competitive environments, which could adversely affect it in many ways, including its profitability, its ability to grow, and its ability to manage its businesses.

Murphy operates in the oil and gas industry and experiences intense competition from other oil and gas companies, which include state-owned foreign oil companies, major integrated oil companies, independent producers of oil and natural gas and independent refining and marketing companies. Virtually all of the state-owned and major integrated oil companies and many of the independent producers and refiners that compete with the Company have substantially greater resources than Murphy. In addition, the oil industry as a whole competes with other industries in supplying energy requirements around the world. Murphy competes, among other things, for valuable acreage positions, exploration licenses, drilling equipment and human resources.

If Murphy cannot replace its oil and natural gas reserves, it will not be able to sustain or grow its business.

Murphy continually depletes its oil and natural gas reserves as production occurs. In order to sustain and grow its business, the Company must successfully replace the crude oil and natural gas it produces with additional reserves. Therefore, it must create and maintain a portfolio of good prospects for future reserve additions and production by obtaining rights to explore for, develop and produce hydrocarbons in promising areas. In addition, it must find, develop and produce and/or purchase reserves at a competitive cost structure to be successful in the long-term. Murphy’s ability to operate profitably in the exploration and production segments of its business, therefore, is dependent on its ability to find, develop and produce and/or purchase oil and natural gas reserves at costs that are less than the realized sales price for these products and at costs competitive with competing companies in the industry.

Murphy’s proved reserves are based on the professional judgment of its engineers and may be subject to revision.

Proved oil and natural gas reserves included in this report on pages F-48 and F-49 have been prepared by qualified Company personnel or qualified independent engineers based on an unweighted average of oil and natural gas prices in effect at the beginning of each month in 2010 and 2011 as well as other conditions and information available at the time the estimates were prepared. Estimation of reserves is a subjective process that involves professional judgment by engineers about volumes to be recovered in future periods from underground crude oil and natural gas reservoirs. Estimates of economically recoverable crude oil and natural gas reserves and

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future net cash flows depend upon a number of variable factors and assumptions, and consequently, different engineers could arrive at different estimates of reserves and future net cash flows based on the same available data and using industry accepted engineering practices and scientific methods. Under existing SEC rules, reported proved reserves must be reasonably certain of recovery in future periods.

Actual future crude oil and natural gas production may vary substantially from the reported quantity of our proved reserves due to a number of factors, including:

• Oil and natural gas prices which are materially different than prices used to compute proved reserves

• Operating and/or capital costs which are materially different than those assumed to compute proved reserves

• Future reservoir performance which is materially different from models used to compute proved reserves, and

• Governmental regulations or actions which materially change operations of a field.

The Company’s proved undeveloped reserves represent significant portions of total proved reserves. As of December 31, 2011, approximately 32% of the Company’s proved oil reserves and 36% of proved natural gas reserves are undeveloped. The ability of the Company to reclassify these undeveloped proved reserves to the proved developed classification is generally dependent on the successful completion of one or more operations, which might include further development drilling, construction of facilities or pipelines, and well workovers.

The discounted future net revenues from our proved reserves as reported on page F-53 should not be considered as the market value of the reserves attributable to our properties. As required by generally accepted accounting principles, the estimated discounted future net revenues from our proved reserves are based on an unweighted average of the oil and natural gas prices in effect at the beginning of each month during the year. Actual future prices and costs may be materially higher or lower than those used in the reserves computations. In addition, the 10 percent discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under generally accepted accounting principles is not necessarily the most appropriate discount factor based on our cost of capital and the risks associated with our business and the crude oil and natural gas business in general.

Volatility in the global prices of oil, natural gas and petroleum products significantly affects the Company’s operating results.

The most significant variables affecting the Company’s results of operations are the sales prices for crude oil and natural gas that it produces. West Texas Intermediate (WTI) crude oil prices averaged about $95 per barrel in 2011, $80 per barrel in 2010 and $62 per barrel in 2009. Earnings for the exploration and production business were favorably impacted in 2011 by the higher oil prices. The Company’s net income is also significantly affected by changes in the margins on refining and marketing operations. As demonstrated in 2011, the sales prices for oil and natural gas can be significantly different in U.S. markets compared to markets in foreign locations. The Company cannot predict how changes in the sales prices of oil and natural gas and changes in refining and marketing margins will affect its results of operations in future periods. Except in limited cases, the Company typically does not seek to hedge any significant portion of its exposure to the effects of changing prices of crude oil, natural gas and refined products. Certain of the Company’s crude oil production is heavy and more sour than WTI quality crude; therefore, this crude oil usually sells at a discount to WTI and other light and sweet crude oils. In addition, the sales prices for heavy and sour crude oils do not always move in relation to price changes for WTI and lighter/sweeter crude oils. However, certain oil and natural gas production, particularly in Sarawak Malaysia and the U.K., was sold at a premium to average U.S. natural gas prices in 2011 due to different pricing structures for gas in these regions.

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Exploration drilling results can significantly affect the Company’s operating results.

The Company generally drills numerous wildcat wells each year which subjects its exploration and production operating results to significant exposure to dry holes expense, which have adverse effects on, and create volatility for, the Company’s net income. In 2011, significant wildcat wells were primarily drilled offshore Brunei, Indonesia and Suriname. The Company’s 2012 exploratory drilling program includes wells onshore in Western Canada and Kurdistan and offshore in the Gulf of Mexico, Brunei, Republic of the Congo, Australia and Malaysia.

Capital financing may not always be available to fund Murphy’s activities.

Murphy usually must spend and risk a significant amount of capital to find and develop reserves before revenue is generated from production. Although most capital needs are funded from operating cash flow, the timing of cash flows from operations and capital funding needs may not always coincide, and the levels of cash flow may not fully cover capital funding requirements. Therefore, the Company maintains financing arrangements with lending institutions to meet certain funding needs. The Company must periodically renew these financing arrangements based on foreseeable financing needs or as they expire. The Company’s primary bank financing facility was renewed in 2011 and now expires in June 2016. Although not considered likely, there is the possibility that financing arrangements may not always be available at sufficient levels required to fund the Company’s activities 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 September 2012. Outstanding notes of $350 million mature in April 2012. Although not considered likely, the Company may not be able in the future to sell notes at reasonable rates in the marketplace.

Murphy has limited or virtually no control over several factors that could adversely affect the Company.

The ability of the Company to successfully manage development and operating costs is important because virtually all of the products it sells are energy commodities such as crude oil, natural gas and refined products, for which the Company has little or no influence on the sales prices or regional and worldwide consumer demand for these products. As an example, an economic slowdown in 2009 had a detrimental effect on the worldwide demand for these energy commodities, which effectively lead to reduced prices for oil, natural gas and refined products. Lower prices for crude oil and natural gas inevitably lead to lower earnings in the Company’s exploration and production operations. Murphy is a net purchaser of crude oil and other refinery feedstocks in the U.K., and also purchases refined products, particularly gasoline, needed to supply its U.S. retail marketing stations. Therefore, its most significant costs are subject to volatility of prices for these commodities. The Company also often experiences pressure on its operating and capital expenditures in periods of strong crude oil, natural gas and refined product prices because an increase in exploration and production activities due to high oil and gas sales prices generally leads to higher demand for, and consequently higher costs for, goods and services in the oil and gas industry.

Many of the Company’s major oil and natural gas producing properties are operated by others. Therefore, Murphy does not fully control all activities at certain of its significant revenue generating properties. During 2011, approximately 19% of the Company’s total production was at fields operated by others, while at December 31, 2011, approximately 38% of the Company’s total proved reserves were at fields operated by others.

Murphy’s operations and earnings have been and will continue to be affected by worldwide political developments.

Many governments, including those that are members of the Organization of Petroleum Exporting Countries (OPEC), unilaterally intervene at times in the orderly market of crude oil and natural gas produced in their countries through such actions as setting prices, determining rates of production, and controlling who may buy and sell the production. As of December 31, 2011, approximately 31% of proved reserves, as defined by the

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U.S. Securities and Exchange Commission, were located in countries other than the U.S., Canada and the U.K. Certain of the reserves held outside these three countries could be considered to have more political risk. In addition, prices and availability of crude oil, natural gas and refined products could be influenced by political unrest and by various governmental policies to restrict or increase petroleum usage and supply. Other governmental actions that could affect Murphy’s operations and earnings include tax changes, royalty increases and regulations concerning: currency fluctuations, protection and remediation of the environment, concerns over the possibility of global warming being affected by human activity including the production and use of hydrocarbon energy, preferential and discriminatory awarding of oil and gas leases, restrictions on drilling and/or production, restraints and controls on imports and exports, safety, and relationships between employers and employees. Because these and other factors too numerous to list are subject to changes caused by governmental and political considerations and are often made in response to changing internal and worldwide economic conditions and to actions of other governments or specific events, it is not practical to attempt to predict the effects of such factors on Murphy’s future operations and earnings.

Murphy’s business is subject to operational hazards and risks normally associated with the exploration for and production of oil and natural gas and the refining and marketing of crude oil and petroleum products.

The Company operates in urban and remote, and often inhospitable, areas around the world. The occurrence of an event, including but not limited to acts of nature such as hurricanes, floods, earthquakes and other forms of severe weather, and mechanical equipment failures, industrial accidents, fires, explosions, acts of war and intentional terrorist attacks could result in the loss of hydrocarbons and associated revenues, environmental pollution or contamination, and personal injury, including death, for which the Company could be deemed to be liable, and which could subject the Company to substantial fines and/or claims for punitive damages.

In April 2010, a drilling accident and subsequent oil spill occurred in the Gulf of Mexico at the Macondo well owned by other companies. In May 2010, the U.S. President placed a temporary moratorium on new drilling in the Gulf of Mexico that forced the Company to defer planned exploration drilling in the Gulf of Mexico, and to renegotiate a drilling contract to move a deepwater drilling rig to Republic of the Congo. Further impacts of the accident and oil spill include added delays in deepwater Gulf of Mexico drilling activities, and additional future regulations covering offshore drilling operations, plus expected higher costs for future drilling operations and offshore insurance. The permitting delays and other restrictions associated with drilling and similar operations in the Gulf of Mexico are expected to have an adverse affect on the Company’s, and likely many other companies’, volume and costs of oil and natural gas produced in this area.

The location of many of Murphy’s key assets causes the Company to be vulnerable to severe weather, including hurricanes and tropical storms. A number of significant oil and natural gas fields lie in offshore waters around the world. Probably the most vulnerable of the Company’s offshore fields are in the U.S. Gulf of Mexico, where severe hurricanes and tropical storms have often led to shutdowns and damages. The U.S. hurricane season runs from June through November, but the most severe storm activities usually occur in late summer, such as with Hurricanes Katrina and Rita in 2005. Other assets such as gasoline terminals and certain retail gasoline stations also lie near the Gulf of Mexico coastline and are vulnerable to storm damages. Although the Company maintains insurance for such risks as described below, due to policy deductibles and possible coverage limits, weather-related risks are not fully insured.

Murphy’s insurance may not be adequate to offset costs associated with certain events and there can be no assurance that insurance coverage will continue to be available in the future on terms that justify its purchase.

Murphy maintains insurance against certain, but not all, hazards that could arise from its operations. The Company maintains liability insurance sufficient to cover its share of gross insured claim costs up to approximately $700 million per occurrence and in the annual aggregate. These policies have up to $10 million in deductibles. Generally, this insurance covers various types of third party claims related to personal injury, death

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and property damage, including claims arising from “sudden and accidental” pollution events. The Company also maintains insurance coverage with an additional limit of $250 million per occurrence ($700 million for Gulf of Mexico operations not related to a named windstorm), all or part of which could be applicable to certain sudden and accidental pollution events. The occurrence of an event that is not insured or not fully insured could have a material adverse effect on the Company’s financial condition and results of operations in the future. During 2005, damages from hurricanes caused a temporary shut-down of certain U.S. oil and gas production operations as well as the Meraux, Louisiana, refinery. The Company repaired the Meraux refinery and it restarted operations in mid-2006, but the Company did not fully recover repair costs incurred at Meraux under its insurance policies. See Note P in the consolidated financial statements for further discussion.

Lawsuits against Murphy and its subsidiaries could adversely affect its operating results.

The Company is involved in numerous lawsuits seeking cash settlements for alleged personal injuries, property damages and other business-related matters.

The Company is exposed to credit risks associated with sales of certain of its products to third parties.

Although Murphy limits its credit risk by selling its products to numerous entities worldwide, it still, at times, carries substantial credit risk from its customers. For certain oil and gas properties operated by the Company, other companies which own partial interests may not be able to meet their financial obligation to pay for their share of capital and operating costs as they come due.

Murphy’s operations could be adversely affected by changes in foreign currency conversion rates.

The Company’s worldwide operational scope exposes it to risks associated with foreign currencies. Most of the Company’s business is transacted in U.S. dollars, therefore, the Company and most of its subsidiaries are U.S. dollar functional entities for accounting purposes. However, the Canadian dollar is the functional currency for all Canadian operations and the British pound is the functional currency for U.K. refining and marketing operations. In certain countries, such as Malaysia, the United Kingdom and Canada, significant levels of transactions occur in currencies other than the functional currency. In Malaysia, such transactions include tax payments, while in the U.K., virtually all crude oil feedstock purchases and certain bulk product sales are priced in U.S. dollars, and in Canada, certain crude oil sales are priced in U.S. dollars. This exposure to currencies other than the functional currency can lead to significant impacts on consolidated financial results. In Malaysia, known future tax payments based in local currency are usually hedged with contracts that match tax payment amounts and dates to lock in the exchange rate between the U.S. dollar and Malaysian ringgit. Exposures associated with deferred income tax liability balances in Malaysia are not hedged. A strengthening of the Malaysian ringgit against the U.S. dollar would be expected to lead to currency losses in consolidated income; gains would be expected if the ringgit weakens versus the dollar. Foreign exchange exposures between the U.S. dollar and the British pound are not hedged due to the frequency and volatility of U.S. dollar transactions in the U.K. downstream business. The Company would generally expect to incur currency losses when the U.S. dollar strengthens against the British pound. In Canada, currency risk is often managed by selling forward U.S. dollars to match the collection dates for crude oil sold in that currency. See Note L in the consolidated financial statements for additional information on derivative contracts.

The costs and funding requirements related to the Company’s retirement plans are affected by several factors.

A number of actuarial assumptions impact funding requirements for the Company’s retirement plans. The most significant of these assumptions include return on assets, long-term interest rates and mortality. If the actual results for the plans vary significantly from the actuarial assumptions used, or if laws regulating such retirement plans are changed, Murphy could be required to make more significant funding payments to one or more of its retirement plans in the future and/or it could be required to record a larger liability for future obligations in its Consolidated Balance Sheet.

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Item 1B. UNRESOLVED STAFF COMMENTS

The Company had no unresolved comments from the staff of the U.S. Securities and Exchange Commission as of December 31, 2011.

Item 2. PROPERTIES

Descriptions of the Company’s oil and natural gas and refining and marketing properties are included in Item 1 of this Form 10-K report beginning on page 1. Information required by the Securities Exchange Act Industry Guide No. 2 can be found in the Supplemental Oil and Gas Information section of this Annual Report on Form 10-K on pages F-46 to F-54 and in Note E–Property, Plant and Equipment beginning on page F-17.

Executive Officers of the Registrant

The age at January 1, 2012, present corporate office and length of service in office of each of the Company’s executive officers are reported in the following listing. Executive officers are elected annually but may be removed from office at any time by the Board of Directors.

David M. Wood – Age 54; President and Chief Executive Officer and Director and Member of the Executive Committee since January 2009. Mr. Wood served as Executive Vice President responsible for the Company’s worldwide exploration and production operations from January 2007 through December 2008 and President of Murphy Exploration & Production Company-International from March 2003 through December 2006.

Kevin G. Fitzgerald – Age 56; Executive Vice President and Chief Financial Officer since December 2011. Mr. Fitzgerald was Senior Vice President and CFO from January 2007 to November 2011. He served as Treasurer from July 2001 through December 2006.

Roger W. Jenkins – Age 50; Executive Vice President Exploration and Production since August 2009. Mr. Jenkins has served as President of the Company’s exploration and production subsidiary since January 2009. He was Senior Vice President, North America for this subsidiary from September 2007 to December 2008, and prior to that time, held various positions, including General Manager of the Company’s exploration and production operations in Sabah, Malaysia.

Thomas McKinlay – Age 48; Executive Vice President, World Wide Downstream Operations since January 2011. Mr. McKinlay was Vice President, U.S. Manufacturing from August 2009 to January 2011. Mr. McKinlay also became President of the Company’s U.S. refining and marketing subsidiary effective January 2011 and was Vice President, Supply and Transportation of this subsidiary from April 2009 to January 2011. From August 2008 to March 2009, Mr. McKinlay was General Manager, Supply and Transportation of this U.S. subsidiary, and from January 2007 to August 2008 was Supply Director for the Company’s U.K. refining and marketing subsidiary.

Bill H. Stobaugh – Age 60; Executive Vice President, Corporate Planning & Business Development since February 2012. Mr. Stobaugh was Senior Vice President from February 2005 to January 2012.

Walter K. Compton – Age 49; Senior Vice President and General Counsel since March 2011. Mr. Compton was Vice President, Law from February 2009 to February 2011 and was Manager, Law from November 1996 to January 2009.

John W. Eckart – Age 53; Senior Vice President and Controller since December 2011. Mr. Eckart was Vice President and Controller from January 2007 to November 2011, and has served as Controller since March 2000.

Mindy K. West – Age 42; Vice President and Treasurer since January 2007. Ms. West was Director of Investor Relations from July 2001 through December 2006.

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Kelli M. Hammock – Age 40; Vice President, Administration since December 2009. Ms. Hammock was General Manager, Administration from June 2006 to November 2009.

Thomas J. Mireles – Age 39; Vice President, Corporate Planning & Development since February 2012. Mr. Mireles was General Manager, Planning & Analysis from June 2010 to January 2012. He had previously served as Senior Manager, Business Development from February 2009 to May 2010 and was Manager, Business Development from January 2007 to January 2009.

John A. Moore – Age 44; Secretary since March 2011. Mr. Moore was Senior Attorney from August 2005 to February 2011.

Item 3. LEGAL PROCEEDINGS

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 matters referred to in this item is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

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PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The Company’s Common Stock is traded on the New York Stock Exchange using “MUR” as the trading symbol. There were 2,212 stockholders of record as of December 31, 2011. Information as to high and low market prices per share and dividends per share by quarter for 2011 and 2010 are reported on page F-55 of this Form 10-K report.

SHAREHOLDER RETURN PERFORMANCE PRESENTATION

The following graph presents a comparison of cumulative five-year shareholder returns (including the reinvestment of dividends) as if a $100 investment was made on December 31, 2006 for the Company, the Standard & Poor’s 500 Stock Index (S&P 500 Index) and the NYSE ARCA Oil Index. This performance information is “furnished” by the Company and is not considered as “filed” with this Form 10-K and it is not incorporated into any document that incorporates this Form 10-K by reference.

	2006		2007		2008		2009		2010		2011
Murphy Oil Corporation		100		169		89		111		156		119
S&P 500 Index		100		105		66		84		97		99
NYSE ARCA Oil Index		100		134		87		98		115		119

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Item 6. SELECTED FINANCIAL DATA

(Thousands of dollars except per share data)	2011		2010		2009		2008		2007
Results of Operations for the Year
Sales and other operating revenues	$	27,689,332		20,225,764		16,800,972		24,134,820		15,573,086
Net cash provided by continuing operations		1,999,875		3,028,070		1,770,205		2,863,748		1,438,079
Income from continuing operations		740,932		779,559		713,854		1,764,631		560,570
Net income		872,702		798,081		837,621		1,739,986		766,529
Per Common share – diluted
Income from continuing operations	$	3.81		4.03		3.71		9.18		2.93
Net income		4.49		4.13		4.35		9.06		4.01
Cash dividends per Common share		1.10		1.05		1.00		.875		.675
Percentage return on1
Average stockholders’ equity		9.9		10.3		12.5		29.1		16.8
Average borrowed and invested capital		9.2		9.4		10.9		24.4		13.9
Average total assets		5.7		5.9		7.0		15.1		8.5
Capital Expenditures for the Year 2
Continuing operations
Exploration and production	$	2,768,222		2,034,828		1,807,561		1,928,346		1,740,327
Refining and marketing		122,301		290,090		263,413		348,476		481,959
Corporate and other		5,218		5,899		22,967		3,235		4,146
		2,895,741		2,330,817		2,093,941		2,280,057		2,226,432
Discontinued operations		48,071		117,323		113,328		84,629		130,915
	$	2,943,812		2,448,140		2,207,269		2,364,686		2,357,347
Financial Condition at December 31
Current ratio		1.22		1.21		1.55		1.51		1.37
Working capital	$	622,743		619,783		1,194,087		958,818		777,530
Net property, plant and equipment		10,475,149		10,367,847		9,065,088		7,727,718		7,109,822
Total assets		14,138,138		14,233,243		12,756,359		11,149,098		10,535,849
Long-term debt		249,553		939,350		1,353,183		1,026,222		1,516,156
Stockholders’ equity		8,778,397		8,199,550		7,346,026		6,278,945		5,066,174
Per share		45.31		42.52		38.44		32.92		26.70
Long-term debt – percent of capital employed1		2.8		10.3		15.6		14.0		23.0

¹  Company management uses certain measures for assessing our business results, including percentage return on average stockholders’ equity, percentage return on average borrowed and invested capital, and percentage return on average total assets. Additionally, we measure our long-term debt leverage using long-term debt as a percentage of total capital employed (long-term debt plus stockholders’ equity). We consistently disclose these financial measures because we believe our shareholders and other interested parties find such measures helpful in understanding trends and results of the Company and as a comparison of Murphy Oil to other companies in our and other industries.

Specifically, these measures were computed as follows for each year.

• Percentage return on average stockholders’ equity – net income for the year (as per the consolidated statement of income) divided by a 12-month average for January to December of total stockholders’ equity.

• Percentage return on average borrowed and invested capital – the sum of net income for the year (as per the consolidated statement of income) plus after-tax interest expense for the year divided by a 12-month average for January to December of the sum of total long-term debt plus total stockholders’ equity.

• Percentage return on average total assets – net income for the year (as per the consolidated statement of income) divided by a 12-month average for January to December of total consolidated assets.

• Long-term debt – percent of capital employed – total long-term debt at the balance sheet date (as per the consolidated balance sheet) divided by the sum of total long-term debt plus total stockholders’ equity at that date (as per the consolidated balance sheet).

These financial measures may be calculated differently than similarly titled measures that may be presented by other companies.

²  Capital expenditures presented here include accruals for incurred but unpaid capital activities, while property additions and dry holes in the Statements of Cash Flows are cash-based capital expenditures and do not include capital accruals and geological, geophysical and certain other exploration expenses that are not eligible for capitalization under oil and gas accounting rules.

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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

Murphy Oil Corporation is a worldwide oil and gas exploration and production company with petroleum marketing operations in the United States and refining and marketing operations in the United Kingdom. A more detailed description of the Company’s significant assets can be found in Item 1 of this Form 10-K report.

Murphy generates revenue by selling oil and natural gas production to customers in the United States, Canada, Malaysia, the United Kingdom and other countries. Additionally, the Company generates revenue by selling refined petroleum and ethanol products at hundreds of locations in the United States and the United Kingdom. The Company’s revenue is highly affected by the prices of oil, natural gas and refined petroleum products that it sells. Also, because crude oil is purchased by the Company for U.K. refinery feedstocks, natural gas is purchased for fuel at its U.K. refinery and at worldwide oil production facilities, and gasoline is purchased to supply its retail gasoline stations in the U.S. that are primarily located at Walmart Supercenters, the purchase prices for these commodities also have a significant effect on the Company’s costs. In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products, amortization of capital expenditures and expenses related to exploration and administration. Profits and generation of cash in the Company’s refining and marketing operations are dependent upon achieving adequate margins, which are determined by the sales prices for refined petroleum products less the costs of purchased refinery feedstocks and gasoline and expenses associated with manufacturing, transporting and marketing these products. Murphy also incurs certain costs for general company administration and for capital borrowed from lending institutions and note holders.

Worldwide oil prices were significantly higher in 2011 than 2010, but North American natural gas prices were weaker in 2011 than in the prior year. The sales price for a barrel of West Texas Intermediate (WTI) crude oil averaged $95.11 in 2011, $79.61 in 2010 and $62.05 in 2009. The NYMEX natural gas price per million British Thermal Units (MMBTU) averaged $4.03 in 2011, $4.38 in 2010 and $3.94 in 2009. Crude oil prices rose in 2011 primarily due to a combination of recovering demand and unrest in the oil-rich Middle East and Northern Africa. While the 2011 prices of WTI crude oil rose almost 20% compared to the prior year, crude oil sold based on other worldwide benchmark prices, such as Brent and Tapis, rose even more than WTI. The rise in prices of WTI based crude oil, which is only used as a benchmark in North America, was held back in 2011 compared to other worldwide benchmark price increases due to a somewhat temporary crude oil dislocation discount and a bit of supply/demand disparity in the continental U.S. during the year. The average price of NYMEX natural gas was 8% lower in 2011 than 2010. The disparity between crude oil and natural gas prices in North America continued to widen during 2011 compared to an energy equivalent basis of six thousand cubic feet of gas to one barrel of oil due to gas production growth that exceeded demand. The increase in natural gas production was primarily associated with volumes produced at a number of expanding U.S. unconventional shale gas plays. Natural gas prices in North America have declined further in early 2012 due to milder than normal winter temperatures across much of the U.S. Crude oil and North American natural gas prices were both higher in 2010 than in 2009. Crude oil prices generally strengthened in 2010 as the worldwide economy began to show signs of recovery following the deep recession that began in 2008. WTI oil prices in 2010 averaged 28% higher than 2009, while NYMEX natural gas prices increased 11%. Changes in the price of crude oil and natural gas have a significant impact on the profitability of the Company, especially the price of crude oil as oil represented approximately 57% of the total hydrocarbons produced on an energy equivalent basis (one barrel of oil equals six thousand cubic feet of natural gas) by the Company in 2011. In 2012, the percentage of hydrocarbon production represented by oil is expected to remain relatively consistent with 2011. If the prices for crude oil and natural gas should weaken in 2012 or beyond, the Company would expect this to have an unfavorable impact on operating profits for its exploration and production business. Such lower oil and gas prices could, but may not, have a favorable impact on the Company’s refining and marketing operating profits.

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Results of Operations

Net income in 2011 of $872.7 million ($4.49 per diluted share) was 9% better than net income in 2010 of $798.1 million ($4.13 per diluted share). The improvement in 2011 net income in comparison to 2010 was primarily attributable to higher oil prices in 2011 and stronger U.S. retail marketing and refining margins. These were mostly offset by an impairment charge of $368.6 million in 2011 to reduce the carrying value of the Azurite oil field offshore Republic of the Congo to fair value. The net cost of corporate activities not allocated to the operating segments was lower in 2011 than in 2010. Net income in 2011 included income from discontinued operations of $131.8 million ($0.68 per diluted share) compared to income from discontinued operations of $18.5 million ($0.10 per diluted share) in 2010. The results of discontinued operations in both years are associated with two U.S. refineries and certain associated marketing assets that were sold in 2011. Income from continuing operations was $740.9 million ($3.81 per diluted share) in 2011 compared to $779.6 million ($4.03 per diluted share) in 2010.

Murphy had net income in 2010 of $798.1 million ($4.13 per diluted share), down 5% compared to net income of $837.6 million ($4.35 per diluted share) in 2009. Net income in 2010 included income from discontinued operations of $18.5 million ($0.10 per diluted share), while 2009 had income from discontinued operations of $123.8 million ($0.64 per diluted share). The results of discontinued operations in 2010 were associated with operating income of the two U.S. refineries and associated marketing assets that were sold in 2011; income from discontinued operations in 2009 primarily arose from a $103.6 million after-tax gain on disposal of all Ecuador assets in March 2009, but also included operating income of the U.S. refineries and marketing assets sold in 2011. Income from continuing operations was $779.6 million ($4.03 per diluted share) in 2010 and $713.8 million ($3.71 per diluted share) in 2009. Income in 2010 rose for both exploration and production (E&P) and refining and marketing (R&M) operations compared to the prior year. Earnings for the Company’s E&P operations increased in 2010 primarily due to higher sales prices and sales volumes of crude oil and natural gas. The Company’s R&M earnings from continuing operations were higher in 2010 primarily due to stronger profits on U.S. retail gasoline fuel and merchandise sales. Earnings in 2010 were unfavorably affected compared to 2009 by higher net costs associated with Corporate activities that were not allocated to operating segments, with the higher costs primarily caused by an unfavorable variance for the effects of transactions denominated in foreign currencies.

Further explanations of each of these variances are found in the following sections.

2011 vs. 2010 – Net income in 2011 totaled $872.7 million ($4.49 per diluted share) compared to $798.1 million ($4.13 per diluted share) in 2010. These earnings included income from discontinued operations of $131.8 million ($0.68 per diluted share) in 2011 compared to income of $18.5 million ($0.10 per diluted share) in 2009. Discontinued operations in both years were associated with the Company’s two U.S. refineries which were sold in 2011. Income from continuing operations amounted to $740.9 million ($3.81 per diluted share) in 2011, down from $779.6 million ($4.03 per diluted share) in 2010. The lower earnings from continuing operations in 2011 was primarily attributable to a $368.6 million impairment charge to reduce the carrying value of the Azurite oil field, offshore Republic of the Congo, to fair value. Higher sales prices for worldwide crude oil and Sarawak natural gas production and higher U.S. retail marketing profits partially offset the impact of the Congo impairment.

E&P income in 2011 was $181.2 million lower than 2010, primarily attributable to the $368.6 million impairment charge at the Azurite oil field in Republic of the Congo. Other unfavorable impacts in 2011 included higher dry hole costs compared to 2010, lower crude oil sales volumes, lower North American natural gas sales prices and higher extraction costs for oil and gas produced in 2011. E&P results in 2011 benefited from a 41% higher average sales prices for crude oil produced and a 34% higher sales prices for natural gas produced offshore Sarawak, Malaysia. Income from R&M continuing operations was $59.7 million higher in 2011 compared to 2010, essentially attributable to stronger U.S. retail gasoline marketing margins of more than $0.04 per gallon and larger profits on sales of merchandise in the U.S. retail marketing business. The net costs of corporate activities were $82.8 million less in 2011 than 2010 primarily due to gains from transactions

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denominated in foreign currencies in 2011 compared to losses on such transactions in 2010. During 2011 the U.S. dollar generally strengthened in comparison to the Malaysian ringgit, which provided a favorable foreign currency impact to the Company’s earnings due to fewer U.S. dollars being required to pay 2011 and future income taxes owed in the local currency.

Sales and operating revenues were $7.5 billion more in 2011 than 2010 primarily due to higher prices realized on crude oil production and gasoline and other refined products sold by the Company. Gain on sale of assets classified in continuing operations was $21.8 million more in 2011 than 2010 principally due to a profit on sale of gas storage assets in Spain in the current year. Interest and other income (loss) in 2011 was favorable $90.5 million compared to 2010 principally due to improved income effects from transactions denominated in foreign currencies. Additionally, the Company collected higher interest income on invested cash balances in 2011 primarily due to larger average invested balances during the year. Crude oil and product purchases expense was $6.5 billion more in 2011 than 2010 due to higher costs of crude oil feedstocks at the Milford Haven, Wales refinery, higher costs for gasoline purchased for resale in the U.S. retail marketing operations and an increase in volume of merchandise purchased for resale at U.S. retail gasoline stations. Operating expenses in 2011 were $314.8 million more than 2010 mostly due to higher costs associated with the Company’s production of oil and natural gas in 2011, plus higher operating expenses at U.S. retail marketing stations, and higher power and other costs at the Milford Haven, Wales refinery. Exploration expense in 2011 was $197.6 million above 2010 primarily due to higher dry hole costs associated with unsuccessful exploratory drilling activities in Brunei, Indonesia, Canada and Suriname. Selling and general expenses rose $41.8 million in 2011 compared to 2010 primarily due to a combination of higher costs for employee compensation and professional services. Depreciation, depletion and amortization expense was down $21.1 million in 2011 mostly due to fewer barrels of oil equivalent produced in 2011 compared to 2010. Impairment of long-lived assets of $368.6 million in 2011 was attributable to a charge to reduce the net book value of the Azurite oil field to fair value. The charge was necessitated by a reduction of proved oil reserves at this field at year-end 2011. Accretion of asset retirement obligations increased $5.8 million in 2011, primarily due to future abandonment costs to be incurred on oil and gas development wells drilled in the Eagle Ford Shale and Montney areas in 2011, and higher estimated abandonment costs for existing wells in the Gulf of Mexico and offshore Malaysia and for synthetic oil operations at Syncrude in Western Canada. The income effect of the redetermination of the Company’s working interest at the Terra Nova field, offshore Eastern Canada, was favorable $23.9 million in 2011 compared to 2010. The final settlement related to the redetermination was made in early 2011 at a net cost to the Company that was $5.4 million less than previously estimated. The benefit from this reduced settlement payment was recognized in 2011. The net cost of $18.6 million in 2010 related to the portion of Terra Nova’s operating results in 2010 that were estimated to be owed to other partners upon final settlement. Due to the redetermination process, the Company’s working interest at Terra Nova was reduced from 12.0% to 10.475%. Interest expense in 2011 was $2.7 million more than 2010 primarily due to interest associated with tax reassessments in Canada in the most recent year. Interest capitalized to oil and gas development projects in 2011 was $3.3 million below 2010 due to cessation of interest capitalized upon commencement of production at the Tupper West area in Western Canada in the first quarter 2011. Income tax expense was $200.9 million more in 2011 than 2010 due to higher pretax income in 2011 plus higher exploration and impairment expenses in the year for which no tax benefit was recognizable by the Company. The effective tax rate on a consolidated basis increased from 43.9% in 2010 to 52.2% in 2011 due to a larger percentage of earnings in higher tax jurisdictions in 2011 and due to higher exploration, impairment and other expenses in foreign jurisdictions where no income tax benefit can presently be recognized due to no assurance that these expenses would be realized in 2011 or future years to reduce taxes owed. The tax rates in both 2011 and 2010 were higher than the U.S. federal statutory rate of 35.0% due to a combination of U.S. state income taxes, certain foreign tax rates that exceeded the U.S. federal tax rate, and certain exploration and other expenses in foreign taxing jurisdictions for which no income tax benefit is currently being recognized because of the Company’s uncertain ability to obtain tax benefits for these expenses in 2011 or future years. Income from discontinued operations was $113.2 million higher in 2011 than 2010 due to stronger U.S. refining margins in 2011 prior to the sale of the refineries near the end of the third quarter of 2011. Additionally, 2011 discontinued operations included a pretax gain on sale of the two U.S. refineries of $18.7 million.

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2010 vs. 2009 – Net income in 2010 was $798.1 million ($4.13 per diluted share) compared to $837.6 million ($4.35 per diluted share) in 2009. The 2010 and 2009 results included income from discontinued operations of $18.5 million ($0.10 per diluted share) and $123.8 million ($0.64 per diluted share), respectively. The discontinued operations income in 2010 included the operating results of the Meraux, Louisiana, and Superior, Wisconsin, refineries and associated marketing assets that were sold in 2011. The 2009 discontinued operations income included the operating results of these two refineries plus properties in Ecuador that were sold in March 2009 at an after-tax gain of $103.6 million. Income from continuing operations in 2010 and 2009 were $779.6 million ($4.03 per diluted share) and $713.8 million ($3.71 per diluted share), respectively. The higher 2010 income from continuing operations compared to 2009 was caused by higher earnings in both the E&P and R&M businesses, but these were partially offset by higher net costs for unallocated corporate activities.

E&P income from continuing operations improved $115.1 million in 2010, primarily due to a $10.70 per barrel higher realized sales price for crude oil in 2010. The 2009 results were impacted by two unusual items. First, an after-tax gain of $158.3 million in 2009 was derived from a recovery of certain deepwater Gulf of Mexico federal royalties paid in prior years. Second, an after-tax charge of $58.4 million was recorded in 2009 associated with a required one-time working interest redetermination at the Terra Nova field, offshore Eastern Canada. The 2010 E&P results were also favorably affected, but in less significant measures, by higher sales volumes for crude oil and natural gas and higher sales prices for natural gas. E&P was unfavorably affected in 2010 compared to the prior year by higher expenses for exploration, production, depreciation and administration. Income from R&M continuing operations was $85.6 million more in 2010, with the improvement mostly attributable to slightly more than a $0.03 per gallon improvement in margins on sale of gasoline at U.S. retail marketing stations. This was partially offset by higher net losses in 2010 for U.K. R&M operations. The net costs of corporate activities were higher by $134.9 million in 2010, mostly attributable to unfavorable effects of transactions denominated in foreign currencies. To a lesser degree, the 2010 corporate net costs were unfavorably affected by lower interest income and higher expenses for interest and administration. The unfavorable variance in foreign currency transactions in 2010 was primarily attributable to a strengthening of the Malaysian ringgit versus the U.S. dollar and weakening of the British pound sterling against the U.S. dollar during the year.

Sales and other operating revenues grew $3.4 billion in 2010 compared to 2009 mostly due to higher sales prices for gasoline and other motor fuels in the later year. Additionally, higher sales prices and sales volumes for crude oil and natural gas in the E&P segment contributed to the increase in 2010 revenue. Gain on sale of assets was $2.8 million less in 2010 than 2009 because the earlier year included a $3.9 million gain on sale of a small Canadian natural gas field. Interest and other operating income (loss) was unfavorable by $147.4 million in 2010 compared to 2009 mostly due to a $114.3 million unfavorable variance from the effects of transactions denominated in foreign currencies, plus nonrecurring interest income in 2009 of $42.0 million associated with a recovery of Federal royalties paid in prior years for production at certain deepwater Gulf of Mexico fields. The expense associated with crude oil and product purchases increased by $2.5 billion in 2010 compared to 2009 due to higher average costs for wholesale gasoline and other motor fuels which were purchased for resale at the Company’s retail fueling stations in the U.S. and U.K. and higher costs for crude oil feedstocks at the Company’s U.K. refinery. Operating expenses were $327.9 million higher in 2010 than 2009 due to a combination of higher oil and natural gas production costs and higher costs for U.S. retail gasoline station operations. Exploration expenses rose $27.1 million in 2010 compared to 2009 due to higher geophysical costs in the Gulf of Mexico and Republic of the Congo, higher amortization expense for undeveloped leases in the Eagle Ford Shale, and higher administrative office and study costs in foreign locations. Exploration costs in 2010 included lower dry hole costs in Malaysia, Australia and the U.S., which more than offset higher dry hole costs in Republic of the Congo, Suriname and the U.K. Selling and general expenses were $46.8 million more in 2010 than in 2009 primarily due to higher employee compensation costs. Depreciation, depletion and amortization expense rose $243.5 million in 2010 versus 2009 due to higher natural gas and crude oil sales volumes in 2010, higher E&P per-unit depreciation rates, and higher R&M depreciation that included a new ethanol production facility, more U.S. retail gasoline stations in operation and a crude unit expansion at the Milford Haven, Wales, refinery that was completed in 2010. Impairment of properties was nil in 2010 and $5.2 million in 2009, with the earlier year costs related to write-off of an underperforming natural gas field in the Gulf of Mexico. Accretion of asset retirement

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obligations was $5.7 million more in 2010 than 2009 primarily due to higher discounted abandonment liabilities in 2010 for wells drilled in Malaysia and for synthetic oil operations at Syncrude. Expense for redetermination of working interest at the Terra Nova field was $64.9 million less in 2010 than 2009 because the earlier year included cumulative costs for the period of December 2004 through 2009, while 2010 costs related only to that year’s operations at Terra Nova. Interest expense was $0.2 million higher in 2010 primarily due to nine months of interest in 2010 on nonrecourse debt associated with the Hankinson, North Dakota, ethanol production facility, compared to three months of interest on this debt in 2009 following the October 1, 2009 acquisition date. The nonrecourse debt was paid off by the Company in September 2010. The higher nonrecourse debt interest was mostly offset by lower interest expense on outstanding general bank financing balances in 2010. Capitalized interest was $10.2 million less in 2010 than in the prior year due to interest amounts allocated to the Sarawak natural gas development in 2009 prior to start-up of operations later that year, partially offset by higher interest allocated to the Tupper West gas development in 2010. Income tax expense in 2010 was $87.6 million more than 2009 due to higher pretax earnings and a slightly higher overall effective tax rate in the later year. The consolidated effective tax rate was 43.9% in 2010 compared to 42.2% in 2009, with the rate increase in the later year caused by a larger percentage of earnings in higher tax jurisdictions in 2010 and due to higher current year exploration and other expenses in foreign jurisdictions where no income tax benefit can presently be recognized due to no assurance that these expenses will be realized in 2010 or future years to reduce taxes owed. The tax rates in both 2010 and 2009 were higher than the U.S. federal statutory tax rate of 35.0% due to a combination of U.S. state income taxes, certain foreign tax rates that exceeded the U.S. federal tax rate, and certain exploration and other expenses in foreign taxing jurisdictions for which no income tax benefit is currently being recognized because of the Company’s uncertain ability to obtain tax benefits for these costs in 2010 or future years. Income from discontinued operations was $18.5 million ($0.10 per diluted share) in 2010 and $123.8 million ($0.64 per diluted share) in 2009. Income from discontinued operations in both years included operating results for the two U.S. petroleum refineries sold in late 2011. Income from discontinued operations in 2009 included an after-tax gain of $103.6 million on Ecuador assets which were sold in March 2009.

Segment Results – In the following table, the Company’s results of operations for the three years ended December 31, 2011, are presented by segment. More detailed reviews of operating results for the Company’s exploration and production and refining and marketing activities follow the table.

(Millions of dollars)	2011			2010			2009
Exploration and production – continuing operations
United States	$	152.7			72.7			178.0
Canada		328.0			213.8			64.8
Malaysia		812.7			659.4			561.9
United Kingdom		11.5			30.5			12.6
Republic of the Congo		(385.3	)		(77.2	)		(20.6	)
Other		(293.9	)		(92.3	)		(104.9	)
		625.7			806.9			691.8
Refining and marketing – continuing operations
United States		223.6			165.3			65.5
United Kingdom		(33.3	)		(34.7	)		(20.5	)
		190.3			130.6			45.0
Corporate and other		(75.1	)		(157.9	)		(23.0	)
Income from continuing operations		740.9			779.6			713.8
Income from discontinued operations		131.8			18.5			123.8
Net income	$	872.7			798.1			837.6

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Exploration and Production – Earnings from exploration and production (E&P) continuing operations were $625.7 million in 2011, $806.9 million in 2010 and $691.8 million in 2009.

E&P income in 2011 was $181.2 million less than in 2010 primarily due to a $368.6 million impairment charge in 2011 to reduce the carrying value of the Azurite oil field to fair value. The 2011 period also had higher exploration expense, lower crude oil sales volumes and lower North American natural gas sales prices. But the latest year benefited from higher oil and Sarawak natural gas sales prices and higher natural gas sales volumes. The Company’s realized crude oil sales prices averaged $27.43 per barrel more in 2011 than 2010. North American natural gas sales prices in 2011 were $0.26 per MCF below 2010 levels, but natural gas sales prices from fields offshore Sarawak were higher in 2011 by $1.79 per MCF. Crude oil, condensate and gas liquids sales volumes were 22% lower in 2011 compared to 2010, compared to a decrease in oil production volumes of 19% in 2011. Oil sales volumes declined more than oil production volumes during 2011 primarily due to the timing of scheduling oil sales transactions at the Kikeh field offshore Malaysia. Sales volumes at Kikeh were below production levels in 2011 due to an increase in the volume of unsold barrels at the field at the latest year-end, while in 2010, Kikeh sales volumes exceeded production, which effectively reduced the Company’s unsold inventory balance from year-end 2009. U.S. crude oil sales volumes were lower in 2011 than 2010 principally due to less production at the Thunder Hawk field in the Gulf of Mexico. Lower crude oil sales volumes in Canada in 2011 were mostly attributable to production issues and a lower Company working interest percentage in 2011 at the Terra Nova field, but this was partially offset by higher sales volumes at the Seal heavy oil field in Alberta. Crude oil sales volume in the U.K. in 2011 were below 2010 levels primarily due to lower oil volumes produced at the Schiehallion and Mungo/Monan fields during the later year. Crude oil sales volumes at Kikeh in 2011 fell compared to 2010 due to lower annual production in 2011 caused by well downtime for mechanical issues. Sales of crude oil and condensate increased at fields offshore Sarawak in 2011 due to higher volumes produced during the year. Crude oil sales volumes in Republic of the Congo fell in 2011 due to production decline at the Azurite field. Natural gas sales volumes increased 28% in 2011 and the improvement was primarily attributable to higher gas volumes produced during 2011 at the Tupper West area in Western Canada following start-up in the first quarter of the year. Natural gas sales volumes also improved in 2011 at the Tupper area in Canada and at fields offshore Sarawak; both of these areas had active development programs during 2011. Natural gas sales volumes were lower during 2011 at the Kikeh field principally due to less volumes produced because of mechanical issues with wells.

Income from E&P continuing operations in 2010 was $115.1 million more than in 2009. The increase was primarily attributable to higher sales prices for crude oil and other liquid hydrocarbons produced in 2010. The Company’s average realized sales price for crude oil, condensate and gas liquids in 2010 increased $10.70 per barrel over 2009. The Company’s average natural gas sales prices in North America and Sarawak Malaysia were also higher in 2010 than 2009. E&P income in 2009 included a $158.3 million after-tax one-time benefit from recovery of previously paid federal royalties associated with certain fields in the deep waters of the Gulf of Mexico. Although both 2010 and 2009 had charges associated with a redetermination of working interest at the Terra Nova field offshore Eastern Canada, 2009 charges were higher by $64.9 million due to 2009 including estimated costs to settle the period from December 2004 to 2009, while 2010 included only costs for that year’s operating activities. Earnings in 2010 benefited from higher crude oil and natural sales volumes compared to 2009. Crude oil and liquids sales volumes increased 2% in 2010 while natural gas sales volumes rose 91%. The increase in hydrocarbon sales volumes in 2010 led to higher expenses for production and depreciation of $225.0 million and $229.2 million, respectively. The 2010 year also had higher exploration expenses of $27.1 million compared to 2009, essentially due to higher expenses related to geophysical activities, undeveloped lease amortization and administration, which were somewhat offset by lower expenses for dry holes. Crude oil sales volumes increased in 2010 in the U.S. due to a full year of production at the Thunder Hawk field in the Gulf of Mexico; this field started producing in July 2009. Heavy oil sales volumes in Canada in 2010 were less than 2009 due to lower gross production and a higher royalty rate in the Seal area of Western Canada. Oil sales volumes in 2010 offshore Canada were below 2009 levels mostly due to lower gross production at the Terra Nova field and a higher royalty rate at the Hibernia field. Synthetic oil sales at Syncrude increased in 2010 due to higher gross production compared to 2009. Sales volumes for crude oil produced in Malaysia were lower

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in 2010 due to less production at the Kikeh field offshore Sabah. Crude oil sold in the U.K. rose in 2010 due to making up for undersold inventory barrels produced in 2009 at the Schiehallion field. Crude oil sales increased in 2010 in Republic of the Congo due to a full year of production at the Azurite field following production start-up in August 2009. Natural gas sales volumes in 2010 increased significantly compared to the prior year due to a full year of production and higher daily sales volumes at gas fields which started up in 2009 offshore Sarawak Malaysia, as well as higher sales volumes at the Tupper area in Western Canada.

The results of operations for oil and gas producing activities for each of the last three years are shown by major operating areas on pages F-51 and F-52 of this Form 10-K report. Average daily production and sales rates and weighted average sales prices are shown on page 5 of the 2011 Annual Report.

A summary of oil and gas revenues, including intersegment sales that are eliminated in the consolidated financial statements, is presented in the following table.

(Millions of dollars)	2011		2010		2009
United States
Oil and gas liquids	$	648.8		557.6		374.8
Natural gas		71.1		87.0		80.6
Canada
Conventional oil and gas liquids		505.6		388.6		365.6
Synthetic oil		506.6		378.6		288.5
Natural gas		280.2		132.1		68.6
Malaysia
Oil and gas liquids		1,583.0		1,531.1		1,478.4
Natural gas		461.3		307.1		45.4
United Kingdom
Oil and gas liquids		92.4		118.8		54.7
Natural gas		14.3		14.1		6.4
Republic of the Congo – oil		148.8		156.7		24.5
Total oil and gas revenues	$	4,312.1		3,671.7		2,787.5

The Company’s total crude oil, condensate and natural gas liquids production from continuing operations, which excludes discontinued operations in Ecuador sold in March 2009, averaged 103,160 barrels per day in 2011, 126,927 barrels per day in 2010 and 130,522 barrels per day in 2009.

United States oil production decreased from 20,114 barrels per day in 2010 to 17,148 barrels per day in 2011 with the lower volumes mostly caused by field decline at Thunder Hawk that was primarily caused by a delay in development drilling operations in 2010 and 2011 following the Macondo incident in April 2010. The production decline at Thunder Hawk was partially offset by higher oil volumes produced in 2011 at the Eagle Ford Shale area in South Texas. Production of heavy oil in the Western Canada Sedimentary Basin was 7,264 barrels per day in 2011, up from 5,988 barrels per day in 2010, primarily due to ongoing drilling operations at the Seal area in Alberta. Oil production offshore Canada fell from 11,497 barrels per day in 2010 to 9,204 barrels per day in 2011 primarily due to field decline at Terra Nova and a reduction of the Company’s working interest at this field from 12.0% in 2010 to 10.475% in 2011. Synthetic oil operations at Syncrude had net production of 13,498 barrels per day in 2011, up from 13,273 barrels per day in 2010, with the increase caused by a lower royalty rate in 2011 due to higher costs incurred for the operations. Oil production in Malaysia decreased from 66,897 barrels per day in 2010 to 48,551 barrels per day in 2011, primarily due to lower production at the Kikeh field. Sands and other fines produced with the oil at Kikeh led to certain wells being down for a portion of 2011. Oil production in Malaysia was favorably affected in 2011 by higher condensate and other gas liquids produced at gas fields offshore Sarawak. Oil production in the U.K. was 2,423 barrels per day in 2011, down from 3,295 barrels per day in 2010, with the decline primarily due to more downtime at the Schiehallion and Mungo/Monan fields during

30

the later year. The Azurite field offshore Republic of the Congo averaged 4,989 barrels per day in 2011, down from 5,820 barrels per day in 2010 due to faster than expected well decline.

United States crude oil production averaged 20,114 barrels per day in 2010, up from 17,053 barrels per day in 2009. The U.S. increase was primarily attributable to a full year of oil production at the Thunder Hawk field that started up in July 2009 in the Gulf of Mexico. Heavy oil production in Western Canada declined from 6,813 barrels per day in 2009 to 5,988 barrels per day in 2010 due to a combination of lower gross production in the Seal area plus a higher royalty rate there due to higher sales prices in 2010. Crude oil production offshore Canada fell from 12,357 barrels per day in 2009 to 11,497 barrels per day in 2010 essentially due to lower production levels at Terra Nova caused by field decline and a higher royalty rate at Hibernia. Synthetic oil production of 13,273 barrels per day in 2010 exceeded 2009 volumes of 12,855 per day due to less downtime for maintenance in the later year. Crude oil and liquids production in Malaysia averaged 66,897 barrels per day in 2010, down from 76,322 barrels per day in 2009, with the decrease mainly due to downtime in the later year at Kikeh for well maintenance and installation of drilling equipment on the production facility. Crude oil production in the U.K. in 2010 was about flat with 2009 as higher production volumes at Schiehallion almost offset lower volumes due to well decline at Mungo/Monan. Oil production in Republic of the Congo rose to 5,820 barrels per day in 2010 after averaging 1,743 barrels per day for all of 2009; the Azurite field came on production in August 2009. The Company sold its interest in Block 16 and other areas in Ecuador in March 2009 and has accounted for Ecuador as discontinued operations. Oil production in Ecuador, excluded from the totals for continuing operations, averaged 1,317 barrels per day in 2009.

Worldwide sales of natural gas were 457.4 million cubic feet (MMCF) per day in 2011, 356.8 MMCF per day in 2010 and 187.3 MMCF per day in 2009.

Natural gas production in the U.S. averaged 47.2 MMCF per day in 2011, compared to 53.0 MMCF per day in 2010. The lower volume in 2011 was primarily attributable to the Thunder Hawk field where production declined during the year due to delay in development drilling operations following the Macondo incident in April 2010. Natural gas production in Canada rose from 85.6 MMCF per day in 2010 to an annual Company record of 188.8 MMCF per day in 2011 primarily due to start up of production at the Tupper West area in Western Canada in the first quarter 2011. Gas sales volumes also increased in 2011 at the nearby Tupper area due to development drilling activities during the year. Natural gas production in Malaysia rose to 217.4 MMCF per day in 2011 compared to 212.7 MMCF per day in 2010. Natural gas sales volumes during 2011 at Sarawak and Kikeh averaged 176.9 MMCF per day and 40.5 MMCF per day, respectively. Gas sales rose 22.4 MMCF per day at Sarawak due to higher demand from the local purchaser, while Kikeh gas volumes fell 17.7 MMCF per day in 2011 due to lower demand and wells down for mechanical repairs for a portion of the year. Natural gas production in the U.K. fell from 5.5 MMCF per day in 2010 to 3.9 MMCF per day in 2011 primarily due to more downtime for repairs at the Amethyst field during the just completed year.

Natural gas sales volumes in the U.S. were 53.0 MMCF per day in 2010, down from 2009 production of 54.2 MMCF per day as higher production at Thunder Hawk in the Gulf of Mexico and the Eagle Ford Shale area did not fully offset declines at fields onshore South Louisiana and at other fields in the Gulf of Mexico. Natural gas volumes in Western Canada increased from 54.9 MMCF per day in 2009 to 85.6 MMCF per day in 2010 essentially due to continued ramp-up of Tupper area production during the later year. Natural gas sales volumes in Malaysia increased in 2010 for both the Sarawak and Sabah offshore areas. Sarawak production rose to 154.5 MMCF per day in 2010 following volumes of 28.1 MMCF per day in 2009. Sarawak gas production began in September 2009 and as such was on production for all of 2010 versus four months in 2009. The Company also continued ramp-up of new wells at Sarawak gas fields during 2010. Gas sales at the Kikeh field averaged 58.2 MMCF per day in 2010, up from 46.6 MMCF per day the prior year. Natural gas sales volumes in the U.K. increased from 3.5 MMCF per day in 2009 to 5.5 MMCF per day in 2010 as gas volumes rose at both the Mungo/Monan and Amethyst fields during the later year.

The Company’s average worldwide realized sales price for crude oil, condensate and gas liquids from continuing operations was $94.54 per barrel in 2011 compared to $67.11 per barrel in 2010 and $56.41 per barrel in 2009.

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The Company’s average realized oil sales price of $94.54 in 2011 was an increase of 41% compared to 2010. The average price of West Texas Intermediate (WTI) crude oil rose 19% during 2011. The Company’s average oil price increased more than WTI because other worldwide benchmark prices rose more than WTI during 2011. Dated Brent prices, for example, rose 40% during 2011. Additionally, the Company’s realized sales price in Malaysia in 2011 and a portion of 2010 benefited from a switch to the Brent benchmark price during the prior year. Crude oil prices strengthened in 2011 due to an improvement in energy demand in association with a slowly recovering worldwide economy and unrest in Northern Africa and the Middle East during 2011 that caused concern in the oil markets about the potential for supply disruptions. Compared to 2010, the Company’s average 2011 crude oil sales prices in the U.S. rose 36% to $103.92 per barrel; heavy oil prices in Canada sold for 14% more and averaged $57.00 per barrel; offshore Canada prices increased 43% to $110.02 per barrel; synthetic crude oil sold for 32% more at $102.94 per barrel; crude oil in Malaysia was up 48% and averaged $90.14 per barrel; U.K. crude oil production sold for 41% more at $110.13 per barrel; and crude oil in Republic of the Congo sold at $103.02 per barrel in 2011, an increase of 38% from 2010.

The average realized crude oil sales price increased 19% in 2010 compared to 2009. The higher price for 2010 was slightly below the 28% increase in WTI sales price between the years. Other benchmark oil prices used for sale of Company crude oil did not increase at the same rate as WTI. The increase in the sales price for APPI Tapis based crude oil during 2010 did not keep pace with the increase in the WTI price due to differences in market conditions in Asia versus the U.S. During most of 2010, the Company sold its Kikeh crude oil based on the APPI Tapis benchmark price. In late 2010, the Company began to sell its Kikeh crude oil based on a Brent crude oil benchmark. Compared to 2009, the Company’s average 2010 crude oil sales prices rose 27% in the U.S. to average $76.31 per barrel; heavy oil sales prices in Canada rose 23% to an average of $49.89 per barrel; offshore Canada oil sold at $76.87 per barrel, an increase of 32%; Canadian synthetic crude oil sold for 27% more and averaged $77.90 per barrel; crude oil produced in Malaysia increased 10% to an average price of $60.97 per barrel; U.K. crude oil prices increased 27% to $77.95 per barrel; and crude oil sold in Republic of the Congo increased only 8% to $74.87 per barrel as the only sale in 2009 was near the end of the year when prices were above the 2009 average.

The Company’s natural gas sales prices in North America in 2011 did not generally increase in concert with crude oil prices. A growing gas supply from unconventional sources such as shale operations kept gas prices in check during the latest year. The Company’s average realized North American natural gas sales price was $4.08 per thousand cubic feet (MCF) in 2011, a decline of 6% from the $4.34 per MCF realized in 2010. Natural gas produced in 2011 offshore Sarawak was sold at an average price of $7.10 per MCF, an increase of 34% from the $5.31 per MCF realized during 2010. In the U.K. the average sales price rose from $7.01 per MCF in 2010 to $9.99 per MCF in 2011, up 43% in the current year.

Virtually all natural gas prices showed improvements in 2010 compared to 2009. The prices for natural gas generally rose in 2010 in sympathy with the increase in average crude oil prices during the same period. The Company’s average sales prices for natural gas in North America increased 22% to $4.34 per MCF in 2010. Natural gas produced offshore Sarawak sold for 31% more in 2010 than in 2009 and averaged $5.31 per MCF in the later year. Natural gas produced in the U.K. sold at an average of $7.01 per MCF in 2010, a 39% increase from 2009.

Based on 2011 sales volumes and deducting taxes at marginal rates, each $1.00 per barrel and $0.10 per MCF fluctuation in prices would have affected 2011 earnings from exploration and production continuing operations by $23.5 million and $10.9 million, respectively. The effect of these price fluctuations on consolidated net income cannot be measured precisely because operating results of the Company’s refining and marketing segments could be affected differently.

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Production expenses from continuing operations were $1,038.6 million in 2011, $879.5 million in 2010 and $654.5 million in 2009. These amounts are shown by major operating area on pages F-51 and F-52 of this Form 10-K report. Costs per equivalent barrel during the last three years are shown in the following table.

(Dollars per equivalent barrel)	2011		2010		2009
United States	$	18.05		12.46		10.62
Canada
Excluding synthetic oil		8.65		8.45		9.44
Synthetic oil		47.91		42.61		36.64
Malaysia		13.66		9.31		8.00
United Kingdom		26.24		14.46		17.97
Republic of the Congo		26.04		31.30		43.51
Worldwide – excluding synthetic oil		13.39		10.51		9.21

Production expense per equivalent barrel in the U.S. increased in 2011 compared to 2010 due to lower volumes produced at the Thunder Hawk field and higher facility rental costs in the early days of the Eagle Ford Shale operation as production ramped up. The per-unit cost for Canadian conventional oil and gas operations, excluding synthetic oil, was slightly higher in 2011 compared to 2010 as the benefit of significantly higher natural gas production at Tupper West and Tupper was more than offset by lower production volumes without a comparable reduction in costs at Hibernia and Terra Nova. Higher cost per barrel in 2011 compared to 2010 at Canadian synthetic oil operations was mostly caused by higher overall maintenance and fuel costs. Production cost per unit in Malaysia was higher in 2011 compared to 2010 primarily at Kikeh caused by higher costs for the work program to address equipment damaged by sand produced with the oil and the associated downtime which led to lower oil production. Higher per-barrel production expense in the U.K. in 2011 compared to 2010 was primarily attributable to lower production levels at all fields and extended maintenance work. Production expense in Republic of the Congo was lower on a per-unit basis in 2011 compared to 2010 due to lower gross costs incurred at the Azurite field in the later year.

Production expense per equivalent barrel in the U.S. increased in 2010 compared to 2009 due to a larger proportion of production in the later year coming from the higher-cost Thunder Hawk field in the Gulf of Mexico. Cost per barrel for Canada conventional oil and gas operations, excluding synthetic oil, was lower in 2010 than 2009 due to a larger portion of total hydrocarbons produced coming from the Tupper gas area, but this was partially offset by higher unit costs for offshore operations at Hibernia and Terra Nova. The increase in production costs per barrel for synthetic oil operations in 2010 compared to 2009 was caused by higher maintenance and natural gas costs in the current year. Production expense in Malaysia rose in 2010 compared to 2009 as higher well maintenance and workover costs at Kikeh were only partially offset by a higher proportion of lower-cost natural gas produced at fields offshore Sarawak. Production expense in 2010 in the U.K. on a per-unit basis was lower than 2009 due to less repair costs at Schiehallion and higher natural gas production at Amethyst. Per-unit production expense in 2010 in Republic of the Congo was less than in 2009 due to higher production levels associated with ramp-up of the Azurite field, which came onstream in August 2009.

Exploration expenses from continuing operations for each of the last three years are shown in total in the following table, and amounts are reported by major operating area on pages F-51 and F-52 on this Form 10-K report. Expenses other than leasehold amortization are included in the capital expenditures total for exploration and production activities.

(Millions of dollars)	2011		2010		2009
Dry holes	$	251.0		90.1		125.3
Geological and geophysical		79.7		65.1		40.5
Other		41.0		29.1		16.2
		371.7		184.3		182.0
Undeveloped lease amortization		118.2		108.0		83.2
Total exploration expenses	$	489.9		292.3		265.2

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Dry hole expense was $160.9 million higher in 2011 than 2010 due to more unsuccessful exploratory drilling results in the current year, with the most significant areas including Brunei, Indonesia, Southern Alberta and Suriname. Lower dry hole costs in 2011 in Malaysia, Republic of the Congo and the U.K. somewhat offset the higher costs noted above. Geological and geophysical (G&G) expenses were $14.6 million higher in 2011 compared to 2010. The increase in G&G expenses in 2011 was attributable to higher spending on seismic in Brunei, the Kurdistan region of Iraq, Block H Malaysia and Cameroon, but the current year included lower seismic spending in Republic of the Congo. Other exploration costs were $11.9 million more in 2011 than 2010 mostly due to higher office costs allocable to exploration activities in Brunei, Indonesia and Iraq, and an exploration well drilling penalty in Southern Alberta. Undeveloped leasehold amortization expense was $10.2 million higher in 2011 than 2010 mostly due to lease costs associated with concessions in the Kurdistan region of Iraq, but partially offset by slightly lower amortization costs in 2011 for Eagle Ford Shale leases in South Texas and the Montney area of Western Canada.

Dry hole expense was $35.2 million lower in 2010 than in 2009 despite a 50% increase in spending for exploratory drilling. Dry hole expense in the U.S. was lower in 2010 mostly due to deferral of planned Gulf of Mexico drilling due to the moratorium imposed by the Federal government following the April 2010 blowout and oil spill at the Macondo well owned by other companies. Malaysian operations had lower dry hole expense in 2010 due to more successful exploratory drilling results and favorable adjustments to final costs on prior-year wells. Dry holes in the U.K. in 2010 primarily related to a decision to expense a well drilled in 2008 for which studies in 2010 indicated a lack of economical development options based on current pricing levels. Dry hole expense in Republic of the Congo was higher in 2010 than 2009 due to drilling more unsuccessful wells in the MPS block in the later year. Dry hole expense in 2010 in other foreign areas was less than in 2009 primarily due to an unsuccessful well offshore Australia in 2009. G&G expenses were $24.6 million higher in 2010 than 2009. Areas of higher spending on seismic in the 2010 year included the Eagle Ford Shale area of South Texas, the MPN and MPS blocks offshore Republic of the Congo, and offshore Malaysia. These higher G&G costs in 2010 were somewhat offset by lower spending in the Tupper area of Western Canada and offshore Suriname. Other exploration costs in 2010 were $12.9 million above 2009 levels primarily due to higher administrative costs for operations in Suriname, Indonesia and Australia in 2010. Undeveloped leasehold amortization expense rose $24.8 million in 2010 compared to 2009, primarily due to higher amortization associated with lease acquisition costs in the Eagle Ford Shale area of South Texas, partially offset by less amortization expense in 2010 following sanction of development at the Tupper West property in August 2009.

The Company recorded a $368.6 million impairment charge in 2011 to reduce the carrying value of the Azurite oil field, offshore Republic of the Congo, to fair value. The impairment charge at Azurite was necessitated by a reduction in the field’s proved oil reserves at year-end 2011 due to poor well performance. An impairment charge of $5.2 million was recorded in 2009 to write-off the remaining costs of a poorly performing natural gas field in the Gulf of Mexico.

Depreciation, depletion and amortization expense for exploration and production operations totaled $969.7 million in 2011, $1,005.0 million in 2010 and $775.8 million in 2009. The $35.3 million decrease in 2011 compared to 2010 was primarily attributable to lower overall levels of hydrocarbon volumes sold, somewhat offset by a slightly higher per-barrel depreciation rate based on a change in the mix of production between 2011 and 2010. The $229.2 million increase in 2010 compared to 2009 was primarily caused by higher overall volumes of oil and natural gas sold during 2010. Additionally, a higher proportion of 2010 production was derived from fields brought onstream in recent years under a higher-cost development environment.

The exploration and production business recorded expenses of $36.8 million in 2011, $31.1 million in 2010 and $25.5 million in 2009 for accretion on discounted abandonment liabilities. Because the abandonment liability is carried on the balance sheet at a discounted fair value, accretion must be recorded annually so that the liability will be recorded at full value at the projected time of abandonment. The $5.7 million increase in accretion costs in 2011 compared to 2010 was attributable to a higher number of wells drilled in the current year in the Eagle Ford Shale and Montney areas and higher overall future estimated abandonment cost liabilities for Gulf of

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Mexico wells and synthetic oil operations at Syncrude. The $5.6 million increase in accretion expense in 2010 compared to 2009 was due to additional wells drilled during the later year in several geographical areas and higher estimated abandonment costs for offshore operations in Malaysia and for Syncrude synthetic oil operations.

The effective income tax rate for exploration and production continuing operations was 53.8% in 2011, 41.7% in 2010 and 40.8% in 2009. The effective tax rate was significantly higher in 2011 than 2010 due to no tax benefit recorded on the impairment charge for the Azurite field and higher exploration and administrative expenses in certain foreign tax jurisdictions where no tax benefit can be currently recognized due to lack of sufficient revenue to realize a current or future benefit. Income tax expense in 2011 was reduced by a $25.6 million benefit for expenses incurred in prior years in Block P, Malaysia. It was determined during 2011 that these expenses in Block P are deductible against taxable income generated in Block K Malaysia. Also, in 2011, the U.K. government enacted a 12% supplemental tax on oil and gas company profits in that country. This tax increase raised the Company’s tax expense in 2011 by $14.5 million, primarily to increase the recorded balance for deferred income taxes that will be paid in future years at the new higher rate. The effective tax rate is now 62% in the U.K. The overall effective income tax rate was slightly higher in 2010 than 2009 mostly due to tax barrels owed the government of Republic of the Congo under the production sharing agreement covering the Azurite field. More tax barrels were owed the government due to higher Azurite production levels in 2010. The effective tax rates in all three years exceeded the U.S. statutory tax rate of 35.0% due to higher overall foreign tax rates and exploration and other expenses in areas where current tax benefits cannot be recorded by the Company. Tax jurisdictions with no current tax benefit on expenses primarily include certain non-revenue generating areas in Malaysia, Suriname, Australia, Indonesia, Brunei, Cameroon and the Kurdistan region of Iraq. Each main exploration area in Malaysia is currently considered a distinct taxable entity and expenses in certain areas may not be used to offset revenues generated in other areas. No tax benefits have thus far been recognized for costs incurred for Block H, offshore Sabah, and Blocks PM 311/312, offshore Peninsula Malaysia.

At December 31, 2011, 34.5 million barrels of the Company’s U.S. proved oil reserves and 40.2 billion cubic feet of U.S. proved natural gas reserves were undeveloped. More than 77% of the total U.S. undeveloped reserves (on a barrel of oil equivalent basis) are associated with the Company’s Eagle Ford Shale operations in South Texas. Further drilling and facility construction are generally required to move the undeveloped reserves in the Eagle Ford Shale area to developed. In the Western Canadian Sedimentary Basin, total proved undeveloped natural gas reserves totaled 211.8 billion cubic feet, with the migration of these reserves, primarily in the Tupper and Tupper West areas, dependent on both development drilling and completion of processing and transportation facilities. In Block K Malaysia, all oil reserves of 14.7 million barrels for the Kakap field are undeveloped pending completion of facilities and development drilling directed by another company. Additionally, the Kikeh field had undeveloped oil reserves of 28.0 million barrels, which are subject to further development drilling before being moved to developed. Also in Malaysia, there were 98.3 billion cubic feet of undeveloped natural gas reserves at various fields offshore Sarawak at year-end 2011, which were held under this category pending completion of development drilling and facilities. The deepwaters of the Gulf of Mexico and the Schiehallion field in the U.K. North Sea accounted for additional proved undeveloped reserves of 9.2 million and 17.4 million equivalent barrels of oil, respectively, at December 31, 2011. On a worldwide basis, the Company spent approximately $1.88 billion in 2011, $1.27 billion in 2010 and $1.34 billion in 2009 to develop proved reserves.

Refining and Marketing – The Company’s refining and marketing (R&M) operations generated earnings from continuing operations of $190.3 million in 2011, $130.6 million in 2010 and $45.0 million in 2009. The R&M earnings improvement of $59.7 million in 2011 compared to 2010 was mostly attributable to a $0.042 per gallon improvement in retail fuel marketing sales margin in the U.S. and higher profits on merchandise sales at U.S. retail stations in 2011. The R&M earnings increase of $85.6 million in 2010 compared to 2009 was driven primarily by a $0.03 per gallon improvement in sales margin for retail fuel, partially offset by lower refining margins in the U.K. in 2010 compared to the prior year.

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The Company has announced its intention to divest its U.K. refining and marketing operations in 2012. The Meraux, Louisiana and Superior, Wisconsin refineries were sold in 2011 and are reported as discontinued operations.

The Company’s United States R&M operations generated earnings from continuing operations of $223.6 million in 2011, $165.3 million in 2010 and $65.5 million in 2009. U.S. R&M operations include two ethanol production facilities, along with retail and wholesale fuel marketing operations. The $58.3 million increase in U.S. income in 2011 compared to 2010 was primarily attributable to more than a $0.04 per gallon improvement in retail fuel margin partially offset by a reduction in gallons sold. Additionally, the Company had higher profits in 2011 on the sale of merchandise in this business. Total fuel sales volumes per station at Company operated sites in the U.S. averaged about 277,700 gallons per month during 2011, down 9% from the prior year. U.S. profits in 2011 included higher income from the Company’s ethanol production facilities compared to 2010. The Hankinson plant operated for both years while the Hereford plant was open for most of 2011 only. Corn costs were higher in 2011 compared to 2010, but this increase was essentially offset by higher sales prices for ethanol and by-products, dried distillers grains and wet distillers grains, in the current year.

United States R&M profits from continuing operations increased $99.8 million in 2010 compared to 2009. The 2010 increase was due to a $0.03 per gallon higher fuel margin compared to 2009 in the retail marketing business. The retail marketing business had slightly lower volumes sold in 2010 compared to 2009. Fuel margins in the retail chain were hurt in 2009 by both lower demand for gasoline and diesel due to the weak economy and generally rising wholesale fuel costs caused by crude oil prices that rose gradually during the year.

United States refined product sales volumes (including discontinued operations) averaged 420,737 barrels per day in 2011, compared to 450,100 barrels per day in 2010 and 432,700 barrels per day in 2009. The decrease in 2011 was primarily due to the sale of the two U.S. refineries near the end of September 2011, plus lower gasoline volumes sold through the U.S. retail marketing business. The sales volume increase in 2010 compared to 2009 was mostly attributable to more finished products produced at the U.S. refineries compared to the prior year. Additionally 2010 included a full year of ethanol production from the Hankinson facility acquired in October 2009, compared to only three months of ethanol production in 2009. The retail marketing business added 29 stations in 2011, 51 stations in 2010 and 23 stations in 2009. The U.S. retail marketing network included 1,128 stations at year-end 2011.

United Kingdom R&M operations incurred a loss of $33.3 million in 2011 compared to losses of $34.7 million in 2010 and $20.5 million in 2009. The loss in 2011 decreased from 2010 by $1.4 million, primarily caused by slightly better refining margins in 2011 and higher throughput volumes in 2011 due to a two-month plant wide turnaround at the Milford Haven, Wales refinery in 2010. The loss in 2010 was higher than 2009 for U.K. R&M operations primarily due to weaker margins at the Milford Haven refinery and lower crude oil throughput caused by the refinery undergoing approximately a two-month plant-wide turnaround during 2010. U.K. refining margin was hurt by weak demand during the two-year period of 2009 and 2010. Soft demand for refined products in the U.K. and Western Europe led to an industry-wide oversupply of gasoline and diesel products in the area.

Unit margins in the United Kingdom averaged $(0.67) per barrel in 2011, $(1.47) per barrel in 2010 and $(0.28) per barrel in 2009. Overall refined product sales volumes in the U.K. averaged 135,697 barrels per day in 2011, up 57% compared to 2010. The increase in sales volumes in 2011 was primarily due to downtime associated with a turnaround at the Milford Haven refinery in 2010. Sales volumes of refined products in the U.K. declined 16% to 86,657 barrels per day in 2010 compared to 2009, essentially due to the same refinery turnaround in 2010.

Corporate – The after-tax costs of corporate activities, which include interest income, interest expense, foreign exchange gains and losses, and unallocated corporate overhead, were $75.1 million in 2011, $157.9 million in 2010 and $23.0 million in 2009.

The net cost of corporate activities in 2011 was $82.8 million lower than in 2010, primarily due to more favorable effects of foreign currency exchange, which was associated with transactions denominated in currencies other than the respective operation’s predominant functional currency. The effect of foreign currency

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exchange after taxes was a gain of $20.7 million in 2011 compared to a loss after taxes of $58.1 million in 2010. The U.S. dollar generally strengthened against the Malaysian ringgit in 2011 after having weakened against this currency during 2010. The stronger U.S. currency in 2011 reduced the dollar cost of tax liabilities in Malaysia which are payable in the local currency. The Malaysian operation’s functional currency is the U.S. dollar. Foreign currency transaction effects in the U.K. were also favorable in 2011 compared to the prior year. The corporate area also benefited in 2011 from higher interest income of $3.2 million compared to 2010, principally due to higher levels of invested cash earning interest during the current year. Net interest expense, after capitalization of finance-related costs to development projects, was $6.0 million higher in 2011 than 2010. This unfavorable variance was principally due to interest charged on certain tax assessments in Canada and lower amounts of interest capitalized to development projects in the latest year, primarily at the Tupper West area development in Western Canada where gas production started up in the first quarter of 2011. Administrative expenses associated with corporate activities were also higher in 2011 compared to 2010, primarily associated with additional costs for compensation and professional services.

The net cost of corporate activities rose $134.9 million in 2010 compared to 2009. The most significant variance related to the effects of foreign currency exchange. The Company had after-tax losses from foreign currency exchange of $58.1 million in 2010, while 2009 had after-tax gains of $33.3 million. The foreign currency exchange loss in 2010 was primarily associated with a stronger Malaysian ringgit compared to the U.S. dollar. This led to costs associated with higher recorded future income tax liabilities, which are required to be paid in local currency. Foreign currency exchange losses were also experienced in the U.K. during 2010 caused by a stronger U.S. dollar compared to the British pound sterling. This led to higher costs for U.S. dollar denominated liabilities owed by the Company’s U.K. refining and marketing business, which has a sterling functional currency. Additionally, 2009 benefited from interest income of $42.0 million associated with a recovery of Federal royalties previously paid on certain deepwater Gulf of Mexico oil and natural gas production. Net interest expense, after capitalization of finance-related costs to development projects, was $10.3 million higher in 2010 than 2009 mostly due to lower interest capitalized on oil and natural gas development projects during 2010. Corporate activities had higher administrative and depreciation expenses in 2010 than in 2009 of $14.9 million and $2.0 million, respectively, compared to 2009. The increase in administrative expense in 2010 was primarily associated with higher employee compensation costs. Income taxes associated with corporate activities in 2010 were significantly favorable to 2009 due to higher net pretax costs in the later year.

Discontinued Operations – On September 30, 2011, the Company sold its Superior, Wisconsin refinery and related assets for $214 million, 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 million, plus the fair value of associated hydrocarbon inventories. The Company began to account for the Superior, Wisconsin and Meraux, Louisiana refineries and associated marketing assets as discontinued operations beginning in the third quarter 2011. All prior years presented have been reclassified to conform to this presentation of the Superior and Meraux operating results as discontinued operations.

Income from discontinued operations was $131.8 million in 2011, including operating profits of $113.1 million and an after-tax gain on sale of the two U.S. refineries of $18.7 million. The after-tax gain from disposal of the two refineries included a gain on the Superior refinery (including associated inventories) of $77.6 million and a loss on the Meraux refinery (including associated inventories) of $58.9 million. The net gain on disposal was based on the selling prices of the refineries, plus the sales of all associated inventories at fair value, which was significantly above the last-in, first-out carrying value of the inventories sold. Operating profits in 2011 of $113.1 million were significantly better than the 2010 operating profits of $18.5 million due to much stronger refining margins in 2011.

Income from discontinued operations associated with the two U.S. refineries was a profit of $18.5 million in 2010 compared to income of $26.7 million in the 2009 period. The 2010 decline in results was primarily due to lower refining margins, and a nonrecurring income item in 2009 related to insurance settlements for Hurricane

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Katrina. The 2010 results benefited from higher crude oil throughput volumes compared to 2009. The 2009 results from discontinued operations also included income from Ecuador properties of $97.1 million, which primarily arose from a gain on disposal of $103.6 million.

Capital Expenditures

As shown in the selected financial data on page 23 of this Form 10-K report, capital expenditures from continuing operations, including exploration expenditures, were $2.90 billion in 2011 compared to $2.33 billion in 2010 and $2.09 billion in 2009. These amounts excluded capital expenditures of $48.1 million in 2011, $117.3 million in 2010 and $113.3 million in 2009 related to discontinued operations, which was primarily associated with two U.S. petroleum refineries sold during 2011. Capital expenditures included $371.7 million, $184.3 million and $182.0 million, respectively, in 2011, 2010 and 2009 for exploration costs that were expensed. Capital expenditures for exploration and production continuing operations totaled $2.77 billion in 2011, $2.03 billion in 2010 and $1.81 billion in 2009, representing 96%, 87% and 86%, respectively, of the Company’s total capital expenditures from continuing operations for these years. Capital expenditures in 2011 for the E&P business included $279.3 million for undeveloped lease acquisitions, $23.5 million associated with a contract revision at the Azurite field, $560.2 million of exploration activities and $1.91 billion for development programs. Lease acquisitions were primarily associated with activities in the Eagle Ford Shale area of South Texas and exploration concessions in the Kurdistan region of Iraq. Exploration costs principally related to exploratory drilling at resource plays in North America, including the Eagle Ford Shale in South Texas and new areas in Southern Alberta, plus wildcat drilling activities in Brunei, Indonesia and Suriname. Development projects in 2011, primarily included spend of $572.2 million at the Tupper West and Tupper natural gas areas in Western Canada; $153.7 million for Seal heavy oil area activities; $339.6 million for the Kikeh field in Malaysia; $236.4 million for Sarawak SK Blocks 309/311 oil and gas projects offshore Malaysia; $115.7 million for the Kakap field in Block K, offshore Sabah Malaysia; $219.7 million for work in the Eagle Ford Shale; and $73.9 million for synthetic oil operations at Syncrude.

E&P capital expenditures in 2010 included $242.8 million for acquisition of undeveloped leases, which primarily included leases acquired in the Eagle Ford Shale area of South Texas and in the Tupper West area in Western Canada, $470.0 million for exploration activities, $1.30 billion for development projects, and $22.0 million for acquisition of proved properties in Canada. Development expenditures included $524.7 million at the Tupper and Tupper West areas; $46.8 million for deepwater fields in the Gulf of Mexico; $166.8 million for Kikeh; $160.4 million for natural gas and oil development activities in SK Blocks 309/311; $58.1 million for Kakap; $63.2 million for Syncrude; $84.9 million for Western Canada heavy oil projects; $126.5 million for development of the Azurite field in Republic of the Congo; and $21.2 million for the Terra Nova and Hibernia oil fields, offshore Newfoundland. Exploration and production capital expenditures are shown by major operating area on page F-50 of this Form 10-K report.

Refining and marketing capital expenditures for continuing operations totaled $122.3 million in 2011, $290.1 million in 2010 and $263.4 million in 2009. These amounts represented 4%, 12% and 13% of capital expenditures of the Company in 2011, 2010 and 2009, respectively. Total refining and marketing capital expenditures above excluded $48.1 million, $117.3 million and $112.5 million in 2011, 2010 and 2009, respectively, for U.S. refineries sold in 2011, which are now classified as discontinued activities. Refining capital spending for discontinued operations during the three years primarily included costs at Meraux to reduce benzene production, construct a new laboratory, revamp the distillate hydrotreater and expand crude oil storage capacity, and at Superior to meet compliance with ultra-low sulfur diesel and Mobile Source Air Toxic requirements. Refining spend within continuing operations totaled $14.7 million in 2011, $59.8 million in 2010 and $94.9 million in 2009. These expenditures related to the Milford Haven, Wales refinery, and in 2011 principally included minor capital improvements, while the majority of 2010 and 2009 spend related to costs to expand crude oil throughput capacity at Milford Haven to 135,000 barrels per day. Marketing expenditures amounted to $84.9 million in 2011, $185.4 million in 2010 and $77.1 million in 2009. Marketing capital spending in 2011 was principally related to new station construction in the U.S. market. Marketing capital expenditures in 2010 were primarily associated with building new retail stations and acquiring land for new station sites in the U.S., while

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marketing capital expenditures in 2009 were primarily associated with new station builds and other improvements within the U.S. retail gasoline station network. The Company added 29 stations within its U.S. retail gasoline network in 2011, after adding 51 in 2010 and 23 in 2009. Capital expenditures related to ethanol operations in the U.S. totaled $22.7 million in 2011, $44.9 million in 2010 and $91.4 million in 2009. The Company spent $40.0 million in 2010 to acquire an unfinished ethanol production facility in Hereford, Texas. Construction of the Hereford facility was completed at an added cost of about $25.1 million and the facility commenced operation near the end of the first quarter 2011. In 2009, the Company spent $92.0 million to acquire an ethanol production facility and inventory in Hankinson, North Dakota. The Hankinson ethanol plant was financed with an $82.0 million nonrecourse loan from the seller and a cash payment of $10.0 million. The nonrecourse loan was repaid in 2010. See Note D of the consolidated financial statements for further details about these acquisitions.

Cash Flows

Operating activities – Cash provided by operating activities was $2.15 billion in 2011, $3.13 billion in 2010 and $1.86 billion in 2009. Cash provided by operating activities included cash from discontinued operations of $145.5 million in 2011, $100.5 million in 2010 and $94.4 million in 2009. Cash provided by continuing operations in 2011 was $1.03 billion less than 2010 primarily due to timing of cash collected and disbursed associated with changes in other working capital balances. Cash was primarily used to pay down accounts payable for crude oil feedstocks at formerly owned U.S. petroleum refineries and to pay income taxes in the U.S and Malaysia. Cash provided by continuing operations in 2010 was $1.26 billion more than 2009 primarily due to a drawdown of working capital other than cash in the current year and higher income from continuing operations. The working capital reduction in 2010 included cash receipts of $286.4 million related to recovery of federal royalties and associated interest income. Income associated with the royalty recovery was recorded in 2009, but the cash proceeds were collected in early 2010. Cash provided by operating activities was reduced by expenditures for abandonment of oil and gas properties totaling $24.7 million in 2011, $36.5 million in 2010 and $48.7 million in 2009.

Investing activities – Cash proceeds from property sales classified as continuing operations were $27.8 million in 2011, $2.2 million in 2010 and $1.6 million in 2009. The 2011 proceeds primarily related to sale of gas storage assets in Spain. In 2011, the Company generated cash of $950.0 million from sale of two U.S. refineries and associated marketing assets, including liquid inventories. The U.S. refineries’ operating results and cash flow have been classified as discontinued operations in the Company’s consolidated financial statements. Other investing activities for discontinued operations included capital expenditures of $48.1 million in 2011, $117.3 million in 2010 and $113.3 million in 2009. Additionally, the two U.S. refineries which were sold used cash of $1.5 million in 2011, $37.5 million in 2010 and $10.2 million in 2009 for maintenance turnarounds. During 2009, the Company generated cash of $78.9 million from the sale of its 20% working interest in Block 16 in Ecuador. Operating results and cash flows associated with Ecuador operations have also been classified as discontinued operations. Property additions and dry hole costs for continuing operations used cash of $2.62 billion in 2011, $2.24 billion in 2010 and $1.88 billion in 2009. Cash used to pay for capital expenditures increased each year compared to the prior year, with these variances essentially in line with changes in capital expenditures in each year. Cash of $1.69 billion, $2.39 billion and $2.53 billion was spent in 2011, 2010 and 2009, respectively, to acquire Canadian government securities with maturities greater than 90 days at the time of purchase. Proceeds from maturities of Canadian government securities with maturities greater than 90 days at date of acquisition were $1.77 billion in 2011, $2.55 billion in 2010 and $2.17 billion in 2009. Cash of $5.4 million in 2011, $61.4 million in 2010 and $19.3 million in 2009 was used for turnarounds at the Milford Haven, Wales, refinery and Syncrude. The higher spend in 2010 was attributable to a plant-wide turnaround at Milford Haven.

Financing activities – During 2011 and 2010, the Company used available cash flow to repay $340.0 million and $414.0 million, respectively, of debt. During 2009, the Company borrowed $243.5 million under debt agreements primarily to fund a portion of the Company’s development capital expenditures. The debt reduction in 2011 was accomplished with proceeds from sale of the two U.S. refineries. In 2009, the Company paid $10.0 million to partially finance the acquisition of the Hankinson, North Dakota, ethanol plant; the remaining $82.0 million acquisition price was financed with a seller-provided nonrecourse loan. This nonrecourse loan was fully

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repaid in 2010. Cash proceeds from stock option exercises and employee stock purchase plans, including income tax benefits on stock options, amounted to $20.4 million in 2011, $54.7 million in 2010 and $16.9 million in 2009. In 2011, the Company used cash of $7.9 million for fees and other expenses associated with renewing its primary $1.5 billion committed credit facility that expires in June 2016. Also, in 2011 and 2010, cash of $8.0 million and $5.2 million, respectively, was used to pay statutory withholding taxes on stock-based incentive awards that vested with a net-of-tax payout. Cash used for dividends to stockholders was $212.8 million in 2011, $201.4 million in 2010 and $190.8 million in 2009. The Company maintained its $1.10 per share annualized dividend rate in 2011. It had previously raised its annualized dividend rate from $1.00 per share to $1.10 per share beginning in the third quarter of 2010.

Financial Condition

Year-end working capital (total current assets less total current liabilities) totaled $622.7 million in 2011 and $619.8 million in 2010. The current level of working capital does not fully reflect the Company’s liquidity position as the carrying value for inventories under last-in, first-out accounting was $580.2 million below fair value at December 31, 2011. Cash and cash equivalents at the end of 2011 totaled $513.9 million compared to $535.8 million at year-end 2010.

Long-term debt decreased by $689.8 million during 2011 and totaled $249.6 million at year-end 2011, representing 2.8% of total capital employed. The reduction in long-term debt in 2011 included a $350.0 million reclassification of notes payable to a current liability. These notes mature in May 2012 and the Company is evaluating whether to sell replacement debt instruments. Long-term debt decreased by $413.8 million in 2010. Stockholders’ equity was $8.78 billion at the end of 2011 compared to $8.20 billion a year ago and $7.35 billion at the end of 2009. A summary of transactions in stockholders’ equity accounts is presented on page F-8 of this Form 10-K report.

Other changes in Murphy’s year-end 2011 balance sheet compared to 2010 included an $84.5 million reduction in the balance of short-term investments in Canadian government securities with maturities greater than 90 days at the time of purchase. The total investment in these Canadian government securities was $532.1 million at year-end 2011 and $616.6 million at year-end 2010. These slightly longer-term investments were purchased in each year because of a tight supply of shorter-term securities available for purchase in Canada. An $86.9 million increase in accounts receivable in 2011 was primarily caused by higher sales prices for crude oil and finished products sold, and higher natural gas sales volumes sold on credit terms by the Company, but partially offset by the sale of U.S. refineries in 2011, which effectively reduced refined products volumes sold under credit arrangements in the U.S. in 2011. Inventory values were $95.6 million less at year-end 2011 than in 2010 mostly due to lower levels of crude oil and refined products held in storage within downstream operations in the later year due to sale of two refineries in the U.S., but partially offset by higher costs for unsold crude oil production held in inventory in the current year. Prepaid expenses increased $5.2 million in 2011 primarily due to prepaid income taxes in the U.S. at year-end 2011. Short-term deferred income tax assets were $6.9 million higher at year-end 2011 compared to 2010 due mostly to more current temporary differences for expense deductions within U.K. downstream operations. Net property, plant and equipment increased by $107.3 million in 2011 as a significant level of property additions during the year exceeded the amounts of depreciation, amortization and impairment expenses recorded during 2011. Goodwill decreased $1.0 million in 2011 due to a weaker Canadian dollar exchange rate versus the U.S. dollar. Deferred charges and other assets decreased $98.4 million mostly due to no deferred turnaround costs and other noncurrent assets remaining for the Meraux and Superior refineries following their sale in 2011. Current maturities of long-term debt at year-end 2011 was $350.0 million higher than at the prior year-end due to a reclassification of $350.0 million of outstanding notes payable to current based on their upcoming maturity in May 2012. Accounts payable decreased by $296.9 million at year-end 2011 compared to 2010 primarily due to lower amounts owed for purchased crude oil feedstocks following the sale of the U.S. refineries in 2011. Income taxes payable was $157.0 million lower at year-end 2011 than at the end of 2010, primarily due to less U.S. income tax liabilities owed in 2011. Other taxes payable at year-end 2011 was $37.4 million lower than in 2010 mostly due to less value added taxes owed by the U.K. downstream operations

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and lower excise taxes owed by U.S. downstream operations. Other accrued liabilities increased by $30.1 million at year-end 2011 mostly due to higher amounts owed for compensation and other operating costs. The current portion of deferred income tax liabilities increased $5.3 million in 2011 due to higher short-term temporary differences for tax deductions in Canada in the current year. Noncurrent deferred income tax liabilities were $17.9 million higher at year-end 2011 mostly due to accelerated tax depreciation associated with the Company’s 2011 capital expenditures, primarily in Malaysia and Canada. The liability associated with future asset retirement obligations increased by $60.3 million at year-end 2011 mostly due to higher estimated future costs to retire assets in the U.S. and Canada. Deferred credits and other liabilities were $43.6 million more in 2011 compared to 2010 mostly due to higher noncurrent liabilities associated with postemployment benefit plans in the current year.

Murphy had commitments for future capital projects of approximately $1.85 billion at December 31, 2011, including $839.5 million for field development and future work commitments in Malaysia, $149.7 million for costs to develop deepwater Gulf of Mexico fields, $124.5 million for work in the Eagle Ford Shale and $127.5 million for future work commitments offshore Brunei.

The primary sources of the Company’s liquidity are internally generated funds, access to outside financing and working capital. The Company uses its internally generated funds to finance the major portion of its capital and other expenditures, but it also maintains lines of credit with banks and borrows as necessary to meet spending requirements. At December 31, 2011, the Company had access to a long-term committed credit facility in the amount of $1.5 billion. There were no outstanding borrowings under the committed credit facility at year-end 2011. The most restrictive covenants under this committed credit facility limit the Company’s long-term debt to capital ratio (as defined in the agreements) to 60%. The committed credit facility expires in 2016. At December 31, 2011, the Company had uncommitted bank credit lines of approximately $400.0 million, but no borrowings were outstanding under these lines. The long-term debt to total capital ratio was 2.8% at year-end 2011. In September 2009, the Company filed a Form S-3 registration statement with the U.S. Securities and Exchange Commission which permits the offer and sale of debt and/or equity securities. The Company may use this shelf registration, if needed, in future years to raise debt or equity capital to fund operational requirements. This shelf registration expires in September 2012. Current financing arrangements are set forth more fully in Note F to the consolidated financial statements. Based on the anticipated level of capital expenditures the Company has budgeted during 2012, the Company anticipates that it will need to borrow under its long-term debt facility during 2012. The Company’s ratio of earnings to fixed charges was 15.6 to 1 in 2011, 14.6 to 1 in 2010 and 14.5 to 1 in 2009.

Cash and invested cash are maintained in several operating locations outside the United States. At December 31, 2011, cash, cash equivalents and cash temporarily invested in Canadian government securities held outside the U.S. included approximately $608 million in Canada, $94 million in the U.K. and $83 million in Malaysia. In certain cases, the Company could incur taxes or other costs should these cash balances be repatriated to the U.S. in future periods. This could occur due to withholding taxes and/or potential additional U.S. tax burden when less than the U.S. tax rate of 35% has been paid for cash taxes in foreign locations. A lower cash tax rate is often paid in foreign countries in the early years of operations when accelerated tax deductions exist to incent oil and gas investments; cash tax rates are generally higher in later years after accelerated tax deductions in early years are exhausted. Canada collects a 5% withholding tax on any cash repatriated to the U.S. See Note I of the consolidated financial statements for further information regarding potential tax expense that could be incurred upon distribution of foreign earnings back to the United States.

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. Virtually all operations of the Company are affected by laws and regulations covering environmental, health and safety matters. Compliance with existing and anticipated environmental regulations affects Murphy’s overall cost of business, including capital costs to construct,

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maintain and upgrade equipment and facilities, and operating costs for ongoing environmental compliance. Murphy’s competitive position may be impacted to the extent that regulatory requirements with respect to a particular production technology may give rise to costs that competitors might not bear. Environmental regulations have historically been subject to frequent change by regulatory authorities and these are expected to continue to evolve in the foreseeable future. The Company is unable to predict the ongoing cost of complying with these laws and regulations or the future impact of such regulations on its operations. 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 Murphy 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.

Murphy allocates a portion of its capital expenditure program to comply with environmental laws and regulations, and such capital expenditures were $103.7 million in 2011 and are projected to be $74.7 million in 2012. The sale of U.S. refineries in 2011 will reduce future capital expenditures required to comply with environmental laws and regulations.

The most significant of those laws and the corresponding regulations affecting Murphy’s operations are:

• The U.S. Clean Air Act, which regulates air emissions

• The U.S. Clean Water Act, which regulates discharges into U.S. waters

• The U.S. Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which addresses liability for hazardous substance releases

• The U.S. Federal Resource Conservation and Recovery Act (RCRA), which regulates solid waste and hazardous waste treatment, storage and disposal.

• The U.S. Federal Oil Pollution Act of 1990 (OPA90), which addresses liability for discharges of oil into navigable waters of the United States

• The U.S Safe Drinking Water Act, which regulates disposal of wastewater into underground injection wells

• The Federal Water Pollution Control Act of 1972 (FWPCA) also addressing discharge of pollutants into navigable waters

• The Department of the Interior governing offshore oil and gas operations.

• The European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (REACH)

• The European Union Trading Directive resulting in European Emissions Trading Scheme

These laws and their associated regulations establish limits on emissions and standards for quality of air, water and solid waste discharges. They also generally require permits for new or modified operations. Many states and foreign countries where the Company operates also have or are in the process of developing similar statutes and regulations governing air and water as well as the characteristics and composition of refined products, which in some cases impose or could impose additional and more stringent requirements. Murphy is also subject to certain acts and regulations, including legal and administrative proceedings, governing remediation of wastes or oil spills from current and past operations, which include but may not be limited to leaks from pipelines, underground storage tanks and general environmental operations. Murphy is actively engaged in the legislative and regulatory process, both nationally and internationally, in response to climate change issues and environmental and health related matters.

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Murphy’s Environmental, Health, and Safety Committee, a standing committee of the Board of Directors, was created to oversee and monitor the Company’s environmental, health, and safety (EHS) policies and practices. In February 2009, the Board approved a worldwide environmental, health, and safety policy (the EHS Policy), which is available on the Company’s Web site. In addition to requiring that the Company comply with all applicable EHS laws and regulations, the EHS Policy includes a directive that the Company will continue to minimize the impact of its operations, products and services on the environment by implementing economically feasible projects that promote energy efficiency and use natural resources effectively.

CERCLA

CERCLA commonly referred to as the Superfund Act, and comparable state statutes, primarily address historic contamination and impose joint and several liability upon Potentially Responsible Parties (PRP), without regard to fault or the legality of the original act that contributed to the release of a “hazardous substance” into the environment. Cleanup of contaminated sites is the responsibility of the owners and operators of the sites that released, disposed, or arranged for the disposal of the hazardous substances found at the site. CERCLA requires reporting to the National Response Center for releases to the environment of substances defined as hazardous or extremely hazardous if the released quantities exceed an EPA established reportable level. CERCLA also authorizes the U.S. Environmental Protection Agency (EPA) and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible persons. In the course of ordinary operations, the Company generates waste that falls within CERCLA’s definition of a “hazardous substance.” Murphy may be jointly and severally liable under CERCLA for all or part of the costs required to remediate sites at which such hazardous substances have been disposed of or released into the environment.

The EPA currently considers Murphy to be a PRP at one Superfund site. The potential total cost to all parties to perform necessary remedial work at this site may be substantial. However, based on current negotiations and available information, the Company believes that it is a de minimis party as to ultimate responsibility at the Superfund site and as such, it has not recorded a liability for remedial costs. 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 this site or other Superfund sites. The Company believes that its share of the ultimate costs to remediate this Superfund site will be immaterial and will not have a material adverse effect on net income, financial condition or liquidity in a future period.

Waste

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. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws Murphy 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, Murphy is investigating the extent of any such liability and the availability of applicable defenses, including state funding for remediation, and believe costs related to these sites will not have a material adverse affect on its net income, financial condition or liquidity in a future period. Although certain environmental expenditures are likely to be recovered from other sources, no assurance can be given that future recoveries from these sources will occur. Therefore, the Company has not recorded a benefit for likely recoveries as of December 31, 2011.

RCRA and comparable state statutes govern the management and disposal of solid wastes, with the most stringent regulations applicable to treatment, storage or disposal of hazardous wastes. Murphy generates

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non-hazardous solid wastes that are subject to the requirements of RCRA and comparable state statutes. The Company’s operating sites also incur costs to handle and dispose of hazardous waste and other chemical substances. The costs of disposing of these substances are expensed as incurred and are not expected to have a material adverse effect on net income, financial condition or liquidity in a future period. However, it is possible that additional wastes, which could include wastes currently generated during operations, will in the future be designated as “hazardous wastes.” Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. Such changes in the regulations could result in additional capital expenditures and operating expenses.

Water

Under OPA90, owners and operators of tankers, owners and operators of onshore facilities and pipelines, and lessees or permittees of an area in which an offshore facility is located are liable for removal and cleanup costs of oil discharges into navigable waters of the United States. The Company is not aware of OPA90 claims made against Murphy.

Each Murphy offshore facility in the Gulf of Mexico has in place an Emergency Evacuation Plan (EEP) and all such facilities are covered by an Oil Spill Response Plan (OSRP). In the event of an explosion, personnel would be evacuated immediately in accordance with the EEP. The appropriate OSRP would be activated if needed. In the event of an oil spill or containment event, the appropriate OSRP and Containment Plan would be executed as needed. The EEP is approved by the U.S. Coast Guard (USCG) and the OSRP and Containment Plan are approved by the Bureau of Ocean Energy Management (BOEM). The Company also has comprehensive emergency and spill response plans for offshore facilities in international waters.

Murphy’s OSRP utilizes a consortium of seasoned and well equipped contract service companies to provide response equipment and personnel. One company has been contracted to provide spill containment and recovery equipment, including skimmers, boom, and vessels such as fast response boats and high volume open sea skimmer barges. This company has hired other companies to store and maintain response equipment and provide certified tanks and barges. Murphy is a founding member of Marine Preservation Association, which provides access to Marine Spill Response Corporation assets to support marine spills in the Gulf of Mexico and other offshore areas. Additionally, Murphy has an agreement with another company to provide aerial dispersant spraying services, and has further contracted with another company to utilize their equipment for oil containment should a well blowout occur.

The Federal Water Pollution Control Act of 1972 (FWPCA) imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters. The FWPCA imposes substantial potential liability for the costs of removal, remediation and damages. Murphy maintains wastewater discharge permits for its facilities where required pursuant to the FWPCA and comparable state laws. Murphy has also applied for all necessary permits to discharge storm water under such laws. The Company believes that compliance with existing permits and foreseeable new permit requirements will not have a material adverse effect on net income, financial condition or liquidity in a future period.

Murphy utilizes hydraulic fracturing technology for its exploration and production activities in Canada and the U.S. Murphy is actively engaged in exploration and production in the Eagle Ford Shale play in South Texas. On January 31, 2012, the Texas Railroad Commission finalized a rule that requires oil and gas operators to publicly disclose the chemicals and amount of water used in hydraulic fracturing of wells.

Air

Murphy’s U.S. operations are subject to the Federal Clean Air Act and comparable state and local statutes. The Company believes that its operations are in substantial compliance with these statutes in all states in which it operates. Amendments to the Federal Clean Air Act enacted in 1990 required most refining operations in the U.S. to incur capital expenditures in order to meet air emission control standards developed by the EPA and state environmental agencies.

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Under the EPA’s Clean Air Act authority, the National Petroleum Refinery (NPR) Initiative (Global Consent Decree) was used by the EPA to undertake at virtually all U.S. refineries an investigation of four marquee compliance areas, including: (i) New Source Review/Prevention of Significant Deterioration for fluidized catalytic cracking units, heaters and boilers; (ii) New Source Performance Standards for flares, sulfur recovery units, fuel gas combustion devices (including heaters and boilers); (iii) Leak Detection and Repair requirements; and (iv) Benzene National Emissions Standards for Hazardous Air Pollutants. Murphy began negotiations with the EPA in 2005, but was interrupted by the events of Hurricane Katrina. The states of Louisiana and Wisconsin are both parties to the NPR. Negotiations with EPA resumed in 2007 and were essentially completed in 2010. Under the Global Consent Decree, the Company paid a fine of $1.25 million and committed to certain future capital improvements. The Company sold its two U.S. refineries in 2011.

The European Union has adopted an Emissions Trading Scheme in response to the Kyoto Protocol in order to achieve reductions in greenhouse gas emissions. Murphy’s refinery at Milford Haven, Wales, currently has the most exposure to these requirements and may require purchase of emission allowances to maintain compliance with environmental permit requirements. These environmental expenditures are expensed as incurred. In 2011, Murphy was notified by the Environment Agency (EA) that it failed to surrender proper emission allowances, which Murphy self-reported to the EA in 2010. The Company is evaluating all available options regarding this matter.

Climate Change

Currently, various national and international legislative and regulatory measures to address greenhouse gas emissions (including carbon dioxide, methane and nitrous oxides) are in various phases of discussion or implementation. These include a promulgated EPA regulation, Mandatory Reporting of Greenhouse Gases for numerous industrial business segments, including refineries and offshore production, which became effective December 29, 2009. These were followed by a more recent regulation requiring Mandatory Reporting of Greenhouse Gases for Petroleum and Natural Gas Systems, including onshore exploration and production facilities, which became effective December 31, 2010 and was revised December 23, 2011. During 2011, U.S. federal legislation (EPA’s Greenhouse Gas Endangerment Finding, EPA’s Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, Low Carbon Fuel Standards, etc.) and various state actions were proposed/finalized to develop statewide or regional programs, each of which have or could impose mandatory reductions and reporting of greenhouse gas emissions. Murphy believes it has met all of the EPA required reporting deadlines and strives to ensure accurate and consistent emissions data reporting. The impact of existing and pending climate change legislation, regulations, international treaties and accords could result in increased costs to the Company to (i) operate and maintain facilities; (ii) install new emission controls on facilities; and (iii) administer and manage any greenhouse gas emissions trading program. These actions could also impact the consumption of refined products, thereby affecting gasoline and ethanol marketing operations. The physical impacts of climate change present potential risks for severe weather (floods, hurricanes, tornadoes, etc.) at certain of the Company’s refined product terminals in the U.S. and its offshore platforms in the Gulf of Mexico. Commensurate with this risk is the possibility of indirect financial and operational impacts to the Company from disruptions to the operations of major customers or suppliers caused by severe weather. The Company has repositioned itself to take advantage of potential climate change opportunities by acquiring renewable energy sources through the acquisition of two ethanol production facilities, thereby achieving a lower carbon footprint and an enhanced capability to meet governmental fuel standards. The Company is unable to predict at this time how much the cost of compliance with any future legislation or regulation of greenhouse gas emissions, or the cost impact of natural catastrophic events resulting from climate change, if it occurs, will be in future periods.

The Company recognizes the importance of environmental stewardship as a core component of its mission as a responsible international energy company and has implemented sufficient disclosure controls and procedures to capture and process environmental, safety and climate-change related information. As a companion to Murphy’s EHS Policy, the Company’s Web site also contains a statement on climate change. Not only does this statement

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on climate change include Murphy’s goal of reducing greenhouse gas emissions on an absolute basis while growing its upstream and certain downstream operations, the information on the Company’s Web site describes actions already taken to move towards that goal. These efforts include incorporating climate change into the Company’s planning processes, reducing emissions, pursuing new opportunities and engaging legislative and regulatory entities externally. In support of these efforts, worldwide greenhouse gas inventories have been conducted since 2001. Additionally, Murphy participates in the Massachusetts Institute of Technology (MIT) Joint Program on the Science and Policy of Global Change. The initiatives cited above demonstrate the Company’s commitment regarding environmental issues, which are at the forefront of today’s global public policy dialogue.

Other Matters

The Energy Independence and Security Act (EISA) was signed into law in December 2007. The EISA, through EPA regulation, requires refiners and gasoline blenders to obtain renewable fuel volume or representative trading credits as a percentage of their finished product production. EISA greatly increases the renewable fuels obligation defined in the Renewable Fuels Standard (RFS) which began in September 2007. Murphy is actively blending renewable fuel volumes through its retail and wholesale operations and trading corresponding credits known as Renewable Identification Numbers (RINs) to meet most of its obligation. On July 1, 2010, the RFS-2 standard came into effect requiring the blending/phase-in of ethanol, biodiesel, cellulosic and advanced renewable fuels. Murphy is meeting its obligations for RFS-2 primarily through the RINs system.

The Company is also involved in personal injury and property damage claims, allegedly caused by exposure to or by the release or disposal of materials manufactured or used in its operations. Under Murphy’s accounting policies, an environmental liability is recorded when such an obligation is probable 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. Recorded liabilities are reviewed routinely. Actual cash expenditures often occur one or more years after a liability is recognized.

Safety Matters

The Company is subject to the requirements of the Federal Occupational Safety and Health Act (OSHA) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in Murphy’s operations and that this information be provided to employees, state and local government authorities and citizens. The Company believes that its operations are in substantial compliance with OSHA requirements, including general industry standards, record-keeping requirements and monitoring of occupational exposure to regulated substances.

Other Matters

Impact of inflation – General inflation was moderate during the last three years in most countries where the Company operates; however, the Company’s revenues and capital and operating costs are influenced to a larger extent by specific price changes in the oil and gas and allied industries than by changes in general inflation. Crude oil and petroleum product prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC production levels and/or attitudes of traders concerning supply and demand in the near future. Natural gas prices are affected by supply and demand, which are often affected by the weather and by the fact that delivery of gas is generally restricted to specific geographic areas. Prices for oil field goods and services have generally risen (with certain of these price increases such as drilling rig day rates having been significant at times) during the last few years primarily driven by high demand for such goods and services when oil and gas prices were strong. As noted earlier, oil and natural gas prices have been extremely volatile over the last several years. Oil prices were very strong in early to mid 2008, then fell precipitously in late 2008 and into early 2009, then have generally strengthened since that time. The prices for oil field goods and services

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generally rise in periods of higher oil prices and do not usually decline as significantly as oil and gas prices in a lower price environment. Should oil prices continue to rise in future periods, the Company anticipates that prices for certain oil field equipment and services could rise sharply. Due to the volatility of oil and natural gas prices, it is not possible to determine what effect these prices will have on the future cost of oil field goods and services.

Accounting changes and recent accounting pronouncements – The Company adopted guidance issued by the Financial Accounting Standards Board (FASB) regarding accounting for transfers of financial assets effective January 1, 2010. This guidance makes the concept of a qualifying special-purpose entity as defined previously no longer relevant for accounting purposes. Therefore, formerly qualifying special-purpose entities were reevaluated for consolidation by reporting entities in accordance with the applicable consolidation guidance. This adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted, effective January 1, 2010, guidance issued by the FASB that requires a company to perform an analysis to determine whether its variable interests give it a controlling financial interest in a variable interest entity. The primary beneficiary of a variable interest entity has both the power to direct the activities of the entity that most significantly impact the entity’s economic performance and the obligation to absorb potentially significant losses of the entity or the right to receive potentially significant benefits from the entity. A company is required to make ongoing reassessments of whether it is the primary beneficiary of a variable interest entity. This guidance also amended previous guidance for determining whether an entity is considered a variable interest entity. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

In July 2010, the FASB issued accounting guidance that expanded the disclosure requirements about financing receivables and the related allowance for credit losses. This guidance became effective for the Company at December 31, 2010. Because the Company has no significant financing receivables that extend beyond one year, the impact of this guidance did not have a significant effect on its consolidated financial statement disclosures.

The U.S. Securities and Exchange Commission (SEC) adopted revisions to oil and natural gas reserves reporting requirements which were effective for the Company at year-end 2009. In January 2010, the FASB issued guidance that aligned its oil and gas reserves reporting requirements and effective date with the SEC’s guidance. The primary changes to reserves reporting included:

• A revised definition of proved reserves, including the use of unweighted average oil and natural gas prices in effect at the beginning of each month during the year to compute such reserves,

• Expanding the definition of oil and gas producing activities to include non-traditional and unconventional resources, which includes the Company’s Canadian synthetic oil operations at Syncrude,

• Allowing companies to voluntarily disclose probable and possible reserves in SEC filings,

• Amending required proved reserve disclosures to include separate amounts for synthetic oil and gas,

• Expanded disclosures of proved undeveloped reserves, including discussion of such proved undeveloped reserves five years old or more, and

• Disclosure of the qualifications of the chief technical person who oversees the Company’s overall reserve process.

The Company utilized the new SEC and FASB guidance at December 31, 2011, 2010 and 2009 to determine its proved reserves and to develop associated disclosures. The Company chose not to provide voluntary disclosures of probable and possible reserves in this Form 10-K.

In September 2011, the FASB issued an accounting standards update that simplifies the annual goodwill impairment assessment process by permitting a company to assess whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount before applying the two-step goodwill impairment test.

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If a company concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the company would be required to conduct the current two-step goodwill impairment test. This change is effective for annual and interim goodwill impairment tests performed in fiscal years beginning in 2012. Early adoption is permitted. The Company does not expect the adoption of this standard in 2012 to have a significant effect on its consolidated financial statements.

In June 2011, the FASB issued an accounting standards update that only permits two options for presentation of Comprehensive Income. Comprehensive Income can be presented in (a) a single continuous Statement of Comprehensive Income, including total comprehensive income, the components of net income, and the components of other comprehensive income, or (b) in two separate but continuous statements for the Statement of Income and the Statement of Comprehensive Income. The new guidance is effective for the Company beginning in the first quarter of 2012. As in prior years, the Company expects to continue to present the Statements of Income and Comprehensive Income in two separate statements, and the adoption of this guidance in 2012 is not expected to have a significant effect on the Company’s consolidated financial statements. In December 2011, the FASB deferred the requirement for reclassification adjustments from accumulated other comprehensive income to be measured and presented by line item in the Statements of Income and Comprehensive Income.

The United States Congress passed the Dodd-Frank Act in 2010. Among other requirements, the law requires companies in the oil and gas industry to disclose payments made to the U.S. Federal and all foreign governments. The SEC was directed to develop the reporting requirements in accordance with the law. The SEC has issued preliminary guidance and has received feedback thereon from interested parties. The preliminary rules indicated that payment disclosures would be required at a project level within the annual Form 10-K report beginning with the year ending December 31, 2012. The SEC has not issued final guidance regarding required disclosure. Therefore, it is expected that reporting will be delayed beyond year-end 2012. The Company cannot predict the final disclosure requirements that will be required by the SEC.

Significant accounting policies – In preparing the Company’s consolidated financial statements in accordance with U.S. generally accepted accounting principles, management must make a number of estimates and assumptions related to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Application of certain of the Company’s accounting policies requires significant estimates. The most significant of these accounting policies and estimates are described below.

• Proved oil and gas reserves – Proved oil and gas reserves are defined by the SEC as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic method or probabilistic method is used for the estimation. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well, or through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Although the Company’s engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. SEC rules require that we use an unweighted average of the oil and gas prices in effect at the beginning of each month of the year for determining proved reserve quantities. These historical prices often do not approximate the average price that the Company expects to receive for its oil and natural gas production in the future. The Company often uses significantly different oil and natural gas price and reserve assumptions when making its own internal economic property evaluations. Estimated reserves are subject to future revision, certain of which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and gas prices can

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lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to adjustments of the Company’s depreciation rates and the timing of settlement of asset retirement obligations. Downward reserve revisions can also lead to significant impairment expense. The Company cannot predict the type of oil and natural gas reserve revisions that will be required in future periods. The Company’s proved reserves of oil and natural gas are presented on pages F-48 and F-49 of this Form 10-K.

Murphy has utilized reliable geologic and engineering technology in 2011 to include proved undeveloped reserves more than one location from producing wells in the more developed portions of the Eagle Ford Shale. The study incorporated public and proprietary data from multiple sources and encompassed the entire basin. This included analysis of seismic data, well log data, test production and fluids properties to establish geologic consistency as well as significant statistical performance data yielding predictable and repeatable reserve estimates within certain analogous areas. These locations were limited to only those areas with both established geologic consistency and sufficient statistical performance data where such data could be demonstrated to provide reasonable certain results.

Oil proved reserves revisions

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 2011 oil 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 in 2011 due to change in royalty rate. Positive oil revisions in 2011 in Malaysia were primarily at the Kikeh field caused by production performance. Positive oil revisions in the U.K. in 2011 were associated with the Schiehallion field which is being redeveloped by its owners. The negative revision in oil reserves in Republic of the Congo in 2011 was attributable to poor production results for wells in the field. The positive revision in U.S. proved oil reserves in 2010 was primarily associated with better than anticipated performance of wells at the Thunder Hawk and Medusa fields in the Gulf of Mexico. Better well performance at the Hibernia and Terra Nova fields led to favorable proved oil reserve revisions in Canada in 2010. Proved oil reserves for Canadian synthetic oil operations had a positive revision in 2010 primarily due to a lower royalty. The positive proved oil reserve revision in Malaysia in 2010 primarily related to better well performance at the Kikeh field. A positive proved oil reserve revision in Republic of the Congo in 2010 was attributable to improved terms under the production sharing agreement that allocated a larger share of production at the Azurite field to the account of the Company beginning in October 2010. A favorable oil reserve revision in 2009 in the United States was attributable to favorable performance of the Thunder Hawk and Front Runner fields and federal royalty relief for various deepwater fields. A favorable conventional oil revision in Canada in 2009 was caused by performance of the Terra Nova field and improved heavy oil pricing which added reserves in the Seal area. Due to changes in the SEC’s definition of proved oil reserves, which were first effective as of December 31, 2009, synthetic oil reserves are now included as proved oil reserves. Consequently, total synthetic oil reserves as of January 1, 2009 of 131.6 million barrels were added to total oil reserves in 2009. The positive revision to synthetic oil reserves during 2009 was attributable to lower royalties compared to a year earlier. An unfavorable revision to oil reserves in Malaysia in 2009 was due to current-year drilling results for a well in the Kikeh field, along with reduced entitlements at Kikeh and West Patricia due to increased prices in 2009 compared to year-end 2008. Oil reserves in the U.K. reflected an unfavorable revision in 2009 because of an anticipated reduction in life expectancy for major equipment at the Schiehallion project.

Natural gas proved reserves revisions

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 in South Texas. Positive gas reserve revisions in Canada in 2011 were primarily at the Tupper and Tupper West areas and these were based on better than anticipated well performance. Negative gas reserve revisions in Malaysia in 2011 were primarily due to higher sales prices which effectively reduced the entitlement percentage for

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future production at the Sarawak gas fields. Negative gas reserve revisions in the U.K. in 2011 were essentially caused by revised estimate of gas-cap volumes at the Mungo/Monan field. Proved natural gas reserves in the U.S. had positive revisions in 2010 due to better well performance at the Thunder Hawk and Mondo fields in the Gulf of Mexico. The positive gas reserve revision in Canada in 2010 was attributable to performance at various wells in the Tupper area of British Columbia. Proved reserves of natural gas in Malaysia were revised downward in 2010 due to higher prices leading to a lower future entitlement percentage for the Company. Positive gas reserve revisions in the U.K. in 2010 were attributable to better well performance at all gas producing fields. In 2009, a positive U.S. gas reserve revision was caused by favorable performance of the Thunder Hawk, Front Runner and Mondo NW fields as well as federal royalty relief for various deepwater fields. In Malaysia, a combination of increased entitlements due to pricing and drilling performance at the Sarawak gas project led to positive gas revisions in 2009. Gas reserves in the U.K. were favorably revised in 2009 because of the Amethyst field gas compression project and better Mungo field performance.

• Successful efforts accounting – The Company utilizes the successful efforts method to account for exploration and development expenditures. Unsuccessful exploration wells are expensed and can have a significant effect on net income. Successful exploration drilling costs, all development capital expenditures and asset retirement costs are capitalized and systematically charged to expense using the units of production method based on proved developed oil and natural gas reserves as estimated by the Company’s engineers.

In some cases, a determination of whether a drilled 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, in turn, usually dependent on whether additional exploratory wells find a sufficient quantity of additional reserves. Under current accounting rules, the Company holds well costs in Property, Plant and Equipment in the Consolidated Balance Sheet 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.

Based on the time required to complete further exploration and appraisal drilling in areas where hydrocarbons have been found but proved reserves have not been booked, dry hole expense may be recorded one or more years after the original drilling costs are incurred. In 2011, a dry hole was recorded for a well drilled in Republic of the Congo in 2009. A significant reduction in proved oil reserves at the Azurite field in the same MPS block during 2011 reduced the likelihood of this well being produced in future years. In 2010, a dry hole was recorded for a well in the North Sea that was drilled in 2008. Extensive evaluations of this oil discovery determined in 2010 that recovery of hydrocarbons was not economical in the current price environment. There were no dry holes in 2009 that were drilled in prior years.

• Impairment of long-lived assets – The Company continually monitors its long-lived assets recorded in Property, Plant and Equipment and Goodwill in the Consolidated Balance Sheet to make sure that they are fairly presented. The Company must evaluate its properties for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable from future cash flows. Goodwill is evaluated for impairment at least annually. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the amount of oil and natural gas that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, future capital and abandonment costs, future margins on refined products produced and sold, and future inflation levels. The need to test a property for impairment can be based on several factors, including but not limited to a significant reduction in sales prices for oil and/or natural gas, unfavorable reserve revisions, expected deterioration of future refining and/or marketing margins for refined products, or other changes to contracts, environmental regulations or tax laws. All of these same factors must be considered when evaluating a property’s carrying value for possible impairment.

In making its impairment assessments involving exploration and production property and equipment, the Company must make a number of projections involving future oil and natural gas sales prices, future

50

production volumes, and future capital and operating costs. Due to the volatility of world oil and gas markets, the actual sales prices for oil and natural gas have often been quite different from the Company’s projections. Estimates of future oil and gas production and sales volumes are based on a combination of proved and risked probable and possible reserves. Although the estimation of reserves and future production is uncertain, the Company believes that its estimates are reasonable; however, there have been cases where actual production volumes were higher or lower than projected and the timing was different than the original projection. The Company adjusts reserves and production estimates as new information becomes available. The Company generally projects future costs by using historical costs adjusted for both assumed long-term inflation rates and known or expected changes in future operations. Although the projected future costs are considered to be reasonable, at times, costs have been higher or lower than originally estimated. In assessing potential impairment involving refining and marketing assets, the Company evaluates its properties when circumstances indicate that carrying value of an asset may not be recoverable from future cash flows. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events, which include projections of future margins, future capital expenditures and future operating expenses. Future marketing or operating decisions, such as closing or selling certain assets, and future regulatory or tax changes could also impact the Company’s conclusion about potential asset impairment. Impairment expense of $368.6 million was recognized in 2011 to reduce the carrying value of the Azurite oil field, offshore Republic of the Congo, to fair value. The expense was necessitated by a significant year-end 2011 reduction of proved reserves at this field which was caused by poor well performance. Additionally, an impairment expense of $5.2 million was recorded in 2009 to write-off the remaining carrying value of one underperforming natural gas field in the Gulf of Mexico. Based on an evaluation of expected future cash flows from properties at year-end 2011, the Company does not believe it had any other significant properties with carrying values that were impaired at that date. The expected future sales prices for crude oil and natural gas used in the evaluation were based on quoted future prices for the respective production periods. These quoted prices often reflect higher expected prices for oil and natural gas in the future compared to the existing spot prices at the time of assessment. If quoted prices for future years had been lower, the smaller projected cash flows for properties could have led to significant impairment charges being recorded for certain properties in 2011. In addition, one or a combination of factors such as lower future sales prices, lower future production, higher future costs, lower future margins on refining and marketing sales, or the actions of government authorities could lead to impairment expenses in future periods. Based on these unknown future factors as described herein, the Company cannot predict the amount or timing of impairment expenses that may be recorded in the future.

• Income taxes – The Company is subject to income and other similar taxes in all areas in which it operates. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of its annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; and (c) future events often impact the timing of when income tax expenses and benefits are recognized by the Company. The Company has deferred tax assets mostly relating to basis differences for property, equipment and inventories, and dismantlements and retirement benefit plan liabilities. The Company routinely evaluates all deferred tax assets to determine the likelihood of their realization. A valuation allowance has been recognized for deferred tax assets related to basis differences for Blocks H and PM 311/312 in Malaysia and Blocks MPS and MPN in Republic of the Congo, for exploration licenses in certain areas, the largest of which are Australia, Suriname, Indonesia and Brunei, and for certain basis differences in the U.K. due to management’s belief that these assets cannot be deemed to be realizable with any degree of confidence at this time. The Company occasionally is challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions in its various income tax returns. Although the Company believes that it has adequate accruals for matters not resolved with various taxing authorities, gains or losses could occur in future years from changes in estimates or resolution of outstanding matters.

• Accounting for retirement and postretirement benefit plans – Murphy Oil and certain of its subsidiaries maintain defined benefit retirement plans covering most of its full-time employees. The Company also sponsors health care and life insurance benefit plans covering most retired U.S. employees. The expense

51

associated with these plans is determined by management based on a number of assumptions and with consultation assistance from qualified third-party actuaries. The most important of these assumptions for the retirement plans involve the discount rate used to measure future plan obligations and the expected long-term rate of return on plan assets. For the retiree medical and insurance plans, the most important assumptions are the discount rate for future plan obligations and the health care cost trend rate. Discount rates 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. Anticipated health care cost trend rates are determined based on prior experience of the Company and an assessment of near-term and long-term trends for medical and drug costs.

Based on bond yields at year-end 2011, the Company has used a discount rate of 4.87% at year-end 2011 and beyond for the primary U.S. plans. Although the Company presently assumes a return on plan assets of 6.50% for the primary U.S. plan, it periodically reconsiders the appropriateness of this and other key assumptions. The smoothing effect of current accounting regulations tends to buffer the current year’s pension expense from wide swings in liabilities and asset valuations. The Company’s normal annual retirement and postretirement plan expenses are expected to increase slightly in 2012 compared to 2011 based on the effects of a growing employee base. In 2011, the Company paid $38.4 million into various retirement plans and $4.1 million into postretirement plans. In 2012, the Company is expecting to fund payments of approximately $35.5 million into various retirement plans and $5.8 million for postretirement plans. The Company could be required to make additional and more significant funding payments to retirement plans in future years. Future required payments and the amount of liabilities recorded on the balance sheet associated with the plans could be unfavorably affected if the discount rate declines, the actual return on plan assets falls below the assumed return, or the health care cost trend rate increase is higher than expected. As described above, the Company’s retirement and postretirement expenses are sensitive to certain assumptions, primarily related to discount rates and assumed return on plan assets. A 0.5% decline in the discount rate would increase 2012 annual retirement and postretirement expenses by $6.1 million and $0.9 million, respectively, and a 0.5% decline in the assumed rate of return on plan assets would increase 2012 retirement expense by $2.4 million.

• Legal, environmental and other contingent matters – A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and other contingent matters. In addition, the Company often must estimate the amount of such losses. In many cases, management’s judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. The Company’s management closely monitors known and potential legal, environmental and other contingent matters, and makes its best estimate of the amount of losses and when they should be recorded based on information available to the Company.

Contractual obligations and guarantees – The Company is obligated to make future cash payments under borrowing arrangements, operating leases, purchase obligations primarily associated with existing capital expenditure commitments, and other long-term liabilities. In addition, the Company expects to extend certain operating leases beyond the minimum contractual period. Total payments due after 2012 under such contractual obligations and arrangements are shown below.

	Amount of Obligations
(Millions of dollars)	Total		2012		2013-2014		2015-2016		After 2016
Total debt including current maturities	$	599.6		350.0		0.1		0.1		249.4
Operating leases		826.3		161.6		265.2		150.2		249.3
Purchase obligations		2,513.4		1,967.4		478.7		47.4		19.9
Other long-term liabilities		1,277.3		98.6		120.7		229.5		828.5
Total	$	5,216.6		2,577.6		864.7		427.2		1,347.1

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The Company has entered into agreements to lease production facilities for various producing oil fields. In addition, the Company has other arrangements that call for future payments as described in the following section. The Company’s share of the contractual obligations under these leases and other arrangements has been included in the table above.

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. The amounts of commitments as of December 31, 2011 that expire in future periods are shown below.

	Amount of Commitments
(Millions of dollars)	Total		2012		2013-2014		2015-2016		After 2016
Financial guarantees	$	7.8		—		3.2		1.2		3.4
Letters of credit		162.9		155.7		7.2		—		—
Total	$	170.7		155.7		10.4		1.2		3.4

Material off-balance sheet arrangements – The Company occasionally utilizes off-balance sheet arrangements for operational or funding purposes. The most significant of these arrangements at year-end 2011 included operating leases of floating, production, storage and offloading vessels (FPSO) for the Kikeh and Azurite oil fields, operating leases for production facilities at the Thunder Hawk and West Patricia fields and for certain land and/or fueling stations in the U.K. and U.S., and natural gas transportation contracts in Western Canada. The leases call for future monthly net lease payments through 2016 at Kikeh and Azurite, through 2014 at Thunder Hawk and through 2012 at West Patricia. The U.K. and U.S. fueling stations require monthly payments mostly over the next 20 years. The Western Canada transportation contracts require minimum monthly payments through 2018. Future required minimum annual payments under these arrangements are included in the contractual obligation table shown on the preceding page.

Outlook

Prices for the Company’s primary products are often quite volatile. The price for crude oil is primarily affected by the level of demand for energy. In January 2012, West Texas Intermediate crude oil traded in a band between $98 and $103 per barrel. NYMEX natural gas traded in a band of $2.30 to $3.10 per MMBTU during this same time. U.S. retail marketing margins in January 2011 were squeezed by higher wholesale fuel costs during this period. The Company continually monitors the prices for its main products and often alters its operations and spending based on these prices.

The Company’s capital expenditure budget for 2012 was prepared during the fall of 2011 and based on this budget capital expenditures are expected to be higher than 2011 levels. Since the budget was approved by the Company’s Board of Directors, crude oil prices have generally been above the levels assumed in the 2012 budget, but North American natural gas prices have generally trailed the budgeted prices. Based on a recent review of capital expenditure projects, capital expenditures in 2012 are projected to total approximately $3.53 billion. Of this amount, $3.32 billion or about 94%, is allocated for the exploration and production program. Geographically, E&P capital is spread approximately as follows: 33% for the United States, 37% for Malaysia, 23% for Canada and 7% for all other areas. Spending in the U.S. is primarily associated with development and exploration programs in the Eagle Ford Shale area of South Texas. In Malaysia, the majority of the spending is for continued development of the Kikeh and Kakap fields in Block K and oil development projects offshore Sarawak in Blocks SK 309 and SK 311. Approximately 40% of Canadian spending in 2012 will relate to natural gas development activities at the Tupper and Tupper West areas in Western Canada, with most of the remainder to be spent on continued development of the Seal heavy oil area and at Syncrude. Refining and marketing expenditures in 2012 are budgeted at about $200 million, or 6% of the Company total, including funds for construction of additional U.S. retail gasoline stations. Capital and other expenditures will be routinely reviewed

53

during 2012 and planned capital expenditures may be adjusted to reflect differences between budgeted and actual cash flow during the year. Capital expenditures may also be affected by asset purchases, which often are not anticipated at the time the Budget is prepared.

The Company will primarily fund its capital program in 2012 using operating cash flow, but will supplement funding where necessary using borrowings under available credit facilities. The Company’s 2012 budget calls for borrowings of long-term debt during the year to fund a portion of the capital program. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that higher than anticipated borrowings might be required during the year to maintain funding of the Company’s ongoing development projects.

The Company currently expects production in 2012 to average about 200,000 barrels of oil equivalent per day. A key assumption in projecting the level of 2012 Company production is the anticipated ramp up of natural gas production in Western Canada. Should Canadian natural gas prices continue to remain weak throughout 2012, the Company may elect to delay its development drilling in the prolific Montney gas area. Other key assumptions necessary to achieve the anticipated 2012 production levels include continued reliability of production at significant operations such as Kikeh, Syncrude, Hibernia and Terra Nova, the continued demand for natural gas from our offshore Malaysia fields, and the continued favorable results of ongoing development activities at the Eagle Ford Shale area in South Texas.

The Company announced in 2010 that it planned to exit the U.K. refining and marketing business. The sale process for this U.K. business continues to progress in early 2012.

Forward-Looking Statements

This Form 10-K contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements include, but are not limited to, the volatility and level of crude oil and natural gas prices, the level and success rate of our exploration programs, our ability to maintain production rates and replace reserves, customer demand for our products, political and regulatory instability, and uncontrollable natural hazards. For further discussion of risk factors, see Item 1A. Risk Factors, which begins on page 15 of this Annual Report on Form 10-K. Murphy undertakes no duty to publicly update or revise any forward-looking statements.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note L to the consolidated financial statements, Murphy makes limited use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.

There were short-term commodity derivative contracts in place at December 31, 2011 to hedge the purchase price of about 8.0 million bushels of corn and the sales prices of about 1.1 million equivalent bushels of wet and dried distillers grain at the Company’s ethanol production facilities in Hankinson, North Dakota, and Hereford, Texas. Additionally, the Company had outstanding derivative contracts to price protect the historical cost of about 2.9 million bushels of corn inventories expected to be processed at the Company’s ethanol plants. A 10% increase in the respective benchmark price of these commodities would have increased the recorded net liability associated with these derivative contracts by approximately $2.0 million, while a 10% decrease would have decreased the recorded net liability by a similar amount. Changes in the fair value of these derivative contracts generally offset the changes in the value for an equivalent volume of these feedstocks.

There were short-term derivative foreign exchange contracts in place at December 31, 2011 to hedge the value of U.S. dollars against two foreign currencies. A 10% strengthening of the U.S. dollar against these foreign

54

currencies would have increased the recorded net liability associated with these contracts by approximately $17.6 million, while a 10% weakening of the U.S. dollar would have reduced the recorded net liability by approximately $6.3 million. Changes in the fair value of these derivative contracts generally offset the financial statement impact of an equivalent volume of foreign currency exposures associated with other assets and/or liabilities.

There were short-term derivative interest rate contracts in place at December 31, 2011 to hedge fluctuations in cash flows of anticipated future semi-annual interest payments attributable to changes in the benchmark interest rate. A 10% increase in the respective interest rate would have reduced the recorded liability associated with these derivative contracts by approximately $5.8 million, while a 10% decrease would have increased the recorded liability by a similar amount.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Information required by this item appears on pages F-1 through F-55, which follow page 60 of this Form 10-K report.

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

Item 9A. CONTROLS AND PROCEDURES

Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by Murphy to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

Based on their evaluation, with the participation of the Company’s management, as of December 31, 2011, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

Murphy’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Management has conducted an evaluation of the effectiveness of our internal control over financial reporting based on the criteria set forth in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, management has concluded that our internal control over financial reporting was effective as of December 31, 2011. Our report is included on page F-1 of the annual report. KPMG LLP, an independent registered public accounting firm, has made an independent assessment of the effectiveness of our internal control over financial reporting as of December 31, 2011 and their report is included on page F-3 of this annual report.

There were no changes in the Company’s internal controls over financial reporting that occurred during the fourth quarter of 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 9B. OTHER INFORMATION

None

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PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Certain information regarding executive officers of the Company is included on pages 20 and 21 of this Form 10-K report. Other information required by this item is incorporated by reference to the Registrant’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 9, 2012 under the captions “Election of Directors” and “Committees.”

Murphy Oil has adopted a Code of Ethical Conduct for Executive Management, which can be found under the Corporate Governance and Responsibility tab at www.murphyoilcorp.com. Stockholders may also obtain free of charge a copy of the Code of Ethical Conduct for Executive Management by writing to the Company’s Secretary at P.O. Box 7000, El Dorado, AR 71731-7000. Any future amendments to or waivers of the Company’s Code of Ethical Conduct for Executive Management will be posted on the Company’s internet Web site.

Item 11. EXECUTIVE COMPENSATION

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 9, 2012 under the captions “Compensation Discussion and Analysis” and “Compensation of Directors,” and in various compensation schedules.

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 9, 2012 under the captions “Security Ownership of Certain Beneficial Owners,” “Security Ownership of Management,” and “Equity Compensation Plan Information.”

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 9, 2012 under the caption “Election of Directors.”

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 9, 2012 under the caption “Audit Committee Report.”

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PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) 1. Financial Statements – The consolidated financial statements of Murphy Oil Corporation and consolidated subsidiaries are located or begin on the pages of this Form 10-K report as indicated below.

	Page No.
Report of Management – Consolidated Financial Statements	F-1
Report of Management – Internal Control Over Financial Reporting	F-1
Report of Independent Registered Public Accounting Firm	F-2
Report of Independent Registered Public Accounting Firm	F-3
Consolidated Balance Sheets	F-4
Consolidated Statements of Income	F-5
Consolidated Statements of Comprehensive Income	F-6
Consolidated Statements of Cash Flows	F-7
Consolidated Statements of Stockholders’ Equity	F-8
Notes to Consolidated Financial Statements	F-9
Supplemental Oil and Gas Information (unaudited)	F-46
Supplemental Quarterly Information (unaudited)	F-55
2. Financial Statement Schedules
Schedule II – Valuation Accounts and Reserves	F-56

All other financial statement schedules are omitted because either they are not applicable or the required information is included in the consolidated financial statements or notes thereto.

3. Exhibits – The following is an index of exhibits that are hereby filed as indicated by asterisk (*), that are considered furnished rather than filed, or that are incorporated by reference. Exhibits other than those listed have been omitted since they either are not required or are not applicable.

Exhibit No.		Incorporated by Reference to
2.1	Asset Purchase Agreement between Calumet Specialty Products Partners, L.P. and Murphy Oil Corporation covering the Superior, Wisconsin refinery	Exhibit 2.1 of Murphy’s Form 10-Q report filed November 4, 2011
2.2	Asset Purchase Agreement between Valero Refining-Meraux LLC and Murphy Oil Corporation covering the Meraux, Louisiana refinery	Exhibit 2.2 of Murphy’s Form 10-Q report filed November 4, 2011
3.1	Certificate of Incorporation of Murphy Oil Corporation as amended, effective May 11, 2005	Exhibit 3.1 of Murphy’s Form 10-K report filed February 28, 2011
3.2	By-Laws of Murphy Oil Corporation as amended effective February 3, 2010	Exhibit 3.2 of Murphy’s Form 8-K report filed February 4, 2010
4	Instruments Defining the Rights of Security Holders. Murphy is party to several long-term debt instruments in addition to those in Exhibit 4.1 and 4.2, none of which authorizes securities exceeding 10% of the total consolidated assets of Murphy and its subsidiaries. Pursuant to Regulation S-K, item 601(b), paragraph 4(iii)(A), Murphy agrees to furnish a copy of each such instrument to the Securities and Exchange Commission upon request.

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Exhibit No.		Incorporated by Reference to
4.1	Form of Second Supplemental Indenture between Murphy Oil Corporation and SunTrust Bank, as Trustee	Exhibit 4.1 of Murphy’s Form 10-K report for the year ended December 31, 2008
4.2	Form of Indenture and Form of Supplemental Indenture between Murphy Oil Corporation and SunTrust Bank as Trustee	Exhibit 4.2 of Murphy’s Form 10-K report for the year ended December 31, 2009
10.1	1992 Stock Incentive Plan as amended May 14, 1997, December 1, 1999, May 14, 2003 and December 7, 2005	Exhibit 10.1 of Murphy’s Form 10-K report for the year ended December 31, 2010
10.2	2007 Long-Term Incentive Plan	Exhibit 10.1 of Murphy’s Form 8-K report filed April 24, 2007
10.3	Employee Stock Purchase Plan as amended May 9, 2007	Exhibit C of Murphy’s definitive proxy statement (Definitive 14A) dated March 30, 2007
10.4	2008 Stock Plan for Non-Employee Directors, as approved by shareholders on May 14, 2008	Form S-8 report filed February 5, 2009
*12.1	Computation of Ratio of Earnings to Fixed Charges
*13	2011 Annual Report to Security Holders
*21	Subsidiaries of the Registrant
*23.1	Consent of Independent Registered Public Accounting Firm
*23.2	Consent of Ryder Scott Company, L.P.
*31.1	Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.2	Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	See footnote1 on page 59.
99.1	Form of employee stock option	Exhibit 99.1 of Murphy’s Form 10-K report for the year ended December 31, 2009
99.2	Form of performanced-based employee restricted stock unit grant agreement	Exhibit 99.2 of Murphy’s Form 10-K report for the year ended December 31, 2008
99.3	Form of non-employee director stock option	Exhibit 99.3 of Murphy’s Form 10-K report for the year ended December 31, 2010
99.4	Form of non-employee director restricted stock award	Exhibit 99.4 of Murphy’s Form 10-K report for the year ended December 31, 2006
99.5	Form of non-employee director restricted stock unit award	Exhibit 99.5 of Murphy’s Form 10-K report for the year ended December 31, 2008

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Exhibit No.		Incorporated by Reference to
*99.6	Report of Ryder Scott Company, L.P.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

¹  These certifications will not be deemed to be filed with the Commission or incorporated by reference into any filing by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates such certifications by reference.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

MURPHY OIL CORPORATION
By	DAVID M. WOOD	Date:	February 28, 2012
	David M. Wood, President

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 28, 2012 by the following persons on behalf of the registrant and in the capacities indicated.

WILLIAM C. NOLAN, JR. William C. Nolan, Jr., Chairman and Director	WALENTIN MIROSH Walentin Mirosh, Director
DAVID M. WOOD David M. Wood, President and Chief Executive Officer and Director (Principal Executive Officer)	R. MADISON MURPHY R. Madison Murphy, Director
FRANK W. BLUE Frank W. Blue, Director	NEAL E. SCHMALE Neal E. Schmale, Director
STEVEN A. COSSÉ Steven A. Cossé, Director	DAVID J. H. SMITH David J. H. Smith, Director
CLAIBORNE P. DEMING Claiborne P. Deming, Director	CAROLINE G. THEUS Caroline G. Theus, Director
ROBERT A. HERMES Robert A. Hermes, Director	KEVIN G. FITZGERALD Kevin G. Fitzgerald, Executive Vice President and Chief Financial Officer (Principal Financial Officer)
JAMES V. KELLEY James V. Kelley, Director	JOHN W. ECKART John W. Eckart Senior Vice President and Controller (Principal Accounting Officer)

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REPORT OF MANAGEMENT – CONSOLIDATED FINANCIAL STATEMENTS

The management of Murphy Oil Corporation is responsible for the preparation and integrity of the accompanying consolidated financial statements and other financial data. The statements were prepared in conformity with U.S. generally accepted accounting principles appropriate in the circumstances and include some amounts based on informed estimates and judgments, with consideration given to materiality.

An independent registered public accounting firm, KPMG LLP, has audited the Company’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board and provides an objective, independent opinion about the Company’s consolidated financial statements. The Audit Committee of the Board of Directors appoints the independent registered public accounting firm; ratification of the appointment is solicited annually from the shareholders.

The Board of Directors appoints an Audit Committee annually to implement and to support the Board’s oversight function of the Company’s financial reporting, accounting policies, internal controls and independent registered public accounting firm. This Committee is composed solely of directors who are not employees of the Company. The Committee meets routinely with representatives of management, the Company’s audit staff and the independent registered public accounting firm to review and discuss the adequacy and effectiveness of the Company’s internal controls, the quality and clarity of its financial reporting, the scope and results of independent and internal audits, and to fulfill other responsibilities included in the Committee’s Charter. The independent registered public accounting firm and the Company’s audit staff have unrestricted access to the Committee, without management presence, to discuss audit findings and other financial matters.

REPORT OF MANAGEMENT – INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). The Company’s internal controls have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements in accordance with U.S. generally accepted accounting principles. All internal control systems have inherent limitations, and therefore, can provide only reasonable assurance with respect to the reliability of financial reporting and preparation of consolidated financial statements.

Management has conducted an evaluation of the effectiveness of our internal control over financial reporting based on the criteria set forth in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2011.

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of Murphy Oil Corporation:

We have audited the accompanying consolidated balance sheets of Murphy Oil Corporation and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, cash flows and stockholders’ equity for each of the years in the three-year period ended December 31, 2011. In connection with our audits of the consolidated financial statements, we also have audited financial statement Schedule II. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Murphy Oil Corporation and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Murphy Oil Corporation’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2012 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

February 28, 2012

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of Murphy Oil Corporation:

We have audited Murphy Oil Corporation’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Murphy Oil Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Report of Management – Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Murphy Oil Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Murphy Oil Corporation as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, cash flows and stockholders’ equity for each of the years in the three-year period ended December 31, 2011, and our report dated February 28, 2012 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, Texas

February 28, 2012

F-3

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31 (Thousands of dollars)	2011			2010
Assets
Current assets
Cash and cash equivalents	$	513,873			535,825
Canadian government securities with maturities greater than 90 days at the date of acquisition		532,093			616,558
Accounts receivable, less allowance for doubtful accounts of $7,892 in 2011 and $7,954 in 2010		1,554,184			1,467,311
Inventories, at lower of cost or market
Crude oil and blend stocks		189,320			147,256
Finished products		254,880			388,162
Materials and supplies		222,438			226,795
Prepaid expenses		93,397			88,241
Deferred income taxes		87,486			80,545
Total current assets		3,447,671			3,550,693
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $6,861,494 in 2011 and $6,040,996 in 2010		10,475,149			10,367,847
Goodwill		41,863			42,850
Deferred charges and other assets		173,455			271,853
Total assets	$	14,138,138			14,233,243
Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	350,005			41
Accounts payable		1,941,008			2,237,920
Income taxes payable		201,784			358,764
Other taxes payable		169,535			206,951
Other accrued liabilities		140,024			109,918
Deferred income taxes		22,572			17,316
Total current liabilities		2,824,928			2,930,910
Long-term debt		249,553			939,350
Deferred income taxes		1,230,111			1,212,213
Asset retirement obligations		615,545			555,248
Deferred credits and other liabilities		439,604			395,972
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, 2011 and 2010, issued 193,909,200 shares at December 31, 2011 and 193,293,526 shares at December 31, 2010		193,909			193,294
Capital in excess of par value		817,974			767,762
Retained earnings		7,460,942			6,800,992
Accumulated other comprehensive income		310,420			449,428
Treasury stock		(4,848	)		(11,926	)
Total stockholders’ equity		8,778,397			8,199,550
Total liabilities and stockholders’ equity	$	14,138,138			14,233,243

See notes to consolidated financial statements, page F-9.

F-4

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

Years Ended December 31 (Thousands of dollars except per share amounts)	2011			2010*			2009*
Revenues
Sales and other operating revenues	$	27,689,332			20,225,764			16,800,972
Gain on sale of assets		22,679			884			3,732
Interest and other income (loss)		33,538			(56,930	)		90,502
Total revenues		27,745,549			20,169,718			16,895,206
Costs and Expenses
Crude oil and product purchases		21,875,297			15,351,318			12,821,305
Operating expenses		1,993,346			1,678,515			1,350,658
Exploration expenses, including undeveloped lease amortization		489,862			292,264			265,172
Selling and general expenses		301,005			259,215			212,376
Depreciation, depletion and amortization		1,093,406			1,114,529			870,999
Impairment of properties		368,600			0			5,240
Accretion of asset retirement obligations		37,701			31,857			26,154
Redetermination of Terra Nova working interest		(5,351	)		18,582			83,498
Interest expense		55,831			53,172			53,005
Interest capitalized		(15,131	)		(18,444	)		(28,614	)
Total costs and expenses		26,194,566			18,781,008			15,659,793
Income from continuing operations before income taxes		1,550,983			1,388,710			1,235,413
Income tax expense		810,051			609,151			521,559
Income from continuing operations		740,932			779,559			713,854
Income from discontinued operations, net of income taxes		131,770			18,522			123,767
Net Income	$	872,702			798,081			837,621
Income per Common Share – Basic
Income from continuing operations	$	3.83			4.06			3.74
Income from discontinued operations		0.68			0.10			0.65
Net Income – Basic	$	4.51			4.16			4.39
Income per Common Share – Diluted
Income from continuing operations	$	3.81			4.03			3.71
Income from discontinued operations		0.68			0.10			0.64
Net Income – Diluted	$	4.49			4.13			4.35
Average Common shares outstanding – basic		193,409,621			191,830,357			190,767,077
Average Common shares outstanding – diluted		194,512,402			193,157,814			192,468,450

See notes to consolidated financial statements, page F-9.

* Reclassified to conform to current presentation.

F-5

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Years Ended December 31 (Thousands of dollars)	2011			2010			2009
Net income	$	872,702			798,081			837,621
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation		(91,247	)		165,940			375,951
Retirement and postretirement benefit plan adjustments		(30,909	)		(3,699	)		(1,067	)
Loss deferred on interest rate hedges		(16,852	)		0			0
Other comprehensive income (loss)		(139,008	)		162,241			374,884
Comprehensive Income	$	733,694			960,322			1,212,505

See notes to consolidated financial statements, page F-9.

F-6

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31 (Thousands of dollars)	2011			20101			20091
Operating Activities
Net income	$	872,702			798,081			837,621
Adjustments to reconcile net income to net cash provided by operating activities
Income from discontinued operations		(131,770	)		(18,522	)		(123,767	)
Depreciation, depletion and amortization		1,093,406			1,114,529			870,999
Impairment of long-lived assets		368,600			0			5,240
Amortization of deferred major repair costs		23,076			15,561			7,348
Expenditures for asset retirements		(24,692	)		(36,506	)		(48,694	)
Dry hole costs		250,954			90,125			125,244
Amortization of undeveloped leases		118,211			108,026			83,213
Accretion of asset retirement obligations		37,701			31,857			26,154
Deferred and noncurrent income tax charges		171,565			135,225			95,245
Pretax gains from disposition of assets		(22,679	)		(884	)		(3,709	)
Net decrease (increase) in noncash operating working capital		(825,154	)		639,566			(194,690	)
Other operating activities – net		67,955			151,012			90,001
Net cash provided by continuing operations		1,999,875			3,028,070			1,770,205
Net cash provided by discontinued operations		145,510			100,488			94,428
Net cash provided by operating activities		2,145,385			3,128,558			1,864,633
Investing Activities
Property additions and dry hole costs		(2,623,407	)		(2,199,049	)		(1,866,114	)
Acquisition of ethanol plants 2		0			(40,000	)		(10,000	)
Proceeds from sale of property, plant and equipment		27,776			2,189			1,616
Expenditures for major repairs		(5,409	)		(61,387	)		(19,252	)
Purchase of investment securities 3		(1,689,087	)		(2,388,720	)		(2,531,515	)
Proceeds from maturity of investment securities 3		1,773,552			2,551,187			2,172,830
Other investing activities – net		8,014			(38,157	)		(34,050	)
Investing activities of discontinued operations
Sales proceeds		950,010			0			78,908
Other		(55,803	)		(154,875	)		(124,330	)
Net cash required by investing activities		(1,614,354	)		(2,328,812	)		(2,331,907	)
Financing Activities
Additions to long-term debt		0			0			243,500
Reductions of long-term debt		(340,041	)		(332,038	)		0
Reductions of nonrecourse debt of a subsidiary		0			(82,000	)		(2,572	)
Proceeds from exercise of stock options and employee stock purchase plans		15,551			42,995			12,746
Excess tax benefits related to exercise of stock options		4,838			11,672			4,143
Withholding tax on stock-based incentive awards		(8,014	)		(5,170	)		0
Issue cost of debt facility		(7,905	)		0			0
Cash dividends paid		(212,752	)		(201,405	)		(190,788	)
Net cash provided (required) by financing activities		(548,323	)		(565,946	)		67,029
Effect of exchange rate changes on cash and cash equivalents		(4,660	)		881			35,279
Net increase (decrease) in cash and cash equivalents		(21,952	)		234,681			(364,966	)
Cash and cash equivalents at January 1		535,825			301,144			666,110
Cash and cash equivalents at December 31	$	513,873			535,825			301,144

¹ Reclassified to conform to current presentation.

²  Excludes nonrecourse seller financing of $82 million related to the Company’s acquisition of the Hankinson, North Dakota, ethanol plant in 2009.

³  Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.

See notes to consolidated financial statements, page F-9.

F-7

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

Years Ended December 31 (Thousands of dollars)	2011			2010			2009
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued		0			0			0
Common Stock – par $1.00, authorized 450,000,000 shares at December 31, 2011, 2010 and 2009, issued 193,909,200 shares at December 31, 2011, 193,293,526 shares at December 31, 2010 and 191,797,600 shares at December 31, 2009
Balance at beginning of year	$	193,294			191,798			191,249
Exercise of stock options		615			1,496			549
Balance at end of year		193,909			193,294			191,798
Capital in Excess of Par Value
Balance at beginning of year		767,762			680,509			631,859
Exercise of stock options, including income tax benefits		21,774			54,887			17,244
Restricted stock transactions and other		(15,119	)		(9,688	)		2,473
Stock-based compensation		42,492			40,842			27,976
Sale of stock under employee stock purchase plans		1,065			1,212			957
Balance at end of year		817,974			767,762			680,509
Retained Earnings
Balance at beginning of year		6,800,992			6,204,316			5,557,483
Net income for the year		872,702			798,081			837,621
Cash dividends – $1.10 per share in 2011, $1.05 per share in 2010 and $1.00 per share in 2009		(212,752	)		(201,405	)		(190,788	)
Balance at end of year		7,460,942			6,800,992			6,204,316
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of year		449,428			287,187			(87,697	)
Foreign currency translation gains (losses)		(91,247	)		165,940			375,951
Retirement and postretirement benefit plan adjustments, net of income taxes		(30,909	)		(3,699	)		(1,067	)
Loss deferred on interest rate hedges, net of income taxes		(16,852	)		0			0
Balance at end of year		310,420			449,428			287,187
Treasury Stock
Balance at beginning of year		(11,926	)		(17,784	)		(13,949	)
Sale of stock under employee stock purchase plans		870			1,295			1,604
Awarded restricted stock, net of forfeitures		6,208			4,305			0
Cancellation of performance-based restricted stock and forfeitures		0			258			(5,439	)
Balance at end of year – 185,992 shares of Common Stock in 2011, 457,518 shares in 2010 and 682,222 shares in 2009		(4,848	)		(11,926	)		(17,784	)
Total Stockholders’ Equity	$	8,778,397			8,199,550			7,346,026

See notes to consolidated financial statements, page F-9.

F-8

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. Murphy markets petroleum products under various brand names and to unbranded wholesale customers in the United States and United Kingdom. It owns two ethanol production facilities in the United States and one petroleum refinery in the United Kingdom. In 2011, the Company sold two U.S. petroleum refineries and certain associated marketing assets. The Company has announced its intention to sell the U.K. refining and marketing 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. 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 Company’s 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 December 31, 2011 and 2010, 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-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. 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

F-9

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

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, 2011, the Company owned Canadian government securities with maturities greater than 90 days at date of acquisition that had a carrying value of $532,093,000.

ACCOUNTS RECEIVABLE – The Company’s accounts receivable primarily consists of amounts owed to the Company by customers for sales of crude oil, natural gas and refined products under varying credit arrangements. 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.

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 are generally 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 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.

F-10

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

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. Refineries, certain marketing facilities and certain common 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.

Turnarounds for major processing units at refineries 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 refineries and Syncrude varies depending on operating requirements and events. Murphy defers turnaround costs incurred and amortizes such costs through Operating Expenses over the period until the next scheduled turnaround. All other maintenance and repairs are expensed as incurred. Renewals and betterments are capitalized. Major turnarounds occurred in 2010 at both the Meraux, Louisiana, and Milford Haven, Wales, refineries.

INVENTORIES – 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 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 is generally carried at average cost and is included in Finished Products Inventory. Materials and supplies are valued at the lower of average cost or estimated value and generally consist of tubulars and other drilling equipment as well as 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.

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 at least 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 2011 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, 2011. 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. See Note B for accounting changes applicable to goodwill recoverability testing beginning in 2012.

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

F-11

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

assets and liabilities. Deferred income taxes are measured using the enacted tax rates that are assumed will be in effect when the differences reverse. Petroleum revenue taxes are provided using the estimated effective tax rate over the life of applicable U.K. properties. 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 Spain 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 currency into U.S. dollars are included in Accumulated Other Comprehensive Income (Loss) in Stockholders’ Equity.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES – The fair value of a derivative instrument is recognized as an asset or liability in the Company’s Consolidated Balance Sheet. Upon entering into a derivative contract, the Company may designate the derivative as either a fair value hedge or a cash flow hedge, or decide that the contract is not a hedge, 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 used 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. Changes in the fair value of a qualifying fair value hedge are recorded in earnings along with the gain or loss on the hedged item. Changes in the fair value of a qualifying cash flow hedge are 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 Statement of Income, the fair value of the associated cash flow hedge is reclassified from other comprehensive income into earnings. Ineffective portions of a cash flow hedge derivative’s change in fair value are 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.

STOCK-BASED COMPENSATION – The fair value of awarded stock options, restricted stock and restricted stock units 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 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 and restricted stock units and expense is recognized over the three-year vesting period. The fair value of time-lapse restricted stock 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 and 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.

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.

F-12

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

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.

Note B – New Accounting Principles and Recent Accounting Pronouncements

Accounting Principles Adopted

The Company adopted guidance issued by the Financial Accounting Standards Board (FASB) regarding accounting for transfers of financial assets effective January 1, 2010. This guidance makes the concept of a qualifying special-purpose entity as defined previously no longer relevant for accounting purposes. Therefore, formerly qualifying special-purpose entities were reevaluated for consolidation by reporting entities in accordance with the applicable consolidation guidance. This adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted, effective January 1, 2010, guidance issued by the FASB that requires a company to perform an analysis to determine whether its variable interests give it a controlling financial interest in a variable interest entity. The primary beneficiary of a variable interest entity has both the power to direct the activities of the entity that most significantly impact the entity’s economic performance and the obligation to absorb potentially significant losses of the entity or the right to receive potentially significant benefits from the entity. A company is required to make ongoing reassessments of whether it is the primary beneficiary of a variable interest entity. This guidance also amended previous guidance for determining whether an entity is considered a variable interest entity. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

In July 2010, the FASB issued accounting guidance that expanded the disclosure requirements about financing receivables and the related allowance for credit losses. This guidance became effective for the Company at December 31, 2010. Because the Company has no significant financing receivables that extend beyond one year, the impact of this guidance did not have a significant effect on its consolidated financial statement disclosures.

The U.S. Securities and Exchange Commission (SEC) adopted revisions to oil and natural gas reserves reporting requirements which were effective for the Company at year-end 2009. In January 2010, the FASB issued guidance that aligned its oil and gas reserves reporting requirements and effective date with the SEC’s guidance. The primary changes to reserves reporting included:

• A revised definition of proved reserves, including the use of unweighted average oil and natural gas prices in effect at the beginning of each month during the year to compute such reserves,

• Expanding the definition of oil and gas producing activities to include non-traditional and unconventional resources, which includes the Company’s Canadian synthetic oil operations at Syncrude,

• Allowing companies to voluntarily disclose probable and possible reserves in SEC filings,

• Amending required proved reserve disclosures to include separate amounts for synthetic oil and gas,

• Expanded disclosures of proved undeveloped reserves, including discussion of such proved undeveloped reserves five years old or more, and

• Disclosure of the qualifications of the chief technical person who oversees the Company’s overall reserve process.

F-13

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

The Company utilized the new SEC and FASB guidance at December 31, 2011, 2010 and 2009 to determine its proved reserves and to develop associated disclosures. The Company chose not to provide voluntary disclosures of probable and possible reserves in this Form 10-K.

Recent Accounting and Reporting Rules

In September 2011, the FASB issued an accounting standards update that simplifies the annual goodwill impairment assessment process by permitting a company to assess whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount before applying the two-step goodwill impairment test. If a company concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the company would be required to conduct the current two-step goodwill impairment test. This change is effective for annual and interim goodwill impairment tests performed in fiscal years beginning in 2012. Early adoption is permitted. The Company does not expect the adoption of this standard in 2012 to have a significant effect on its consolidated financial statements.

In June 2011, the FASB issued an accounting standards update that only permits two options for presentation of Comprehensive Income. Comprehensive Income can be presented in (a) a single continuous Statement of Comprehensive Income, including total comprehensive income, the components of net income, and the components of other comprehensive income, or (b) in two separate but continuous statements for the Statement of Income and the Statement of Comprehensive Income. The new guidance is effective for the Company beginning in the first quarter of 2012. As in prior years, the Company expects to continue to present the Statements of Income and Comprehensive Income in two separate statements, and the adoption of this guidance in 2012 is not expected to have a significant effect on the Company’s consolidated financial statements. In December 2011, the FASB deferred the requirement for reclassification adjustments from accumulated other comprehensive income to be measured and presented by line item in the Statements of Income and Comprehensive Income.

Note C – Discontinued Operations

In July 2010, the Company announced that it planned to exit the U.S. refining and U.K. refining and marketing businesses. 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 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 began to account for the results of the Superior, Wisconsin and Meraux, Louisiana refineries and associated marketing assets as discontinued operations beginning in the third quarter 2011. All prior periods presented have been reclassified to conform to this presentation of the Superior and Meraux operating results as discontinued operations. The after-tax gain 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 was based on refinery selling prices, plus the sales of all associated inventories at fair value, which was significantly above the last-in, first-out carrying value of the inventories sold. The net gain on sale of the refineries included an after-tax benefit of $179,152,000 from liquidation of inventories formerly carried mostly under the last-in, first-out cost method. The U.S. refineries sold were formerly reported in the U.S. manufacturing segment. The sale process for the U.K. refining and marketing assets continues.

F-14

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

The major assets and liabilities related to the Superior and Meraux refineries and associated marketing assets at the time of their sale are presented in the following table.

(Thousands of dollars)
Current assets:
Accounts receivable	$	1,191
Liquid inventories		115,014
Materials and supplies inventories		39,853
Total current assets – U.S. refineries		156,058
Noncurrent assets:
Property, plant and equipment, net of accumulated depreciation, depletion and amortization		723,980
Other		48,604
Total noncurrent assets – U.S. refineries		772,584
Total assets – U.S. refineries	$	928,642
Liabilities:
Current liabilities	$	2,637
Other noncurrent liabilities		14,133
Liabilities associated with assets sold – U.S. refineries	$	16,770

On March 12, 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 Block 16 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. Ecuador operating results prior to the sale, and the resulting gain on disposal, have been reported as discontinued operations. The major assets and 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 – Ecuador	$	70,075
Current liabilities	$	105,185
Other noncurrent liabilities		35
Liabilities associated with assets sold – Ecuador	$	105,220

F-15

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

The results of operations associated with these discontinued operations are presented in the following table.

(Thousands of dollars)	2011		2010		2009
Revenues:
U.S. refineries	$	3,700,789		3,175,353		2,117,186
Ecuador E&P operations		0		0		125,654
Total revenues	$	3,700,789		3,175,353		2,242,840
Income (loss) from operations before income taxes:
U.S. refineries	$	188,231		25,521		41,760
Ecuador E&P operations		0		0		(7,692	)
		188,231		25,521		34,068
Gain on sale before income taxes:
U.S. refineries		12,684		0		0
Ecuador E&P operations		0		0		117,557
		12,684		0		117,557
Total income from discontinued operations before taxes		200,915		25,521		151,625
Provision for income taxes		69,145		6,999		27,858
Income from discontinued operations	$	131,770		18,522		123,767

Note D – Acquisitions

In August 2010, a wholly-owned subsidiary of the Company purchased an unfinished ethanol production facility in Hereford, Texas, for $40,000,000. The Company completed construction of the facility and commenced operations near the end of the first quarter of 2011. The Company allocated the purchase price for the Hereford facility based on the fair value of the assets acquired as presented in the following table.

(Thousands of dollars)
Land and land improvements	$	2,379
Buildings and improvements		639
Machinery and transportation equipment		36,982
Total purchase price – Hereford ethanol facility	$	40,000

A wholly-owned subsidiary of the Company purchased an ethanol production facility in Hankinson, North Dakota, on October 1, 2009. The facility has a rated capacity to produce 110 million 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 bore interest at 5.0% per year and was repayable in 2014. This loan was repaid in full in September 2010. Revenue and expenses associated with the facility have been included in the Company’s Consolidated Statement of Income beginning on the date of acquisition. The Company allocated the purchase price for the Hankinson facility based on the 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 – Hankinson ethanol facility	$	92,000

F-16

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note E – Property, Plant and Equipment

	December 31, 2011					December 31, 2010
(Thousands of dollars)	Cost		Net			Cost		Net
Exploration and production1	$	14,766,637		8,730,124	2		12,506,579		7,898,417	2
Refining and marketing		2,456,822		1,688,709			3,794,223		2,409,410
Corporate and other		113,184		56,316			108,041		60,020
	$	17,336,643		10,475,149			16,408,843		10,367,847
1         Includes mineral rights as follows:	$	1,078,770		619,950			779,036		432,051

²  Includes $21,154 in 2011 and $17,067 in 2010 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, 2011, 2010 and 2009, the Company had total capitalized drilling costs pending the determination of proved reserves of $556,412,000, $497,765,000 and $369,862,000, respectively. The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 2011.

(Thousands of dollars)	2011			2010			2009
Beginning balance at January 1	$	497,765			369,862			310,118
Additions to capitalized exploratory well costs pending the determination of proved reserves		86,035			137,403			119,995
Reclassifications to proved properties based on the determination of proved reserves		0			0			(60,251	)
Capitalized exploratory well costs charged to expense or sold		(27,388	)		(9,500	)		0
Ending balance at December 31	$	556,412			497,765			369,862

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.

	2011						2010						2009
(Thousands of dollars)	Amount		No. of Wells		No. of Projects		Amount		No. of Wells		No. of Projects		Amount		No. of Wells		No. of Projects
Aging of capitalized well costs:
Zero to one year	$	69,757		11		5		135,494		15		4	$	117,618		10		6
One to two years		143,611		15		3		115,418		10		4		49,628		4		4
Two to three years		101,696		9		2		42,571		3		3		8,870		5		0
Three years or more		241,348		33		6		204,282		31		4		193,746		27		4
	$	556,412		68		16		497,765		59		15	$	369,862		46		14

Of the $486,655,000 of exploratory well costs capitalized more than one year at December 31, 2011, $306,475,000 is in Malaysia, $138,634,000 is in the U.S., $29,188,000 is in Republic of the Congo and $12,358,000 is in Canada. 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 Republic of the Congo further appraised drilling is planned. In

F-17

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Canada a continuing drilling and development program is underway. The capitalized well costs charged to expense 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 2011, the Company determined that a downward revision of proved oil reserves for the Azurite field, offshore Republic of the Congo, was necessary. The determination was made after 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. Therefore, an impairment charge of $368,600,000 was recorded in 2011 to reduce the carrying value of the field to fair value. Fair value was determined 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 carrying value of the net property, plant and equipment for the Azurite field was reduced at December 31, 2011 to the present value of the net cash inflows for the field based on the results of the discounted cash flow calculation.

In 2010, the Company announced that its Board of Directors had approved plans to exit the U.K. refining and marketing business. These operations are presented as the U.K. refining and marketing segment in Note U. The sale process for the U.K. downstream assets continues. Based on current market conditions, it is possible that the Company could incur a loss if the U.K. downstream assets are sold in a future period. If the sale of the U.K. downstream assets continues to progress, the results of these operations will be presented as discontinued operations in future periods when the criteria for held for sale under U.S. generally accepted accounting principles have been met.

Note F – Financing Arrangements

At December 31, 2011, the Company had a $1.5 billion committed credit facility with a major banking consortium that matures in June 2016. 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 December 31, 2011, the Company had no borrowings under this committed facility. At December 31, 2011, the Company also had no borrowings under uncommitted credit lines that amount to approximately $400,000,000. 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 September 2012.

Note G – Long-term Debt

	December 31
(Thousands of dollars)	2011			2010
Notes payable
6.375% notes, due 2012, net of unamortized discount of $38 at December 31, 2011	$	349,962			349,846
7.05% notes, due 2029, net of unamortized discount of $1,616 at December 31, 2011		248,384			248,291
Notes payable to banks, 0.7375% at December 31, 2010		0			340,000
Other, 6%, due through 2028		1,212			1,254
Total debt including current maturities		599,558			939,391
Current maturities		(350,005	)		(41	)
Total long-term debt	$	249,553			939,350

Future amounts repayable under debt agreements are: $350,005,000 in 2012, $46,000 in 2013, $48,000 in 2014, $51,000 in 2015, $55,000 in 2016 and $249,353,000 thereafter.

F-18

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

During 2011, the Company used a portion of the proceeds from the sale of two U.S. refineries to repay notes payable outstanding under committed and uncommitted credit facilities.

Note H – Asset Retirement Obligations

The majority of the asset retirement obligations liabilities (ARO) recognized by the Company at December 31, 2011 and 2010 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 has not recorded 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 2011 and 2010 is shown in the following table.

(Thousands of dollars)	2011			2010
Balance at beginning of year	$	555,248			476,938
Accretion expense		37,701			31,857
Liabilities incurred		51,858			59,605
Revision of previous estimates		7,608			14,170
Liabilities settled		(32,088	)*		(36,506	)
Changes due to translation of foreign currencies		(4,782	)		9,184
Balance at end of year	$	615,545			555,248

* Includes noncash settlements related to sale of assets in Spain in 2011.

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.

Note I – Income Taxes

The components of income from continuing operations before income taxes for each of the three years ended December 31, 2011 and income tax expense attributable thereto were as follows.

(Thousands of dollars)	2011		2010			2009
Income from continuing operations before income taxes
United States	$	440,753		188,588			261,005
Foreign		1,110,230		1,200,122			974,408
	$	1,550,983		1,388,710			1,235,413
Income tax expense
Federal – Current	$	99,451		110,142			100,276
Deferred		43,602		(40,981	)		2,078
		143,053		69,161			102,354
State		30,372		15,486			7,087
Foreign – Current		497,446		347,746			318,619
Deferred		139,180		176,758			93,499
		636,626		524,504			412,118
Total	$	810,051		609,151			521,559

F-19

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Income tax benefits attributable to employee stock option transactions of $8,775,000 in 2011, $15,896,000 in 2010 and $6,035,000 in 2009 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 Company’s income tax expense.

(Thousands of dollars)	2011			2010		2009
Income tax expense based on the U.S. statutory tax rate	$	542,844			486,049		432,395
Foreign income subject to foreign taxes at a rate different than the U.S. statutory rate		10,053			56,367		33,395
State income taxes, net of federal benefit		19,742			10,066		4,607
Increase in deferred tax asset valuation allowance related to foreign exploration expenditures		102,714			47,128		34,431
Impairment of Azurite field with no tax benefit		129,010			0		0
Malaysian tax benefits on prior year costs in Block P		(25,573	)		0		0
Increase in United Kingdom oil and gas tax rate		14,461			0		0
Other, net		16,800			9,541		16,731
Total	$	810,051			609,151		521,559

An analysis of the Company’s deferred tax assets and deferred tax liabilities at December 31, 2011 and 2010 showing the tax effects of significant temporary differences follows.

(Thousands of dollars)	2011			2010
Deferred tax assets
Property and leasehold costs	$	627,093			391,168
Liabilities for dismantlements		114,175			97,149
Postretirement and other employee benefits		164,044			137,709
Foreign tax credit carryforwards		21,368			47,725
Other deferred tax assets		38,341			47,511
Total gross deferred tax assets		965,021			721,262
Less valuation allowance		(445,842	)		(305,349	)
Net deferred tax assets		519,179			415,913
Deferred tax liabilities
Property, plant and equipment		(851,330	)		(729,699	)
Accumulated depreciation, depletion and amortization		(754,295	)		(702,512	)
Deferred major repair costs		(11,257	)		(35,848	)
Other deferred tax liabilities		(67,494	)		(96,838	)
Total gross deferred tax liabilities		(1,684,376	)		(1,564,897	)
Net deferred tax liabilities	$	(1,165,197	)		(1,148,984	)

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 2014 through 2020. The valuation allowance increased

F-20

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

$140,493,000 in 2011, 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, 2011, undistributed earnings of the Company’s subsidiaries considered indefinitely invested were approximately $4,895,000,000. 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 $492,469,000. 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 years ended December 31, 2011 and 2010 follows.

(Thousands of dollars)	2011			2010
Balance at January 1	$	23,196			25,978
Additions for tax positions related to current year		1,294			1,225
Settlements due to lapse of time		(5,633	)		(4,007	)
Balance at December 31	$	18,857			23,196

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, 2011 and 2010 for interest and penalties of $976,000 and $1,010,000, respectively, associated with uncertain tax positions. Income tax expense for the years ended December 31, 2011, 2010 and 2009 included (charges)/benefits for interest and penalties of $34,000, $(43,000) and $1,763,000, 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 2012 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 2012.

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

F-21

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. As of December 31, 2011, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2008; Canada – 2007; United Kingdom – 2010; and Malaysia – 2006.

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.

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 certain other employees. Cash awards under the 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 2007 Long-Term Incentive Plan (2007 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units, performance units, performance shares, dividend equivalents and other stock-based incentives. The 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. At December 31, 2011, approximately 5,745,000 shares remained available for issuance under the 2007 Long-Term Plan. 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 Company’s 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)	2011		2010		2009
Compensation charged against income before income tax benefit	$	43,272		41,992		28,618
Related income tax benefit recognized in income		13,053		12,169		7,860

As of December 31, 2011, there was $55,100,000 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, 2011, 2010 and 2009 was $15,551,000, $42,995,000 and $12,746,000, respectively. Total income tax benefits realized from tax deductions related to stock option exercises under share-based payment arrangements were $8,775,000, $15,896,000 and $6,035,000 for the years ended December 31, 2011, 2010 and 2009, 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 2007 Long-Term Plan has been unqualified, with a term of seven years and an option price equal to FMV at date of grant. Under the 2007 Long-Term Plan, one-half of each grant is exercisable after two years and the remainder after three years. Under the Directors 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 using the assumptions noted in the following table. Expected volatility is based on historical volatility of the

F-22

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

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 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.

	2011			2010			2009
Fair value per option grant	$	20.34			18.75		$	15.15
Assumptions
Dividend yield		1.80	%		1.80	%		1.40	%
Expected volatility		37.00	%		43.00	%		41.00	%
Risk-free interest rate		2.10	%		2.52	%		1.95	%
Expected life		5.10 yrs.			5.25 yrs.			5.25 yrs.

Changes in options outstanding during the last three years are presented in the following table.

	Number of Shares			Average Exercise Price
Outstanding at December 31, 2008		5,399,060		$	40.90
Granted at FMV		1,057,000			43.95
Exercised		(560,500	)		19.58
Forfeited		(464,000	)		60.65
Outstanding at December 31, 2009		5,431,560			42.01
Granted at FMV		1,605,628			52.85
Exercised		(1,580,950	)		29.04
Forfeited		(153,854	)		53.33
Outstanding at December 31, 2010		5,302,384			48.83
Granted at FMV		1,397,312			67.64
Exercised		(974,500	)		39.30
Forfeited		(290,968	)		52.73
Outstanding at December 31, 2011		5,434,228			55.17
Exercisable at December 31, 2009		3,506,310		$	34.86
Exercisable at December 31, 2010		2,499,610			45.07
Exercisable at December 31, 2011		2,319,735			51.14

Additional information about stock options outstanding at December 31, 2011 is shown below.

	Options Outstanding						Options Exercisable
Range of Exercise Prices per Option	No. of Options		Avg. Life in Years		Aggregate Intrinsic Value		No. of Options		Avg. Life in Years		Aggregate Intrinsic Value
$19.43 to $23.58		393,750		1.0	$	13,571,000		393,750		1.0	$	13,571,000
$30.30 to $45.23		953,610		3.6		11,466,000		541,235		3.2		6,604,000
$51.07 to $57.32		2,067,156		3.9		5,938,000		730,750		1.7		2,069,000
$67.64 to $72.75		2,019,712		5.1		0		654,000		3.1		0
		5,434,228		4.1	$	30,975,000		2,319,735		2.3	$	22,244,000

F-23

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

The total intrinsic value of options exercised during 2011, 2010 and 2009 was $28,145,000, $49,929,000 and $17,932,000, 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.

SAR – SAR may be granted in conjunction with or independent of stock options; if granted, the Committee would determine when SAR may be exercised and the price. No SAR have been granted.

PERFORMANCE-BASED RESTRICTED STOCK UNITS – Restricted stock units (RSU) were granted in each of the last three years under 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. Changes in performance-based RSU outstanding for each of the last three years are presented in the following table.

(Number of shares or share units)	2011			2010			2009
Balance at beginning of year		1,023,492			872,027			806,822
Granted		521,423			449,100			375,050
Awarded		(309,656	)		(252,551	)		0
Forfeited		(60,767	)		(45,084	)		(309,845	)
Balance at end of year		1,174,492			1,023,492			872,027

The fair value of the 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 2011, 2010 and 2009 are presented in the following table.

	2011	2010	2009
Fair value per share at grant date	$38.94 – $64.89	$42.38 – $50.95	$41.18 – $44.94
Assumptions
Expected volatility	51.00%	51.00%	48.00%
Risk-free interest rate	1.04%	1.41%	1.37%
Stock beta	1.006	1.008	0.973
Expected life	3.00 yrs.	3.00 yrs.	3.00 yrs.

TIME-LAPSE RESTRICTED STOCK AND RESTRICTED STOCK UNITS – Restricted stock and 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 fair market value of the Company’s stock on the date of grant, which was $52.66 in 2011, $52.49 per share in

F-24

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

2010 and $43.95 per share in 2009. Changes in time-lapse restricted stock and restricted stock units outstanding for each of the last three years are presented in the following table.

(Number of shares or share units)	2011			2010			2009
Balance at beginning of year		166,173			164,695			132,819
Granted		32,711			43,370			50,290
Expired		(82,160	)		(29,475	)		(18,414	)
Forfeited		0			(12,417	)		0
Balance at end of year		116,724			166,173			164,695

PERFORMANCE UNITS – The Company also awarded performance units in 2011 to certain U.S. retail marketing employees under the 2007 Long-Term Plan. The performance units are 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. Total expense related to these awards was $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 34,612 shares at an average price of $56.08 per share in 2011, 44,361 shares at $51.97 per share in 2010, and 51,271 shares at $44.73 per share in 2009. At December 31, 2011, 321,322 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 $328,000 in 2011, $357,000 in 2010 and $623,000 in 2009. The fair value per share issued under the ESPP was approximately $8.60, $7.51 and $11.47 for the years ended December 31, 2011, 2010 and 2009, respectively.

SAVINGS-RELATED SHARE OPTION PLAN (SOP) – One of the Company’s U.K. subsidiaries has provided a plan that allows shares of the Company’s Common stock to be purchased by eligible employees using payroll withholdings. An eligible employee may elect 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 has a term of three years and employee withholdings are fixed over the life of the plan. At the end of the term of the SOP plan an employee receives interest on withholdings and has 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 is expected to expire in 2012. Compensation costs related to the SOP plan are estimated based on the value of the 10% discount and the fair value of the option that allows the employee to receive a repayment of withholdings plus credited interest. The fair value per share of the SOP plans with holding periods ending in December 2009, August 2010, April 2011 and May 2012 were $19.57, $19.90, $23.77 and $22.85, respectively.

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 $33,035,000, $25,171,000 and $23,073,000 was recorded in 2011, 2010 and 2009, respectively, for these 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

F-25

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

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 the overfunded or underfunded status as of year-end of its defined benefit plans as an asset or liability in its consolidated balance sheet and to recognize changes in that funded status between periods through comprehensive income.

The tables that follow provide a reconciliation of the changes in the plans’ benefit obligations and fair value of assets for the years ended December 31, 2011 and 2010 and a statement of the funded status as of December 31, 2011 and 2010.

	Pension Benefits						Other Postretirement Benefits
(Thousands of dollars)	2011			2010			2011			2010
Change in benefit obligation
Obligation at January 1	$	575,300			521,471			122,879			101,750
Service cost		22,406			20,706			4,547			4,133
Interest cost		30,785			30,144			6,141			6,211
Plan amendments		483			0			0			0
Participant contributions		35			33			1,049			956
Actuarial loss		66,010			30,544			4,791			14,646
Medicare Part D subsidy		0			0			555			528
Exchange rate changes		(2,109	)		(1,357	)		(11	)		22
Benefits paid		(27,745	)		(26,241	)		(5,667	)		(5,367	)
Reduction due to sale of the Superior refinery		(23,021	)		0			0			0
Special termination benefits		695			0			0			0
Curtailments		(13,271	)		0			(19,322	)		0
Obligation at December 31		629,568			575,300			114,962			122,879
Change in plan assets
Fair value of plan assets at January 1		416,272			375,947			0			0
Actual return on plan assets		(1,415	)		46,792			0			0
Employer contributions		38,357			20,651			4,063			3,883
Participant contributions		35			33			1,049			956
Medicare Part D subsidy		0			0			555			528
Exchange rate changes		(1,786	)		(422	)		0			0
Benefits paid		(27,745	)		(26,241	)		(5,667	)		(5,367	)
Distribution to acquirer of the Superior refinery		(18,720	)		0			0			0
Other		(648	)		(488	)		0			0
Fair value of plan assets at December 31		404,350			416,272			0			0
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets		10,621			14,191			0			0
Other accrued liabilities		(3,488	)		(3,378	)		(5,022	)		(5,223	)
Deferred credits and other liabilities		(232,351	)		(169,841	)		(109,940	)		(117,656	)
Funded status and net plan liability recognized at December 31		$(225,218)			(159,028	)		(114,962	)		(122,879	)

F-26

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

The Company sold the Meraux, Louisiana and Superior, Wisconsin refineries in 2011. These sales reduced the pension benefit obligation due to a curtailment whereby no additional future benefits will be earned by the employees at the refineries after the sales. Additionally, the acquirer of the Superior refinery assumed the retirement plan covering the union employees. Therefore during 2011, the pension benefit obligation was reduced and certain applicable retirement plan assets were distributed to the acquirer related to the plan liabilities assumed by the acquirer.

At December 31, 2011, 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 Benefits			Other Postretirement Benefits
Net actuarial loss	$	(216,276	)		(35,336	)
Prior service (cost) credit		(5,262	)		1,130
Transitional asset (liability)		1,609			(17	)
	$	(219,929	)		(34,223	)

Amounts included in AOCI at December 31, 2011 that are expected to be amortized into net periodic benefit expense during 2012 are shown in the following table.

(Thousands of dollars)	Pension Benefits			Other Postretirement Benefits
Net actuarial loss	$	(16,872	)		(1,846	)
Prior service (cost) credit		(1,258	)		173
Transitional asset (liability)		535			(8	)
	$	(17,595	)		(1,681	)

The table that follows includes projected benefit obligations, accumulated benefit obligations and fair value of plan assets for plans where the accumulated benefit obligation exceeded the fair value of plan assets.

	Projected Benefit Obligations				Accumulated Benefit Obligations				Fair Value of Plan Assets
(Thousands of dollars)	2011		2010		2011		2010		2011		2010
Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets	$	513,444		478,234		459,556		431,668		374,360		383,683
Unfunded nonqualified and directors’ plans where accumulated benefit obligation exceeds fair value of plan assets		96,754		78,667		82,642		69,104		0		0
Unfunded other postretirement plans		114,962		122,879		114,962		122,879		0		0

F-27

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

The table that follows provides the components of net periodic benefit expense for each of the three years ended December 31, 2011.

	Pension Benefits									Other Postretirement Benefits
(Thousands of dollars)	2011			2010			2009			2011			2010			2009
Service cost	$	22,406			20,706			17,052			4,547			4,133			3,121
Interest cost		30,785			30,144			28,767			6,141			6,211			5,688
Expected return on plan assets		(25,919	)		(24,199	)		(20,375	)		0			0			0
Amortization of prior service cost		1,314			1,558			1,635			(240	)		(263	)		(263	)
Amortization of transitional asset (liability)		(536	)		(514	)		(466	)		8			8			0
Recognized actuarial loss		12,484			12,257			10,305			2,329			2,790			1,551
		40,534			39,952			36,918			12,785			12,879			10,097
Termination benefits expense		695			0			1,867			0			0			0
Curtailment expense		1,036			0			575			(605	)		0			397
Net periodic benefit expense	$	42,265			39,952			39,360			12,180			12,879			10,494

The increase in net periodic benefit expense in 2011 compared to prior years was primarily attributable to additional employees covered by retirement plans for most of 2011, plus termination and curtailment expenses related to sale of two U.S. petroleum refineries in 2011.

The preceding tables in this note include the following amounts related to foreign benefit plans.

	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)	2011		2010		2011		2010
Benefit obligation at December 31	$	153,947		133,751		454		430
Fair value of plan assets at December 31		135,608		126,075		0		0
Net plan liabilities recognized		18,339		7,676		454		430
Net periodic benefit expense		8,978		9,784		82		60

The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2011 and 2010 and net periodic benefit expense for 2011 and 2010.

	Benefit Obligations												Net Periodic Benefit Expense
	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
	December 31						December 31						Year						Year
	2011			2010			2011			2010			2011			2010			2011			2010
Discount rate		5.00	%		5.66	%		4.87	%		5.66	%		5.50	%		5.88	%		5.50	%		5.90	%
Expected return on plan assets		6.48	%		6.56	%		0	%		0	%		6.48	%		6.56	%		0	%		0	%
Rate of compensation increase		4.22	%		4.19	%		0	%		0	%		4.22	%		4.19	%		0	%		0	%

The discount rates used for purposes of 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

F-28

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

rate within each country. Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics. Expected compensation increases are based on anticipated future averages for the Company.

Benefit payments, reflecting expected future service as appropriate, which are expected to be paid in future years from the assets of the plans or by the Company are shown in the following table.

(Thousands of dollars)	Pension Benefits		Other Postretirement Benefits
2012	$	28,688		5,835
2013		29,911		6,072
2014		31,237		6,262
2015		32,001		6,449
2016		32,738		6,747
2017-2021		185,062		38,516

For purposes of measuring postretirement benefit obligations at December 31, 2011, the future annual rates of increase in the cost of health care were assumed to be 7.8% for 2012 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, 2011	$	2,033		(1,594	)
Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2011		17,041		(13,810	)

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) 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.

The Company provides a health care benefit plan to eligible U.S. employees and most U.S. retired employees. The new law did not significantly affect the Company’s consolidated financial statements as of December 31, 2011 and 2010 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 the evaluation performed 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

F-29

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

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 reminder 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.

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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

The weighted average asset allocation for the Company’s funded pension benefit plans at December 31, 2011 and 2010 are presented in the following table.

	December 31,
	2011			2010.
Equity securities		62.3	%		62.7	%
Fixed income securities		36.5			36.2
Cash equivalents		1.2			1.1
		100.0	%		100.0	%

The Company’s weighted average expected return on plan assets was 6.48% in 2011 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 6.48% expected return was based on an expected average future equity securities return of 8.29% and a fixed income securities return of 4.53% and is net of average expected investment expenses of 0.28%. Over the last 10 years, the return on funded retirement plan assets has averaged 5.06%.

At December 31, 2011 and 2010, the fair value measurements of retirement plan assets within the fair value hierarchy were as follows:

			Fair Value Measurements Using
(Thousands of dollars)	Fair Value at December 31, 2011		Quoted Prices in Active  Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Domestic Plans
Equity securities:
U.S. core equity	$	73,986		73,986		0		0
U.S. small/midcap		18,236		18,236		0		0
U.S. long/short equity fund		13,860		0		13,860		0
International commingled trust fund		56,156		0		56,156		0
Emerging market commingled equity fund		6,980		0		6,980		0
Fixed income securities:
U.S. fixed income		76,764		0		76,764		0
International commingled trust fund		13,109		0		13,109		0
Emerging market mutual fund		6,448		0		6,448		0
Cash and equivalents		3,203		3,203		0		0
Total Domestic Plans		268,742		95,425		173,317		0
Foreign Plans
Equity securities funds		59,349		0		59,349		0
Fixed income securities funds		44,442		0		44,442		0
Diversified pooled fund		29,990		0		29,990		0
Cash and equivalents		1,827		1,827		0		0
Total Foreign Plans		135,608		1,827		133,781		0
Total	$	404,350		97,252		307,098		0

F-31

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

			Fair Value Measurements Using
(Thousands of dollars)	Fair Value at December  31, 2010		Quoted Prices in Active  Markets for Identical Assets (Level 1)		Significant Other  Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Domestic Plans
Equity securities:
U.S. core equity	$	79,550		79,550		0		0
U.S. small/midcap		17,324		17,324		0		0
U.S. long/short equity fund		14,205		0		14,205		0
International commingled trust fund		61,531		0		61,531		0
Emerging market commingled equity fund		7,131		0		7,131		0
Fixed income securities:
U.S. fixed income		81,989		0		81,989		0
International commingled trust fund		19,833		0		19,833		0
Emerging market mutual fund		7,045		0		7,045		0
Cash and equivalents		1,589		1,589		0		0
Total Domestic Plans		290,197		98,463		191,734		0
Foreign Plans
Equity securities funds		58,353		0		58,353		0
Fixed income securities funds		31,948		0		31,948		0
Diversified pooled fund		32,590		0		32,590		0
Cash and equivalents		3,184		3,184		0		0
Total Foreign Plans		126,075		3,184		122,891		0
Total	$	416,272		101,647		314,625		0

The definition of levels within the fair value hierarchy in the tables above is included in Note O.

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, while U.S. long/short equity funds permit withdrawals annually for the first year and then semi-annually thereafter. 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.

During 2011, the Company made contributions of $23,736,000 to its domestic defined benefit pension plans, $14,621,000 to its foreign defined benefit pension plans, $4,011,000 to its domestic postretirement benefits plan and $52,000 to its foreign postretirement benefits plan. The Company currently expects during 2012 to make contributions of $27,171,000 to its domestic defined benefit pension plans, $8,311,000 to its foreign defined benefit pension plans, $5,790,000 to its domestic postretirement benefits plan and $45,000 to its foreign postretirement benefits plan.

F-32

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

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. 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 $10,725,000 in 2011, $11,467,000 in 2010 and $11,617,000 in 2009.

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 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 are accounted for as hedges and the gain or loss associated with recording the fair value of these contracts has been deferred in Accumulated Other Comprehensive Income until the anticipated transactions occur.

• Commodity Purchase Price Risks – The Company is subject to commodity price risks at its ethanol production facilities in the United States related to corn that it will purchase in the future for feedstock and to wet and dried distillers grain that it will sell in the future. At December 31, 2011 and 2010, the Company had open physical delivery fixed-price commitment contracts for purchase of approximately 8.0 million and 7.0 million bushels of corn, respectively, for processing at its ethanol plants. The Company also had outstanding derivative contracts to sell a similar volume of these fixed-price quantities and buy them back at future prices in effect on the expected date of delivery under the purchase commitment contracts. Also, at December 31, 2011, the Company had open physical delivery fixed-price commitment contracts to sell approximately 1.1 million equivalent bushels of wet and dried distillers grain with solubles; it also had outstanding derivative contracts to purchase a similar volume of these fixed-price quantities and sell them back at future prices in effect on the expected date of delivery under the sale commitment contracts. Additionally, at December 31, 2011, the Company had outstanding derivative contracts to sell 2.9 million bushels of corn and buy them back when certain corn inventories are expected to be processed at the Hankinson, North Dakota, and Hereford, Texas facilities. The fair value of these open commodity derivative contracts was a liability of $292,000 at December 31, 2011 and an asset of $750,000 at December 31, 2010.

The Company was formerly subject to commodity price risk related to crude oil feedstocks it held in inventory at its U.S. refineries. Short-term derivative instruments were outstanding at December 31, 2010 to manage the 2011 purchase price of 118,000 barrels of crude oil at the Company’s Superior, Wisconsin refinery. The fair value of these open crude oil derivative contracts was a liability of $335,000 at December 31, 2010. The Superior refinery was sold in 2011 and has been accounted for as discontinued operations. There were no open crude oil feedstock derivative contracts at December 31, 2011.

F-33

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

• 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, 2011 and 2010, short-term derivative instruments were outstanding to manage the currency risk of approximately $16,000,000 and $38,000,000, respectively, of U.S. dollar accounts receivable balances associated with the Company’s sale of Canadian crude oil. Also short-term derivative instruments were outstanding at December 31, 2011 and 2010 to manage the currency risk of approximately $472,000,000 and $366,000,000 equivalent, respectively, of ringgit denominated income tax liability balances in the Company’s Malaysian operations. The fair value of open foreign currency derivative contracts was a liability of $8,459,000 at December 31, 2011 and an asset of $7,261,000 at December 31, 2010.

At December 31, 2011 and 2010, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

December 31, 2011

December 31, 2010

Asset Derivatives

Liability Derivatives

Asset Derivatives

Liability Derivatives

(Thousands of dollars)

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Type of derivative contract

Commodity

Accounts Receivable

$197

Accounts Payable

$489

Accounts Receivable

$750

Accounts Payable

$626

Foreign exchange

—

—

Accounts Payable

$8,459

Accounts Receivable

$7,261

—

—

For the years ended December 31, 2011 and 2010, 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, 2011					Year Ended December 31, 2010
(Thousands of dollars)	Location of Gain (Loss) Recognized in Income on Derivative		Amount of Gain (Loss) Recognized in Income on Derivative			Location of Gain (Loss) Recognized in Income on Derivative		Amount of Gain (Loss) Recognized in Income on Derivative
Type of derivative contract
Commodity		Crude Oil and Product Purchases	$	5,659			Crude Oil and Product Purchases	$	(7,577	)
Foreign exchange		Interest and Other Income (Loss)		(305	)		Interest and Other Income (Loss)		34,215
			$	5,354				$	26,638

F-34

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

• Interest Rate Risks – The Company has ten-year notes totaling $350,000,000 that mature on May 1, 2012. The Company currently anticipates replacing these notes at maturity with new ten-year notes, and it therefore has risk associated with the interest rate related to the anticipated sale of these notes in 2012. To manage this risk, in 2011 the Company entered into a series of derivative contracts known as forward starting interest rate swaps that mature in May 2012. The Company utilizes hedge accounting to defer any gain or loss on these contracts until the payment of interest on these anticipated notes occurs. There was no impact in the 2011 Consolidated Statements of Income associated with accounting for these interest rate derivative contracts.

At December 31, 2011, the fair value of these interest rate derivative contracts, which have been designated as hedging instruments for accounting purposes, are presented in the following table.

	December 31, 2011
	Liability Derivatives
(Thousands of dollars)	Balance Sheet Location		Fair Value
Type of derivative contract
Interest rate		Accounts Payable	$	25,927

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 crude oil, natural gas and petroleum products to a large number of customers in the United States and the United Kingdom. The Company also has credit risk for sales of crude oil and natural gas to various customers in Canada, and sales of crude oil to various customers in Malaysia and Republic of the Congo. Natural gas produced in Malaysia is essentially all sold to the country’s national oil company. 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 limits 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.

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, 2011. No difference existed between net income used in computing basic and diluted income per Common share for these years.

(Weighted-average shares outstanding)	2011		2010		2009
Basic method		193,409,621		191,830,357		190,767,077
Dilutive stock options		1,102,781		1,327,457		1,701,373
Diluted method		194,512,402		193,157,814		192,468,450

Outstanding options to purchase shares of Common Stock were not included in the computation of diluted earnings per share in 2009 through 2011 because the incremental shares from assumed conversion were antidilutive. These included 1,823,564 shares at a weighted average share price of $69.46 in 2011, 2,220,567 shares at a weighted average share price of $58.78 in 2010 and 1,793,905 shares at a weighted average share price of $56.25 in 2009.

F-35

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note N – Other Financial Information

INVENTORIES – Inventories accounted for under the LIFO method totaled $188,390,000 and $345,449,000 at December 31, 2011 and 2010, respectively, and these amounts were $580,238,000 and $735,091,000 less than such inventories would have been valued using the FIFO method. A significant inventory reduction occurred in 2011 associated with sale of the two U.S. refineries. 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.

ACCUMULATED OTHER COMPREHENSIVE INCOME – At December 31, 2011 and 2010, the components of Accumulated Other Comprehensive Income were as follows.

(Thousands of dollars)	2011			2010
Foreign currency translation gains	$	496,161			587,408
Retirement and postretirement plan adjustments, net of tax		(168,889	)		(137,980	)
Loss deferred on interest rate hedges, net of tax		(16,852	)		0
Balance at end of year	$	310,420			449,428

At December 31, 2011, components of the net foreign currency translation gains of $496,161,000 were gains (losses) of $464,736,000 for Canadian dollars, $37,544,000 for pounds sterling and $(6,119,000) 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 $22,131,000 in 2011, $(63,861,000) in 2010 and $48,429,000 in 2009.

CASH FLOW DISCLOSURES – Cash income taxes paid were $938,944,000, $585,759,000 and $501,506,000 in 2011, 2010 and 2009, respectively. Interest paid, net of amounts capitalized, was $38,120,000, $35,452,000 and $21,017,000 in 2011, 2010 and 2009, respectively.

Noncash operating working capital (increased) decreased during each of the three years ended December 31, 2011 as follows.

(Thousands of dollars)	2011			2010			2009
Accounts receivable	$	(43,630	)		(4,363	)		(402,481	)
Inventories		(59,413	)		(28,231	)		(114,569	)
Prepaid expenses		20,548			14,567			7,209
Deferred income tax assets		8,488			(80,073	)		14,772
Accounts payable and accrued liabilities		(478,029	)		766,067			365,257
Current income tax liabilities		(273,118	)		(28,401	)		(64,878	)
Net (increase) decrease in noncash operating working capital	$	(825,154	)		639,566			(194,690	)

F-36

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note O – 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, 2011 and 2010 are presented in the following table.

				Fair Value Measurements at Reporting Date Using
(Thousands of dollars)	Fair Value  at December 31, 2011			Quoted Prices in Active  Markets for Identical Assets (Liabilities) (Level 1)			Significant Other  Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Assets
Commodity derivative contracts	$	197			0			197			0
Liabilities
Nonqualified employee savings plan		(8,030	)		(8,030	)		0			0
Foreign currency exchange derivative contracts		(8,459	)		0			(8,459	)		0
Commodity derivative contracts		(489	)		0			(489	)		0
Interest rate derivative contracts		(25,927	)		0			(25,927	)		0
Total		(42,905	)		(8,030	)		(34,875	)		0

				Fair Value Measurements at Reporting Date Using
(Thousands of dollars)	Fair Value at December  31, 2010			Quoted Prices in Active  Markets for Identical Assets (Liabilities) (Level 1)			Significant Other  Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Assets
Foreign currency exchange derivative contracts	$	7,261			0			7,261			0
Commodity derivative assets		750			0			750			0
Total		8,011			0			8,011			0
Liabilities
Nonqualified employee savings plan		(7,672	)		(7,672	)		0			0
Commodity derivative contracts		(626	)		0			(626	)		0
Total		(8,298	)		(7,672	)		(626	)		0

At the balance sheet dates the fair value of commodity derivatives contracts for crude oil was determined based on market quotes for WTI crude and the fair value of commodity derivative contracts for corn and wet and dried distillers grain with solubles was determined based on market quotes for No. 2 yellow corn. The fair value of derivative contracts for foreign currency exchange and interest rates was based on quotes from active brokers in the respective markets. 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

F-37

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Income (Loss). The interest rate derivative contracts are accounted for under hedge accounting rules; therefore, gains and losses are deferred and are recorded net of income taxes as a component of Accumulated Other Comprehensive Income in the Consolidated Balance Sheet. 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. The fair value of this savings plan liability was based on quoted prices for these equity securities and mutual funds. 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 carrying value of the Company’s Cash and Cash Equivalents, Accounts Receivable and Accounts Payable approximates fair value.

The assets of ethanol plants acquired in 2009 and 2010 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 December 31, 2011 and 2010. 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 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 financial guarantees and letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, was nominal.

	At December 31,
	2011						2010
(Thousands of dollars)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Financial assets (liabilities):
Canadian government securities with maturities greater than 90 days at the date of acquisition	$	532,093			532,899			616,558			617,372
Current and long-term debt		(599,558	)		(715,208	)		(939,391	)		(1,064,225	)

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 Company’s North American refining and marketing operations recorded a benefit of $15,398,000 for business interruption insurance received relating to a fire that occurred at the Meraux, Louisiana refinery in June 2003.

The Company also maintains certain insurance covering property damage, sudden and accidental environmental events and other hazards. In 2009, the Company’s 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 insurer’s 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 Company’s final cash settlement from the insurer led to pretax income of $12,718,000 in 2009. This benefit arose because the ultimate cash settlements received from the insurer exceeded amounts originally estimated by the insurer.

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 2009 with $4,500,000 related to the insurance claim and $2,000,000 of associated interest income. During 2010,

F-38

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

the Company received $3,000,000 to settle its claim against one insurer for legal and other professional costs associated with the insurance coverage negotiation process. These insurance settlements in 2009 and 2010 have been included in Income From Discontinued Operations in the respective year’s Consolidated Statement of Income.

Note Q – Commitments

The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2012 natural gas sales volumes from the Tupper and Tupper West areas in Western Canada. The contract calls for natural gas deliveries of approximately 50 million cubic feet per day during 2012 at an average price of Cdn$4.43 per thousand cubic feet at the AECO “C” sales point. These contracts have 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, production facilities at the Thunder Hawk and West Patricia fields, certain motor fuel stations in the U.K. and land under a portion of gasoline stations in the U.S. During the next five years, expected future rental payments under all operating leases are approximately $161,752,000 in 2012, $138,121,000 in 2013, $127,044,000 in 2014, $115,708,000 in 2015 and $34,525,000 in 2016. Rental expense for noncancellable operating leases, including contingent payments when applicable, was $185,016,000 in 2011, $178,410,000 in 2010 and $124,693,000 in 2009.

The Company has entered into contracts to hire various drilling rigs and associated equipment for periods beyond December 31, 2011. These rigs will primarily be utilized for drilling operations in the Gulf of Mexico, onshore U.S. and Canada, offshore Malaysia, Kurdistan, Australia and Republic of the Congo. Future commitments under these contracts, all of which expire by 2015, total approximately $515,292,000. 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 agreements providing for processing, production handling and transportation services for natural gas in 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 $23,823,000 in 2012, $18,146,000 in 2013, $18,452,000 in 2014, $16,676,000 in 2015 and $11,800,000 in 2016. 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 $24,791,000 in 2011, $10,337,000 in 2010 and $11,860,000 in 2009.

Additionally, the Company has a Reserved Capacity Service Agreement providing for the availability of needed crude oil storage capacity for certain oil fields through 2020. Under the agreement, the Company must make specified minimum payments monthly. Future required minimum annual payments are approximately $1,000,000 in 2012 through 2016. In addition, the Company is required to pay additional amounts depending on actual crude oil quantities stored under the agreement. Total payments under the agreement were $918,000 in 2011, $3,202,000 in 2010 and $2,743,000 in 2009.

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 from 2007 to 2016 to provide scholarships for a specified amount of college expenses for eligible graduates of El Dorado High School in Arkansas. The first

F-39

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

six payments have been made through January 2012. 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 included in Selling and General Expense was $1,317,000 in 2011, $1,534,000 in 2010 and $1,739,000 in 2009.

Commitments for capital expenditures were approximately $1,849,100,000 at December 31, 2011, including $839,500,000 for field development and future work commitments in Malaysia, $149,700,000 for costs to develop deepwater Gulf of Mexico fields, $124,500,000 for work in the Eagle Ford Shale and $127,500,000 for future work commitments offshore Brunei.

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. With the sale of the U.S. refineries in 2011, the Company retained certain liabilities related to environmental matters. The Company also obtained insurance covering certain levels of environmental exposures. 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.

F-40

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

The Company’s liability for remedial obligations includes certain amounts that are based on anticipated regulatory approval for proposed remediation of former refinery waste sites. Although regulatory authorities may require more costly alternatives than the proposed processes, the cost of such potential alternative processes is not expected to exceed the accrued liability by a material amount. Certain environmental expenditures are likely to be recovered by the Company from other sources, primarily environmental funds maintained by certain states. Since no assurance can be given that future recoveries from other sources will occur, the Company has not recorded a benefit for likely recoveries at December 31, 2011.

The U.S. Environmental Protection Agency (EPA) currently considers the Company to be a Potentially Responsible Party (PRP) at one Superfund site. The potential total cost to all parties to perform necessary remedial work at this site may be substantial. However, based on current negotiations and available information, the Company believes that it is a de minimis party as to ultimate responsibility at the Superfund site. Accordingly, the Company has not recorded a liability for remedial costs at the Superfund site at December 31, 2011. 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 this site or other Superfund sites. The Company believes that its share of the ultimate costs to clean-up this Superfund site will be immaterial and will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.

LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

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, 2011, the Company had contingent liabilities of $7,798,000 under a financial guarantee and $162,906,000 on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to the guarantee and the letters of credit because it is believed that the likelihood of having these drawn is remote.

F-41

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

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. The Company recorded expense of $18,582,000 in 2010 and $83,498,000 in 2009 based on the anticipated 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 estimated. The 2009 and 2010 expense and the 2011 benefit have been reflected as Redetermination of Terra Nova Working Interest in the Consolidated Statements of Income.

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, 2011 is shown below.

(Number of shares outstanding)	2011		2010		2009
At beginning of year		192,836,008		191,115,378		190,713,806
Stock options exercised		615,674		1,495,926		548,659
Employee stock purchase and thrift plans		33,390		49,657		61,575
Restricted stock awards, net of forfeitures		238,136		175,047		(208,662	)
At end of year		193,723,208		192,836,008		191,115,378

F-42

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Continued

Note U – Business Segments

Murphy’s reportable segments are organized into two major types of business activities, each subdivided into geographic areas of operations. The Company’s 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 Company’s refining and marketing segments are disclosed geographically for the United States and the United Kingdom and each derives revenue mainly from the sale of petroleum products and merchandise. The United States business also derives revenue from production and sale of ethanol and corn by-products. The Company sells gasoline in the United States at retail stations built primarily at Walmart Supercenters. 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. Discontinued operations primarily include the activities of two U.S. refineries and associated marketing assets sold in 2011. These operations formerly comprised most of the United States Manufacturing segment that was previously reported before the refinery sales. With the sale of the two U.S. refineries in 2011, all continuing operations for U.S. downstream have been reported in the current United States Refining and Marketing segment. Results for the two U.S. refineries for 2010 and 2009 have been reclassified as discontinued operations. Discontinued operations in 2009 also included income of $97,104,000 from the formerly held Ecuador exploration and production operations.

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 the following page, Certain Long-Lived Assets at December 31 exclude investments, noncurrent receivables, deferred tax assets and goodwill and other intangible assets.

Excise taxes on petroleum products of $3,566,876,000, $3,375,509,000 and $3,595,238,000 for the years 2011, 2010 and 2009, respectively, that were collected by the Company and remitted to various government entities by continuing operations were excluded from revenues and costs and expenses.

F-43

Segment Information

	Exploration and Production
(Millions of dollars)	United States			Canada			Malaysia		United Kingdom			Republic of the Congo			Other			Total
Year ended December 31, 2011
Segment income (loss)	$	152.7			328.0			812.7		11.5			(385.3	)		(293.9	)		625.7
Revenues from external customers		737.7			1,145.8			2,045.6		107.3			148.8			24.6			4,209.8
Intersegment revenues		0.0			142.8			0.0		0.0			0.0			0.0			142.8
Interest income		0.0			0.0			0.0		0.0			0.0			0.0			0.0
Interest expense, net of capitalization		0.0			0.0			0.0		0.0			0.0			0.0			0.0
Income tax expense (benefit)		86.5			135.5			434.9		46.8			16.4			7.5			727.6
Significant noncash charges (credits)
Depreciation, depletion, amortization		183.0			326.0			357.3		13.7			87.8			1.9			969.7
Accretion of asset retirement obligations		9.9			12.5			10.6		3.0			0.5			0.3			36.8
Amortization of undeveloped leases		62.2			28.8			0.0		0.0			0.0			27.2			118.2
Impairment of long-lived assets		0.0			0.0			0.0		0.0			368.6			0.0			368.6
Deferred and noncurrent income taxes		54.2			39.6			84.6		14.6			(0.9	)		(0.1	)		192.0
Additions to property, plant, equipment		696.6			885.2			694.8		19.7			79.6			20.6			2,396.5
Total assets at year-end		2,227.6			3,746.8			3,826.9		214.1			257.5			74.1			10,347.0
Year ended December 31, 2010
Segment income (loss)	$	72.7			213.8			659.4		30.5			(77.2	)		(92.3	)		806.9
Revenues from external customers		659.9			780.2			1,837.9		133.6			155.7			3.9			3,571.2
Intersegment revenues		0.0			118.9			0.0		0.0			0.0			0.0			118.9
Interest income		0.0			0.0			0.0		0.0			0.0			0.0			0.0
Interest expense, net of capitalization		0.0			0.0			0.0		0.0			0.0			0.0			0.0
Income tax expense (benefit)		30.0			79.1			414.1		32.6			20.6			0.5			576.9
Significant noncash charges (credits)
Depreciation, depletion, amortization		281.1			225.5			379.0		22.4			95.5			1.5			1,005.0
Accretion of asset retirement obligations		6.9			11.2			9.8		2.3			0.4			0.5			31.1
Amortization of undeveloped leases		68.5			33.7			0.0		0.0			0.0			5.8			108.0
Deferred and noncurrent income taxes		(48.6	)		34.5			145.5		(11.4	)		(0.9	)		0.0			119.1
Additions to property, plant, equipment		369.4			804.4			467.9		(4.7	)		163.6			49.8			1,850.4
Total assets at year-end		1,651.3			3,242.6			3,333.1		187.9			678.9			88.9			9,182.7
Year ended December 31, 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		0.0			85.3			0.0		0.0			0.0			0.0			85.3
Interest income		0.0			0.0			0.0		0.0			0.0			0.0			0.0
Interest expense, net of capitalization		0.0			0.0			0.0		0.0			0.0			0.0			0.0
Income tax expense (benefit)		88.4			21.0			354.1		11.9			1.3			(0.6	)		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 asset retirement obligations		6.8			8.6			7.8		1.6			0.1			0.6			25.5
Amortization of undeveloped leases		34.7			44.1			0.0		0.0			0.0			4.4			83.2
Impairment of long-lived assets		5.2			0.0			0.0		0.0			0.0			0.0			5.2
Deferred and noncurrent income taxes		(4.6	)		(7.2	)		77.6		(0.9	)		0.0			(0.1	)		64.8
Additions to property, plant, equipment		336.8			330.1			739.0		17.2			194.9			7.6			1,625.6
Total assets at year-end		1,679.7			2,507.8			3,249.6		209.0			516.7			33.5			8,196.3

Geographic Information	Certain Long-Lived Assets at December 31
(Millions of dollars)	United States		Canada		Malaysia		United Kingdom		Republic of the Congo		Other		Total
2011	$	2,953.1		3,493.4		3,154.8		694.7		133.7		52.2		10,481.9
2010		3,178.8		3,028.8		2,807.0		706.3		579.4		74.3		10,374.6
2009		2,907.2		2,324.6		2,714.9		704.7		399.9		20.5		9,071.8

F-44

Segment Information (Continued)

	Refining and Marketing							Corporate and Other			Discontinued Operations		Consolidated
(Millions of dollars)	United States		United Kingdom			Total
Year ended December 31, 2011
Segment income (loss)	$	223.6		(33.3	)		190.3		(75.1	)		131.8		872.7
Revenues from external customers		17,471.9		6,030.3			23,502.2		33.5			0.0		27,745.5
Intersegment revenues		0.0		0.0			0.0		0.0			0.0		142.8
Interest income		0.0		0.0			0.0		10.1			0.0		10.1
Interest expense, net of capitalization		0.0		0.0			0.0		40.7			0.0		40.7
Income tax expense (benefit)		146.6		(12.1	)		134.5		(52.0	)		0.0		810.1
Significant noncash charges (credits)
Depreciation, depletion, amortization		68.3		46.7			115.0		8.7			0.0		1,093.4
Accretion of asset retirement obligations		0.9		0.0			0.9		0.0			0.0		37.7
Amortization of undeveloped leases		0.0		0.0			0.0		0.0			0.0		118.2
Impairment of long-lived assets		0.0		0.0			0.0		0.0			0.0		368.6
Deferred and noncurrent income taxes		28.5		(5.3	)		23.2		(43.6	)		0.0		171.6
Additions to property, plant, equipment		100.1		22.2			122.3		5.3			48.1		2,572.2
Total assets at year-end		1,806.5		1,193.8			3,000.3		790.8			0.0		14,138.1
Year ended December 31, 2010
Segment income (loss)	$	165.3		(34.7	)		130.6		(157.9	)		18.5		798.1
Revenues from external customers		13,750.4		2,905.0			16,655.4		(56.9	)		0.0		20,169.7
Intersegment revenues		0.0		0.0			0.0		0.0			0.0		118.9
Interest income		0.0		0.0			0.0		6.9			0.0		6.9
Interest expense, net of capitalization		0.0		0.0			0.0		34.7			0.0		34.7
Income tax expense (benefit)		101.8		(22.3	)		79.5		(47.2	)		0.0		609.2
Significant noncash charges (credits)
Depreciation, depletion, amortization		60.1		41.4			101.5		8.0			0.0		1,114.5
Accretion of asset retirement obligations		0.8		0.0			0.8		0.0			0.0		31.9
Amortization of undeveloped leases		0.0		0.0			0.0		0.0			0.0		108.0
Deferred and noncurrent income taxes		5.1		3.2			8.3		7.8			0.0		135.2
Additions to property, plant, equipment		221.0		69.1			290.1		5.9			117.3		2,263.7
Total assets at year-end		2,996.6		1,113.6			4,110.2		940.3			0.0		14,233.2
Year ended December 31, 2009
Segment income (loss)	$	65.5		(20.5	)		45.0		(23.0	)		123.8		837.6
Revenues from external customers		11,116.4		2,725.9			13,842.3		102.2			0.0		16,895.2
Intersegment revenues		0.0		0.0			0.0		0.0			0.0		85.3
Interest income		0.0		0.0			0.0		51.7			0.0		51.7
Interest expense, net of capitalization		0.0		0.0			0.0		24.4			0.0		24.4
Income tax expense (benefit)		42.3		(1.0	)		41.3		4.2			0.0		521.6
Significant noncash charges (credits)
Depreciation, depletion, amortization		55.4		33.8			89.2		6.0			0.0		871.0
Accretion of asset retirement obligations		0.7		0.0			0.7		0.0			0.0		26.2
Amortization of undeveloped leases		0.0		0.0			0.0		0.0			0.0		83.2
Impairment of long-lived assets		0.0		0.0			0.0		0.0			0.0		5.2
Deferred and noncurrent income taxes		9.5		15.9			25.4		5.0			0.0		95.2
Additions to property, plant, equipment		161.6		101.8			263.4		23.0			113.3		2,025.3
Total assets at year-end		2,490.6		939.8			3,430.4		1,129.7			0.0		12,756.4

Geographic Information	Revenues from External Customers for the Year
(Millions of dollars)	United States		Canada		Malaysia		United Kingdom		Republic of the Congo		Other		Total
2011	$	18,184.0		1,180.3		2,063.0		6,144.8		148.8		24.6		27,745.5
2010		14,386.6		809.3		1,793.8		3,018.7		156.5		4.8		20,169.7
2009		11,855.9		652.5		1,526.4		2,838.7		16.5		5.2		16,895.2

F-45

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.

In 2008, the U.S. Securities and Exchange Commission (SEC) adopted new definitions and rules for oil and gas reserves that became effective for the Company as of December 31, 2009. In January 2010, the Financial Accounting Standards Board (FASB) issued guidance that aligned its oil and gas reserves reporting requirements with the SEC’s guidance. The SEC and FASB now define proved reserves as those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic method is used for the estimation. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well, or through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. The new rules have expanded oil and gas producing activities to include non-traditional and unconventional resources such as the Company’s 5% interest in synthetic oil operations at Syncrude in Western Canada. Therefore, net oil reserves after royalties for this synthetic oil operations have been included as a separate column in the proved oil reserves schedule beginning at December 31, 2009. The rules also now requires expanded disclosures of proved undeveloped reserves, to include discussion of such reserves held for five or more years, plus disclosures of the Company’s controls over the oil and gas reserves processes, including the qualifications of the chief technical person who oversees the Company’s reserves process. The rules also now permit companies to voluntarily disclose probable and possible reserves in SEC filings, but the Company has elected not to provide these voluntary disclosures.

Murphy has utilized reliable geologic and engineering technology in 2011 to include proved undeveloped reserves more than one location from producing wells in the more developed portions of the Eagle Ford Shale. The study incorporated public and proprietary data from multiple sources and encompassed the entire basin. This included analysis of seismic data, well log data, test production and fluids properties to establish geologic consistency as well as significant statistical performance data yielding predictable and repeatable reserve estimates within certain analogous areas. These locations were limited to only those areas with both established geologic consistency and sufficient statistical performance data where such data could be demonstrated to provide reasonable certain results.

As discussed above, Murphy now 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

F-46

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% - 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 reserves in this filing 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 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 reserves associated with the production sharing contracts in Malaysia totaled 104.4 million barrels and 347.8 billion cubic feet, respectively, at December 31, 2011. Approximately 94.0 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 foot. Oil reserves attributable to a production sharing agreement in Republic of the Congo amounted to 2.3 million barrels at December 31, 2011.

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 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. Generally accepted accounting principles require that unweighted average oil and natural gas prices in effect at the beginning of each month of the year be used for calculation of the standardized measure of discounted future net cash flows.

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, 2011.

F-47

Schedule 1 – Summary of Proved Oil Reserves Based on Year-End Prices for 2008 and Average Prices for 2009 - 2011

	Total			Total – by product						United States			Canada						Malaysia			United Kingdom			Republic of the Congo			Ecuador
(Millions of barrels)	All Products			Oil			Synthetic Oil			Oil			Oil			Synthetic Oil			Oil			Oil			Oil			Oil
Proved developed and undeveloped oil reserves:
December 31, 2008		173.6			173.6			0.0			26.8			24.3			0.0			100.7			17.0			0.0			4.8
Synthetic reserves presented as proved under SEC rules		131.6			0.0			131.6			0.0			0.0			131.6			0.0			0.0			0.0			0.0
Revisions of previous estimates		5.8			3.2			2.6			5.0			7.2			2.6			(4.9	)		(4.1	)		0.0			0.0
Improved recovery		31.0			31.0			0.0			0.0			0.0			0.0			31.0			0.0			0.0			0.0
Extensions and discoveries		23.9			23.9			0.0			0.8			3.3			0.0			11.2			0.0			8.6			0.0
Production		(48.2	)		(43.5	)		(4.7	)		(6.2	)		(7.0	)		(4.7	)		(27.9	)		(1.2	)		(0.7	)		(0.5	)
Sales of properties		(4.3	)		(4.3	)		0.0			0.0			0.0			0.0			0.0			0.0			0.0			(4.3	)
December 31, 2009		313.4			183.9			129.5			26.4			27.8			129.5			110.1			11.7			7.9			0.0
Revisions of previous estimates		22.5			18.0			4.5			3.5			5.4			4.5			4.4			0.4			4.3			0.0
Improved recovery		5.8			5.8			0.0			0.0			1.0			0.0			4.8			0.0			0.0			0.0
Extensions and discoveries		12.6			12.6			0.0			4.1			5.0			0.0			3.5			0.0			0.0			0.0
Production		(46.3	)		(41.5	)		(4.8	)		(7.4	)		(6.4	)		(4.8	)		(24.4	)		(1.2	)		(2.1	)		0.0
December 31, 2010		308.0			178.8			129.2			26.6			32.8			129.2			98.4			10.9			10.1			0.0
Revisions of previous estimates		21.2			16.0			5.2			2.4			3.1			5.2			8.4			8.1			(6.0	)		0.0
Improved recovery		14.2			14.2			0.0			0.0			0.0			0.0			10.7			3.5			0.0			0.0
Extensions and discoveries		43.9			43.9			0.0			32.6			6.7			0.0			4.6			0.0			0.0			0.0
Production		(37.6	)		(32.7	)		(4.9	)		(6.3	)		(6.0	)		(4.9	)		(17.7	)		(0.9	)		(1.8	)		0.0
December 31, 2011		349.7			220.2			129.5			55.3			36.6			129.5			104.4			21.6			2.3			0.0
Proved developed oil reserves:
December 31, 2009		270.0			150.3			119.7			18.3			26.2			119.7			90.0			11.7			4.1			0.0
December 31, 2010		248.3			129.2			119.1			15.8			28.6			119.1			66.5			10.9			7.4			0.0
December 31, 2011		238.5			118.0			120.5			20.8			32.6			120.5			57.2			5.1			2.3			0.0
Proved undeveloped oil reserves:
December 31, 2009		43.4			33.6			9.8			8.1			1.6			9.8			20.1			0.0			3.8			0.0
December 31, 2010		59.7			49.6			10.1			10.8			4.2			10.1			31.9			0.0			2.7			0.0
December 31, 2011		111.2			102.2			9.0			34.5			4.0			9.0			47.2			16.5			0.0			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.

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 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 of South Texas 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.

F-48

Schedule 2 – Summary of Proved Natural Gas Reserves Based on Year-End Prices for 2008 and Average Prices for 2009 – 2011

(Billions of cubic feet)	Total			United States			Canada			Malaysia			United Kingdom
Proved developed and undeveloped natural gas reserves:
December 31, 2008		585.6			97.4			62.2			405.2			20.8
Revisions of previous estimates		77.2			9.1			(0.6	)		59.4			9.3
Improved recovery		6.9			0.0			0.0			6.9			0.0
Extensions and discoveries		153.5			2.6			83.3			67.6			0.0
Production		(68.4	)		(19.8	)		(20.0	)		(27.3	)		(1.3	)
Sales of properties		(0.2	)		0.0			(0.2	)		0.0			0.0
December 31, 2009		754.6			89.3			124.7			511.8			28.8
Revisions of previous estimates		15.2			6.6			15.2			(11.2	)		4.6
Improved recovery		(1.0	)		0.0			0.0			(1.0	)		0.0
Extensions and discoveries		220.5			14.3			194.2			12.0			0.0
Purchases of properties		24.0			0.0			24.0			0.0			0.0
Production		(130.2	)		(19.4	)		(31.2	)		(77.6	)		(2.0	)
December 31, 2010		883.1			90.8			326.9			434.0			31.4
Revisions of previous estimates		12.6			(6.3	)		59.4			(32.5	)		(8.0	)
Improved recovery		13.8			0.0			0.0			14.8			(1.0	)
Extensions and discoveries		363.5			31.1			321.5			10.9			0.0
Production		(166.9	)		(17.2	)		(68.9	)		(79.4	)		(1.4	)
December 31, 2011		1,106.1			98.4			638.9			347.8			21.0
Proved developed natural gas reserves:
December 31, 2009		401.6			73.2			89.7			209.9			28.8
December 31, 2010		586.0			67.0			210.1			277.5			31.4
December 31, 2011		711.6			58.2			427.1			210.5			15.8
Proved undeveloped natural gas reserves:
December 31, 2009		353.0			16.1			35.0			301.9			0.0
December 31, 2010		297.1			23.8			116.8			156.5			0.0
December 31, 2011		394.5			40.2			211.8			137.3			5.2

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.

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 in South Texas. 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 of South Texas 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.

F-49

Schedule 3 – Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

(Millions of dollars)	United States			Canada		Malaysia		United Kingdom			Republic of the Congo			Other		Total
Year Ended December 31, 2011
Property acquisition costs
Unproved	$	233.8			18.5		0.0		0.0			0.0			27.0		279.3
Proved		0.0			0.0		0.0		0.0			23.5			0.0		23.5
Total acquisition costs		233.8			18.5		0.0		0.0			23.5			27.0		302.8
Exploration costs*		253.2			76.0		0.7		0.5			0.5			231.6		562.5
Development costs*		263.9			871.9		705.5		30.5			78.7			3.8		1,954.3
Total costs incurred		750.9			966.4		706.2		31.0			102.7			262.4		2,819.6
Charged to expense
Dry hole expense		0.6			50.6		0.1		0.0			18.1			181.6		251.0
Geophysical and other costs		35.9			10.2		11.0		0.5			2.9			60.2		120.7
Total charged to expense		36.5			60.8		11.1		0.5			21.0			241.8		371.7
Property additions	$	714.4			905.6		695.1		30.5			81.7			20.6		2,447.9
Year Ended December 31, 2010
Property acquisition costs
Unproved	$	129.8			78.6		0.0		0.0			0.0			34.4		242.8
Proved		0.0			22.0		0.0		0.0			0.0			0.0		22.0
Total acquisition costs		129.8			100.6		0.0		0.0			0.0			34.4		264.8
Exploration costs*		204.1			1.8		99.6		6.7			93.5			67.7		473.4
Development costs*		98.3			721.0		396.7		15.5			132.3			2.0		1,365.8
Total costs incurred		432.2			823.4		496.3		22.2			225.8			104.1		2,104.0
Charged to expense
Dry hole expense		(1.4	)		0.0		14.3		15.2			35.5			26.5		90.1
Geophysical and other costs		37.1			1.9		5.5		1.0			20.9			27.8		94.2
Total charged to expense		35.7			1.9		19.8		16.2			56.4			54.3		184.3
Property additions	$	396.5			821.5		476.5		6.0			169.4			49.8		1,919.7
Year Ended December 31, 2009
Property acquisition costs
Unproved	$	82.4			31.0		0.0		0.0			0.0			4.7		118.1
Proved		0.0			0.0		0.0		0.0			0.0			0.0		0.0
Total acquisition costs		82.4			31.0		0.0		0.0			0.0			4.7		118.1
Exploration costs*		89.7			9.9		114.4		0.1			19.1			79.4		312.6
Development costs*		197.2			321.4		695.9		15.1			187.5			2.0		1,419.1
Total costs incurred		369.3			362.3		810.3		15.2			206.6			86.1		1,849.8
Charged to expense
Dry hole expense		11.3			0.0		55.0		0.0			13.9			45.1		125.3
Geophysical and other costs		16.2			10.0		0.8		0.2			(3.1	)		32.6		56.7
Total charged to expense		27.5			10.0		55.8		0.2			10.8			77.7		182.0
Property additions	$	341.8			352.3		754.5		15.0			195.8			8.4		1,667.8
*      Includes non-cash asset retirement costs as follows:
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
2010
Exploration costs	$	3.4			0.0		0.0		0.0			0.0			0.0		3.4
Development costs		23.7			17.1		8.6		10.7			5.8			0.0		65.9
	$	27.1			17.1		8.6		10.7			5.8			0.0		69.3
2009
Exploration costs	$	5.0			0.0		0.0		0.0			0.0			0.0		5.0
Development costs		0.0			22.2		15.5		(2.2	)		0.9			0.0		36.4
	$	5.0			22.2		15.5		(2.2	)		0.9			0.0		41.4

F-50

Schedule 4 – Results of Operations for Oil and Gas Producing Activities*

	United States		Canada					Malaysia			United Kingdom		Republic of the Congo			Other			Total
(Millions of dollars)			Conven- tional			Synthetic
Year Ended December 31, 2011
Revenues
Crude oil and natural gas liquids
Sales to unaffiliated enterprises	$	648.8		459.2			410.2		1,583.0			92.4		148.8			0.0			3,342.4
Transfers to consolidated operations		0.0		46.4			96.4		0.0			0.0		0.0			0.0			142.8
Natural gas
Sales to unaffiliated enterprises		71.1		280.2			0.0		461.3			14.3		0.0			0.0			826.9
Total oil and gas revenues		719.9		785.8			506.6		2,044.3			106.7		148.8			0.0			4,312.1
Other operating revenues		17.8		(3.8	)		0.0		1.3			0.6		0.0			24.6			40.5
Total revenues		737.7		782.0			506.6		2,045.6			107.3		148.8			24.6			4,352.6
Costs and expenses
Production expenses		164.8		151.2			236.1		420.6			28.3		37.6			0.0			1,038.6
Exploration costs charged to expense		36.5		60.8			0.0		11.1			0.5		21.0			241.8			371.7
Undeveloped lease amortization		62.2		28.8			0.0		0.0			0.0		0.0			27.2			118.2
Depreciation, depletion and amortization		183.0		273.9			52.1		357.3			13.7		87.8			1.9			969.7
Accretion of asset retirement obligations		9.9		4.9			7.6		10.6			3.0		0.5			0.3			36.8
Impairment of properties		0.0		0.0			0.0		0.0			0.0		368.6			0.0			368.6
Terra Nova working interest redetermination		0.0		(5.4	)		0.0		0.0			0.0		0.0			0.0			(5.4	)
Selling and general expenses		42.1		14.2			0.9		(1.6	)		3.5		2.2			39.8			101.1
Total costs and expenses		498.5		528.4			296.7		798.0			49.0		517.7			311.0			2,999.3
		239.2		253.6			209.9		1,247.6			58.3		(368.9	)		(286.4	)		1,353.3
Income tax expense		86.5		79.7			55.8		434.9			46.8		16.4			7.5			727.6
Results of operations	$	152.7		173.9			154.1		812.7			11.5		(385.3	)		(293.9	)		625.7
Year Ended December 31, 2010
Revenues
Crude oil and natural gas liquids
Sales to unaffiliated enterprises	$	557.6		346.4			301.9		1,531.1			118.8		156.7			0.0			3,012.5
Transfers to consolidated operations		0.0		42.2			76.7		0.0			0.0		0.0			0.0			118.9
Natural gas
Sales to unaffiliated enterprises		87.0		132.1			0.0		307.1			14.1		0.0			0.0			540.3
Total oil and gas revenues		644.6		520.7			378.6		1,838.2			132.9		156.7			0.0			3,671.7
Other operating revenues		15.3		(0.2	)		0.0		(0.3	)		0.7		(1.0	)		3.9			18.4
Total revenues		659.9		520.5			378.6		1,837.9			133.6		155.7			3.9			3,690.1
Costs and expenses
Production expenses		131.7		97.5			206.4		355.0			26.9		62.0			0.0			879.5
Exploration costs charged to expense		35.7		1.9			0.0		19.8			16.2		56.4			54.3			184.3
Undeveloped lease amortization		68.5		33.7			0.0		0.0			0.0		0.0			5.8			108.0
Depreciation, depletion and amortization		281.1		180.3			45.2		379.0			22.4		95.5			1.5			1,005.0
Accretion of asset retirement obligations		6.9		4.8			6.4		9.8			2.3		0.4			0.5			31.1
Terra Nova working interest redetermination		0.0		18.6			0.0		0.0			0.0		0.0			0.0			18.6
Selling and general expenses		33.3		10.5			0.9		0.8			2.7		(2.0	)		33.6			79.8
Total costs and expenses		557.2		347.3			258.9		764.4			70.5		212.3			95.7			2,306.3
		102.7		173.2			119.7		1,073.5			63.1		(56.6	)		(91.8	)		1,383.8
Income tax expense		30.0		44.6			34.5		414.1			32.6		20.6			0.5			576.9
Results of operations	$	72.7		128.6			85.2		659.4			30.5		(77.2	)		(92.3	)		806.9

* Results exclude corporate overhead, interest and discontinued operations.

F-51

Schedule 4 – Results of Operations for Oil and Gas Producing Activities (Continued)¹

(Millions of dollars)	United States		Canada					Malaysia			United Kingdom		Republic of the Congo			Other			Total
			Conven- tional			Synthetic
Year Ended December 31, 2009
Revenues
Crude oil and natural gas liquids
Sales to unaffiliated enterprises	$	374.8		310.7			258.1		1,478.4			54.7		24.5			0.0			2,501.2
Transfers to consolidated operations		0.0		54.9			30.4		0.0			0.0		0.0			0.0			85.3
Natural gas
Sales to unaffiliated enterprises		80.6		68.6			0.0		45.4			6.4		0.0			0.0			201.0
Total oil and gas revenues		455.4		434.2			288.5		1,523.8			61.1		24.5			0.0			2,787.5
Other operating revenues2		253.2		(2.2	)		0.0		2.6			0.5		(8.0	)		2.4			248.5
Total revenues		708.6		432.0			288.5		1,526.4			61.6		16.5			2.4			3,036.0
Costs and expenses
Production expenses		101.2		97.9			171.9		248.2			19.9		15.4			0.0			654.5
Exploration costs charged to expense		27.5		10.0			0.0		55.8			0.2		10.8			77.7			182.0
Undeveloped lease amortization		34.7		44.1			0.0		0.0			0.0		0.0			4.4			83.2
Depreciation, depletion and amortization		246.5		171.8			28.1		304.1			12.4		11.5			1.4			775.8
Accretion of asset retirement obligations		6.8		4.3			4.3		7.8			1.6		0.1			0.6			25.5
Impairment of properties		5.2		0.0			0.0		0.0			0.0		0.0			0.0			5.2
Terra Nova working interest redetermination		0.0		83.5			0.0		0.0			0.0		0.0			0.0			83.5
Selling and general expenses		20.3		18.0			.8		(5.5	)		3.0		(2.0	)		23.8			58.4
Total costs and expenses		442.2		429.6			205.1		610.4			37.1		35.8			107.9			1,868.1
		266.4		2.4			83.4		916.0			24.5		(19.3	)		(105.5	)		1,167.9
Income tax expense (benefits)		88.4		1.2			19.8		354.1			11.9		1.3			(0.6	)		476.1
Results of operations	$	178.0		1.2			63.6		561.9			12.6		(20.6	)		(104.9	)		691.8

¹  Results exclude corporate overhead, interest and discontinued operations.

²  Other operating revenues in the U.S. included $244.4 million for recovery of federal royalties paid on certain properties in the Gulf of Mexico. These royalties related to production for the years 2003 through 2009.

F-52

Schedule 5 – Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

(Millions of dollars)	United States			Canada			Malaysia			United Kingdom			Republic of the Congo			Total
December 31, 2011
Future cash inflows	$	6,105.4			18,835.5			14,110.9			2,509.5			248.6			41,809.9
Future development costs		(1,283.5	)		(1,929.5	)		(1,559.8	)		(356.2	)		(0.0	)		(5,129.0	)
Future production and abandonment costs		(1,417.9	)		(7,199.7	)		(6,161.2	)		(763.0	)		(183.8	)		(15,725.6	)
Future income taxes		(807.2	)		(2,806.8	)		(2,129.7	)		(869.0	)		(39.7	)		(6,652.4	)
Future net cash flows		2,596.8			6,899.5			4,260.2			521.3			25.1			14,302.9
10% annual discount for estimated timing 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	$	1,684.8			3,240.8			2,752.8			216.9			27.9			7,923.2
December 31, 2010
Future cash inflows	$	2,472.8			13,440.2			8,118.9			1,005.1			758.9			25,795.9
Future development costs		(379.7	)		(1,244.5	)		(756.3	)		(14.0	)		(69.6	)		(2,464.1	)
Future production and abandonment costs		(631.3	)		(6,923.3	)		(2,379.0	)		(305.6	)		(330.7	)		(10,569.9	)
Future income taxes		(335.0	)		(1,509.8	)		(1,659.4	)		(329.0	)		(82.4	)		(3,915.6	)
Future net cash flows		1,126.8			3,762.6			3,324.2			356.5			276.2			8,846.3
10% annual discount for estimated timing of cash flows		(254.2	)		(1,818.0	)		(922.2	)		(123.5	)		(34.4	)		(3,152.3	)
Standardized measure of discounted future net cash flows	$	872.6			1,944.6			2,402.0			233.0			241.8			5,694.0
December 31, 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

Following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown.

(Millions of dollars)	2011			2010			2009
Inclusion of synthetic oil reserves beginning in 2009*	$	0.0			0.0			378.9
Net changes in prices, production costs and development costs		(370.5	)		240.1			675.1
Sales and transfers of oil and gas produced, net of production costs		(3,273.5	)		(2,792.2	)		(2,381.5	)
Net change due to extensions and discoveries		3,300.9			1,022.2			1,976.2
Net change due to purchases and sales of proved reserves		0.0			48.7			(36.7	)
Development costs incurred		1,881.5			1,271.3			1,344.1
Accretion of discount		827.7			698.9			422.1
Revisions of previous quantity estimates		892.5			798.8			267.8
Net change in income taxes		(1,029.4	)		(450.2	)		(454.8	)
Net increase		2,229.2			837.6			2,191.2
Standardized measure at January 1		5,694.0			4,856.4			2,665.2
Standardized measure at December 31	$	7,923.2			5,694.0			4,856.4

* Prior to 2009, discounted future net cash flows from synthetic oil operations were excluded from this report. With the SEC’s change in the definition of proved reserves to include synthetic oil as proved reserves, the Company has included synthetic oil reserves in this table beginning in 2009.

F-53

Schedule 6 – Capitalized Costs Relating to Oil and Gas Producing Activities

(Millions of dollars)	United States			Canada			Malaysia			United Kingdom			Republic of the Congo			Other			Subtotal			Synthetic– Oil Canada			Total
December 31, 2011
Unproved oil and gas properties	$	868.0			539.9			372.8			0.0			37.4			84.2			1,902.3			0.0			1,902.3
Proved oil and gas properties		2,276.3			3,756.4			4,252.5			556.6			715.3			0.0			11,557.1			1,230.6			12,787.7
Gross capitalized costs		3,144.3			4,296.3			4,625.3			556.6			752.7			84.2			13,459.4			1,230.6			14,690.0
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties		(188.2	)		(223.5	)		(0.0	)		(0.0	)		(6.1	)		(41.0	)		(458.8	)		(0.0	)		(458.8	)
Proved oil and gas properties		(1,255.1	)		(1,493.4	)		(1,474.3	)		(361.9	)		(613.2	)		(0.0	)		(5,197.9	)		(324.3	)		(5,522.2	)
Net capitalized costs	$	1,701.0			2,579.4			3,151.0			194.7			133.4			43.2			7,802.7			906.3			8,709.0
December 31, 2010
Unproved oil and gas properties	$	564.7			729.0			322.4			0.0			57.9			79.6			1,753.6			0.0			1,753.6
Proved oil and gas properties		1,869.1			2,861.1			3,596.0			526.1			657.0			3.3			9,512.6			1,171.6			10,684.2
Gross capitalized costs		2,433.8			3,590.1			3,918.4			526.1			714.9			82.9			11,266.2			1,171.6			12,437.8
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties		(126.5	)		(200.5	)		(0.0	)		(0.0	)		(6.0	)		(13.8	)		(346.8	)		(0.0	)		(346.8	)
Proved oil and gas properties		(1,074.6	)		(1,258.4	)		(1,115.3	)		(347.9	)		(129.8	)		(3.3	)		(3,929.3	)		(280.3	)		(4,209.6	)
Net capitalized costs	$	1,232.7			2,131.2			2,803.1			178.2			579.1			65.8			6,990.1			891.3			7,881.4

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.

F-54

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 December 31, 2011
Sales and other operating revenues	$	6,271.7		7,415.9		7,240.4		6,761.3			27,689.3
Income from continuing operations before income taxes		411.4		505.2		534.4		100.0			1,551.0
Income (loss) from continuing operations		238.5		280.0		335.7		(113.3	)		740.9
Net income (loss)		268.9		311.6		406.1		(113.9	)		872.7
Income (loss) from continuing operations per Common share
Basic		1.23		1.45		1.74		(0.59	)		3.83
Diluted		1.22		1.44		1.73		(0.59	)		3.81
Net income (loss) per Common share
Basic		1.39		1.61		2.10		(0.59	)		4.51
Diluted		1.38		1.60		2.09		(0.59	)		4.49
Cash dividend per Common share		0.275		0.275		0.275		0.275			1.10
Market price of Common Stock*
High		76.11		77.48		69.71		58.67			77.48
Low		65.74		62.53		44.05		42.10			42.10
Year Ended December 31, 2010
Sales and other operating revenues	$	4,699.3		4,754.9		5,209.0		5,562.6			20,225.8
Income from continuing operations before income taxes		316.2		433.6		352.7		286.2			1,388.7
Income from continuing operations		169.5		263.2		197.4		149.5			779.6
Net income		148.9		272.3		202.8		174.1			798.1
Income from continuing operations per Common share
Basic		0.89		1.37		1.03		0.77			4.06
Diluted		0.88		1.36		1.02		0.77			4.03
Net income per Common share
Basic		0.78		1.42		1.06		0.90			4.16
Diluted		0.77		1.41		1.05		0.90			4.13
Cash dividend per Common share		0.25		0.25		0.275		0.275			1.05
Market price of Common Stock*
High		59.71		61.82		61.92		75.37			75.37
Low		50.13		49.55		48.44		61.01			48.44

* Prices are as quoted on the New York Stock Exchange.

F-55

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SCHEDULE II – VALUATION ACCOUNTS AND RESERVES

(Millions of dollars)	Balance at January 1		Charged (Credited) to Expense		Deductions			Other*			Balance at December 31
2011
Deducted from asset accounts:
Allowance for doubtful accounts	$	8.0		0.2		(0.3	)		0.0			7.9
Deferred tax asset valuation allowance		305.3		140.5		0.0			0.0			445.8
2010
Deducted from asset accounts:
Allowance for doubtful accounts	$	7.8		0.5		(0.2	)		(0.1	)		8.0
Deferred tax asset valuation allowance		290.2		15.1		0.0			0.0			305.3
2009
Deducted from asset accounts:
Allowance for doubtful accounts	$	7.3		0.9		(0.2	)		(0.2	)		7.8
Deferred tax asset valuation allowance		266.8		23.4		0.0			0.0			290.2

*Amounts primarily represent changes in foreign currency exchange rates.

F-56

GLOSSARY OF TERMS

3D seismic

three-dimensional images created by bouncing sound waves off underground rock formations that are used to determine the best places to drill for hydrocarbons

bitumen or oil sands

tar-like hydrocarbon-bearing substance that occurs naturally in certain areas at the Earth’s surface or at relatively shallow depths and which can be recovered, processed and upgraded into a light, sweet synthetic crude oil

deepwater

offshore location in greater than 1,000 feet of water

downstream

refining and marketing operations

dry hole

an unsuccessful exploration well that is plugged and abandoned, with associated costs written off to expense

exploratory

wildcat and delineation, e.g., exploratory wells

hydrocarbons

organic chemical compounds of hydrogen and carbon atoms that form the basis of all petroleum products

synthetic oil

a light, sweet crude oil produced by upgrading bitumen recovered from oil sands

throughput

average amount of raw material processed in a given period by a facility

upstream

oil and natural gas exploration and production operations, including synthetic oil operation

wildcat

well drilled to target an untested or unproved geologic formation

F-57

EX-12.1

EXHIBIT 12.1

Murphy Oil Corporation and Consolidated Subsidiaries

Computation of Ratio of Earnings to Fixed Charges (unaudited)

(Thousands of dollars)

	Years Ended December 31,
	2011		2010		2009		2008		2007
Income from continuing operations before income taxes	$	1,550,983		1,388,710		1,235,413		2,849,489		906,538
Distributions (less than) greater than equity in earnings of affiliates		2,622		5,343		4,970		1,012		294
Previously capitalized interest charged to earnings during period		18,923		29,743		27,180		20,803		13,490
Interest and expense on indebtedness, excluding capitalized interest		40,700		34,728		24,391		42,152		24,784
Interest portion of rentals*		50,756		50,355		38,452		30,618		14,551
Earnings before provision for taxes and fixed charges	$	1,663,984		1,508,879		1,330,406		2,944,074		959,657
Interest and expense on indebtedness, excluding capitalized interest		40,700		34,728		24,391		42,152		24,784
Capitalized interest		15,131		18,444		28,614		31,459		49,881
Interest portion of rentals*		50,756		50,355		38,452		30,618		14,551
Total fixed charges	$	106,587		103,527		91,457		104,229		89,216
Ratio of earnings to fixed charges		15.6		14.6		14.5		28.2		10.8

* Calculated as one-third of rentals. Considered a reasonable approximation of interest factor.

EX-13

Exhibit 13

Financial and Operating Highlights

		000,000,00		000,000,00		000,000,00			000,000,00		000,000,00
					% Change					% Change
(Thousands of dollars except per share data)	2011		2010		2011–2010			2009		2010–2009
For the Year
Revenues	$	27,745,549	$	20,169,718		38	%	$	16,895,206		19	%
Income from continuing operations		740,932		779,559		-5	%		713,854		9	%
Net income		872,702		798,081		9	%		837,621		-5	%
Cash dividends paid		212,752		201,405		6	%		190,788		6	%
Capital expenditures		2,943,812		2,448,140		20	%		2,207,269		11	%
Net cash provided by operating activities		2,145,385		3,128,558		-31	%		1,864,633		68	%
Average common shares outstanding – diluted (thousands)		194,512		193,158		1	%		192,468		0	%
At End of Year
Working capital	$	622,743	$	619,783		0	%	$	1,194,087		-48	%
Net property, plant and equipment		10,475,149		10,367,847		1	%		9,065,088		14	%
Total assets		14,138,138		14,233,243		-1	%		12,756,359		12	%
Long-term debt		249,553		939,350		-73	%		1,353,183		-31	%
Stockholders’ equity		8,778,397		8,199,550		7	%		7,346,026		12	%
Per Share of Common Stock
Income from continuing operations – diluted	$	3.81	$	4.03		-5	%	$	3.71		9	%
Net income – diluted		4.49		4.13		9	%		4.35		-5	%
Cash dividends paid		1.10		1.05		5	%		1.00		5	%
Stockholders’ equity		45.31		42.52		7	%		38.44		11	%
Net Crude Oil and Gas Liquids Produced – barrels per day		103,160		126,927		-19	%		131,839		-4	%
United States		17,148		20,114		-15	%		17,053		18	%
Canada		30,049		30,801		-2	%		32,043		-4	%
Malaysia		48,551		66,897		-27	%		76,322		-12	%
Other International		7,412		9,115		-19	%		6,421		42	%
Net Natural Gas Sold – thousands of cubic feet per day		457,365		356,801		28	%		187,266		91	%
United States		47,212		53,037		-11	%		54,255		-2	%
Canada		188,787		85,563		121	%		54,857		56	%
Malaysia		217,440		212,692		2	%		74,653		185	%
United Kingdom		3,926		5,509		-29	%		3,501		57	%
Petroleum Products Sold – barrels per day		556,434		536,757		4	%		536,474		0	%
United States		420,737		450,100		-7	%		432,700		4	%
United Kingdom		135,697		86,657		57	%		103,774		-16	%
Stockholder and Employee Data at December 31
Common shares outstanding (thousands)		193,723		192,836		0	%		191,115		1	%
Number of stockholders of record		2,212		2,363		-6	%		2,490		-5	%
Number of employees		8,610		8,994		-4	%		8,369		7	%
Average number of employees for year		8,906		8,673		3	%		8,157		6	%

Murphy Oil at a Glance

Murphy Oil Corporation (“Murphy” or “the Company”) is an international oil and gas company that conducts business through various operating subsidiaries. The Company produces oil and/or natural gas in the United States, Canada, Malaysia, the United Kingdom and Republic of the Congo and conducts exploration activities worldwide. Murphy also has an interest in a Canadian synthetic oil operation. The Company operates a growing retail marketing gasoline station chain on the parking lots of Walmart Supercenters and at stand-alone locations in the United States, and also markets petroleum products under various brand names and to unbranded wholesale customers in the United States. Additionally, the Company owns two ethanol production facilities in the United States. The Company owns a petroleum refinery and markets petroleum products in the United Kingdom. The Company has announced its intention to sell its U.K. refining and marketing assets. Murphy is headquartered in El Dorado, Arkansas, and has over 8,500 employees worldwide. The Company’s common stock is traded on the New York Stock Exchange under the ticker symbol “MUR”.

Major Subsidiaries of Murphy Oil Corporation

Murphy Exploration & Production Company, through various operating subsidiaries and affiliates, is engaged in crude oil and natural gas production activities in the United States, Malaysia, the U.K. sector of the North Sea and Republic of the Congo, and explores for oil and natural gas worldwide. The subsidiary has its headquarters in Houston, Texas, and conducts business from offices in Kuala Lumpur, Malaysia; St. Albans, England; Pointe-Noire, Republic of the Congo; Singapore; Jakarta, Indonesia; Perth, Western Australia; and Erbil, in the Kurdistan region of Iraq.

Murphy Oil Company Ltd. is engaged in crude oil and natural gas exploration and production in Western Canada and offshore Eastern Canada as well as the extraction and sale of synthetic crude oil from oil sands. The subsidiary’s office is located in Calgary, Alberta, and is operated as a component of the Company’s worldwide exploration and production operation directed from Houston.

Murphy Oil USA, Inc. is engaged in retail and wholesale marketing of petroleum products in the United States. It is headquartered in El Dorado, Arkansas. High-volume and low-cost Murphy USA^® branded gasoline stations located on-site at Walmart Supercenters and at stand-alone Murphy Express locations provide fuel and merchandise to retail customers in 23 states, primarily in the Southern and Midwestern U.S. Murphy Oil USA also operates a network of six Company-owned terminals that, along with a number of third-party terminals, supply fuel to a retail network and wholesale customers in 23 states. Ethanol production facilities in Hankinson, North Dakota, and Hereford, Texas, produce about one-third of ethanol blended into gasoline sold by the Company.

Murco Petroleum Limited is engaged in refining and marketing of petroleum products in the United Kingdom. Headquartered at St. Albans, England, Murco owns a refinery in Milford Haven, Wales, and operates a network of fueling stations in the United Kingdom. The Company has announced its intention to sell these U.K. operations.

Offices
El Dorado, Arkansas	St. Albans, Hertfordshire, England	Jakarta, Indonesia
Houston, Texas	Pointe-Noire, Republic of the Congo	Perth, Western Australia, Australia
Calgary, Alberta, Canada	Singapore	Erbil, Kurdistan, Iraq
Kuala Lumpur, Malaysia

1

Dear Fellow Shareholders

Two thousand eleven saw continuation of an overall sluggish global economy with Euro zone sovereign debt issues, a Standard & Poor’s downgrade of U.S. government debt and a tragic natural disaster in Japan all adding further drag to any sign of economic recovery. However, oil markets saw some strength on the back of Asian demand and shut-in of Libyan production. The global benchmark crude, Dated Brent, ranged between $95 and $115 per barrel for much of the year and showed strength above U.S. West Texas Intermediate crude that was partially landlocked and in oversupply. This differential, that at times was close to $30 per barrel, closed near year-end 2011 to a more normal $10 as pipeline constraints were being worked. We sold our two U.S. refineries just as this price advantage waned.

While our international natural gas production benefited from strong liquified natural gas market pricing, gas prices in North America continued to fall throughout 2011 and recently dropped below $3 per million British Thermal Units as warm winter temperatures further challenged the current oversupply picture. Absent increased demand or new export opportunities, I expect North American natural gas prices to be under continued pressure for the midterm. We are fortunate to have the opportunity and flexibility to react quickly and redirect spending away from dry gas investments in North America.

Our diverse, oil-weighted global portfolio, complemented by our North American resource position, provides the basis for strength and growth across our upstream business. We are almost two years removed from the unfortunate and tragic events of the Macondo incident in the Gulf of Mexico (GOM) and, while the pace of play has improved, new permits require higher levels of manpower and much more time to complete. That coupled with fewer rigs makes for a much slower, and for us a smaller, business. Over that same time frame, our onshore business has picked up the slack and is on a rapidly growing trajectory.

Last year we established the framework and began executing on our strategy to reposition the company. As mentioned, we closed on the sale of the two U.S. refineries at the end of the third quarter and are now focused on the disposition of the U.K. refinery at Milford Haven, Wales. We are also evaluating the potential to separate our retail business and to unlock its value, which we believe is unrealized within the current corporate structure.

Net income for 2011 totaled $873 million ($4.49 per share), up slightly from 2010 as contributions from Refining and Marketing, including discontinued operations, offset lower Upstream results. The lower net income in our exploration and production segment was primarily due to an impairment charge taken at our Azurite field, offshore Republic of the Congo. Our balance sheet remains strong as we ended the year with a long-term debt-to-capital-employed ratio of 2.8%, providing ample capacity to act on value-added opportunities.

2

Exploration and Production

Annual production for 2011 averaged 179,400 barrels of oil equivalent per day with a weighting of 58% to oil and 16% to oil-indexed natural gas. We were more negatively impacted by lower production from the Kikeh field in Malaysia due to a sand/fines migration issue in some wells, lower Azurite production in Republic of the Congo and less than budgeted wells drilled in the GOM due to lack of permits than we were by positive results in the Eagle Ford Shale (EFS) area in south Texas and Tupper West in British Columbia.

In 2012, we should see good year-on-year production growth with accelerated development at EFS and the Seal heavy oil project in northern Alberta, complemented by stabilized production from Kikeh following the successfully completed remediation program at the end of last year.

Activity in our North American resource program ramped up further in 2011. This oil-weighted resource program now extends over 800,000 net acres with entry into a fifth play. We reorganized our North American resource business as a single unit to bring expertise and complementary disciplines from our successful Montney development program in Canada to the fast growing business in the EFS. Heavy oil production growth at the Seal project is moving forward at an accelerated pace. We are focused at Seal on additional development drilling, down spacing opportunities, multi-leg laterals and advancing our Enhanced Oil Recovery projects related to polymer flooding and thermal stimulation as we look to unlock the large resource in place there. In the southern Alberta Bakken play, we are in the very early stages of evaluating the productive capability of our acreage having drilled six appraisal wells in the play, with the most recent showing encouragement.

In addition to our North American onshore activity, in 2011 we sanctioned seven development projects that will be important growth components starting in 2013. These oil developments include Patricia, Serendah, South Acis, Permas and Endau in the Sarawak blocks and Siakap North in Block K, all in Malaysia, and the Schiehallion field re-development project in the U.K. North Sea.

3

Activity levels and results from our global exploration program were disappointing in 2011. We only drilled four wildcat wells testing targets in Suriname, Indonesia and Brunei. The process of lining up rigs and finalizing well schedules pushed some activity into this year, so I expect the 2012 program will return to a more normal pace of testing 12 to 15 prospects. The year is off to a good start with a gas discovery in Block H, offshore Sabah Malaysia, in close proximity to the Rotan gas discovery, which is being evaluated for Floating LNG development. Impactful prospects will be drilled in the Kurdistan region of Iraq, Republic of the Congo and Australia during the year.

Refining and Marketing

Consistent with our strategy to exit the refining business, we are now progressing on the divestiture of the Milford Haven refinery in Wales.

The Downstream business had a very solid year turning in net income of $190 million, excluding discontinued operations, with the U.S. Retail business contributing the second highest net income in its history. Build out of our chain continued with the addition of 29 stations, bringing the total number of retail outlets to 1,128 at year-end. Our U.S. retail chain broadened its partnership with Wal-Mart and participated in the “10 cents per gallon Rollback” program on gasoline prices from June through December. Longer term we are excited about the opportunity to expand both within and outside our current footprint with Wal-Mart.

In Renewable Energy, we completed the construction and upgrades to the Hereford, Texas ethanol plant, which started up at the end of March, on schedule and within budget. Start-up and commissioning went well and the plant has ramped up to its nameplate capacity of 105 million gallons per year. Operations at our Hankinson, North Dakota ethanol plant continue to be steady in the 120 million gallon per year range. These two plants have now been fully integrated into our U.S. marketing business.

In Closing

The repositioning of our Company remains on track with the sale of the two U.S. refineries and attention shifting to divestiture of the U.K. refinery. Recognizing the value of our retail business is also in focus. The Upstream growth plan is in place with the sanction of key projects in Malaysia and accelerated development of our oil-weighted North American resource portfolio. We will maintain an active and impactful exploration program this year and continue to renew and replenish our prospect inventory. Our plans are set and the team is in place to deliver on these growth initiatives.

Your support over the past year has been greatly appreciated and together we can look forward to a Company better positioned for a bright future.

David M. Wood

President and Chief Executive Officer

February 10, 2012

El Dorado, Arkansas

4

Exploration and Production Statistical Summary

	2011		2010		2009		2008		2007		2006		2005
Net crude oil, condensate and natural gas liquids production – barrels per day
United States		17,148		20,114		17,053		10,668		12,989		21,112		25,897
Canada – light		83		43		18		46		596		443		563
heavy		7,264		5,988		6,813		8,484		11,524		12,613		11,806
offshore		9,204		11,497		12,357		16,826		18,871		14,896		23,124
synthetic		13,498		13,273		12,855		12,546		12,948		11,701		10,593
Malaysia		48,551		66,897		76,322		57,403		20,367		11,298		13,503
United Kingdom		2,423		3,295		3,361		4,869		5,281		7,146		7,992
Republic of the Congo		4,989		5,820		1,743		—		—		—		—
Continuing operations		103,160		126,927		130,522		110,842		82,576		79,209		93,478
Discontinued operations		—		—		1,317		7,412		8,946		8,608		7,871
Total liquids produced		103,160		126,927		131,839		118,254		91,522		87,817		101,349
Net crude oil, condensate and natural gas liquids sold – barrels per day
United States		17,148		20,114		17,053		10,668		12,989		21,112		25,897
Canada – light		83		43		18		46		596		443		563
heavy		7,264		5,988		6,813		8,484		11,524		12,613		11,806
offshore		9,079		11,343		12,455		16,690		18,839		15,360		22,443
synthetic		13,498		13,273		12,855		12,546		12,948		11,701		10,593
Malaysia		48,092		68,975		72,575		61,907		16,018		11,986		13,818
United Kingdom		2,299		4,177		2,445		5,739		5,218		6,678		8,303
Republic of the Congo		3,959		5,428		973		—		—		—		—
Continuing operations		101,422		129,341		125,187		116,080		78,132		79,893		93,423
Discontinued operations		—		—		1,162		7,774		9,470		10,349		9,821
Total liquids sold		101,422		129,341		126,349		123,854		87,602		90,242		103,244
Net natural gas sold – thousands of cubic feet per day
United States		47,212		53,037		54,255		45,785		45,139		56,810		70,452
Canada		188,787		85,563		54,857		1,910		9,922		9,752		10,323
Malaysia – Sarawak		176,943		154,535		28,070		—		—		—		—
– Kikeh		40,497		58,157		46,583		1,399		—		—		—
United Kingdom		3,926		5,509		3,501		6,424		6,021		8,700		9,423
Total natural gas sold		457,365		356,801		187,266		55,518		61,082		75,262		90,198
Net hydrocarbons produced – equivalent barrels1 per day		179,388		186,394		163,050		127,507		101,702		100,361		116,382
Estimated net hydrocarbon reserves – million equivalent barrels1,2		534.1		455.2		439.2		402.8		405.1		388.3		353.6
Weighted average sales prices3
Crude oil, condensate and natural gas liquids –dollars per barrel
United States	$	103.92		76.31		60.08		95.74		65.57		57.30		47.48
Canada4 – light		94.28		75.48		64.24		70.37		50.98		50.45		44.27
heavy		57.00		49.89		40.45		59.05		32.84		25.87		21.30
offshore		110.02		76.87		58.19		96.69		69.83		62.55		51.37
synthetic		102.94		77.90		61.49		100.10		74.35		63.23		58.12
Malaysia5		90.14		60.97		55.51		87.83		74.58		51.78		46.16
United Kingdom		110.13		77.95		61.31		90.16		68.38		64.30		52.83
Republic of the Congo5		103.02		74.87		69.04		—		—		—		—
Natural gas – dollars per thousand cubic feet
United States		4.13		4.52		4.05		9.67		7.38		7.76		8.52
Canada4		4.07		4.23		3.09		6.40		6.34		6.49		7.88
Malaysia – Sarawak		7.10		5.31		4.05		—		—		—		—
– Kikeh		0.24		0.23		0.23		0.23		—		—		—
United Kingdom4		9.99		7.01		5.04		10.98		7.54		7.34		5.80

¹  Natural gas converted at a 6:1 ratio.

²  At December 31.

³  Includes intracompany transfers at market prices.

⁴  U.S. dollar equivalent.

⁵  Prices are net of payments under the terms of the respective production sharing contracts.

5

Refining and Marketing Statistical Summary

	2011			2010			2009			2008			2007			2006			2005
Branded retail outlets at December 31
United States – Murphy USA®		1,003			1,001			996			992			971			987			864
Murphy Express®		125			98			52			33			2			—			—
Other		—			116			121			129			153			177			337
Total United States		1,128			1,215			1,169			1,154			1,126			1,164			1,201
United Kingdom		459			451			453			454			389			402			412
United States retail marketing:
Fuel margin per gallon1	$	0.156			0.114			0.083			0.165			0.103			0.104			0.115
Gallons sold per store month		277,715			306,646			312,493			324,223			294,784			285,665			268,277
Merchandise sales revenue per store month	$	158,144			153,530			137,623			110,943			97,523			80,598			66,516
Merchandise margin as a percentage of merchandise sales		12.8	%		13.1	%		12.5	%		13.5	%		13.2	%		13.3	%		12.8	%
Unit margins per barrel:
United States refining2 – Discontinued operations	$	3.45			0.23			0.75			(1.48	)		5.11			(0.24	)		1.02
United Kingdom refining and marketing		(0.67	)		(1.47	)		(0.28	)		3.41			(1.48	)		4.43			4.81
Petroleum products sold – barrels per day
United States – Gasoline		312,945			333,182			319,549			313,827			298,833			266,353			233,191
Kerosine		11,864			11,449			11,928			4,606			1,685			2,269			5,671
Diesel and home heating oils		74,410			77,799			76,599			86,933			91,344			62,196			60,228
Residuals		12,618			18,015			15,501			14,837			15,422			11,696			15,330
Asphalt, LPG and other		8,900			9,655			9,123			7,287			9,384			8,087			8,294
Total United States		420,737			450,100			432,700			427,490			416,668			350,601			322,714
United Kingdom – Gasoline		35,757			23,085			30,007			34,125			14,356			12,425			12,739
Kerosine		16,298			11,387			12,954			14,835			4,020			3,619			2,410
Diesel and home heating oils		48,893			29,710			35,721			34,560			14,785			11,803			14,910
Residuals		14,427			7,885			10,560			12,744			3,728			3,825			3,242
LPG and other		20,322			14,590			14,532			15,246			4,213			2,998			2,240
Total United Kingdom		135,697			86,657			103,774			111,510			41,102			34,670			35,541
Total petroleum products sold		556,434			536,757			536,474			539,000			457,770			385,271			358,255
Crude capacity of refineries at December 31 – barrels per stream day		135,000			295,000			268,000			268,000			268,000			192,400			192,400
Refinery inputs – barrels per day
Crude – Meraux, Louisiana – Discontinued operations		100,163			106,482			101,864			95,126			106,446			55,129			73,371
Superior, Wisconsin – Discontinued operations		26,483			34,541			32,158			26,580			32,737			34,066			34,768
Milford Haven, Wales		131,959			78,841			96,625			97,521			36,000			30,036			26,983
Other feedstocks		6,456			11,518			14,317			23,300			10,805			6,423			9,131
Total refinery inputs		265,061			231,382			244,964			242,527			185,988			125,654			144,253
Refinery yields – barrels per day
United States – Gasoline		51,950			61,128			62,534			54,020			61,998			37,690			45,287
Kerosine		11,172			11,068			10,670			8,759			871			812			5,001
Diesel and home heating oils		37,723			41,305			40,761			41,658			52,893			30,829			34,561
Residuals		12,736			18,082			15,786			14,585			15,269			11,414			15,019
Asphalt, LPG and other		14,842			14,802			10,845			9,065			13,202			9,893			10,406
Fuel and loss		1,247			834			1,409			1,852			1,999			1,260			722
Total United States – Discontinued operations		129,670			147,219			142,005			129,939			146,232			91,898			110,996
United Kingdom – Gasoline		34,171			20,889			26,902			32,290			12,397			10,624			9,582
Kerosine		17,038			11,374			13,789			15,065			4,500			4,255			2,804
Diesel and home heating oils		47,418			25,995			34,619			33,868			14,218			11,308			13,974
Residuals		14,185			8,296			10,388			12,585			3,641			3,830			3,212
Asphalt, LPG and other		19,448			14,799			13,735			15,750			4,344			2,962			2,862
Fuel and loss		3,131			2,810			3,526			3,030			656			777			823
Total United Kingdom		135,391			84,163			102,959			112,588			39,756			33,756			33,257
Total refinery yields		265,061			231,382			244,964			242,527			185,988			125,654			144,253

¹ Represents net sales prices for fuel less purchased cost of fuel.

² Represents refinery sales realizations less cost of crude and other feedstocks and refinery operating and depreciation expenses.

6

Board of Directors

	William C. Nolan, Jr. Partner, Nolan & Alderson, Attorneys, El Dorado, Arkansas. Director since 1977. Chairman of the Board until May 2012, ex-officio member of all other committees		James V. Kelley President and Chief Operating Officer, BancorpSouth, Inc., Tupelo, Mississippi. Director since 2006. Committees: Audit; Executive Compensation
	Claiborne P. Deming President and Chief Executive Officer, Retired, Murphy Oil Corporation, El Dorado, Arkansas. Director since 1993. Chairman of the Board beginning in May 2012. Committees: Executive (Chairman); Environmental, Health & Safety		Walentin (Val) Mirosh President, Mircan Resources, Inc., Calgary, Alberta, Canada. Director since 2011. Committees: Executive Compensation
	David M. Wood President and Chief Executive Officer, Murphy Oil Corporation, El Dorado, Arkansas. Director since January 2009. Committees: Executive		R. Madison Murphy Managing Member, Murphy Family Management, LLC, El Dorado, Arkansas. Director since 1993. Chairman from 1994–2002. Committees: Executive; Audit (Chairman)
	Frank W. Blue International Legal Advisor/Arbitrator, Santa Barbara, California. Director since 2003. Committees: Audit; Nominating & Governance		Neal E. Schmale President and Chief Operating Officer, Retired, Sempra Energy, San Diego, California. Director since 2004. Committees: Audit; Executive Compensation
	Steven A. Cossé Executive Vice President and General Counsel, Retired, Murphy Oil Corporation, El Dorado, Arkansas. Director since 2011. Committees: Environmental, Health & Safety		David J. H. Smith Chief Executive Officer, Retired, Whatman plc, Maidstone, Kent, England. Director since 2001. Committees: Executive Compensation (Chairman); Nominating & Governance
	Robert A. Hermes Chairman of the Board, Retired, Purvin & Gertz, Inc., Houston, Texas. Director since 1999. Committees: Executive; Nominating & Governance (Chairman); Environmental, Health & Safety		Caroline G. Theus President, Inglewood Land & Development Co., Alexandria, Louisiana. Director since 1985. Committees: Executive; Environmental, Health & Safety (Chairman)

7

Principal Subsidiaries

Murphy Exploration & Production Company Engages in worldwide crude oil and natural gas exploration and production. 16290 Katy Freeway Suite 600 Houston, Texas 77094 (281) 675-9000	Roger W. Jenkins President Eugene T. Coleman Executive Vice President, Worldwide Derek M. Stewart Senior Vice President, Americas, West Africa and Middle East Sam Algar Vice President, Asia Pacific Exploration Keith S. Caldwell Vice President, Finance and Administration Daniel R. Hanchera Vice President, Business Development	Dave B. Perkins Vice President, Health, Safety, Environment & Security Walter K. Compton Vice President and General Counsel Kevin G. Fitzgerald Vice President Mindy K. West Vice President and Treasurer John W. Eckart Vice President John A. Moore Secretary
Murphy Oil Company Ltd. Engages in crude oil and natural gas exploration and production, and extraction and sale of synthetic crude oil in Canada. 4000, 520-3 Avenue SW Calgary, Alberta T2P 0R3 (403) 294-8000 Mailing Address: P.O. Box 2721, Station M Calgary, Alberta T2P 3Y3 Canada	Michael McFadyen President Cal Buchanan Vice President, Business Development Ronald L. Mcllwrick Vice President, Operations	Dennis Ward Vice President, Finance Mindy K. West Vice President and Treasurer Paul Christensen Controller
Murphy Oil USA, Inc. Engages in marketing of petroleum products and manufacturing of ethanol fuel in the United States. 200 Peach Street El Dorado, Arkansas 71730 (870) 862-6411 Mailing Address: P.O. Box 7000 El Dorado, Arkansas 71731-7000	Thomas McKinlay President Marn Cheng Vice President Stephen F. Hunkus Vice President, World Wide Refining and Renewable Energy Walter K. Compton Vice President and General Counsel	Mindy K. West Vice President and Treasurer John W. Eckart Vice President and Controller John A. Moore Secretary
Murco Petroleum Limited Engages in refining and marketing of petroleum products in the United Kingdom. 4 Beaconsfield Road St. Albans, Hertfordshire AL1 3RH, England 44-1727-892-400	Bryan G. Kelly Managing Director Jamie Goodfellow Marketing Director Bernard Pouille Supply and Refining Director	Simon V. Rhodes Financial Director Patricia E. Haylock Secretary

Corporate Information

Corporate Office	Electronic Payment of Dividends	Annual Meeting
200 Peach Street P.O. Box 7000 El Dorado, Arkansas 71731-7000 (870) 862-6411 Stock Exchange Listings Trading Symbol: MUR New York Stock Exchange Transfer Agent and Registrar Computershare Trust Company, N.A. Toll-free (888) 239-5303 Local Chicago (312) 360-5303 (Address for overnight delivery) 250 Royall Street Mail Stop 1A Canton, MA 02021 (Address for first class mail, registered mail and certified mail) P. O. Box 43036 Providence, RI 02940	Shareholders may have dividends deposited directly into their bank accounts by electronic funds transfer. Authorization forms may be obtained by contacting Computershare as described under Transfer Agent and Registrar above. E-mail Address murphyoil@murphyoilcorp.com Web Site www.murphyoilcorp.com Murphy Oil’s website provides frequently updated information about the Company and its operations, including: •    News releases •    Annual report •    Quarterly reports •    Live webcasts of quarterly conference calls •    Links to the Company’s SEC filings •    Stock quotes •    Profiles of the Company’s operations •    Murphy USA station locator	The annual meeting of the Company’s shareholders will be held at 10:00 a.m. on May 9, 2012, at the South Arkansas Arts Center, 110 East 5th Street, El Dorado, Arkansas. A formal notice of the meeting, together with a proxy statement and proxy form, will be provided to all shareholders. Inquiries Inquiries regarding shareholder account matters should be addressed to: John A. Moore Manager, Law and Secretary Murphy Oil Corporation P.O. Box 7000 El Dorado, Arkansas 71731-7000 jmoore@murphyoilcorp.com Members of the financial community should direct their inquiries to: Barry Jeffery Director, Investor Relations Murphy Oil Corporation P.O. Box 7000 El Dorado, Arkansas 71731-7000 (870) 864-6501 bjeffery@murphyoilcorp.com
Executive Officers
David M. Wood President and Chief Executive Officer and Director and Member of the Executive Committee since January 2009. Mr. Wood served as Executive Vice President and President of Murphy Exploration & Production Company from January 2007 until December 2008, and President of Murphy Exploration & Production Company- International from March 2003 through December 2006. Kevin G. Fitzgerald Executive Vice President and Chief Financial Officer since December 2011. Mr. Fitzgerald was Senior Vice President and Chief Financial Officer from January 2007 to November 2011, and was Treasurer from July 2001 through December 2006. Roger W. Jenkins Executive Vice President since August 2009. Mr. Jenkins has served as President of Murphy Exploration & Production Company since January 2009, and prior to that was Senior Vice President, North America for this subsidiary from September 2007 to December 2008.	Thomas McKinlay Executive Vice President, World Wide Downstream operations since January 2011. Mr. McKinlay was Vice President, U.S. Manufacturing from August 2009 to January 2011. Additionally, Mr. McKinlay has served as Senior Vice President of Murphy Oil USA, Inc. since April 2009. From August 2008 to March 2009, he was General Manager, Supply and Transportation for this U.S. subsidiary. Bill H. Stobaugh Executive Vice President, Corporate Planning & Business Development since February 2012. Mr. Stobaugh was Senior Vice President from February 2005 to January 2012. Walter K. Compton Senior Vice President and General Counsel since March 2011. Mr. Compton was Vice President, Law from February 2009 to February 2011, and Manager, Law from November 1996 to January 2009. John W. Eckart Senior Vice President and Controller since December 2011. Mr. Eckart was Vice President and Controller from January 2007 to November 2011, and has been Controller since March 2000.	Mindy K. West Vice President and Treasurer since January 2007. Ms. West was Director of Investor Relations from July 2001 through December 2006. Kelli M. Hammock Vice President, Administration since December 2009. Ms. Hammock was General Manager, Administration from June 2006 to November 2009. Thomas J. Mireles Vice President, Corporate Planning & Development since February 2012. Mr. Mireles was General Manager, Planning & Analysis from June 2010 to January 2012. He also served as Senior Manager, Business Development from February 2009 to May 2010 and was Manager, Business Development from January 2007 to January 2009. John A. Moore Secretary since March 2011. Mr. Moore was Senior Attorney from August 2005 to February 2011.

EX-21

EXHIBIT 21

MURPHY OIL CORPORATION

SUBSIDIARIES OF THE REGISTRANT AS OF DECEMBER 31, 2011

Name of Company	State or Other Jurisdiction of Incorporation		Percentage of Voting Securities Owned by Immediate Parent
Murphy Oil Corporation (REGISTRANT)
A. Caledonia Land Company		Delaware		100.0
B. El Dorado Engineering Inc.		Delaware		100.0
1. El Dorado Contractors Inc.		Delaware		100.0
C. Marine Land Company		Delaware		100.0
D. Murphy Eastern Oil Company		Delaware		100.0
E. Murphy Exploration & Production Company		Delaware		100.0
1. Mentor Holding Corporation		Delaware		100.0
a. Mentor Excess and Surplus Lines Insurance Company		Delaware		100.0
b. MIRC Corporation		Louisiana		100.0
2. Murphy Building Corporation		Delaware		100.0
3. Murphy Exploration & Production Company – International		Delaware		100.0
a. Canam Offshore Limited		Bahamas		100.0
(1) Canam Brunei Oil Ltd.		Bahamas		100.0
(2) Murphy Peninsular Malaysia Oil Co., Ltd.		Bahamas		100.0
(3) Murphy Sabah Oil Co., Ltd.		Bahamas		100.0
(4) Murphy Sarawak Oil Co., Ltd.		Bahamas		100.0
b. El Dorado Exploration, S.A.		Delaware		100.0
c. Murphy Australia Holdings Pty. Ltd.		Western Australia		100.0
(1) Murphy Australia AC/P 36 Oil Pty. Limited		Western Australia		100.0
(2) Murphy Australia NT/P80 Oil Pty. Ltd.		Western Australia		100.0
(3) Murphy Australia Oil Pty. Ltd.		Western Australia		100.0
(4) Murphy Australia WA-423-P Oil Pty. Ltd.		Western Australia		100.0
d. Murphy Baranan Oil Co., Ltd.		Bahamas		100.0
e. Murphy Brazil Exploracao e Producao de Petroleo e Gas Ltda. (see company n.(1) below)		Brazil		90.0
f. Murphy Cameroon Ntem Oil Co. Ltd.		Bahamas		100.0
g. Murphy Central Dohuk Oil Co. Ltd.		Bahamas		100.0
h. Murphy Exploration (Alaska), Inc.		Delaware		100.0
i. Murphy Global, Inc.		Delaware		100.0
j. Murphy International Marketing & Trading Company		Delaware		100.0
k. Murphy Italy Oil Company (see company F. below)		Delaware		95.0
l. Murphy Kurdistan Oil Co., Ltd.		Bahamas		100.0
m. Murphy Nha Trang Oil Co. Ltd.		Bahamas		100.0
n. Murphy Overseas Ventures Inc.		Delaware		100.0
(1) Murphy Brazil Exploracao e Producao de Petroleo e Gas Ltda. (see company e. above)		Brazil		10.0
o. Murphy SE Asia Oil Pte. Ltd.		Singapore		100.0
p. Murphy Semai IV Ltd.		Bahamas		100.0
q. Murphy Semai Oil Co., Ltd.		Bahamas		100.0
r. Murphy Somali Oil Company		Delaware		100.0
s. Murphy South Barito, Ltd.		Bahamas		100.0
t. Murphy-Spain Oil Company		Delaware		100.0
u. Murphy Suriname Company Ltd.		Bahamas		100.0
v. Murphy Suriname Oil Company Ltd.		Bahamas		100.0
w. Murphy West Africa, Ltd.		Bahamas		100.0
x. Murphy Wokam Oil Company Ltd.		Bahamas		100.0
y. Murphy Worldwide, Inc.		Delaware		100.0
z. Ocean Exploration Company		Delaware		100.0
(1) Odeco Italy Oil Company (see company aa. below)		Delaware		5.0
aa. Odeco Italy Oil Company (see company z.(1) above)		Delaware		95.0
4. Murphy Exploration & Production Company – USA		Delaware		100.0

Ex 21-1

EXHIBIT 21 (Contd.)

MURPHY OIL CORPORATION

SUBSIDIARIES OF THE REGISTRANT AS OF DECEMBER 31, 2011 (Contd.)

Name of Company	State or Other Jurisdiction of Incorporation			Percentage of Voting Securities Owned by Immediate Parent
Murphy Oil Corporation (REGISTRANT) – Contd.
F. Murphy Italy Oil Company (see company E.3.k. above)		Delaware			5.0
G. Murphy Oil Company Ltd.		Canada			100.0
1. Murphy Atlantic Offshore Finance Company Ltd.		Canada			100.0
2. Murphy Atlantic Offshore Oil Company Ltd.		Canada			100.0
3. Murphy Canada Exploration Company		NSULCo.	*		100.0
a. Environmental Technologies Inc.		Canada			52.0
(1) Eastern Canadian Coal Gas Venture Ltd.		Canada			100.0
4. Murphy Canada, Ltd.		Canada			100.0
5. Murphy Finance Company		NSULCo.	*		100.0
H. Murphy Oil USA, Inc.		Delaware			100.0
1. 591 Beverage, Inc.		Nebraska			100.0
2. 864 Holdings, Inc.		Texas			100.0
a. 864 Beverage, Inc.		Texas			100.0
3. Arkansas Oil Company		Delaware			100.0
4. Hankinson Holding, LLC		Delaware			100.0
a. Hankinson Renewable Energy, LLC		Delaware			100.0
5. Hereford Renewable Energy, LLC		Delaware			100.0
6. Murphy Crude Oil Marketing, Inc.		Delaware			100.0
7. Murphy Gas Gathering Inc.		Delaware			100.0
8. Murphy Latin America Refining & Marketing, Inc.		Delaware			100.0
9. Murphy LOOP, Inc.		Delaware			100.0
10. Murphy Lot Holdings, LLC		Delaware			100.0
11. Murphy Oil Trading Company (Eastern)		Delaware			100.0
12. Spur Oil Corporation		Delaware			100.0
13. Superior Crude Trading Company		Delaware			100.0
I. Murphy Realty Inc.		Delaware			100.0
J. Murphy Ventures Corporation		Delaware			100.0
K. New Murphy Oil (UK) Corporation		Delaware			100.0
1. Murphy Petroleum Limited		England			100.0
a. Alnery No. 166 Ltd.		England			100.0
b. Petrol Express Ltd.		England			100.0
c. Murco Petroleum Limited		England			100.0
(1) European Petroleum Distributors Ltd.		England			100.0

* Denotes Nova Scotia Unlimited Liability Company.

Ex 21-2

EX-23.1

EXHIBIT 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors of Murphy Oil Corporation:

We consent to the incorporation by reference in the registration statements (Nos. 333-142789, 333-157107 and 333-177206) on Form S-8 and in the registration statement (No. 333-161688) on Form S-3 of Murphy Oil Corporation of our reports dated February 28, 2012, with respect to the consolidated balance sheets of Murphy Oil Corporation and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, cash flows and stockholders’ equity for each of the years in the three-year period ended December 31, 2011, and related financial statement schedule, and the effectiveness of internal control over financial reporting as of December 31, 2011, which reports appear in the December 31, 2011 annual report on Form 10-K of Murphy Oil Corporation.

/s/ KPMG LLP

Houston, Texas

February 28, 2012

EX-23.2

Exhibit 23.2

TBPE REGISTERED ENGINEERING FIRM F-1580		FAX (713) 651-0849
1100 LOUISIANA SUITE 3800	HOUSTON, TEXAS 77002-5235	TELEPHONE (713) 651-9191

Consent Of Ryder Scott Company, L.P.

The Board of Directors of Murphy Oil Corporation:

As independent petroleum engineers, we consent to the incorporation by reference in the registration statements (Nos. 333-142789, 333-157107 and 333-177206) on Form S-8 and in the registration statement (No. 333-161688) on Form S-3 of Murphy Oil Corporation to Our Firm’s name under the caption “Murphy Oil’s Reserves Process and Policies” and the inclusion of our report, dated February 15, 2012, which appears as Exhibit 99.6 in the December 31, 2011 annual report on Form 10-K of Murphy Oil Corporation.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

February 28, 2012

SUITE 600, 1015 4TH STREET, S.W.	CALGARY, ALBERTA T2R 1J4	TEL (403) 262-2799	FAX (403) 262-2790
621 17TH STREET , SUITE 1550	DENVER COLORADO 80293-150	TEL (303) 623-9147	FAX (303) 623-4258

EX-31.1

EXHIBIT 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, David M. Wood, certify that:

1. I have reviewed this annual report on Form 10-K of Murphy Oil Corporation;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and

d) disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2012

/s/ David M. Wood

David M. Wood

President and Chief Executive Officer

(Principal Executive Officer)

Ex. 31-1

EX-31.2

EXHIBIT 31.2

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Kevin G. Fitzgerald, certify that:

1. I have reviewed this annual report on Form 10-K of Murphy Oil Corporation;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and

d) disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2012

/s/ Kevin G. Fitzgerald

Kevin G. Fitzgerald

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

Ex. 31-2

EX-32

EXHIBIT 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Murphy Oil Corporation (the “Company”) on Form 10-K for the period ended December 31, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we, David M. Wood and Kevin G. Fitzgerald, Principal Executive Officer and Principal Financial Officer, respectively, of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to our knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 28, 2012

/s/ David M. Wood

David M. Wood

President and Chief Executive Officer

(Principal Executive Officer)

/s/ Kevin G. Fitzgerald

Kevin G. Fitzgerald

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

Ex. 32-1

EX-99.6

Exhibit 99.6

MURPHY OIL CORPORATION

Proved Reserves Summary

UNITED KINGDOM & EAGLE FORD SHALE

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

SEC Parameters

As of

December 31, 2011

            /s/ Jeffrey D. Wilson            

Jeffrey D. Wilson, P.E.

TBPE License No. 86426

Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Ex. 99.6-1

TBPE REGISTERED ENGINEERING FIRM F-1580		FAX (713) 651-0849
1100 LOUISIANA SUITE 3800	HOUSTON, TEXAS 77002-5235	TELEPHONE (713) 651-9191

February 15, 2012

Mr. Brad Gouge

Manager of Corporate Reserves

Murphy Oil Corporation

16290 Katy Freeway, Suite 600

Houston, TX 77094

Gentlemen:

At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold interests of Murphy Oil Corporation (Murphy) as of December 31, 2011. This report presents these estimates for properties located in the North Sea offshore of the United Kingdom and in the Eagle Ford Shale (EFS) trend in south Texas in the United States. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed in January, 2012 and presented herein, was prepared for public disclosure by Murphy in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent all of the net liquid and net gas reserves of Murphy as of December 31, 2011 in the United Kingdom and 39 percent of the total proved developed net liquid hydrocarbon reserves, 20 percent of the total proved developed net gas reserves, 80 percent of the total proved undeveloped net liquid hydrocarbon reserves and 65 percent of the total proved undeveloped net gas reserves in the United States.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2011, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

SUITE 600, 1015 4TH STREET, S.W.	CALGARY, ALBERTA T2R 1J4	TEL (403) 262-2799	FAX (403) 262-2790
621 17TH STREET, SUITE 1550	DENVER, COLORADO 80293-1501	TEL (303) 623-9147	FAX (303) 623-4258

Ex.99.6-2

Murphy Oil Corporation – United Kingdom & Eagle Ford Shale

February 15, 2012

Page 3

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

Murphy Oil Corporation – United Kingdom

As of December 31, 2011

	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Remaining Reserves
Oil/Condensate – MBarrels		4,279		759		16,535		21,573
Plant Products – MBarrels		7		6		0		13
Gas – MMCF		8,789		7,027		5,240		21,056
Income Data (M$ US)
Future Gross Revenue	$	530,172	$	146,990	$	1,833,096	$	2,510,258
Deductions		164,891		67,020		887,303		1,119,214
Future Net Income (FNI)	$	365,281	$	79,970	$	945,793	$	1,391,044
Discounted FNI @ 10%	$	269,233	$	39,749	$	252,733	$	561,715

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

Murphy Oil Corporation – Eagle Ford Shale, United States

As of December 31, 2011

	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Remaining Reserves
Oil/Condensate – MBarrels		7,833		270		27,589		35,692
Plant Products – MBarrels		0		0		0		0
Gas – MMCF		9,583		2,232		26,339		38,154
Income Data (M$ US)
Future Gross Revenue	$	775,272	$	33,322	$	2,691,444	$	3,500,038
Deductions		177 ,085		6,991		1,443,412		1,627,488
Future Net Income (FNI)	$	598,187	$	26,331	$	1,248,032	$	1,872,550
Discounted FNI @ 10%	$	398,034	$	19,017	$	523,356	$	940,407

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions and income data are expressed as thousands of U.S. dollars (M$ US).

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Ex. 99.6-3

Murphy Oil Corporation – United Kingdom & Eagle Ford Shale

February 15, 2012

Page 4

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PHDWin Petroleum Economic Evaluation Software (Version 2.9 Build 3), a copyrighted program of TRC Consultants L.C. The program was used at the request of Murphy. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The deductions incorporate the normal direct costs of operating the wells, recompletion costs, development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal or foreign income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

For the United Kingdom properties, liquid hydrocarbon reserves account for approximately 95 percent and gas reserves account for the remaining five percent of total future gross revenue from proved reserves.

For the EFS properties, liquid hydrocarbon reserves account for approximately 94 percent and gas reserves account for the remaining six percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

	Murphy Oil Corporation –United Kingdom Discounted Future Net Income
	As of December 31, 2011
Discount Rate Percent	Total Proved (M$ US)
5	$	871,751
8	$	667,670
12	$	474,228
15	$	369,875

	Murphy Oil Corporation – Eagle Ford Shale Discounted Future Net Income
	As of December 31, 2011
Discount Rate Percent	Total Proved (M$ US)
5	$	1,300,840
8	$	1,066,653
12	$	832,529
15	$	697,746

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Ex. 99.6-4

Murphy Oil Corporation – United Kingdom & Eagle Ford Shale

February 15, 2012

Page 5

Reserves Included in This Report

The proved reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The proved developed non-producing reserves included herein consist of the shut-in and behind pipe categories for the UK properties and the shut-in category for the EFS properties.

In the UK properties, the Schiehallion field has in place a sanctioned project to replace the current FPSO. The operator’s best estimate is that the removal and replacement project will occur from March 2014 through November 2015. Reserves classified as producing are only classified as such through March 2014. Subsequent reserves from the existing producing and shut-in wells are assigned as undeveloped due to the necessity for FPSO replacement. The field is expected to return to production in November 2015.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. For the UK properties, the proved summary gas volumes included herein include gas consumed in operations as reserves. These specific volumes are denoted as “fuel gas” entries and do not contribute to revenue; furthermore, they are represented as negative volumes, but are not subtracted from the summary volumes. For the EFS properties, the proved gas volumes included herein do not attribute gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Murphy’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward”. The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Ex. 99.6-5

Murphy Oil Corporation – United Kingdom & Eagle Ford Shale

February 15, 2012

Page 6

included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

The proved reserves reported herein are limited to the period prior to expiration of current contracts providing the legal rights to produce or a revenue interest in such production unless evidence indicates that contract renewal is reasonably certain. Furthermore, properties may be subjected to significantly varying contractual fiscal terms that affect the net revenue to Murphy for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with Murphy the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Murphy’s representations regarding such contractual information should be construed as a legal opinion on this matter.

Ryder Scott did not evaluate the country and geopolitical risks where Murphy operates or has interests. Murphy’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Murphy owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Ex. 99.6-6

Murphy Oil Corporation – United Kingdom & Eagle Ford Shale

February 15, 2012

Page 7

identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by a combination of performance methods and volumetric methods. For both areas, the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis and material balance which utilized extrapolations of historical production and pressure data available through August, 2011 for the UK properties and through December, 2011 for the EFS properties in those cases where such data were considered to be definitive. Volumetric methods were used to confirm the performance based estimates in both areas. The data utilized in this analysis were furnished to Ryder Scott by Murphy and were considered sufficient for the purpose thereof.

For both areas, the proved developed non-producing and undeveloped reserves included herein were estimated by analogy and confirmed by volumetric methods. The data utilized in this analysis were furnished to Ryder Scott by Murphy and were considered sufficient for the purpose thereof.

All current and planned wells are horizontal completions for the EFS area.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Murphy has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Murphy

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Ex. 99.6-7

Murphy Oil Corporation – United Kingdom & Eagle Ford Shale

February 15, 2012

Page 8

with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Murphy. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Murphy. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Ex. 99.6-8

Murphy Oil Corporation – United Kingdom & Eagle Ford Shale

February 15, 2012

Page 9

Murphy furnished us with the above mentioned average prices in effect on December 31, 2011. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements. In cases where there are numerous contracts or price references within the same geographic area, the benchmark price is represented by the unweighted arithmetic average of the initial 12-month average first-day-of-the-month benchmark prices used.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Murphy. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Murphy to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves by reserve category for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Proved Realized Prices
North America USA	Oil/Condensate	WTI Cushing	$96.19/Bbl	$96.88/Bbl
	Gas	Henry Hub	$4.12/MMBtu	$5.71/MCF
Europe United Kingdom	Oil/Condensate	Brent	$110.96/Bbl	$110.88/Bbl
	NGLs	Brent	$110.96/Bbl	$99.86/Bbl
	Gas*	Contract	N/A	$5.56/MCF

* UK Average Realized Gas Prices are materially impacted by the inclusion of fuel volumes.

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report are based on the operating expense reports of Murphy and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs for non-operated properties include the overhead costs that are allocated directly

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Ex. 99.6-9

Murphy Oil Corporation – United Kingdom & Eagle Ford Shale

February 15, 2012

Page 10

to the leases and wells under terms of operating agreements. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Murphy. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Murphy based on capital expenditure forecasts supplied by the operator and are in line with historical capital costs. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for both properties. Abandonment costs net of salvage are significant for the UK properties. The estimates of the net abandonment costs furnished by Murphy were accepted without independent verification.

The proved undeveloped reserves in this report have been incorporated herein in accordance with Murphy’s plans to develop these reserves as of December 31, 2011. The implementation of Murphy’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Murphy’s management. As the result of our inquiries during the course of preparing this report, Murphy has informed us that the development activities included herein have been subjected to and received the internal approvals required by Murphy’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Murphy. Additionally, Murphy has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

The proved undeveloped reserves associated with the Schiehallion field In the UK were limited to those locations in the currently sanctioned development plan approved by Murphy’s management.

Current costs used by Murphy were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Ex. 99.6-10

Murphy Oil Corporation – United Kingdom & Eagle Ford Shale

February 15, 2012

Page 11

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Murphy. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Murphy.

Murphy makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Murphy has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Murphy of the references to our name as well as to the references to our third party report for Murphy, which appears in the December 31, 2011 annual report on Form 10-K of Murphy. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Murphy.

We have provided Murphy with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Murphy and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

/s/ Jeffrey D. Wilson

Jeffrey D. Wilson, P.E.

TBPE License No. 86426

Senior Vice President

[SEAL]

JDW (FPR)/pl

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Ex. 99.6-11

Professional Qualifications of Primary Technical Engineer

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Jeffrey D. Wilson was the primary technical person responsible for the estimate of the reserves, future production and income presented herein.

Mr. Wilson, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1998, is a Senior Vice President and also serves as a member of the Board of Directors responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Wilson served in a number of engineering positions with Exxon. For more information regarding Mr. Wilson’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Wilson earned a Bachelor of Science degree in Mechanical Engineering from the University of Houston in 1991, graduating with Magna Cum Laude honors, and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and currently serves as a member of the SPE Oil and Gas Reserves Committee.

The Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Wilson fulfills. As part of his 2011 continuing education hours, Mr. Wilson attended an internally presented 6 hours of formalized training and 24 hours of formalized external training on various topics including SEC oil and gas reporting requirements, the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, overviews of the various productive basins, evaluations of resource play reserves, petroleum economics evaluation methods and software, and ethics training. Mr. Wilson also taught multiple classes throughout the year for a total of 12 hours class time on advanced economic modeling techniques and production sharing contract modeling.

Based on his educational background, professional training and more than 20 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Wilson has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Ex. 99.6-12

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Ex. 99.6-13

PETROLEUM RESERVES DEFINITIONS

Page 14

Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Ex. 99.6-14

PETROLEUM RESERVES DEFINITIONS

Page 15

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Ex. 99.6-15

RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Ex. 99.6-16

RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 17

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Ex. 99.6-17

XML

Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2011

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/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. Murphy markets petroleum products under various brand names and to unbranded wholesale customers in the United States and United Kingdom. It owns two ethanol production facilities in the United States and one petroleum refinery in the United Kingdom. In 2011, the Company sold two U.S. petroleum refineries and certain associated marketing assets. The Company has announced its intention to sell the U.K. refining and marketing 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. 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 Company’s 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 December 31, 2011 and 2010, 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

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. 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, 2011, the Company owned Canadian government securities with maturities greater than 90 days at date of acquisition that had a carrying value of $532,093,000.

ACCOUNTS RECEIVABLE

ACCOUNTS RECEIVABLE – The Company’s accounts receivable primarily consists of amounts owed to the Company by customers for sales of crude oil, natural gas and refined products under varying credit arrangements. 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.

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 are generally 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 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. Refineries, certain marketing facilities and certain common 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.

Turnarounds for major processing units at refineries 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 refineries and Syncrude varies depending on operating requirements and events. Murphy defers turnaround costs incurred and amortizes such costs through Operating Expenses over the period until the next scheduled turnaround. All other maintenance and repairs are expensed as incurred. Renewals and betterments are capitalized. Major turnarounds occurred in 2010 at both the Meraux, Louisiana, and Milford Haven, Wales, refineries.

INVENTORIES

INVENTORIES – 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 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 is generally carried at average cost and is included in Finished Products Inventory. Materials and supplies are valued at the lower of average cost or estimated value and generally consist of tubulars and other drilling equipment as well as 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.

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 at least 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 2011 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, 2011. 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. See Note B for accounting changes applicable to goodwill recoverability testing beginning in 2012.

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. Petroleum revenue taxes are provided using the estimated effective tax rate over the life of applicable U.K. properties. 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 Spain 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 currency into U.S. dollars are included in Accumulated Other Comprehensive Income (Loss) in Stockholders’ Equity.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES – The fair value of a derivative instrument is recognized as an asset or liability in the Company’s Consolidated Balance Sheet. Upon entering into a derivative contract, the Company may designate the derivative as either a fair value hedge or a cash flow hedge, or decide that the contract is not a hedge, 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 used 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. Changes in the fair value of a qualifying fair value hedge are recorded in earnings along with the gain or loss on the hedged item. Changes in the fair value of a qualifying cash flow hedge are 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 Statement of Income, the fair value of the associated cash flow hedge is reclassified from other comprehensive income into earnings. Ineffective portions of a cash flow hedge derivative’s change in fair value are 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.

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION – The fair value of awarded stock options, restricted stock and restricted stock units 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 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 and restricted stock units and expense is recognized over the three-year vesting period. The fair value of time-lapse restricted stock 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 and 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.

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.

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Activity in Number of Shares of Common Stock Issued and Outstanding (Detail)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Reconciliation of Common Stock Outstanding [Line Items]
At beginning of year	192,836,008	191,115,378	190,713,806
Stock options exercised	615,674	1,495,926	548,659
Employee stock purchase and thrift plans	33,390	49,657	61,575
Restricted stock awards, net of forfeitures	238,136	175,047	(208,662)
At end of year	193,723,208	192,836,008	191,115,378

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Significant Accounting Policies - Additional Information (Detail) (USD $) In Thousands, unless otherwise specified			12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2011 Stock Options	Dec. 31, 2011 Stock Options Minimum	Dec. 31, 2011 Stock Options Maximum	Dec. 31, 2011 Performance-Based Restricted Stock	Dec. 31, 2011 Restricted Stock and Restricted Stock Units	Dec. 31, 2011 Refining Year	Dec. 31, 2011 Refining Minimum	Dec. 31, 2011 Refining Maximum	Dec. 31, 2011 Gasoline stations and other properties Year	Dec. 31, 2011 Syncrude Minimum	Dec. 31, 2011 Syncrude Maximum
Significant Accounting Policies [Line Items]
Canadian government securities with maturities greater than 90 days at the date of acquisition	$ 532,093	$ 616,558
Depreciable lives, Gasoline stations and other properties, straight-line method, minimum								14			3
Depreciable lives, Gasoline stations and other properties, straight-line method, maximum								25			20
Turnarounds for major processing units									4 years	5 years		2 years	3 years
Stock-based compensation, fair value assumption model			Black-Scholes pricing model			Monte Carlo valuation model
Stock-based compensation, vesting period				2 years	3 years	3 years	3 years

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Financial Instruments and Risk Management (Tables)

12 Months Ended

Dec. 31, 2011

Fair Value of Derivative Instruments Not Designated as Hedging Instruments

At December 31, 2011 and 2010, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

December 31, 2011

December 31, 2010

Asset Derivatives

Liability Derivatives

Asset Derivatives

Liability Derivatives

(Thousands of dollars)

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Type of derivative contract

Commodity

Accounts Receivable

$197

Accounts Payable

$489

Accounts Receivable

$750

Accounts Payable

$626

Foreign exchange

—

—

Accounts Payable

$8,459

Accounts Receivable

$7,261

—

—

Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments

For the years ended December 31, 2011 and 2010, 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, 2011					Year Ended December 31, 2010
(Thousands of dollars)	Location of Gain (Loss) Recognized in Income on Derivative		Amount of Gain (Loss) Recognized in Income on Derivative			Location of Gain (Loss) Recognized in Income on Derivative		Amount of Gain (Loss) Recognized in Income on Derivative
Type of derivative contract
Commodity		Crude Oil and Product Purchases	$	5,659			Crude Oil and Product Purchases	$	(7,577	)
Foreign exchange		Interest and Other Income (Loss)		(305	)		Interest and Other Income (Loss)		34,215
			$	5,354				$	26,638

Fair Value of Interest Rate Derivative Contracts Designated as Hedging Instruments

At December 31, 2011, the fair value of these interest rate derivative contracts, which have been designated as hedging instruments for accounting purposes, are presented in the following table.

	December 31, 2011
	Liability Derivatives
(Thousands of dollars)	Balance Sheet Location		Fair Value
Type of derivative contract
Interest rate		Accounts Payable	$	25,927

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Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Detail) (USD $)	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Property acquisition costs
Unproved	$ 279,300,000		$ 242,800,000		$ 118,100,000
Proved	23,500,000		22,000,000		0
Total acquisition costs	302,800,000		264,800,000		118,100,000
Exploration costs	562,500,000	[1]	473,400,000	[1]	312,600,000	[1]
Development costs	1,954,300,000	[1]	1,365,800,000	[1]	1,419,100,000	[1]
Total costs incurred	2,819,600,000		2,104,000,000		1,849,800,000
Charged to expense
Dry hole expense	250,954,000		90,125,000	[2]	125,244,000	[2]
Geophysical and other costs	120,700,000		94,200,000		56,700,000
Total charged to expense	371,700,000	[3]	184,300,000	[3]	182,000,000	[3]
Property additions	2,447,900,000		1,919,700,000		1,667,800,000
United States
Property acquisition costs
Unproved	233,800,000		129,800,000		82,400,000
Proved	0		0		0
Total acquisition costs	233,800,000		129,800,000		82,400,000
Exploration costs	253,200,000	[1]	204,100,000	[1]	89,700,000	[1]
Development costs	263,900,000	[1]	98,300,000	[1]	197,200,000	[1]
Total costs incurred	750,900,000		432,200,000		369,300,000
Charged to expense
Dry hole expense	600,000		(1,400,000)		11,300,000
Geophysical and other costs	35,900,000		37,100,000		16,200,000
Total charged to expense	36,500,000		35,700,000		27,500,000
Property additions	714,400,000		396,500,000		341,800,000
Canada
Property acquisition costs
Unproved	18,500,000		78,600,000		31,000,000
Proved	0		22,000,000		0
Total acquisition costs	18,500,000		100,600,000		31,000,000
Exploration costs	76,000,000	[1]	1,800,000	[1]	9,900,000	[1]
Development costs	871,900,000	[1]	721,000,000	[1]	321,400,000	[1]
Total costs incurred	966,400,000		823,400,000		362,300,000
Charged to expense
Dry hole expense	50,600,000		0		0
Geophysical and other costs	10,200,000		1,900,000		10,000,000
Total charged to expense	60,800,000		1,900,000		10,000,000
Property additions	905,600,000		821,500,000		352,300,000
Malaysia
Property acquisition costs
Unproved	0		0		0
Proved	0		0		0
Total acquisition costs	0		0		0
Exploration costs	700,000	[1]	99,600,000	[1]	114,400,000	[1]
Development costs	705,500,000	[1]	396,700,000	[1]	695,900,000	[1]
Total costs incurred	706,200,000		496,300,000		810,300,000
Charged to expense
Dry hole expense	100,000		14,300,000		55,000,000
Geophysical and other costs	11,000,000		5,500,000		800,000
Total charged to expense	11,100,000		19,800,000		55,800,000
Property additions	695,100,000		476,500,000		754,500,000
United Kingdom
Property acquisition costs
Unproved	0		0		0
Proved	0		0		0
Total acquisition costs	0		0		0
Exploration costs	500,000	[1]	6,700,000	[1]	100,000	[1]
Development costs	30,500,000	[1]	15,500,000	[1]	15,100,000	[1]
Total costs incurred	31,000,000		22,200,000		15,200,000
Charged to expense
Dry hole expense	0		15,200,000		0
Geophysical and other costs	500,000		1,000,000		200,000
Total charged to expense	500,000		16,200,000		200,000
Property additions	30,500,000		6,000,000		15,000,000
Republic of the Congo
Property acquisition costs
Unproved	0		0		0
Proved	23,500,000		0		0
Total acquisition costs	23,500,000		0		0
Exploration costs	500,000	[1]	93,500,000	[1]	19,100,000	[1]
Development costs	78,700,000	[1]	132,300,000	[1]	187,500,000	[1]
Total costs incurred	102,700,000		225,800,000		206,600,000
Charged to expense
Dry hole expense	18,100,000		35,500,000		13,900,000
Geophysical and other costs	2,900,000		20,900,000		(3,100,000)
Total charged to expense	21,000,000		56,400,000		10,800,000
Property additions	81,700,000		169,400,000		195,800,000
Other Regions
Property acquisition costs
Unproved	27,000,000		34,400,000		4,700,000
Proved	0		0		0
Total acquisition costs	27,000,000		34,400,000		4,700,000
Exploration costs	231,600,000	[1]	67,700,000	[1]	79,400,000	[1]
Development costs	3,800,000	[1]	2,000,000	[1]	2,000,000	[1]
Total costs incurred	262,400,000		104,100,000		86,100,000
Charged to expense
Dry hole expense	181,600,000		26,500,000		45,100,000
Geophysical and other costs	60,200,000		27,800,000		32,600,000
Total charged to expense	241,800,000		54,300,000		77,700,000
Property additions	$ 20,600,000		$ 49,800,000		$ 8,400,000

[1] Includes non-cash asset retirement costs as follows: 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 2010 Exploration costs $ 3.4 0.0 0.0 0.0 0.0 0.0 3.4 Development costs 23.7 17.1 8.6 10.7 5.8 0.0 65.9 $ 27.1 17.1 8.6 10.7 5.8 0.0 69.3 2009 Exploration costs $ 5.0 0.0 0.0 0.0 0.0 0.0 5.0 Development costs 0.0 22.2 15.5 (2.2 ) 0.9 0.0 36.4 $ 5.0 22.2 15.5 (2.2 ) 0.9 0.0 41.4

[2] Reclassified to conform to current presentation.

[3] Results exclude corporate overhead, interest and discontinued operations.

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Long-Term Debt - Additional Information (Detail) (USD $)	Dec. 31, 2011
Debt Instrument [Line Items]
Future maturities of long term debt in 2012	$ 350,005,000
Future maturities of long term debt in 2013	46,000
Future maturities of long term debt in 2014	48,000
Future maturities of long term debt in 2015	51,000
Future maturities of long term debt in 2016	55,000
Thereafter	$ 249,353,000

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Results of Operations for Oil and Gas Producing Activities (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2009
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Other operating revenues, anticipated recovery of federal royalties paid	$ 244.4	[1]

[1] Results exclude corporate overhead, interest and discontinued operations.

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Discontinued Operations - Additional Information (Detail) (USD $)	1 Months Ended	3 Months Ended	12 Months Ended
	Mar. 12, 2009	Sep. 30, 2011	Dec. 31, 2011	Dec. 31, 2010		Dec. 31, 2009
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sales of assets			$ 27,776,000	$ 2,189,000	[1]	$ 1,616,000	[1]
Number of Refineries for disposal		2
Gain (loss) on disposal of refineries, net of tax		18,724,000
Net cash proceeds from operations sold in Ecuador	78,900,000
Gain from the sale of the Ecuador properties, net of income taxes	103,596,000
Gain from the sale of the Ecuador properties, income taxes	13,961,000
Superior Refinery
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sales of assets		214,000,000
Gain (loss) on disposal of refineries, net of tax		77,585,000
Meraux Refinery
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sales of assets		325,000,000
Gain (loss) on disposal of refineries, net of tax		(58,861,000)
Gain (loss) on liquidation of inventories		$ 179,152,000

[1] Reclassified to conform to current presentation.

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Share-Based Plans, Amounts Recognized (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation charged against income before income tax benefit	$ 43,272	$ 41,992	$ 28,618
Related income tax benefit recognized in income	$ 13,053	$ 12,169	$ 7,860

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Components of Accumulated Other Comprehensive Income (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Accumulated Other Comprehensive Income (Loss) [Line Items]
Foreign currency translation gains	$ 496,161	$ 587,408
Retirement and postretirement plan adjustments, net of tax	(168,889)	(137,980)
Loss deferred on interest rate hedges, net of tax	(16,852)	0
Balance at end of year	$ 310,420	$ 449,428

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Incentive Plans (Tables)

12 Months Ended

Dec. 31, 2011

Share-Based Plans, Amounts Recognized

Amounts recognized in the financial statements with respect to share-based plans are as follows.

(Thousands of dollars)	2011		2010		2009
Compensation charged against income before income tax benefit	$	43,272		41,992		28,618
Related income tax benefit recognized in income		13,053		12,169		7,860

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 using 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 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.

	2011			2010			2009
Fair value per option grant	$	20.34			18.75		$	15.15
Assumptions
Dividend yield		1.80	%		1.80	%		1.40	%
Expected volatility		37.00	%		43.00	%		41.00	%
Risk-free interest rate		2.10	%		2.52	%		1.95	%
Expected life		5.10 yrs.			5.25 yrs.			5.25 yrs.

Changes in Options Outstanding

Changes in options outstanding during the last three years are presented in the following table.

	Number of Shares			Average Exercise Price
Outstanding at December 31, 2008		5,399,060		$	40.90
Granted at FMV		1,057,000			43.95
Exercised		(560,500	)		19.58
Forfeited		(464,000	)		60.65
Outstanding at December 31, 2009		5,431,560			42.01
Granted at FMV		1,605,628			52.85
Exercised		(1,580,950	)		29.04
Forfeited		(153,854	)		53.33
Outstanding at December 31, 2010		5,302,384			48.83
Granted at FMV		1,397,312			67.64
Exercised		(974,500	)		39.30
Forfeited		(290,968	)		52.73
Outstanding at December 31, 2011		5,434,228			55.17
Exercisable at December 31, 2009		3,506,310		$	34.86
Exercisable at December 31, 2010		2,499,610			45.07
Exercisable at December 31, 2011		2,319,735			51.14

Additional Information about Stock Options Outstanding

Additional information about stock options outstanding at December 31, 2011 is shown below.

	Options Outstanding						Options Exercisable
Range of Exercise Prices per Option	No. of Options		Avg. Life in Years		Aggregate Intrinsic Value		No. of Options		Avg. Life in Years		Aggregate Intrinsic Value
$19.43 to $23.58		393,750		1.0	$	13,571,000		393,750		1.0	$	13,571,000
$30.30 to $45.23		953,610		3.6		11,466,000		541,235		3.2		6,604,000
$51.07 to $57.32		2,067,156		3.9		5,938,000		730,750		1.7		2,069,000
$67.64 to $72.75		2,019,712		5.1		0		654,000		3.1		0
		5,434,228		4.1	$	30,975,000		2,319,735		2.3	$	22,244,000

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.

(Number of shares or share units)	2011			2010			2009
Balance at beginning of year		1,023,492			872,027			806,822
Granted		521,423			449,100			375,050
Awarded		(309,656	)		(252,551	)		0
Forfeited		(60,767	)		(45,084	)		(309,845	)
Balance at end of year		1,174,492			1,023,492			872,027

Assumptions used in Valuation of Performance Awards Granted

The assumptions used in the valuation of the performance awards granted in 2011, 2010 and 2009 are presented in the following table.

	2011	2010	2009
Fair value per share at grant date	$38.94 – $64.89	$42.38 – $50.95	$41.18 – $44.94
Assumptions
Expected volatility	51.00%	51.00%	48.00%
Risk-free interest rate	1.04%	1.41%	1.37%
Stock beta	1.006	1.008	0.973
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 and restricted stock units outstanding for each of the last three years are presented in the following table.

(Number of shares or share units)	2011			2010			2009
Balance at beginning of year		166,173			164,695			132,819
Granted		32,711			43,370			50,290
Expired		(82,160	)		(29,475	)		(18,414	)
Forfeited		0			(12,417	)		0
Balance at end of year		116,724			166,173			164,695

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Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

12 Months Ended

Dec. 31, 2011

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			Canada		Malaysia		United Kingdom			Republic of the Congo			Other		Total
Year Ended December 31, 2011
Property acquisition costs
Unproved	$	233.8			18.5		0.0		0.0			0.0			27.0		279.3
Proved		0.0			0.0		0.0		0.0			23.5			0.0		23.5
Total acquisition costs		233.8			18.5		0.0		0.0			23.5			27.0		302.8
Exploration costs*		253.2			76.0		0.7		0.5			0.5			231.6		562.5
Development costs*		263.9			871.9		705.5		30.5			78.7			3.8		1,954.3
Total costs incurred		750.9			966.4		706.2		31.0			102.7			262.4		2,819.6
Charged to expense
Dry hole expense		0.6			50.6		0.1		0.0			18.1			181.6		251.0
Geophysical and other costs		35.9			10.2		11.0		0.5			2.9			60.2		120.7
Total charged to expense		36.5			60.8		11.1		0.5			21.0			241.8		371.7
Property additions	$	714.4			905.6		695.1		30.5			81.7			20.6		2,447.9
Year Ended December 31, 2010
Property acquisition costs
Unproved	$	129.8			78.6		0.0		0.0			0.0			34.4		242.8
Proved		0.0			22.0		0.0		0.0			0.0			0.0		22.0
Total acquisition costs		129.8			100.6		0.0		0.0			0.0			34.4		264.8
Exploration costs*		204.1			1.8		99.6		6.7			93.5			67.7		473.4
Development costs*		98.3			721.0		396.7		15.5			132.3			2.0		1,365.8
Total costs incurred		432.2			823.4		496.3		22.2			225.8			104.1		2,104.0
Charged to expense
Dry hole expense		(1.4	)		0.0		14.3		15.2			35.5			26.5		90.1
Geophysical and other costs		37.1			1.9		5.5		1.0			20.9			27.8		94.2
Total charged to expense		35.7			1.9		19.8		16.2			56.4			54.3		184.3
Property additions	$	396.5			821.5		476.5		6.0			169.4			49.8		1,919.7
Year Ended December 31, 2009
Property acquisition costs
Unproved	$	82.4			31.0		0.0		0.0			0.0			4.7		118.1
Proved		0.0			0.0		0.0		0.0			0.0			0.0		0.0
Total acquisition costs		82.4			31.0		0.0		0.0			0.0			4.7		118.1
Exploration costs*		89.7			9.9		114.4		0.1			19.1			79.4		312.6
Development costs*		197.2			321.4		695.9		15.1			187.5			2.0		1,419.1
Total costs incurred		369.3			362.3		810.3		15.2			206.6			86.1		1,849.8
Charged to expense
Dry hole expense		11.3			0.0		55.0		0.0			13.9			45.1		125.3
Geophysical and other costs		16.2			10.0		0.8		0.2			(3.1	)		32.6		56.7
Total charged to expense		27.5			10.0		55.8		0.2			10.8			77.7		182.0
Property additions	$	341.8			352.3		754.5		15.0			195.8			8.4		1,667.8
*      Includes non-cash asset retirement costs as follows:
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
2010
Exploration costs	$	3.4			0.0		0.0		0.0			0.0			0.0		3.4
Development costs		23.7			17.1		8.6		10.7			5.8			0.0		65.9
	$	27.1			17.1		8.6		10.7			5.8			0.0		69.3
2009
Exploration costs	$	5.0			0.0		0.0		0.0			0.0			0.0		5.0
Development costs		0.0			22.2		15.5		(2.2	)		0.9			0.0		36.4
	$	5.0			22.2		15.5		(2.2	)		0.9			0.0		41.4

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Fair Value of Option Award Estimated on Date of Grant using Black-Scholes Pricing Model (Detail) (Stock Options, USD $)	12 Months Ended
	Dec. 31, 2011 Year	Dec. 31, 2010 Year	Dec. 31, 2009 Year
Stock Options
Share based Compensation Arrangement by Share based Payment Award, Fair Value Assumptions, Method Used [Line Items]
Fair value per option grant	$ 20.34	$ 18.75	$ 15.15
Assumptions
Dividend yield	1.80%	1.80%	1.40%
Expected volatility	37.00%	43.00%	41.00%
Risk-free interest rate	2.10%	2.52%	1.95%
Expected life (in years)	5.10	5.25	5.25

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STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES - Additional Information (Detail)	Dec. 31, 2011
Reserve Quantities [Line Items]
Future net cash flows annual discount factor, percentage	10.00%

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Capitalized Costs Relating to Oil and Gas Producing Activities (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	$ 1,902.3	$ 1,753.6
Proved oil and gas properties	12,787.7	10,684.2
Gross capitalized costs	14,690.0	12,437.8
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	(458.8)	(346.8)
Proved oil and gas properties	(5,522.2)	(4,209.6)
Net capitalized costs	8,709.0	7,881.4
Oil Reserves
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	1,902.3	1,753.6
Proved oil and gas properties	11,557.1	9,512.6
Gross capitalized costs	13,459.4	11,266.2
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	(458.8)	(346.8)
Proved oil and gas properties	(5,197.9)	(3,929.3)
Net capitalized costs	7,802.7	6,990.1
United States | Oil Reserves
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	868.0	564.7
Proved oil and gas properties	2,276.3	1,869.1
Gross capitalized costs	3,144.3	2,433.8
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	(188.2)	(126.5)
Proved oil and gas properties	(1,255.1)	(1,074.6)
Net capitalized costs	1,701.0	1,232.7
Canada | Oil Reserves
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	539.9	729.0
Proved oil and gas properties	3,756.4	2,861.1
Gross capitalized costs	4,296.3	3,590.1
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	(223.5)	(200.5)
Proved oil and gas properties	(1,493.4)	(1,258.4)
Net capitalized costs	2,579.4	2,131.2
Canada | Synthetic Oil
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	1,230.6	1,171.6
Gross capitalized costs	1,230.6	1,171.6
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	0	0
Proved oil and gas properties	(324.3)	(280.3)
Net capitalized costs	906.3	891.3
Malaysia | Oil Reserves
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	372.8	322.4
Proved oil and gas properties	4,252.5	3,596.0
Gross capitalized costs	4,625.3	3,918.4
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	0	0
Proved oil and gas properties	(1,474.3)	(1,115.3)
Net capitalized costs	3,151.0	2,803.1
United Kingdom | Oil Reserves
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	556.6	526.1
Gross capitalized costs	556.6	526.1
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	0	0
Proved oil and gas properties	(361.9)	(347.9)
Net capitalized costs	194.7	178.2
Republic of the Congo | Oil Reserves
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	37.4	57.9
Proved oil and gas properties	715.3	657.0
Gross capitalized costs	752.7	714.9
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	(6.1)	(6.0)
Proved oil and gas properties	(613.2)	(129.8)
Net capitalized costs	133.4	579.1
Other Regions | Oil Reserves
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	84.2	79.6
Proved oil and gas properties	0	3.3
Gross capitalized costs	84.2	82.9
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	(41.0)	(13.8)
Proved oil and gas properties	0	(3.3)
Net capitalized costs	$ 43.2	$ 65.8

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Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income Taxes [Line Items]
Income tax benefits attributable to employee stock option transactions	$ 8,775,000	$ 15,896,000	$ 6,035,000
Increase in deferred tax asset valuation allowance related to foreign exploration expenditures	102,714,000	47,128,000	34,431,000
Undistributed earnings of subsidiaries considered indefinitely invested	4,895,000,000
Unrecognized deferred tax liability	492,469,000
Withholding tax on any monies repatriated from Canada to the U.S.	5.00%
Other recorded liabilities for interest and penalties	976,000	1,010,000
Income tax expense, (charges) benefits for interest and penalties	34,000	(43,000)	1,763,000
Earliest years remaining open for audit and/or settlement in major taxing jurisdictions	As of December 31, 2011, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2008; Canada – 2007; United Kingdom – 2010; and Malaysia – 2006.
Minimum
Income Taxes [Line Items]
Income tax uncertainties threshold, percentage of tax benefit more likely to be measured and recognized	50.00%
Expected liability to be added for uncertain taxes for 2012 events	1,000,000
Maximum
Income Taxes [Line Items]
Expected liability to be added for uncertain taxes for 2012 events	2,000,000
Foreign Country
Income Taxes [Line Items]
Increase in deferred tax asset valuation allowance related to foreign exploration expenditures	$ 140,493,000
Foreign Country | Minimum
Income Taxes [Line Items]
Foreign tax credit carryforwards expiration year	2014
Foreign Country | Maximum
Income Taxes [Line Items]
Foreign tax credit carryforwards expiration year	2020

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Components of Net Periodic Benefit Expense (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 22,406	$ 20,706	$ 17,052
Interest cost	30,785	30,144	28,767
Expected return on plan assets	(25,919)	(24,199)	(20,375)
Amortization of prior service cost	1,314	1,558	1,635
Amortization of transitional asset (liability)	(536)	(514)	(466)
Recognized actuarial loss	12,484	12,257	10,305
Defined Benefit Plan, Gross Periodic Benefit Cost, Total	40,534	39,952	36,918
Termination benefits expense	695	0	1,867
Curtailment expense	1,036	0	575
Net periodic benefit expense	42,265	39,952	39,360
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	4,547	4,133	3,121
Interest cost	6,141	6,211	5,688
Expected return on plan assets	0	0	0
Amortization of prior service cost	(240)	(263)	(263)
Amortization of transitional asset (liability)	8	8	0
Recognized actuarial loss	2,329	2,790	1,551
Defined Benefit Plan, Gross Periodic Benefit Cost, Total	12,785	12,879	10,097
Termination benefits expense	0	0	0
Curtailment expense	(605)	0	397
Net periodic benefit expense	$ 12,180	$ 12,879	$ 10,494

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Major Assets and Liabilities Associated with Ecuador Properties (Detail) (Ecuador, USD $) In Thousands, unless otherwise specified	Dec. 31, 2009
Ecuador
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Current assets	$ 4,214
Property, plant and equipment, net of accumulated depreciation, depletion and amortization	65,178
Other noncurrent assets	683
Assets sold - Ecuador	70,075
Current liabilities	105,185
Other noncurrent liabilities	35
Liabilities associated with assets sold - Ecuador	$ 105,220

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Commitments - Additional Information (Detail)	12 Months Ended									12 Months Ended
	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2011 Malaysia USD ($)	Dec. 31, 2011 Gulf of Mexico USD ($)	Dec. 31, 2011 Eagle Ford Shale USD ($)	Dec. 31, 2011 Brunei Offshore USD ($)	Dec. 31, 2011 Forecasted in 2012 cf	Dec. 31, 2011 Drilling Rigs And Associated Equipment USD ($)	Dec. 31, 2011 Processing Production Handling and Transportation Services USD ($)	Dec. 31, 2010 Processing Production Handling and Transportation Services USD ($)	Dec. 31, 2009 Processing Production Handling and Transportation Services USD ($)	Dec. 31, 2011 Crude Oil Storage Capacity USD ($)	Dec. 31, 2010 Crude Oil Storage Capacity USD ($)	Dec. 31, 2009 Crude Oil Storage Capacity USD ($)	Dec. 31, 2011 El Dorado Promise Annual Commitment from 2007 to 2016 USD ($)	Dec. 31, 2010 El Dorado Promise Annual Commitment from 2007 to 2016 USD ($)	Dec. 31, 2009 El Dorado Promise Annual Commitment from 2007 to 2016 USD ($)	Dec. 31, 2006 El Dorado Promise Annual Commitment from 2007 to 2016 USD ($)
Commitments and Contingencies Disclosure [Line Items]
Natural gas deliveries contract, million cubic feet per day								50,000,000
Natural gas deliveries contract, price per thousand cubic feet, in Canadian dollars								4.43
Operating lease rental payments due in 2012	$ 161,752,000									$ 23,823,000			$ 1,000,000
Operating lease rental payments due in 2013	138,121,000									18,146,000			1,000,000
Operating lease rental payments due in 2014	127,044,000									18,452,000			1,000,000
Operating lease rental payments due in 2015	115,708,000									16,676,000			1,000,000
Operating lease rental payments due in 2016	34,525,000									11,800,000			1,000,000
Total payments for crude oil storage capacity													918,000	3,202,000	2,743,000
Processing and transportation charges										24,791,000	10,337,000	11,860,000
Rental expenses for noncancellable lease, including contingent payments	185,016,000	178,410,000	124,693,000
Future commitments									515,292,000							5,000,000
Discounted liability, unconditional commitment																			38,700,000
Accretion costs																1,317,000	1,534,000	1,739,000
Commitments for capital expenditures	$ 1,849,100,000			$ 839,500,000	$ 149,700,000	$ 124,500,000	$ 127,500,000

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Reconciliation of Beginning and Ending Amount of Consolidated Liability for Unrecognized Income Tax Benefits (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Income Tax Contingency [Line Items]
Beginning balance	$ 23,196	$ 25,978
Additions for tax positions related to current year	1,294	1,225
Settlements due to lapse of time	(5,633)	(4,007)
Ending balance	$ 18,857	$ 23,196

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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 (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ (216,276)
Prior service (cost) credit	(5,262)
Transitional asset (liability)	1,609
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax, Total	(219,929)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	(35,336)
Prior service (cost) credit	1,130
Transitional asset (liability)	(17)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax, Total	$ (34,223)

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Additional Information about Stock Options Outstanding (Detail) (USD $)	12 Months Ended
	Dec. 31, 2011 Year
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options Outstanding, No. of Options	5,434,228
Options Outstanding, Avg. Life in Years	4.1
Options Outstanding, Aggregate Intrinsic Value	$ 30,975,000
Options Exercisable, No. of Options	2,319,735
Options Exercisable, Avg. Life in Years	2.3
Options Exercisable, Aggregate Intrinsic Value	22,244,000
Range of Exercise Prices per Option $19.43 to $23.58
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options Outstanding, No. of Options	393,750
Options Outstanding, Avg. Life in Years	1.0
Options Outstanding, Aggregate Intrinsic Value	13,571,000
Options Exercisable, No. of Options	393,750
Options Exercisable, Avg. Life in Years	1.0
Options Exercisable, Aggregate Intrinsic Value	13,571,000
Range of Exercise Prices per Option $19.43 to $23.58 | Minimum
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices	$ 19.43
Range of Exercise Prices per Option $19.43 to $23.58 | Maximum
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices	$ 23.58
Range of Exercise Prices per Option $30.30 to $45.23
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options Outstanding, No. of Options	953,610
Options Outstanding, Avg. Life in Years	3.6
Options Outstanding, Aggregate Intrinsic Value	11,466,000
Options Exercisable, No. of Options	541,235
Options Exercisable, Avg. Life in Years	3.2
Options Exercisable, Aggregate Intrinsic Value	6,604,000
Range of Exercise Prices per Option $30.30 to $45.23 | Minimum
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices	$ 30.30
Range of Exercise Prices per Option $30.30 to $45.23 | Maximum
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices	$ 45.23
Range of Exercise Prices per Option $51.07 to $57.32
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options Outstanding, No. of Options	2,067,156
Options Outstanding, Avg. Life in Years	3.9
Options Outstanding, Aggregate Intrinsic Value	5,938,000
Options Exercisable, No. of Options	730,750
Options Exercisable, Avg. Life in Years	1.7
Options Exercisable, Aggregate Intrinsic Value	2,069,000
Range of Exercise Prices per Option $51.07 to $57.32 | Minimum
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices	$ 51.07
Range of Exercise Prices per Option $51.07 to $57.32 | Maximum
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices	$ 57.32
Range of Exercise Prices per Option $67.64 to $72.75
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options Outstanding, No. of Options	2,019,712
Options Outstanding, Avg. Life in Years	5.1
Options Outstanding, Aggregate Intrinsic Value	0
Options Exercisable, No. of Options	654,000
Options Exercisable, Avg. Life in Years	3.1
Options Exercisable, Aggregate Intrinsic Value	$ 0
Range of Exercise Prices per Option $67.64 to $72.75 | Minimum
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices	$ 67.64
Range of Exercise Prices per Option $67.64 to $72.75 | Maximum
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices	$ 72.75

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Amounts Included in AOCI that are Expected to be Amortized into Net Periodic Benefit Expense (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ (16,872)
Prior service (cost) credit	(1,258)
Transitional asset (liability)	535
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Total	(17,595)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	(1,846)
Prior service (cost) credit	173
Transitional asset (liability)	(8)
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year, Total	$ (1,681)

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Incentive Plans - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2011 USD ($) Year	Dec. 31, 2010 USD ($)		Dec. 31, 2009 USD ($)		Dec. 31, 2011 Maximum	Dec. 31, 2011 Annual Incentive Plan, 2007 Annual Plan	Dec. 31, 2007 Annual Incentive Plan, 2007 Annual Plan	Dec. 31, 2011 Directors Plan	Dec. 31, 2011 Stock Options	Dec. 31, 2011 Performance-Based Restricted Stock	Dec. 31, 2011 Performance-Based Restricted Stock Maximum USD ($)	Dec. 31, 2010 Performance-Based Restricted Stock Maximum USD ($)	Dec. 31, 2009 Performance-Based Restricted Stock Maximum USD ($)	Dec. 31, 2011 Performance-Based Restricted Stock Minimum USD ($)	Dec. 31, 2010 Performance-Based Restricted Stock Minimum USD ($)	Dec. 31, 2009 Performance-Based Restricted Stock Minimum USD ($)	Dec. 31, 2011 Time-Lapse Restricted Stock and Restricted Stock Units USD ($)	Dec. 31, 2010 Time-Lapse Restricted Stock and Restricted Stock Units USD ($)	Dec. 31, 2009 Time-Lapse Restricted Stock and Restricted Stock Units USD ($)	Dec. 31, 2011 Performance Based Units USD ($)	Dec. 31, 2011 Employee Stock Purchase Plan USD ($)	Dec. 31, 2010 Employee Stock Purchase Plan USD ($)	Dec. 31, 2009 Employee Stock Purchase Plan USD ($)	Dec. 31, 2011 Savings Related Share Option Plan (SOP)	Dec. 31, 2011 Savings Related Share Option Plan (SOP) Maximum GBP (£)	Dec. 31, 2011 Savings Related Share Option Plan (SOP) Minimum GBP (£)	Dec. 31, 2011 Savings Related Share Option Plan (SOP) SOP plans with holding periods ending in December 2009 USD ($)	Dec. 31, 2011 Savings Related Share Option Plan (SOP) SOP plans with holding periods ending in August 2010 USD ($)	Dec. 31, 2011 Savings Related Share Option Plan (SOP) SOP plans with holding periods ending in April 2011 USD ($)	Dec. 31, 2011 Savings Related Share Option Plan (SOP) SOP plans with holding periods ending in May 2012 USD ($)
Compensation Related Costs Share Based Payments Disclosure [Line Items]
Salary that can be withhold 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 purchase plan, authorized shares							5,745,000	6,700,000														980,000
Employee stock purchases, shares																						34,612	44,361	51,271
Maximum number of shares available for issuance, annual rate								1.00%
Employee stock purchases, per share																						$ 56.08	$ 51.97	$ 44.73
Number of shares remained available																						321,322
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 are estimated based on the value of the 10% discount and the fair value of the option that allows the employee to receive a repayment of withholdings plus credited interest.
Compensation costs related to the ESPP																						$ 328,000	$ 357,000	$ 623,000
Fair value per share issued under ESPP																						$ 8.60	$ 7.51	$ 11.47
Unvested share-based compensation arrangements, compensation costs to be expensed	55,100,000
Unvested share-based compensation arrangements, number of years compensation costs to be expensed	2
Proceeds from exercise of stock options and employee stock purchase plans	15,551,000	42,995,000	[1]	12,746,000	[1]
Income tax benefits realized for the tax deductions from option exercises	8,775,000	15,896,000		6,035,000
Option granted to date, term of years						7 years	7 years
Employee stock purchase plan, vesting scheme							Under the 2007 Long-Term Plan, one-half of each grant is exercisable after two years and the remainder after three years.		Under the Directors 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	28,145,000	49,929,000		17,932,000
Compensation expense for incentive plans	33,035,000	25,171,000		23,073,000
Granted restricted stock, valuation												$ 64.89	$ 50.95	$ 44.94	$ 38.94	$ 42.38	$ 41.18	$ 52.66	$ 52.49	$ 43.95
Percentage of targeted amounts paid in cash and awards based on achivement, minimum																					0.00%
Percentage of targeted amounts paid in cash and awards based on achivement, maximum																					200.00%
Total expense related to performance award																					871,000
Monthly salary that can be withhold by eligible employee for stock purchase																										£ 250	£ 5
Fair value per share of SOP plans																												$ 19.57	$ 19.90	$ 23.77	$ 22.85

[1] Reclassified to conform to current presentation.

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Reconciliation of Beginning and Ending Aggregate Carrying Amount of Asset Retirement Obligation (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Reconciliation of Changes in Asset Retirement Obligations [Line Items]
Balance at beginning of year	$ 555,248		$ 476,938
Accretion expense	37,701		31,857	[1]	26,154	[1]
Liabilities incurred	51,858		59,605
Revision of previous estimates	7,608		14,170
Liabilities settled	(32,088)	[2]	(36,506)
Changes due to translation of foreign currencies	(4,782)		9,184
Balance at end of year	$ 615,545		$ 555,248		$ 476,938

[1] Reclassified to conform to current presentation.

[2] Includes noncash settlements related to sale of assets in Spain in 2011.

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Hurricane and Insurance Related Matters

12 Months Ended

Dec. 31, 2011

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 Company’s North American refining and marketing operations recorded a benefit of $15,398,000 for business interruption insurance received relating to a fire that occurred at the Meraux, Louisiana refinery in June 2003.

The Company also maintains certain insurance covering property damage, sudden and accidental environmental events and other hazards. In 2009, the Company’s 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 insurer’s 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 Company’s final cash settlement from the insurer led to pretax income of $12,718,000 in 2009. This benefit arose because the ultimate cash settlements received from the insurer exceeded amounts originally estimated by the insurer.

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 2009 with $4,500,000 related to the insurance claim and $2,000,000 of associated interest income. During 2010, the Company received $3,000,000 to settle its claim against one insurer for legal and other professional costs associated with the insurance coverage negotiation process. These insurance settlements in 2009 and 2010 have been included in Income From Discontinued Operations in the respective year’s Consolidated Statement of Income.

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Other Financial Information (Tables)

12 Months Ended

Dec. 31, 2011

Components of Accumulated Other Comprehensive Income

ACCUMULATED OTHER COMPREHENSIVE INCOME – At December 31, 2011 and 2010, the components of Accumulated Other Comprehensive Income were as follows.

(Thousands of dollars)	2011			2010
Foreign currency translation gains	$	496,161			587,408
Retirement and postretirement plan adjustments, net of tax		(168,889	)		(137,980	)
Loss deferred on interest rate hedges, net of tax		(16,852	)		0
Balance at end of year	$	310,420			449,428

Noncash Operating Working Capital (Increased) Decreased

Noncash operating working capital (increased) decreased during each of the three years ended December 31, 2011 as follows.

(Thousands of dollars)	2011			2010			2009
Accounts receivable	$	(43,630	)		(4,363	)		(402,481	)
Inventories		(59,413	)		(28,231	)		(114,569	)
Prepaid expenses		20,548			14,567			7,209
Deferred income tax assets		8,488			(80,073	)		14,772
Accounts payable and accrued liabilities		(478,029	)		766,067			365,257
Current income tax liabilities		(273,118	)		(28,401	)		(64,878	)
Net (increase) decrease in noncash operating working capital	$	(825,154	)		639,566			(194,690	)

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2011

Property, Plant and Equipment

	December 31, 2011					December 31, 2010
(Thousands of dollars)	Cost		Net			Cost		Net
Exploration and production1	$	14,766,637		8,730,124	2		12,506,579		7,898,417	2
Refining and marketing		2,456,822		1,688,709			3,794,223		2,409,410
Corporate and other		113,184		56,316			108,041		60,020
	$	17,336,643		10,475,149			16,408,843		10,367,847
1         Includes mineral rights as follows:	$	1,078,770		619,950			779,036		432,051

²  Includes $21,154 in 2011 and $17,067 in 2010 related to administrative assets and support equipment.

Net Changes in Capitalized Exploratory Well Costs

and $369,862,000, respectively. The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 2011.

(Thousands of dollars)	2011			2010			2009
Beginning balance at January 1	$	497,765			369,862			310,118
Additions to capitalized exploratory well costs pending the determination of proved reserves		86,035			137,403			119,995
Reclassifications to proved properties based on the determination of proved reserves		0			0			(60,251	)
Capitalized exploratory well costs charged to expense or sold		(27,388	)		(9,500	)		0
Ending balance at December 31	$	556,412			497,765			369,862

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.

	2011						2010						2009
(Thousands of dollars)	Amount		No. of Wells		No. of Projects		Amount		No. of Wells		No. of Projects		Amount		No. of Wells		No. of Projects
Aging of capitalized well costs:
Zero to one year	$	69,757		11		5		135,494		15		4	$	117,618		10		6
One to two years		143,611		15		3		115,418		10		4		49,628		4		4
Two to three years		101,696		9		2		42,571		3		3		8,870		5		0
Three years or more		241,348		33		6		204,282		31		4		193,746		27		4
	$	556,412		68		16		497,765		59		15	$	369,862		46		14

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Analysis of Deferred Tax Assets and Deferred Tax Liabilities Showing Tax Effects of Significant Temporary Differences (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Deferred tax assets
Property and leasehold costs	$ 627,093	$ 391,168
Liabilities for dismantlements	114,175	97,149
Postretirement and other employee benefits	164,044	137,709
Foreign tax credit carryforwards	21,368	47,725
Other deferred tax assets	38,341	47,511
Total gross deferred tax assets	965,021	721,262
Less valuation allowance	(445,842)	(305,349)
Net deferred tax assets	519,179	415,913
Deferred tax liabilities
Property, plant and equipment	(851,330)	(729,699)
Accumulated depreciation, depletion and amortization	(754,295)	(702,512)
Deferred major repair costs	(11,257)	(35,848)
Other deferred tax liabilities	(67,494)	(96,838)
Total gross deferred tax liabilities	(1,684,376)	(1,564,897)
Net deferred tax liabilities	$ (1,165,197)	$ (1,148,984)

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Financial Instruments and Risk Management - Additional Information (Detail) (USD $)								12 Months Ended
	Dec. 31, 2011 Bushel	Dec. 31, 2010 Bushel	Dec. 31, 2011 Derivative Outstanding Bushel	Dec. 31, 2011 Foreign Exchange Derivative Contracts Currency, U.S. Dollar	Dec. 31, 2010 Foreign Exchange Derivative Contracts Currency, U.S. Dollar	Dec. 31, 2011 Foreign Exchange Derivative Contracts Currency, Malaysian ringgit	Dec. 31, 2010 Foreign Exchange Derivative Contracts Currency, Malaysian ringgit	Dec. 31, 2010 Crude Oil Commodity Derivative Contracts bbl	Dec. 31, 2011 Nondesignated Commodity Derivative Contracts Accounts Receivable	Dec. 31, 2010 Nondesignated Commodity Derivative Contracts Accounts Receivable	Dec. 31, 2011 Nondesignated Commodity Derivative Contracts Other Liabilities	Dec. 31, 2011 Nondesignated Commodity Derivative Contracts Accounts Payable	Dec. 31, 2010 Nondesignated Commodity Derivative Contracts Accounts Payable	Dec. 31, 2010 Nondesignated Foreign Exchange Derivative Contracts Accounts Receivable	Dec. 31, 2011 Nondesignated Foreign Exchange Derivative Contracts Accounts Payable
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Fixed-price purchase commitment contracts of bushels of corn	8,000,000	7,000,000
Open physical delivery fixed-price purchase commitment contracts	1,100,000		2,900,000
Asset Derivatives									$ 197,000	$ 750,000				$ 7,261,000
Liability Derivatives											292,000,000,000	489,000	626,000		8,459,000
Short-term derivative instruments								118,000
Increase (decrease) in income before taxes due to the impact of marking to market of derivative contracts								335,000
Short-term derivative instruments				16,000,000	38,000,000	472,000,000	366,000,000
Future maturities of long term debt in 2012	$ 350,005,000

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SUPPLEMENTAL QUARTERLY INFORMATION (UNAUDITED)

12 Months Ended

Dec. 31, 2011

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 December 31, 2011
Sales and other operating revenues	$	6,271.7		7,415.9		7,240.4		6,761.3			27,689.3
Income from continuing operations before income taxes		411.4		505.2		534.4		100.0			1,551.0
Income (loss) from continuing operations		238.5		280.0		335.7		(113.3	)		740.9
Net income (loss)		268.9		311.6		406.1		(113.9	)		872.7
Income (loss) from continuing operations per Common share
Basic		1.23		1.45		1.74		(0.59	)		3.83
Diluted		1.22		1.44		1.73		(0.59	)		3.81
Net income (loss) per Common share
Basic		1.39		1.61		2.10		(0.59	)		4.51
Diluted		1.38		1.60		2.09		(0.59	)		4.49
Cash dividend per Common share		0.275		0.275		0.275		0.275			1.10
Market price of Common Stock*
High		76.11		77.48		69.71		58.67			77.48
Low		65.74		62.53		44.05		42.10			42.10
Year Ended December 31, 2010
Sales and other operating revenues	$	4,699.3		4,754.9		5,209.0		5,562.6			20,225.8
Income from continuing operations before income taxes		316.2		433.6		352.7		286.2			1,388.7
Income from continuing operations		169.5		263.2		197.4		149.5			779.6
Net income		148.9		272.3		202.8		174.1			798.1
Income from continuing operations per Common share
Basic		0.89		1.37		1.03		0.77			4.06
Diluted		0.88		1.36		1.02		0.77			4.03
Net income per Common share
Basic		0.78		1.42		1.06		0.90			4.16
Diluted		0.77		1.41		1.05		0.90			4.13
Cash dividend per Common share		0.25		0.25		0.275		0.275			1.05
Market price of Common Stock*
High		59.71		61.82		61.92		75.37			75.37
Low		50.13		49.55		48.44		61.01			48.44

* Prices are as quoted on the New York Stock Exchange.

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Common Stock Issued and Outstanding (Tables)

12 Months Ended

Dec. 31, 2011

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, 2011 is shown below.

(Number of shares outstanding)	2011		2010		2009
At beginning of year		192,836,008		191,115,378		190,713,806
Stock options exercised		615,674		1,495,926		548,659
Employee stock purchase and thrift plans		33,390		49,657		61,575
Restricted stock awards, net of forfeitures		238,136		175,047		(208,662	)
At end of year		193,723,208		192,836,008		191,115,378

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Financing Arrangements - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2011
Line of Credit Facility [Line Items]
Credit facility maximum borrowing capacity	$ 1,500,000,000
Credit facility, maturity date	2016-06-30
Uncommitted Credit Facility
Line of Credit Facility [Line Items]
Credit facility maximum borrowing capacity	$ 400,000,000

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Terra Nova Working Interest Redetermination - Additional Information (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Commitments and Contingencies Disclosure [Line Items]
Redetermination of Terra Nova working interest	$ (5,351)	[1]	$ 18,582	[1],[2]	$ 83,498	[1],[2]
Joint Operating Agreement
Commitments and Contingencies Disclosure [Line Items]
Joint agreement ownership interest	12.00%
End of Period
Commitments and Contingencies Disclosure [Line Items]
Joint agreement ownership interest	10.475%

[1] Results exclude corporate overhead, interest and discontinued operations.

[2] Reclassified to conform to current presentation.

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Purchase Price Allocation for Hankinson Facility Based on Estimated Fair Value of Assets Acquired (Detail) (Ethanol Plant in Hankinson, North Dakota, USD $)	Dec. 31, 2009
Business Acquisition [Line Items]
Inventory	$ 2,469,000
Total purchase price	92,000,000
Land and Land Improvements
Business Acquisition [Line Items]
Business acquisition, purchase price allocation	11,833,000
Buildings and Improvements
Business Acquisition [Line Items]
Business acquisition, purchase price allocation	9,819,000
Machinery and Transportation Equipment
Business Acquisition [Line Items]
Business acquisition, purchase price allocation	$ 67,879,000

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Employee and Retiree Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2011

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

At December 31, 2011, 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 Benefits			Other Postretirement Benefits
Net actuarial loss	$	(216,276	)		(35,336	)
Prior service (cost) credit		(5,262	)		1,130
Transitional asset (liability)		1,609			(17	)
	$	(219,929	)		(34,223	)

Amounts Included in AOCI that are Expected to be Amortized into Net Periodic Benefit Expense

Amounts included in AOCI at December 31, 2011 that are expected to be amortized into net periodic benefit expense during 2012 are shown in the following table.

(Thousands of dollars)	Pension Benefits			Other Postretirement Benefits
Net actuarial loss	$	(16,872	)		(1,846	)
Prior service (cost) credit		(1,258	)		173
Transitional asset (liability)		535			(8	)
	$	(17,595	)		(1,681	)

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.

< /TR>

	Projected Benefit Obligations				Accumulated Benefit Obligations				Fair Value of Plan Assets
(Thousands of dollars)	2011		2010		2011		2010		2011		2010
Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets	$	513,444		478,234		459,556		431,668		374,360		383,683
Unfunded nonqualified and directors’ plans where accumulated benefit obligation exceeds fair value of plan assets		96,754		78,667		82,642		69,104		0		0
Unfunded other postretirement plans		114,962		122,879		114,962		122,879		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, 2011.

	Pension Benefits									Other Postretirement Benefits
(Thousands of dollars)	2011			2010			2009			2011			2010			2009
Service cost	$	22,406			20,706			17,052			4,547			4,133			3,121
Interest cost		30,785			30,144			28,767			6,141			6,211			5,688
Expected return on plan assets		(25,919	)		(24,199	)		(20,375	)		0			0			0
Amortization of prior service cost		1,314			1,558			1,635			(240	)		(263	)		(263	)
Amortization of transitional asset (liability)		(536	)		(514	)		(466	)		8			8			0
Recognized actuarial loss		12,484			12,257			10,305			2,329			2,790			1,551
		40,534			39,952			36,918			12,785			12,879			10,097
Termination benefits expense		695			0			1,867			0			0			0
Curtailment expense		1,036			0			575			(605	)		0			397
Net periodic benefit expense	$	42,265			39,952			39,360			12,180			12,879			10,494

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, 2011 and 2010 and net periodic benefit expense for 2011 and 2010.

	Benefit Obligations												Net Periodic Benefit Expense
	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
	December 31						December 31						Year						Year
	2011			2010			2011			2010			2011			2010			2011			2010
Discount rate		5.00	%		5.66	%		4.87	%		5.66	%		5.50	%		5.88	%		5.50	%		5.90	%
Expected return on plan assets		6.48	%		6.56	%		0	%		0	%		6.48	%		6.56	%		0	%		0	%
Rate of compensation increase		4.22	%		4.19	%		0	%		0	%		4.22	%		4.19	%		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 Benefits		Other Postretirement Benefits
2012	$	28,688		5,835
2013		29,911		6,072
2014		31,237		6,262
2015		32,001		6,449
2016		32,738		6,747
2017-2021		185,062		38,516

1% Change in Assumed Health Care Cost Trend Rates

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, 2011	$	2,033		(1,594	)
Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2011		17,041		(13,810	)

Domestic Plans

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, 2011 and 2010 and a statement of the funded status as of December 31, 2011 and 2010.

	Pension Benefits						Other Postretirement Benefits
(Thousands of dollars)	2011			2010			2011			2010
Change in benefit obligation
Obligation at January 1	$	575,300			521,471			122,879			101,750
Service cost		22,406			20,706			4,547			4,133
Interest cost		30,785			30,144			6,141			6,211
Plan amendments		483			0			0			0
Participant contributions		35			33			1,049			956
Actuarial loss		66,010			30,544			4,791			14,646
Medicare Part D subsidy		0			0			555			528
Exchange rate changes		(2,109	)		(1,357	)		(11	)		22
Benefits paid		(27,745	)		(26,241	)		(5,667	)		(5,367	)
Reduction due to sale of the Superior refinery		(23,021	)		0			0			0
Special termination benefits		695			0			0			0
Curtailments		(13,271	)		0			(19,322	)		0
Obligation at December 31		629,568			575,300			114,962			122,879
Change in plan assets
Fair value of plan assets at January 1		416,272			375,947			0			0
Actual return on plan assets		(1,415	)		46,792			0			0
Employer contributions		38,357			20,651			4,063			3,883
Participant contributions		35			33			1,049			956
Medicare Part D subsidy		0			0			555			528
Exchange rate changes		(1,786	)		(422	)		0			0
Benefits paid		(27,745	)		(26,241	)		(5,667	)		(5,367	)
Distribution to acquirer of the Superior refinery		(18,720	)		0			0			0
Other		(648	)		(488	)		0			0
Fair value of plan assets at December 31		404,350			416,272			0			0
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets		10,621			14,191			0			0
Other accrued liabilities		(3,488	)		(3,378	)		(5,022	)		(5,223	)
Deferred credits and other liabilities		(232,351	)		(169,841	)		(109,940	)		(117,656	)
Funded status and net plan liability recognized at December 31		$(225,218)			(159,028	)		(114,962	)		(122,879	)

Foreign Plans

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 Benefits				Other Postretirement Benefits
(Thousands of dollars)	2011		2010		2011		2010
Benefit obligation at December 31	$	153,947		133,751		454		430
Fair value of plan assets at December 31		135,608		126,075		0		0
Net plan liabilities recognized		18,339		7,676		454		430
Net periodic benefit expense		8,978		9,784		82		60

Funded Defined Benefit Pension Plans

Asset Allocation for Benefit Plans

The weighted average asset allocation for the Company’s funded pension benefit plans at December 31, 2011 and 2010 are presented in the following table.

	December 31,
	2011			2010.
Equity securities		62.3	%		62.7	%
Fixed income securities		36.5			36.2
Cash equivalents		1.2			1.1
		100.0	%		100.0	%

Other Postretirement Benefits

Asset Allocation for Benefit Plans

At December 31, 2011 and 2010, the fair value measurements of retirement plan assets within the fair value hierarchy were as follows:

			Fair Value Measurements Using
(Thousands of dollars)	Fair Value at December 31, 2011		Quoted Prices in Active  Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Domestic Plans
Equity securities:
U.S. core equity	$	73,986		73,986		0		0
U.S. small/midcap		18,236		18,236		0		0
U.S. long/short equity fund		13,860		0		13,860		0
International commingled trust fund		56,156		0		56,156		0
Emerging market commingled equity fund		6,980		0		6,980		0
Fixed income securities:
U.S. fixed income		76,764		0		76,764		0
International commingled trust fund		13,109		0		13,109		0
Emerging market mutual fund		6,448		0		6,448		0
Cash and equivalents		3,203		3,203		0		0
Total Domestic Plans		268,742		95,425		173,317		0
Foreign Plans
Equity securities funds		59,349		0		59,349		0
Fixed income securities funds		44,442		0		44,442		0
Diversified pooled fund		29,990		0		29,990		0
Cash and equivalents		1,827		1,827		0		0
Total Foreign Plans		135,608		1,827		133,781		0
Total	$	404,350		97,252		307,098		0

			Fair Value Measurements Using
(Thousands of dollars)	Fair Value at December  31, 2010		Quoted Prices in Active  Markets for Identical Assets (Level 1)		Significant Other  Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Domestic Plans
Equity securities:
U.S. core equity	$	79,550		79,550		0		0
U.S. small/midcap		17,324		17,324		0		0
U.S. long/short equity fund		14,205		0		14,205		0
International commingled trust fund		61,531		0		61,531		0
Emerging market commingled equity fund		7,131		0		7,131		0
Fixed income securities:
U.S. fixed income		81,989		0		81,989		0
International commingled trust fund		19,833		0		19,833		0
Emerging market mutual fund		7,045		0		7,045		0
Cash and equivalents		1,589		1,589		0		0
Total Domestic Plans		290,197		98,463		191,734		0
Foreign Plans
Equity securities funds		58,353		0		58,353		0
Fixed income securities funds		31,948		0		31,948		0
Diversified pooled fund		32,590		0		32,590		0
Cash and equivalents		3,184		3,184		0		0
Total Foreign Plans		126,075		3,184		122,891		0
Total	$	416,272		101,647		314,625		0

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2011 Retained Earnings	Dec. 31, 2010 Retained Earnings	Dec. 31, 2009 Retained Earnings	Dec. 31, 2011 Treasury Stock	Dec. 31, 2010 Treasury Stock	Dec. 31, 2009 Treasury Stock
Cash dividends, per share	$ 1.10	$ 1.05	$ 1.00
Balance at end of year, shares of Common Stock				185,992	457,518	682,222

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Geographic Information on Revenues from External Customers (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues from External Customers	$ 27,745.5	$ 20,169.7	$ 16,895.2
United States
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues from External Customers	18,184.0	14,386.6	11,855.9
Canada
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues from External Customers	1,180.3	809.3	652.5
Malaysia
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues from External Customers	2,063.0	1,793.8	1,526.4
United Kingdom
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues from External Customers	6,144.8	3,018.7	2,838.7
Republic of the Congo
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues from External Customers	148.8	156.5	16.5
Other
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues from External Customers	$ 24.6	$ 4.8	$ 5.2

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Property, Plant and Equipment (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011		Dec. 31, 2010
Property, Plant and Equipment [Line Items]
Property, plant and equipment, Net	$ 10,475,149		$ 10,367,847
Property, plant and equipment, Cost	17,336,643		16,408,843
Exploration and Production Equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment, Net	8,730,124	[1],[2]	7,898,417	[1],[2]
Property, plant and equipment, Cost	14,766,637	[1]	12,506,579	[1]
Refining and Marketing
Property, Plant and Equipment [Line Items]
Property, plant and equipment, Net	1,688,709		2,409,410
Property, plant and equipment, Cost	2,456,822		3,794,223
Corporate and Other
Property, Plant and Equipment [Line Items]
Property, plant and equipment, Net	56,316		60,020
Property, plant and equipment, Cost	$ 113,184		$ 108,041

[1] Includes mineral rights as follows: $ 1,078,770 619,950 779,036 432,051

[2] Includes $21,154 in 2011 and $17,067 in 2010 related to administrative assets and support equipment.

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Supplemental Quarterly Information (Detail) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended																12 Months Ended
	Dec. 31, 2011		Sep. 30, 2011		Jun. 30, 2011		Mar. 31, 2011		Dec. 31, 2010		Sep. 30, 2010		Jun. 30, 2010		Mar. 31, 2010		Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Quarterly Financial Information [Line Items]
Sales and other operating revenues	$ 6,761,300		$ 7,240,400		$ 7,415,900		$ 6,271,700		$ 5,562,600		$ 5,209,000		$ 4,754,900		$ 4,699,300		$ 27,689,332		$ 20,225,764	[1]	$ 16,800,972	[1]
Income from continuing operations before income taxes	100,000		534,400		505,200		411,400		286,200		352,700		433,600		316,200		1,550,983		1,388,710	[1]	1,235,413	[1]
Income (loss) from continuing operations	(113,300)		335,700		280,000		238,500		149,500		197,400		263,200		169,500		740,932		779,559	[1]	713,854	[1]
Net income	$ (113,900)		$ 406,100		$ 311,600		$ 268,900		$ 174,100		$ 202,800		$ 272,300		$ 148,900		$ 872,702		$ 798,081	[1]	$ 837,621	[1]
Income (loss) from continuing operations per Common share
Basic	$ (0.59)		$ 1.74		$ 1.45		$ 1.23		$ 0.77		$ 1.03		$ 1.37		$ 0.89		$ 3.83		$ 4.06	[1]	$ 3.74	[1]
Diluted	$ (0.59)		$ 1.73		$ 1.44		$ 1.22		$ 0.77		$ 1.02		$ 1.36		$ 0.88		$ 3.81		$ 4.03	[1]	$ 3.71	[1]
Net income (loss) per Common share
Basic	$ (0.59)		$ 2.10		$ 1.61		$ 1.39		$ 0.90		$ 1.06		$ 1.42		$ 0.78		$ 4.51		$ 4.16	[1]	$ 4.39	[1]
Diluted	$ (0.59)		$ 2.09		$ 1.60		$ 1.38		$ 0.90		$ 1.05		$ 1.41		$ 0.77		$ 4.49		$ 4.13	[1]	$ 4.35	[1]
Cash dividend per Common share	$ 0.275		$ 0.275		$ 0.275		$ 0.275		$ 0.275		$ 0.275		$ 0.250		$ 0.250		$ 1.100		$ 1.050
Market price of Common Stock
High	$ 58.67	[2]	$ 69.71	[2]	$ 77.48	[2]	$ 76.11	[2]	$ 75.37	[2]	$ 61.92	[2]	$ 61.82	[2]	$ 59.71	[2]	$ 77.48	[2]	$ 75.37	[2]
Low	$ 42.10	[2]	$ 44.05	[2]	$ 62.53	[2]	$ 65.74	[2]	$ 61.01	[2]	$ 48.44	[2]	$ 49.55	[2]	$ 50.13	[2]	$ 42.10	[2]	$ 48.44	[2]

[1] Reclassified to conform to current presentation.

[2] Prices are as quoted on the New York Stock Exchange.

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Long-term Debt (Tables)

12 Months Ended

Dec. 31, 2011

Long-term Debt

	December 31
(Thousands of dollars)	2011			2010
Notes payable
6.375% notes, due 2012, net of unamortized discount of $38 at December 31, 2011	$	349,962			349,846
7.05% notes, due 2029, net of unamortized discount of $1,616 at December 31, 2011		248,384			248,291
Notes payable to banks, 0.7375% at December 31, 2010		0			340,000
Other, 6%, due through 2028		1,212			1,254
Total debt including current maturities		599,558			939,391
Current maturities		(350,005	)		(41	)
Total long-term debt	$	249,553			939,350

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Common Stock Issued and Outstanding

12 Months Ended

Dec. 31, 2011

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, 2011 is shown below.

(Number of shares outstanding)	2011		2010		2009
At beginning of year		192,836,008		191,115,378		190,713,806
Stock options exercised		615,674		1,495,926		548,659
Employee stock purchase and thrift plans		33,390		49,657		61,575
Restricted stock awards, net of forfeitures		238,136		175,047		(208,662	)
At end of year		193,723,208		192,836,008		191,115,378

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Terra Nova Working Interest Redetermination

12 Months Ended

Dec. 31, 2011

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. The Company recorded expense of $18,582,000 in 2010 and $83,498,000 in 2009 based on the anticipated 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 estimated. The 2009 and 2010 expense and the 2011 benefit have been reflected as Redetermination of Terra Nova Working Interest in the Consolidated Statements of Income.

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Fair Value of Interest Rate Derivative Contracts Designated as Hedging Instruments (Detail) (Designated as Hedging Instrument, Interest Rate Swap Contract, Accounts Payable, USD $) In Thousands, unless otherwise specified	Dec. 31, 2011
Designated as Hedging Instrument | Interest Rate Swap Contract | Accounts Payable
Derivatives, Fair Value [Line Items]
Liability Derivatives	$ 25,927

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Assets and Liabilities Related to Superior and Meraux Refineries and Associated Marketing Assets (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Sep. 30, 2010 Superior and Meraux Refineries
Current assets:
Accounts receivable	$ 1,554,184	$ 1,467,311	$ 1,191
Liquid inventories			115,014
Materials and supplies inventories			39,853
Total current assets	3,447,671	3,550,693	156,058
Noncurrent assets:
Property, plant and equipment, net of accumulated depreciation, depletion and amortization	10,475,149	10,367,847	723,980
Other	173,455	271,853	48,604
Total noncurrent assets - U.S. refineries			772,584
Total assets	14,138,138	14,233,243	928,642
Liabilities:
Current liabilities	2,824,928	2,930,910	2,637
Other noncurrent liabilities	439,604	395,972	14,133
Liabilities associated with assets sold - U.S. refineries			$ 16,770

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2011

Reconciliation of Beginning and Ending Aggregate Carrying Amount of Asset Retirement Obligation

reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligation for 2011 and 2010 is shown in the following table.

(Thousands of dollars)	2011			2010
Balance at beginning of year	$	555,248			476,938
Accretion expense		37,701			31,857
Liabilities incurred		51,858			59,605
Revision of previous estimates		7,608			14,170
Liabilities settled		(32,088	)*		(36,506	)
Changes due to translation of foreign currencies		(4,782	)		9,184
Balance at end of year	$	615,545			555,248

* Includes noncash settlements related to sale of assets in Spain in 2011.

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Business Segments

12 Months Ended

Dec. 31, 2011

Business Segments

Note U – Business Segments

Murphy’s reportable segments are organized into two major types of business activities, each subdivided into geographic areas of operations. The Company’s 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 Company’s refining and marketing segments are disclosed geographically for the United States and the United Kingdom and each derives revenue mainly from the sale of petroleum products and merchandise. The United States business also derives revenue from production and sale of ethanol and corn by-products. The Company sells gasoline in the United States at retail stations built primarily at Walmart Supercenters. 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. Discontinued operations primarily include the activities of two U.S. refineries and associated marketing assets sold in 2011. These operations formerly comprised most of the United States Manufacturing segment that was previously reported before the refinery sales. With the sale of the two U.S. refineries in 2011, all continuing operations for U.S. downstream have been reported in the current United States Refining and Marketing segment. Results for the two U.S. refineries for 2010 and 2009 have been reclassified as discontinued operations. Discontinued operations in 2009 also included income of $97,104,000 from the formerly held Ecuador exploration and production operations.

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 the following page, Certain Long-Lived Assets at December 31 exclude investments, noncurrent receivables, deferred tax assets and goodwill and other intangible assets.

Excise taxes on petroleum products of $3,566,876,000, $3,375,509,000 and $3,595,238,000 for the years 2011, 2010 and 2009, respectively, that were collected by the Company and remitted to various government entities by continuing operations were excluded from revenues and costs and expenses.

Segment Information

	Exploration and Production
(Millions of dollars)	United States			Canada			Malaysia		United Kingdom			Republic of the Congo			Other			Total
Year ended December 31, 2011
Segment income (loss)	$	152.7			328.0			812.7		11.5			(385.3	)		(293.9	)		625.7
Revenues from external customers		737.7			1,145.8			2,045.6		107.3			148.8			24.6			4,209.8
Intersegment revenues		0.0			142.8			0.0		0.0			0.0			0.0			142.8
Interest income		0.0			0.0			0.0		0.0			0.0			0.0			0.0
Interest expense, net of capitalization		0.0			0.0			0.0		0.0			0.0			0.0			0.0
Income tax expense (benefit)		86.5			135.5			434.9		46.8			16.4			7.5			727.6
Significant noncash charges (credits)
Depreciation, depletion, amortization		183.0			326.0			357.3		13.7			87.8			1.9			969.7
Accretion of asset retirement obligations		9.9			12.5			10.6		3.0			0.5			0.3			36.8
Amortization of undeveloped leases		62.2			28.8			0.0		0.0			0.0			27.2			118.2
Impairment of long-lived assets		0.0			0.0			0.0		0.0			368.6			0.0			368.6
Deferred and noncurrent income taxes		54.2			39.6			84.6		14.6			(0.9	)		(0.1	)		192.0
Additions to property, plant, equipment		696.6			885.2			694.8		19.7			79.6			20.6			2,396.5
Total assets at year-end		2,227.6			3,746.8			3,826.9		214.1			257.5			74.1			10,347.0
Year ended December 31, 2010
Segment income (loss)	$	72.7			213.8			659.4		30.5			(77.2	)		(92.3	)		806.9
Revenues from external customers		659.9			780.2			1,837.9		133.6			155.7			3.9			3,571.2
Intersegment revenues		0.0			118.9			0.0		0.0			0.0			0.0			118.9
Interest income		0.0			0.0			0.0		0.0			0.0			0.0			0.0
Interest expense, net of capitalization		0.0			0.0			0.0		0.0			0.0			0.0			0.0
Income tax expense (benefit)		30.0			79.1			414.1		32.6			20.6			0.5			576.9
Significant noncash charges (credits)
Depreciation, depletion, amortization		281.1			225.5			379.0		22.4			95.5			1.5			1,005.0
Accretion of asset retirement obligations		6.9			11.2			9.8		2.3			0.4			0.5			31.1
Amortization of undeveloped leases		68.5			33.7			0.0		0.0			0.0			5.8			108.0
Deferred and noncurrent income taxes		(48.6	)		34.5			145.5		(11.4	)		(0.9	)		0.0			119.1
Additions to property, plant, equipment		369.4			804.4			467.9		(4.7	)		163.6			49.8			1,850.4
Total assets at year-end		1,651.3			3,242.6			3,333.1		187.9			678.9			88.9			9,182.7
Year ended December 31, 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		0.0			85.3			0.0		0.0			0.0			0.0			85.3
Interest income		0.0			0.0			0.0		0.0			0.0			0.0			0.0
Interest expense, net of capitalization		0.0			0.0			0.0		0.0			0.0			0.0			0.0
Income tax expense (benefit)		88.4			21.0			354.1		11.9			1.3			(0.6	)		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 asset retirement obligations		6.8			8.6			7.8		1.6			0.1			0.6			25.5
Amortization of undeveloped leases		34.7			44.1			0.0		0.0			0.0			4.4			83.2
Impairment of long-lived assets		5.2			0.0			0.0		0.0			0.0			0.0			5.2
Deferred and noncurrent income taxes		(4.6	)		(7.2	)		77.6		(0.9	)		0.0			(0.1	)		64.8
Additions to property, plant, equipment		336.8			330.1			739.0		17.2			194.9			7.6			1,625.6
Total assets at year-end		1,679.7			2,507.8			3,249.6		209.0			516.7			33.5			8,196.3

Geographic Information	Certain Long-Lived Assets at December 31
(Millions of dollars)	United States		Canada		Malaysia		United Kingdom		Republic of the Congo		Other		Total
2011	$	2,953.1		3,493.4		3,154.8		694.7		133.7		52.2		10,481.9
2010		3,178.8		3,028.8		2,807.0		706.3		579.4		74.3		10,374.6
2009		2,907.2		2,324.6		2,714.9		704.7		399.9		20.5		9,071.8

Segment Information (Continued)

	Refining and Marketing							Corporate and Other			Discontinued Operations		Consolidated
(Millions of dollars)	United States		United Kingdom			Total
Year ended December 31, 2011
Segment income (loss)	$	223.6		(33.3	)		190.3		(75.1	)		131.8		872.7
Revenues from external customers		17,471.9		6,030.3			23,502.2		33.5			0.0		27,745.5
Intersegment revenues		0.0		0.0			0.0		0.0			0.0		142.8
Interest income		0.0		0.0			0.0		10.1			0.0		10.1
Interest expense, net of capitalization		0.0		0.0			0.0		40.7			0.0		40.7
Income tax expense (benefit)		146.6		(12.1	)		134.5		(52.0	)		0.0		810.1
Significant noncash charges (credits)
Depreciation, depletion, amortization		68.3		46.7			115.0		8.7			0.0		1,093.4
Accretion of asset retirement obligations		0.9		0.0			0.9		0.0			0.0		37.7
Amortization of undeveloped leases		0.0		0.0			0.0		0.0			0.0		118.2
Impairment of long-lived assets		0.0		0.0			0.0		0.0			0.0		368.6
Deferred and noncurrent income taxes		28.5		(5.3	)		23.2		(43.6	)		0.0		171.6
Additions to property, plant, equipment		100.1		22.2			122.3		5.3			48.1		2,572.2
Total assets at year-end		1,806.5		1,193.8			3,000.3		790.8			0.0		14,138.1
Year ended December 31, 2010
Segment income (loss)	$	165.3		(34.7	)		130.6		(157.9	)		18.5		798.1
Revenues from external customers		13,750.4		2,905.0			16,655.4		(56.9	)		0.0		20,169.7
Intersegment revenues		0.0		0.0			0.0		0.0			0.0		118.9
Interest income		0.0		0.0			0.0		6.9			0.0		6.9
Interest expense, net of capitalization		0.0		0.0			0.0		34.7			0.0		34.7
Income tax expense (benefit)		101.8		(22.3	)		79.5		(47.2	)		0.0		609.2
Significant noncash charges (credits)
Depreciation, depletion, amortization		60.1		41.4			101.5		8.0			0.0		1,114.5
Accretion of asset retirement obligations		0.8		0.0			0.8		0.0			0.0		31.9
Amortization of undeveloped leases		0.0		0.0			0.0		0.0			0.0		108.0
Deferred and noncurrent income taxes		5.1		3.2			8.3		7.8			0.0		135.2
Additions to property, plant, equipment		221.0		69.1			290.1		5.9			117.3		2,263.7
Total assets at year-end		2,996.6		1,113.6			4,110.2		940.3			0.0		14,233.2
Year ended December 31, 2009
Segment income (loss)	$	65.5		(20.5	)		45.0		(23.0	)		123.8		837.6
Revenues from external customers		11,116.4		2,725.9			13,842.3		102.2			0.0		16,895.2
Intersegment revenues		0.0		0.0			0.0		0.0			0.0		85.3
Interest income		0.0		0.0			0.0		51.7			0.0		51.7
Interest expense, net of capitalization		0.0		0.0			0.0		24.4			0.0		24.4
Income tax expense (benefit)		42.3		(1.0	)		41.3		4.2			0.0		521.6
Significant noncash charges (credits)
Depreciation, depletion, amortization		55.4		33.8			89.2		6.0			0.0		871.0
Accretion of asset retirement obligations		0.7		0.0			0.7		0.0			0.0		26.2
Amortization of undeveloped leases		0.0		0.0			0.0		0.0			0.0		83.2
Impairment of long-lived assets		0.0		0.0			0.0		0.0			0.0		5.2
Deferred and noncurrent income taxes		9.5		15.9			25.4		5.0			0.0		95.2
Additions to property, plant, equipment		161.6		101.8			263.4		23.0			113.3		2,025.3
Total assets at year-end		2,490.6		939.8			3,430.4		1,129.7			0.0		12,756.4

Geographic Information	Revenues from External Customers for the Year
(Millions of dollars)	United States		Canada		Malaysia		United Kingdom		Republic of the Congo		Other		Total
2011	$	18,184.0		1,180.3		2,063.0		6,144.8		148.8		24.6		27,745.5
2010		14,386.6		809.3		1,793.8		3,018.7		156.5		4.8		20,169.7
2009		11,855.9		652.5		1,526.4		2,838.7		16.5		5.2		16,895.2

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.

In 2008, the U.S. Securities and Exchange Commission (SEC) adopted new definitions and rules for oil and gas reserves that became effective for the Company as of December 31, 2009. In January 2010, the Financial Accounting Standards Board (FASB) issued guidance that aligned its oil and gas reserves reporting requirements with the SEC’s guidance. The SEC and FASB now define proved reserves as those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic method is used for the estimation. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well, or through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. The new rules have expanded oil and gas producing activities to include non-traditional and unconventional resources such as the Company’s 5% interest in synthetic oil operations at Syncrude in Western Canada. Therefore, net oil reserves after royalties for this synthetic oil operations have been included as a separate column in the proved oil reserves schedule beginning at December 31, 2009. The rules also now requires expanded disclosures of proved undeveloped reserves, to include discussion of such reserves held for five or more years, plus disclosures of the Company’s controls over the oil and gas reserves processes, including the qualifications of the chief technical person who oversees the Company’s reserves process. The rules also now permit companies to voluntarily disclose probable and possible reserves in SEC filings, but the Company has elected not to provide these voluntary disclosures.

Murphy has utilized reliable geologic and engineering technology in 2011 to include proved undeveloped reserves more than one location from producing wells in the more developed portions of the Eagle Ford Shale. The study incorporated public and proprietary data from multiple sources and encompassed the entire basin. This included analysis of seismic data, well log data, test production and fluids properties to establish geologic consistency as well as significant statistical performance data yielding predictable and repeatable reserve estimates within certain analogous areas. These locations were limited to only those areas with both established geologic consistency and sufficient statistical performance data where such data could be demonstrated to provide reasonable certain results.

As discussed above, Murphy now 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% - 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 reserves in this filing 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 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 reserves associated with the production sharing contracts in Malaysia totaled 104.4 million barrels and 347.8 billion cubic feet, respectively, at December 31, 2011. Approximately 94.0 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 foot. Oil reserves attributable to a production sharing agreement in Republic of the Congo amounted to 2.3 million barrels at December 31, 2011.

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 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. Generally accepted accounting principles require that unweighted average oil and natural gas prices in effect at the beginning of each month of the year be used for calculation of the standardized measure of discounted future net cash flows.

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, 2011.

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Summary of Proved Oil Reserves Based on Year-End Prices for 2008 and Average Prices for 2009 - 2011

12 Months Ended

Dec. 31, 2011

Summary of Proved Oil Reserves Based on Year-End Prices for 2008 and Average Prices for 2009 - 2011

Schedule 1 – Summary of Proved Oil Reserves Based on Year-End Prices for 2008 and Average Prices for 2009 - 2011

	Total			Total – by product						United States			Canada						Malaysia			United Kingdom			Republic of the Congo			Ecuador
(Millions of barrels)	All Products			Oil			Synthetic Oil			Oil			Oil			Synthetic Oil			Oil			Oil			Oil			Oil
Proved developed and undeveloped oil reserves:
December 31, 2008		173.6			173.6			0.0			26.8			24.3			0.0			100.7			17.0			0.0			4.8
Synthetic reserves presented as proved under SEC rules		131.6			0.0			131.6			0.0			0.0			131.6			0.0			0.0			0.0			0.0
Revisions of previous estimates		5.8			3.2			2.6			5.0			7.2			2.6			(4.9	)		(4.1	)		0.0			0.0
Improved recovery		31.0			31.0			0.0			0.0			0.0			0.0			31.0			0.0			0.0			0.0
Extensions and discoveries		23.9			23.9			0.0			0.8			3.3			0.0			11.2			0.0			8.6			0.0
Production		(48.2	)		(43.5	)		(4.7	)		(6.2	)		(7.0	)		(4.7	)		(27.9	)		(1.2	)		(0.7	)		(0.5	)
Sales of properties		(4.3	)		(4.3	)		0.0			0.0			0.0			0.0			0.0			0.0			0.0			(4.3	)
December 31, 2009		313.4			183.9			129.5			26.4			27.8			129.5			110.1			11.7			7.9			0.0
Revisions of previous estimates		22.5			18.0			4.5			3.5			5.4			4.5			4.4			0.4			4.3			0.0
Improved recovery		5.8			5.8			0.0			0.0			1.0			0.0			4.8			0.0			0.0			0.0
Extensions and discoveries		12.6			12.6			0.0			4.1			5.0			0.0			3.5			0.0			0.0			0.0
Production		(46.3	)		(41.5	)		(4.8	)		(7.4	)		(6.4	)		(4.8	)		(24.4	)		(1.2	)		(2.1	)		0.0
December 31, 2010		308.0			178.8			129.2			26.6			32.8			129.2			98.4			10.9			10.1			0.0
Revisions of previous estimates		21.2			16.0			5.2			2.4			3.1			5.2			8.4			8.1			(6.0	)		0.0
Improved recovery		14.2			14.2			0.0			0.0			0.0			0.0			10.7			3.5			0.0			0.0
Extensions and discoveries		43.9			43.9			0.0			32.6			6.7			0.0			4.6			0.0			0.0			0.0
Production		(37.6	)		(32.7	)		(4.9	)		(6.3	)		(6.0	)		(4.9	)		(17.7	)		(0.9	)		(1.8	)		0.0
December 31, 2011		349.7			220.2			129.5			55.3			36.6			129.5			104.4			21.6			2.3			0.0
Proved developed oil reserves:
December 31, 2009		270.0			150.3			119.7			18.3			26.2			119.7			90.0			11.7			4.1			0.0
December 31, 2010		248.3			129.2			119.1			15.8			28.6			119.1			66.5			10.9			7.4			0.0
December 31, 2011		238.5			118.0			120.5			20.8			32.6			120.5			57.2			5.1			2.3			0.0
Proved undeveloped oil reserves:
December 31, 2009		43.4			33.6			9.8			8.1			1.6			9.8			20.1			0.0			3.8			0.0
December 31, 2010		59.7			49.6			10.1			10.8			4.2			10.1			31.9			0.0			2.7			0.0
December 31, 2011		111.2			102.2			9.0			34.5			4.0			9.0			47.2			16.5			0.0			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.

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (USD $) In Thousands	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, 2011, 2010 and 2009, issued 193,909,200 shares at December 31, 2011, 193,293,526 shares at December 31, 2010 and 191,797,600 shares at December 31, 2009	Capital in Excess of Par Value	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Treasury Stock
Balance at beginning of period at Dec. 31, 2008			$ 0	$ 191,249	$ 631,859	$ 5,557,483	$ (87,697)	$ (13,949)
Exercise of stock options				549	17,244
Foreign currency translation gains (losses)	375,951						375,951
Net income for the year	837,621	[1]				837,621
Restricted stock transactions and other					2,473
Retirement and postretirement benefit plan adjustments, net of income taxes	(1,067)						(1,067)
Cash dividends - $1.10 per share in 2011, $1.05 per share in 2010 and $1.00 per share in 2009						(190,788)
Stock-based compensation					27,976
Loss deferred on interest rate hedges, net of income taxes	0						0
Sale of stock under employee stock purchase plans					957			1,604
Awarded restricted stock, net of forfeitures								0
Cancellation of performance-based restricted stock and forfeitures								(5,439)
Balance at end of period at Dec. 31, 2009	7,346,026		0	191,798	680,509	6,204,316	287,187	(17,784)
Exercise of stock options				1,496	54,887
Foreign currency translation gains (losses)	165,940						165,940
Net income for the year	798,081	[1]				798,081
Restricted stock transactions and other					(9,688)
Retirement and postretirement benefit plan adjustments, net of income taxes	(3,699)						(3,699)
Cash dividends - $1.10 per share in 2011, $1.05 per share in 2010 and $1.00 per share in 2009						(201,405)
Stock-based compensation					40,842
Loss deferred on interest rate hedges, net of income taxes	0						0
Sale of stock under employee stock purchase plans					1,212			1,295
Awarded restricted stock, net of forfeitures								4,305
Cancellation of performance-based restricted stock and forfeitures								258
Balance at end of period at Dec. 31, 2010	8,199,550		0	193,294	767,762	6,800,992	449,428	(11,926)
Exercise of stock options				615	21,774
Foreign currency translation gains (losses)	(91,247)						(91,247)
Net income for the year	872,702					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 - $1.10 per share in 2011, $1.05 per share in 2010 and $1.00 per share in 2009						(212,752)
Stock-based compensation					42,492
Loss deferred 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, net of forfeitures								6,208
Cancellation of performance-based restricted stock and forfeitures								0
Balance at end of period at Dec. 31, 2011	$ 8,778,397		$ 0	$ 193,909	$ 817,974	$ 7,460,942	$ 310,420	$ (4,848)

[1] Reclassified to conform to current presentation.

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Summary of Proved Natural Gas Reserves Based on Year-End Prices for 2008 and Average Prices for 2009 - 2011

12 Months Ended

Dec. 31, 2011

Summary of Proved Natural Gas Reserves Based on Year-End Prices for 2008 and Average Prices for 2009 - 2011

Schedule 2 – Summary of Proved Natural Gas Reserves Based on Year-End Prices for 2008 and Average Prices for 2009 – 2011

(Billions of cubic feet)	Total			United States			Canada			Malaysia			United Kingdom
Proved developed and undeveloped natural gas reserves:
December 31, 2008		585.6			97.4			62.2			405.2			20.8
Revisions of previous estimates		77.2			9.1			(0.6	)		59.4			9.3
Improved recovery		6.9			0.0			0.0			6.9			0.0
Extensions and discoveries		153.5			2.6			83.3			67.6			0.0
Production		(68.4	)		(19.8	)		(20.0	)		(27.3	)		(1.3	)
Sales of properties		(0.2	)		0.0			(0.2	)		0.0			0.0
December 31, 2009		754.6			89.3			124.7			511.8			28.8
Revisions of previous estimates		15.2			6.6			15.2			(11.2	)		4.6
Improved recovery		(1.0	)		0.0			0.0			(1.0	)		0.0
Extensions and discoveries		220.5			14.3			194.2			12.0			0.0
Purchases of properties		24.0			0.0			24.0			0.0			0.0
Production		(130.2	)		(19.4	)		(31.2	)		(77.6	)		(2.0	)
December 31, 2010		883.1			90.8			326.9			434.0			31.4
Revisions of previous estimates		12.6			(6.3	)		59.4			(32.5	)		(8.0	)
Improved recovery		13.8			0.0			0.0			14.8			(1.0	)
Extensions and discoveries		363.5			31.1			321.5			10.9			0.0
Production		(166.9	)		(17.2	)		(68.9	)		(79.4	)		(1.4	)
December 31, 2011		1,106.1			98.4			638.9			347.8			21.0
Proved developed natural gas reserves:
December 31, 2009		401.6			73.2			89.7			209.9			28.8
December 31, 2010		586.0			67.0			210.1			277.5			31.4
December 31, 2011		711.6			58.2			427.1			210.5			15.8
Proved undeveloped natural gas reserves:
December 31, 2009		353.0			16.1			35.0			301.9			0.0
December 31, 2010		297.1			23.8			116.8			156.5			0.0
December 31, 2011		394.5			40.2			211.8			137.3			5.2

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.

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Assumptions used in Valuation of Performance Awards Granted (Detail) (Performance-Based Restricted Stock, USD $)	12 Months Ended
	Dec. 31, 2011 Year	Dec. 31, 2010 Year	Dec. 31, 2009 Year
Assumptions
Expected volatility	51.00%	51.00%	48.00%
Risk-free interest rate	1.04%	1.41%	1.37%
Stock beta	1.006	1.008	0.973
Expected life (in years)	3.00	3.00	3.00
Minimum
Share based Compensation Arrangement by Share based Payment Award, Fair Value Assumptions, Method Used [Line Items]
Fair value per share at grant date	38.94	42.38	41.18
Maximum
Share based Compensation Arrangement by Share based Payment Award, Fair Value Assumptions, Method Used [Line Items]
Fair value per share at grant date	64.89	50.95	44.94

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Segment Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Segment Reporting Disclosure [Line Items]
Interest expense, net of capitalization	$ 55,831,000		$ 53,172,000	[1]	$ 53,005,000	[1]
Income tax expense (benefit)	810,051,000		609,151,000	[1]	521,559,000	[1]
Significant noncash charges (credits)
Depreciation, depletion, amortization	1,093,406,000		1,114,529,000	[1]	870,999,000	[1]
Accretion of asset retirement obligations	37,701,000		31,857,000	[1]	26,154,000	[1]
Amortization of undeveloped leases	118,211,000		108,026,000	[1]	83,213,000	[1]
Impairment of long-lived assets	368,600,000	[2]			5,200,000	[2]
Deferred and noncurrent income taxes	171,565,000		135,225,000	[1]	95,245,000	[1]
Additions to property, plant, equipment	2,447,900,000		1,919,700,000		1,667,800,000
Total assets at year-end	14,138,138,000		14,233,243,000
United States
Significant noncash charges (credits)
Additions to property, plant, equipment	714,400,000		396,500,000		341,800,000
Canada
Significant noncash charges (credits)
Additions to property, plant, equipment	905,600,000		821,500,000		352,300,000
Malaysia
Significant noncash charges (credits)
Additions to property, plant, equipment	695,100,000		476,500,000		754,500,000
United Kingdom
Significant noncash charges (credits)
Additions to property, plant, equipment	30,500,000		6,000,000		15,000,000
Republic of the Congo
Significant noncash charges (credits)
Additions to property, plant, equipment	81,700,000		169,400,000		195,800,000
Exploration and production
Segment Reporting Disclosure [Line Items]
Segment income (loss)	625,700,000		806,900,000		691,800,000
Revenues from external customers	4,209,800,000		3,571,200,000		2,950,700,000
Intersegment revenues	142,800,000		118,900,000		85,300,000
Interest income	0		0		0
Interest expense, net of capitalization	0		0		0
Income tax expense (benefit)	727,600,000		576,900,000		476,100,000
Significant noncash charges (credits)
Depreciation, depletion, amortization	969,700,000		1,005,000,000		775,800,000
Accretion of asset retirement obligations	36,800,000		31,100,000		25,500,000
Amortization of undeveloped leases	118,200,000		108,000,000		83,200,000
Impairment of long-lived assets	368,600,000				5,200,000
Deferred and noncurrent income taxes	192,000,000		119,100,000		64,800,000
Additions to property, plant, equipment	2,396,500,000		1,850,400,000		1,625,600,000
Total assets at year-end	10,347,000,000		9,182,700,000		8,196,300,000
Exploration and production | United States
Segment Reporting Disclosure [Line Items]
Segment income (loss)	152,700,000		72,700,000		178,000,000
Revenues from external customers	737,700,000		659,900,000		708,600,000
Intersegment revenues	0		0		0
Interest income	0		0		0
Interest expense, net of capitalization	0		0		0
Income tax expense (benefit)	86,500,000		30,000,000		88,400,000
Significant noncash charges (credits)
Depreciation, depletion, amortization	183,000,000		281,100,000		246,500,000
Accretion of asset retirement obligations	9,900,000		6,900,000		6,800,000
Amortization of undeveloped leases	62,200,000		68,500,000		34,700,000
Impairment of long-lived assets	0				5,200,000
Deferred and noncurrent income taxes	54,200,000		(48,600,000)		(4,600,000)
Additions to property, plant, equipment	696,600,000		369,400,000		336,800,000
Total assets at year-end	2,227,600,000		1,651,300,000		1,679,700,000
Exploration and production | Canada
Segment Reporting Disclosure [Line Items]
Segment income (loss)	328,000,000		213,800,000		64,800,000
Revenues from external customers	1,145,800,000		780,200,000		635,200,000
Intersegment revenues	142,800,000		118,900,000		85,300,000
Interest income	0		0		0
Interest expense, net of capitalization	0		0		0
Income tax expense (benefit)	135,500,000		79,100,000		21,000,000
Significant noncash charges (credits)
Depreciation, depletion, amortization	326,000,000		225,500,000		199,900,000
Accretion of asset retirement obligations	12,500,000		11,200,000		8,600,000
Amortization of undeveloped leases	28,800,000		33,700,000		44,100,000
Impairment of long-lived assets	0				0
Deferred and noncurrent income taxes	39,600,000		34,500,000		(7,200,000)
Additions to property, plant, equipment	885,200,000		804,400,000		330,100,000
Total assets at year-end	3,746,800,000		3,242,600,000		2,507,800,000
Exploration and production | Malaysia
Segment Reporting Disclosure [Line Items]
Segment income (loss)	812,700,000		659,400,000		561,900,000
Revenues from external customers	2,045,600,000		1,837,900,000		1,526,400,000
Intersegment revenues	0		0		0
Interest income	0		0		0
Interest expense, net of capitalization	0		0		0
Income tax expense (benefit)	434,900,000		414,100,000		354,100,000
Significant noncash charges (credits)
Depreciation, depletion, amortization	357,300,000		379,000,000		304,100,000
Accretion of asset retirement obligations	10,600,000		9,800,000		7,800,000
Amortization of undeveloped leases	0		0		0
Impairment of long-lived assets	0				0
Deferred and noncurrent income taxes	84,600,000		145,500,000		77,600,000
Additions to property, plant, equipment	694,800,000		467,900,000		739,000,000
Total assets at year-end	3,826,900,000		3,333,100,000		3,249,600,000
Exploration and production | United Kingdom
Segment Reporting Disclosure [Line Items]
Segment income (loss)	11,500,000		30,500,000		12,600,000
Revenues from external customers	107,300,000		133,600,000		61,600,000
Intersegment revenues	0		0		0
Interest income	0		0		0
Interest expense, net of capitalization	0		0		0
Income tax expense (benefit)	46,800,000		32,600,000		11,900,000
Significant noncash charges (credits)
Depreciation, depletion, amortization	13,700,000		22,400,000		12,400,000
Accretion of asset retirement obligations	3,000,000		2,300,000		1,600,000
Amortization of undeveloped leases	0		0		0
Impairment of long-lived assets	0				0
Deferred and noncurrent income taxes	14,600,000		(11,400,000)		(900,000)
Additions to property, plant, equipment	19,700,000		(4,700,000)		17,200,000
Total assets at year-end	214,100,000		187,900,000		209,000,000
Exploration and production | Republic of the Congo
Segment Reporting Disclosure [Line Items]
Segment income (loss)	(385,300,000)		(77,200,000)		(20,600,000)
Revenues from external customers	148,800,000		155,700,000		16,500,000
Intersegment revenues	0		0		0
Interest income	0		0		0
Interest expense, net of capitalization	0		0		0
Income tax expense (benefit)	16,400,000		20,600,000		1,300,000
Significant noncash charges (credits)
Depreciation, depletion, amortization	87,800,000		95,500,000		11,500,000
Accretion of asset retirement obligations	500,000		400,000		100,000
Amortization of undeveloped leases	0		0		0
Impairment of long-lived assets	368,600,000				0
Deferred and noncurrent income taxes	(900,000)		(900,000)		0
Additions to property, plant, equipment	79,600,000		163,600,000		194,900,000
Total assets at year-end	257,500,000		678,900,000		516,700,000
Exploration and production | Other
Segment Reporting Disclosure [Line Items]
Segment income (loss)	(293,900,000)		(92,300,000)		(104,900,000)
Revenues from external customers	24,600,000		3,900,000		2,400,000
Intersegment revenues	0		0		0
Interest income	0		0		0
Interest expense, net of capitalization	0		0		0
Income tax expense (benefit)	7,500,000		500,000		(600,000)
Significant noncash charges (credits)
Depreciation, depletion, amortization	1,900,000		1,500,000		1,400,000
Accretion of asset retirement obligations	300,000		500,000		600,000
Amortization of undeveloped leases	27,200,000		5,800,000		4,400,000
Impairment of long-lived assets	0				0
Deferred and noncurrent income taxes	(100,000)		0		(100,000)
Additions to property, plant, equipment	20,600,000		49,800,000		7,600,000
Total assets at year-end	74,100,000		88,900,000		33,500,000
Refining and Marketing
Segment Reporting Disclosure [Line Items]
Segment income (loss)	190,300,000		130,600,000		45,000,000
Revenues from external customers	23,502,200,000		16,655,400,000		13,842,300,000
Intersegment revenues	0		0		0
Interest income	0		0		0
Interest expense, net of capitalization	0		0		0
Income tax expense (benefit)	134,500,000		79,500,000		41,300,000
Significant noncash charges (credits)
Depreciation, depletion, amortization	115,000,000		101,500,000		89,200,000
Accretion of asset retirement obligations	900,000		800,000		700,000
Amortization of undeveloped leases	0		0		0
Impairment of long-lived assets	0				0
Deferred and noncurrent income taxes	23,200,000		8,300,000		25,400,000
Additions to property, plant, equipment	122,300,000		290,100,000		263,400,000
Total assets at year-end	3,000,300,000		4,110,200,000		3,430,400,000
Refining and Marketing | United States
Segment Reporting Disclosure [Line Items]
Segment income (loss)	223,600,000		165,300,000		65,500,000
Revenues from external customers	17,471,900,000		13,750,400,000		11,116,400,000
Intersegment revenues	0		0		0
Interest income	0		0		0
Interest expense, net of capitalization	0		0		0
Income tax expense (benefit)	146,600,000		101,800,000		42,300,000
Significant noncash charges (credits)
Depreciation, depletion, amortization	68,300,000		60,100,000		55,400,000
Accretion of asset retirement obligations	900,000		800,000		700,000
Amortization of undeveloped leases	0		0		0
Impairment of long-lived assets	0				0
Deferred and noncurrent income taxes	28,500,000		5,100,000		9,500,000
Additions to property, plant, equipment	100,100,000		221,000,000		161,600,000
Total assets at year-end	1,806,500,000		2,996,600,000		2,490,600,000
Refining and Marketing | United Kingdom
Segment Reporting Disclosure [Line Items]
Segment income (loss)	(33,300,000)		(34,700,000)		(20,500,000)
Revenues from external customers	6,030,300,000		2,905,000,000		2,725,900,000
Intersegment revenues	0		0		0
Interest income	0		0		0
Interest expense, net of capitalization	0		0		0
Income tax expense (benefit)	(12,100,000)		(22,300,000)		(1,000,000)
Significant noncash charges (credits)
Depreciation, depletion, amortization	46,700,000		41,400,000		33,800,000
Accretion of asset retirement obligations	0		0		0
Amortization of undeveloped leases	0		0		0
Impairment of long-lived assets	0				0
Deferred and noncurrent income taxes	(5,300,000)		3,200,000		15,900,000
Additions to property, plant, equipment	22,200,000		69,100,000		101,800,000
Total assets at year-end	1,193,800,000		1,113,600,000		939,800,000
Corporate and Other
Segment Reporting Disclosure [Line Items]
Segment income (loss)	(75,100,000)		(157,900,000)		(23,000,000)
Revenues from external customers	33,500,000		(56,900,000)		102,200,000
Intersegment revenues	0		0		0
Interest income	10,100,000		6,900,000		51,700,000
Interest expense, net of capitalization	40,700,000		34,700,000		24,400,000
Income tax expense (benefit)	(52,000,000)		(47,200,000)		4,200,000
Significant noncash charges (credits)
Depreciation, depletion, amortization	8,700,000		8,000,000		6,000,000
Accretion of asset retirement obligations	0		0		0
Amortization of undeveloped leases	0		0		0
Impairment of long-lived assets	0				0
Deferred and noncurrent income taxes	(43,600,000)		7,800,000		5,000,000
Additions to property, plant, equipment	5,300,000		5,900,000		23,000,000
Total assets at year-end	790,800,000		940,300,000		1,129,700,000
Discontinued Operations
Segment Reporting Disclosure [Line Items]
Segment income (loss)	131,800,000		18,500,000		123,800,000
Revenues from external customers	0		0		0
Intersegment revenues	0		0		0
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
Deferred and noncurrent income taxes	0		0		0
Additions to property, plant, equipment	48,100,000		117,300,000		113,300,000
Total assets at year-end	0		0		0
Consolidated
Segment Reporting Disclosure [Line Items]
Segment income (loss)	872,700,000		798,100,000		837,600,000
Revenues from external customers	27,745,500,000		20,169,700,000		16,895,200,000
Intersegment revenues	142,800,000		118,900,000		85,300,000
Interest income	10,100,000		6,900,000		51,700,000
Interest expense, net of capitalization	40,700,000		34,700,000		24,400,000
Income tax expense (benefit)	810,100,000		609,200,000		521,600,000
Significant noncash charges (credits)
Depreciation, depletion, amortization	1,093,400,000		1,114,500,000		871,000,000
Accretion of asset retirement obligations	37,700,000		31,900,000		26,200,000
Amortization of undeveloped leases	118,200,000		108,000,000		83,200,000
Impairment of long-lived assets	368,600,000				5,200,000
Deferred and noncurrent income taxes	171,600,000		135,200,000		95,200,000
Additions to property, plant, equipment	2,572,200,000		2,263,700,000		2,025,300,000
Total assets at year-end	$ 14,138,100,000		$ 14,233,200,000		$ 12,756,400,000

[1] Reclassified to conform to current presentation.

[2] Results exclude corporate overhead, interest and discontinued operations.

XML

Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2011

Results of Operations Associated with Discontinued Operations

The results of operations associated with these discontinued operations are presented in the following table.

(Thousands of dollars)	2011		2010		2009
Revenues:
U.S. refineries	$	3,700,789		3,175,353		2,117,186
Ecuador E&P operations		0		0		125,654
Total revenues	$	3,700,789		3,175,353		2,242,840
Income (loss) from operations before income taxes:
U.S. refineries	$	188,231		25,521		41,760
Ecuador E&P operations		0		0		(7,692	)
		188,231		25,521		34,068
Gain on sale before income taxes:
U.S. refineries		12,684		0		0
Ecuador E&P operations		0		0		117,557
		12,684		0		117,557
Total income from discontinued operations before taxes		200,915		25,521		151,625
Provision for income taxes		69,145		6,999		27,858
Income from discontinued operations	$	131,770		18,522		123,767

Superior and Meraux Refineries

Presentation of Major Assets and liabilities

The major assets and liabilities related to the Superior and Meraux refineries and associated marketing assets at the time of their sale are presented in the following table.

(Thousands of dollars)
Current assets:
Accounts receivable	$	1,191
Liquid inventories		115,014
Materials and supplies inventories		39,853
Total current assets – U.S. refineries		156,058
Noncurrent assets:
Property, plant and equipment, net of accumulated depreciation, depletion and amortization		723,980
Other		48,604
Total noncurrent assets – U.S. refineries		772,584
Total assets – U.S. refineries	$	928,642
Liabilities:
Current liabilities	$	2,637
Other noncurrent liabilities		14,133
Liabilities associated with assets sold – U.S. refineries	$	16,770

Ecuador

Presentation of Major Assets and liabilities

The major assets and 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 – Ecuador	$	70,075
Current liabilities	$	105,185
Other noncurrent liabilities		35
Liabilities associated with assets sold – Ecuador	$	105,220

XML

Business Segments (Tables)

12 Months Ended

Dec. 31, 2011

Segment Information

Segment Information

	Exploration and Production
(Millions of dollars)	United States			Canada			Malaysia		United Kingdom			Republic of the Congo			Other			Total
Year ended December 31, 2011
Segment income (loss)	$	152.7			328.0			812.7		11.5			(385.3	)		(293.9	)		625.7
Revenues from external customers		737.7			1,145.8			2,045.6		107.3			148.8			24.6			4,209.8
Intersegment revenues		0.0			142.8			0.0		0.0			0.0			0.0			142.8
Interest income		0.0			0.0			0.0		0.0			0.0			0.0			0.0
Interest expense, net of capitalization		0.0			0.0			0.0		0.0			0.0			0.0			0.0
Income tax expense (benefit)		86.5			135.5			434.9		46.8			16.4			7.5			727.6
Significant noncash charges (credits)
Depreciation, depletion, amortization		183.0			326.0			357.3		13.7			87.8			1.9			969.7
Accretion of asset retirement obligations		9.9			12.5			10.6		3.0			0.5			0.3			36.8
Amortization of undeveloped leases		62.2			28.8			0.0		0.0			0.0			27.2			118.2
Impairment of long-lived assets		0.0			0.0			0.0		0.0			368.6			0.0			368.6
Deferred and noncurrent income taxes		54.2			39.6			84.6		14.6			(0.9	)		(0.1	)		192.0
Additions to property, plant, equipment		696.6			885.2			694.8		19.7			79.6			20.6			2,396.5
Total assets at year-end		2,227.6			3,746.8			3,826.9		214.1			257.5			74.1			10,347.0
Year ended December 31, 2010
Segment income (loss)	$	72.7			213.8			659.4		30.5			(77.2	)		(92.3	)		806.9
Revenues from external customers		659.9			780.2			1,837.9		133.6			155.7			3.9			3,571.2
Intersegment revenues		0.0			118.9			0.0		0.0			0.0			0.0			118.9
Interest income		0.0			0.0			0.0		0.0			0.0			0.0			0.0
Interest expense, net of capitalization		0.0			0.0			0.0		0.0			0.0			0.0			0.0
Income tax expense (benefit)		30.0			79.1			414.1		32.6			20.6			0.5			576.9
Significant noncash charges (credits)
Depreciation, depletion, amortization		281.1			225.5			379.0		22.4			95.5			1.5			1,005.0
Accretion of asset retirement obligations		6.9			11.2			9.8		2.3			0.4			0.5			31.1
Amortization of undeveloped leases		68.5			33.7			0.0		0.0			0.0			5.8			108.0
Deferred and noncurrent income taxes		(48.6	)		34.5			145.5		(11.4	)		(0.9	)		0.0			119.1
Additions to property, plant, equipment		369.4			804.4			467.9		(4.7	)		163.6			49.8			1,850.4
Total assets at year-end		1,651.3			3,242.6			3,333.1		187.9			678.9			88.9			9,182.7
Year ended December 31, 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		0.0			85.3			0.0		0.0			0.0			0.0			85.3
Interest income		0.0			0.0			0.0		0.0			0.0			0.0			0.0
Interest expense, net of capitalization		0.0			0.0			0.0		0.0			0.0			0.0			0.0
Income tax expense (benefit)		88.4			21.0			354.1		11.9			1.3			(0.6	)		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 asset retirement obligations		6.8			8.6			7.8		1.6			0.1			0.6			25.5
Amortization of undeveloped leases		34.7			44.1			0.0		0.0			0.0			4.4			83.2
Impairment of long-lived assets		5.2			0.0			0.0		0.0			0.0			0.0			5.2
Deferred and noncurrent income taxes		(4.6	)		(7.2	)		77.6		(0.9	)		0.0			(0.1	)		64.8
Additions to property, plant, equipment		336.8			330.1			739.0		17.2			194.9			7.6			1,625.6
Total assets at year-end		1,679.7			2,507.8			3,249.6		209.0			516.7			33.5			8,196.3

Geographic Information on Certain Long-Lived Assets

Geographic Information	Certain Long-Lived Assets at December 31
(Millions of dollars)	United States		Canada		Malaysia		United Kingdom		Republic of the Congo		Other		Total
2011	$	2,953.1		3,493.4		3,154.8		694.7		133.7		52.2		10,481.9
2010		3,178.8		3,028.8		2,807.0		706.3		579.4		74.3		10,374.6
2009		2,907.2		2,324.6		2,714.9		704.7		399.9		20.5		9,071.8

Segment Information

Segment Information (Continued)

	Refining and Marketing							Corporate and Other			Discontinued Operations		Consolidated
(Millions of dollars)	United States		United Kingdom			Total
Year ended December 31, 2011
Segment income (loss)	$	223.6		(33.3	)		190.3		(75.1	)		131.8		872.7
Revenues from external customers		17,471.9		6,030.3			23,502.2		33.5			0.0		27,745.5
Intersegment revenues		0.0		0.0			0.0		0.0			0.0		142.8
Interest income		0.0		0.0			0.0		10.1			0.0		10.1
Interest expense, net of capitalization		0.0		0.0			0.0		40.7			0.0		40.7
Income tax expense (benefit)		146.6		(12.1	)		134.5		(52.0	)		0.0		810.1
Significant noncash charges (credits)
Depreciation, depletion, amortization		68.3		46.7			115.0		8.7			0.0		1,093.4
Accretion of asset retirement obligations		0.9		0.0			0.9		0.0			0.0		37.7
Amortization of undeveloped leases		0.0		0.0			0.0		0.0			0.0		118.2
Impairment of long-lived assets		0.0		0.0			0.0		0.0			0.0		368.6
Deferred and noncurrent income taxes		28.5		(5.3	)		23.2		(43.6	)		0.0		171.6
Additions to property, plant, equipment		100.1		22.2			122.3		5.3			48.1		2,572.2
Total assets at year-end		1,806.5		1,193.8			3,000.3		790.8			0.0		14,138.1
Year ended December 31, 2010
Segment income (loss)	$	165.3		(34.7	)		130.6		(157.9	)		18.5		798.1
Revenues from external customers		13,750.4		2,905.0			16,655.4		(56.9	)		0.0		20,169.7
Intersegment revenues		0.0		0.0			0.0		0.0			0.0		118.9
Interest income		0.0		0.0			0.0		6.9			0.0		6.9
Interest expense, net of capitalization		0.0		0.0			0.0		34.7			0.0		34.7
Income tax expense (benefit)		101.8		(22.3	)		79.5		(47.2	)		0.0		609.2
Significant noncash charges (credits)
Depreciation, depletion, amortization		60.1		41.4			101.5		8.0			0.0		1,114.5
Accretion of asset retirement obligations		0.8		0.0			0.8		0.0			0.0		31.9
Amortization of undeveloped leases		0.0		0.0			0.0		0.0			0.0		108.0
Deferred and noncurrent income taxes		5.1		3.2			8.3		7.8			0.0		135.2
Additions to property, plant, equipment		221.0		69.1			290.1		5.9			117.3		2,263.7
Total assets at year-end		2,996.6		1,113.6			4,110.2		940.3			0.0		14,233.2
Year ended December 31, 2009
Segment income (loss)	$	65.5		(20.5	)		45.0		(23.0	)		123.8		837.6
Revenues from external customers		11,116.4		2,725.9			13,842.3		102.2			0.0		16,895.2
Intersegment revenues		0.0		0.0			0.0		0.0			0.0		85.3
Interest income		0.0		0.0			0.0		51.7			0.0		51.7
Interest expense, net of capitalization		0.0		0.0			0.0		24.4			0.0		24.4
Income tax expense (benefit)		42.3		(1.0	)		41.3		4.2			0.0		521.6
Significant noncash charges (credits)
Depreciation, depletion, amortization		55.4		33.8			89.2		6.0			0.0		871.0
Accretion of asset retirement obligations		0.7		0.0			0.7		0.0			0.0		26.2
Amortization of undeveloped leases		0.0		0.0			0.0		0.0			0.0		83.2
Impairment of long-lived assets		0.0		0.0			0.0		0.0			0.0		5.2
Deferred and noncurrent income taxes		9.5		15.9			25.4		5.0			0.0		95.2
Additions to property, plant, equipment		161.6		101.8			263.4		23.0			113.3		2,025.3
Total assets at year-end		2,490.6		939.8			3,430.4		1,129.7			0.0		12,756.4

Geographic Information on Revenues from External Customers

Geographic Information	Revenues from External Customers for the Year
(Millions of dollars)	United States		Canada		Malaysia		United Kingdom		Republic of the Congo		Other		Total
2011	$	18,184.0		1,180.3		2,063.0		6,144.8		148.8		24.6		27,745.5
2010		14,386.6		809.3		1,793.8		3,018.7		156.5		4.8		20,169.7
2009		11,855.9		652.5		1,526.4		2,838.7		16.5		5.2		16,895.2

XML

Components of Income from Continuing Operations Before Income Taxes and Income Tax Expense (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010		Dec. 31, 2009
Income from continuing operations before income taxes
United States									$ 440,753	$ 188,588		$ 261,005
Foreign									1,110,230	1,200,122		974,408
Income from continuing operations before income taxes	100,000	534,400	505,200	411,400	286,200	352,700	433,600	316,200	1,550,983	1,388,710	[1]	1,235,413	[1]
Income tax expense
Federal - Current									99,451	110,142		100,276
Federal - Deferred									43,602	(40,981)		2,078
Federal Income Tax Expense (Benefit), Continuing Operations, Total									143,053	69,161		102,354
State									30,372	15,486		7,087
Foreign - Current									497,446	347,746		318,619
Foreign - Deferred									139,180	176,758		93,499
Foreign Income Tax Expense (Benefit), Continuing Operations, Total									636,626	524,504		412,118
Total									$ 810,051	$ 609,151	[1]	$ 521,559	[1]

[1] Reclassified to conform to current presentation.

XML

CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current assets
Cash and cash equivalents	$ 513,873	$ 535,825	[1]
Canadian government securities with maturities greater than 90 days at the date of acquisition	532,093	616,558
Accounts receivable, less allowance for doubtful accounts of $7,892 in 2011 and $7,954 in 2010	1,554,184	1,467,311
Inventories, at lower of cost or market
Crude oil and blend stocks	189,320	147,256
Finished products	254,880	388,162
Materials and supplies	222,438	226,795
Prepaid expenses	93,397	88,241
Deferred income taxes	87,486	80,545
Total current assets	3,447,671	3,550,693
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $6,861,494 in 2011 and $6,040,996 in 2010	10,475,149	10,367,847
Goodwill	41,863	42,850
Deferred charges and other assets	173,455	271,853
Total assets	14,138,138	14,233,243
Current liabilities
Current maturities of long-term debt	350,005	41
Accounts payable	1,941,008	2,237,920
Income taxes payable	201,784	358,764
Other taxes payable	169,535	206,951
Other accrued liabilities	140,024	109,918
Deferred income taxes	22,572	17,316
Total current liabilities	2,824,928	2,930,910
Long-term debt	249,553	939,350
Deferred income taxes	1,230,111	1,212,213
Asset retirement obligations	615,545	555,248
Deferred credits and other liabilities	439,604	395,972
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, 2011 and 2010, issued 193,909,200 shares at December 31, 2011 and 193,293,526 shares at December 31, 2010	193,909	193,294
Capital in excess of par value	817,974	767,762
Retained earnings	7,460,942	6,800,992
Accumulated other comprehensive income	310,420	449,428
Treasury stock	(4,848)	(11,926)
Total stockholders' equity	8,778,397	8,199,550
Total liabilities and stockholders' equity	$ 14,138,138	$ 14,233,243

[1] Reclassified to conform to current presentation.

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

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, 2011 and income tax expense attributable thereto were as follows.

(Thousands of dollars)	2011		2010			2009
Income from continuing operations before income taxes
United States	$	440,753		188,588			261,005
Foreign		1,110,230		1,200,122			974,408
	$	1,550,983		1,388,710			1,235,413
Income tax expense
Federal – Current	$	99,451		110,142			100,276
Deferred		43,602		(40,981	)		2,078
		143,053		69,161			102,354
State		30,372		15,486			7,087
Foreign – Current		497,446		347,746			318,619
Deferred		139,180		176,758			93,499
		636,626		524,504			412,118
Total	$	810,051		609,151			521,559

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)	2011			2010		2009
Income tax expense based on the U.S. statutory tax rate	$	542,844			486,049		432,395
Foreign income subject to foreign taxes at a rate different than the U.S. statutory rate		10,053			56,367		33,395
State income taxes, net of federal benefit		19,742			10,066		4,607
Increase in deferred tax asset valuation allowance related to foreign exploration expenditures		102,714			47,128		34,431
Impairment of Azurite field with no tax benefit		129,010			0		0
Malaysian tax benefits on prior year costs in Block P		(25,573	)		0		0
Increase in United Kingdom oil and gas tax rate		14,461			0		0
Other, net		16,800			9,541		16,731
Total	$	810,051			609,151		521,559

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, 2011 and 2010 showing the tax effects of significant temporary differences follows.

(Thousands of dollars)	2011			2010
Deferred tax assets
Property and leasehold costs	$	627,093			391,168
Liabilities for dismantlements		114,175			97,149
Postretirement and other employee benefits		164,044			137,709
Foreign tax credit carryforwards		21,368			47,725
Other deferred tax assets		38,341			47,511
Total gross deferred tax assets		965,021			721,262
Less valuation allowance		(445,842	)		(305,349	)
Net deferred tax assets		519,179			415,913
Deferred tax liabilities
Property, plant and equipment		(851,330	)		(729,699	)
Accumulated depreciation, depletion and amortization		(754,295	)		(702,512	)
Deferred major repair costs		(11,257	)		(35,848	)
Other deferred tax liabilities		(67,494	)		(96,838	)
Total gross deferred tax liabilities		(1,684,376	)		(1,564,897	)
Net deferred tax liabilities	$	(1,165,197	)		(1,148,984	)

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 years ended December 31, 2011 and 2010 follows.

(Thousands of dollars)	2011			2010
Balance at January 1	$	23,196			25,978
Additions for tax positions related to current year		1,294			1,225
Settlements due to lapse of time		(5,633	)		(4,007	)
Balance at December 31	$	18,857			23,196

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Fair Value Measurements of Retirement Plan Assets within Fair Value Hierarchy (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	$ 404,350	$ 416,272
Domestic Plans
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	268,742	290,197
Domestic Plans | Equity Securities | US core equity
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	73,986	79,550
Domestic Plans | Equity Securities | U.S. small/midcap
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	18,236	17,324
Domestic Plans | Equity Securities | US long/short equity fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	13,860	14,205
Domestic Plans | Equity Securities | International | Commingled trust fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	56,156	61,531
Domestic Plans | Equity Securities | Emerging market | Commingled equity fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	6,980	7,131
Domestic Plans | Fixed Income Securities | U.S. fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	76,764	81,989
Domestic Plans | Fixed Income Securities | International | Commingled trust fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	13,109	19,833
Domestic Plans | Fixed Income Securities | Emerging market | Mutual fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	6,448	7,045
Domestic Plans | Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	3,203	1,589
Foreign Plans
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	135,608	126,075
Foreign Plans | Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	1,827	3,184
Foreign Plans | Equity securities funds
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	59,349	58,353
Foreign Plans | Fixed income securities funds
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	44,442	31,948
Foreign Plans | Diversified pooled fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	29,990	32,590
Quoted Prices in Active Markets for Identical Assets (Level 1)
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	97,252	101,647
Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic Plans
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	95,425	98,463
Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic Plans | Equity Securities | US core equity
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	73,986	79,550
Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic Plans | Equity Securities | U.S. small/midcap
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	18,236	17,324
Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic Plans | Equity Securities | US long/short equity fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic Plans | Equity Securities | International | Commingled trust fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic Plans | Equity Securities | Emerging market | Commingled equity fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic Plans | Fixed Income Securities | U.S. fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic Plans | Fixed Income Securities | International | Commingled trust fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic Plans | Fixed Income Securities | Emerging market | Mutual fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic Plans | Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	3,203	1,589
Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign Plans
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	1,827	3,184
Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign Plans | Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	1,827	3,184
Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign Plans | Equity securities funds
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign Plans | Fixed income securities funds
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign Plans | Diversified pooled fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Other Observable Inputs (Level 2)
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	307,098	314,625
Significant Other Observable Inputs (Level 2) | Domestic Plans
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	173,317	191,734
Significant Other Observable Inputs (Level 2) | Domestic Plans | Equity Securities | US core equity
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Other Observable Inputs (Level 2) | Domestic Plans | Equity Securities | U.S. small/midcap
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Other Observable Inputs (Level 2) | Domestic Plans | Equity Securities | US long/short equity fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	13,860	14,205
Significant Other Observable Inputs (Level 2) | Domestic Plans | Equity Securities | International | Commingled trust fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	56,156	61,531
Significant Other Observable Inputs (Level 2) | Domestic Plans | Equity Securities | Emerging market | Commingled equity fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	6,980	7,131
Significant Other Observable Inputs (Level 2) | Domestic Plans | Fixed Income Securities | U.S. fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	76,764	81,989
Significant Other Observable Inputs (Level 2) | Domestic Plans | Fixed Income Securities | International | Commingled trust fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	13,109	19,833
Significant Other Observable Inputs (Level 2) | Domestic Plans | Fixed Income Securities | Emerging market | Mutual fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	6,448	7,045
Significant Other Observable Inputs (Level 2) | Domestic Plans | Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Other Observable Inputs (Level 2) | Foreign Plans
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	133,781	122,891
Significant Other Observable Inputs (Level 2) | Foreign Plans | Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Other Observable Inputs (Level 2) | Foreign Plans | Equity securities funds
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	59,349	58,353
Significant Other Observable Inputs (Level 2) | Foreign Plans | Fixed income securities funds
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	44,442	31,948
Significant Other Observable Inputs (Level 2) | Foreign Plans | Diversified pooled fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	29,990	32,590
Significant Unobservable Inputs (Level 3)
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Domestic Plans
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Domestic Plans | Equity Securities | US core equity
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Domestic Plans | Equity Securities | U.S. small/midcap
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Domestic Plans | Equity Securities | US long/short equity fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Domestic Plans | Equity Securities | International | Commingled trust fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Domestic Plans | Equity Securities | Emerging market | Commingled equity fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Domestic Plans | Fixed Income Securities | U.S. fixed income
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Domestic Plans | Fixed Income Securities | International | Commingled trust fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Domestic Plans | Fixed Income Securities | Emerging market | Mutual fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Domestic Plans | Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Foreign Plans
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Foreign Plans | Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Foreign Plans | Equity securities funds
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Foreign Plans | Fixed income securities funds
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Significant Unobservable Inputs (Level 3) | Foreign Plans | Diversified pooled fund
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	$ 0	$ 0

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Business Segments - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Segment Reporting Disclosure [Line Items]
Excise taxes collected on petroleum products and remitted to various government entities	$ 3,566,876,000	$ 3,375,509,000	$ 3,595,238,000
Discontinued Operations
Segment Reporting Disclosure [Line Items]
Segment income (loss)	$ 131,800,000	$ 18,500,000	$ 123,800,000
U.S. refineries and associated marketing assets sold	2
Customer Concentration Revenue
Segment Reporting Disclosure [Line Items]
Percentage of revenues	The Company had no single customer from which it derived more than 10% of its revenues.

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Operating Activities
Net income	$ 872,702		$ 798,081	[1]	$ 837,621	[1]
Adjustments to reconcile net income to net cash provided by operating activities
Income from discontinued operations	(131,770)		(18,522)	[1]	(123,767)	[1]
Depreciation, depletion and amortization	1,093,406		1,114,529	[1]	870,999	[1]
Impairment of long-lived assets	368,600		0	[1]	5,240	[1]
Amortization of deferred major repair costs	23,076		15,561	[1]	7,348	[1]
Expenditures for asset retirements	(24,692)		(36,506)	[1]	(48,694)	[1]
Dry hole costs	250,954		90,125	[1]	125,244	[1]
Amortization of undeveloped leases	118,211		108,026	[1]	83,213	[1]
Accretion of asset retirement obligations	37,701		31,857	[1]	26,154	[1]
Deferred and noncurrent income tax charges	171,565		135,225	[1]	95,245	[1]
Pretax gains from disposition of assets	(22,679)		(884)	[1]	(3,709)	[1]
Net decrease (increase) in noncash operating working capital	(825,154)		639,566	[1]	(194,690)	[1]
Other operating activities - net	67,955		151,012	[1]	90,001	[1]
Net cash provided by continuing operations	1,999,875		3,028,070	[1]	1,770,205	[1]
Net cash provided by discontinued operations	145,510		100,488	[1]	94,428	[1]
Net cash provided by operating activities	2,145,385		3,128,558	[1]	1,864,633	[1]
Investing Activities
Property additions and dry hole costs	(2,623,407)		(2,199,049)	[1]	(1,866,114)	[1]
Acquisition of ethanol plants	0	[2]	(40,000)	[1],[2]	(10,000)	[1],[2]
Proceeds from sale of property, plant and equipment	27,776		2,189	[1]	1,616	[1]
Expenditures for major repairs	(5,409)		(61,387)	[1]	(19,252)	[1]
Purchase of investment securities	(1,689,087)	[3]	(2,388,720)	[1],[3]	(2,531,515)	[1],[3]
Proceeds from maturity of investment securities	1,773,552	[3]	2,551,187	[1],[3]	2,172,830	[1],[3]
Other investing activities - net	8,014		(38,157)	[1]	(34,050)	[1]
Investing activities of discontinued operations
Sales proceeds	950,010		0	[1]	78,908	[1]
Other	(55,803)		(154,875)	[1]	(124,330)	[1]
Net cash required by investing activities	(1,614,354)		(2,328,812)	[1]	(2,331,907)	[1]
Financing Activities
Additions to long-term debt	0		0	[1]	243,500	[1]
Reductions of long-term debt	(340,041)		(332,038)	[1]	0	[1]
Reductions of nonrecourse debt of a subsidiary	0		(82,000)	[1]	(2,572)	[1]
Proceeds from exercise of stock options and employee stock purchase plans	15,551		42,995	[1]	12,746	[1]
Excess tax benefits related to exercise of stock options	4,838		11,672	[1]	4,143	[1]
Withholding tax on stock-based incentive awards	(8,014)		(5,170)	[1]	0	[1]
Issue cost of debt facility	(7,905)		0	[1]	0	[1]
Cash dividends paid	(212,752)		(201,405)	[1]	(190,788)	[1]
Net cash provided (required) by financing activities	(548,323)		(565,946)	[1]	67,029	[1]
Effect of exchange rate changes on cash and cash equivalents	(4,660)		881	[1]	35,279	[1]
Net increase (decrease) in cash and cash equivalents	(21,952)		234,681	[1]	(364,966)	[1]
Cash and cash equivalents at January 1	535,825	[1]	301,144	[1]	666,110	[1]
Cash and cash equivalents at December 31	$ 513,873		$ 535,825	[1]	$ 301,144	[1]

[1] Reclassified to conform to current presentation.

[2] Excludes nonrecourse seller financing of $82 million related to the Company's acquisition of the Hankinson, North Dakota, ethanol plant in 2009.

[3] Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.

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1% Change in Assumed Health Care Cost Trend Rates (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Assumed Health Care Cost Trend Rates, Effect of One Percentage Point Change [Line Items]
A 1% Increase effect on total service and interest cost components of net periodic postretirement benefit expense	$ 2,033
A 1% Increase effect on the health care component of the accumulated postretirement benefit obligation	17,041
A 1% decrease effect on total service and interest cost components of net periodic postretirement benefit expense	(1,594)
A 1% decrease effect on the health care component of the accumulated postretirement benefit obligation	$ (13,810)

XML

Acquisitions - Additional Information (Detail) (USD $)	12 Months Ended	3 Months Ended
	Dec. 31, 2010 Ethanol Plant in Hereford, Texas	Dec. 31, 2009 Ethanol Plant in Hankinson, North Dakota gal
Schedule of Business Acquisitions, Cost of Acquired Entity [Line Items]
Date of acquisition of business	2010-08-31	2009-10-01
Plant capacity		110,000,000
Total purchase price	$ 40,000,000	$ 92,000,000
Nonrecourse loan		$ 82,000,000
Nonrecourse loan, Interest rate		5.00%
Nonrecourse loan maturity period		2014
Date of loan repaid		Sep. 30, 2010

XML

Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments (Detail) (Nondesignated, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivative	$ 5,354	$ 26,638
Commodity Derivative Contracts | Crude Oil and Product Purchases
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivative	5,659	(7,577)
Foreign Exchange Derivative Contracts | Interest and other income
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivative	$ (305)	$ 34,215

XML

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

12 Months Ended

Dec. 31, 2011

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			Canada			Malaysia			United Kingdom			Republic of the Congo			Total
December 31, 2011
Future cash inflows	$	6,105.4			18,835.5			14,110.9			2,509.5			248.6			41,809.9
Future development costs		(1,283.5	)		(1,929.5	)		(1,559.8	)		(356.2	)		(0.0	)		(5,129.0	)
Future production and abandonment costs		(1,417.9	)		(7,199.7	)		(6,161.2	)		(763.0	)		(183.8	)		(15,725.6	)
Future income taxes		(807.2	)		(2,806.8	)		(2,129.7	)		(869.0	)		(39.7	)		(6,652.4	)
Future net cash flows		2,596.8			6,899.5			4,260.2			521.3			25.1			14,302.9
10% annual discount for estimated timing 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	$	1,684.8			3,240.8			2,752.8			216.9			27.9			7,923.2
December 31, 2010
Future cash inflows	$	2,472.8			13,440.2			8,118.9			1,005.1			758.9			25,795.9
Future development costs		(379.7	)		(1,244.5	)		(756.3	)		(14.0	)		(69.6	)		(2,464.1	)
Future production and abandonment costs		(631.3	)		(6,923.3	)		(2,379.0	)		(305.6	)		(330.7	)		(10,569.9	)
Future income taxes		(335.0	)		(1,509.8	)		(1,659.4	)		(329.0	)		(82.4	)		(3,915.6	)
Future net cash flows		1,126.8			3,762.6			3,324.2			356.5			276.2			8,846.3
10% annual discount for estimated timing of cash flows		(254.2	)		(1,818.0	)		(922.2	)		(123.5	)		(34.4	)		(3,152.3	)
Standardized measure of discounted future net cash flows	$	872.6			1,944.6			2,402.0			233.0			241.8			5,694.0
December 31, 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

Following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown.

(Millions of dollars)	2011			2010			2009
Inclusion of synthetic oil reserves beginning in 2009*	$	0.0			0.0			378.9
Net changes in prices, production costs and development costs		(370.5	)		240.1			675.1
Sales and transfers of oil and gas produced, net of production costs		(3,273.5	)		(2,792.2	)		(2,381.5	)
Net change due to extensions and discoveries		3,300.9			1,022.2			1,976.2
Net change due to purchases and sales of proved reserves		0.0			48.7			(36.7	)
Development costs incurred		1,881.5			1,271.3			1,344.1
Accretion of discount		827.7			698.9			422.1
Revisions of previous quantity estimates		892.5			798.8			267.8
Net change in income taxes		(1,029.4	)		(450.2	)		(454.8	)
Net increase		2,229.2			837.6			2,191.2
Standardized measure at January 1		5,694.0			4,856.4			2,665.2
Standardized measure at December 31	$	7,923.2			5,694.0			4,856.4

* Prior to 2009, discounted future net cash flows from synthetic oil operations were excluded from this report. With the SEC’s change in the definition of proved reserves to include synthetic oil as proved reserves, the Company has included synthetic oil reserves in this table beginning in 2009.

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Net Changes in Capitalized Exploratory Well Costs (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Beginning Balance	$ 497,765	$ 369,862	$ 310,118
Additions to capitalized exploratory well costs pending the determination of proved reserves	86,035	137,403	119,995
Reclassifications to proved properties based on the determination of proved reserves	0	0	(60,251)
Capitalized exploratory well costs charged to expense or sold	(27,388)	(9,500)	0
Ending Balance	$ 556,412	$ 497,765	$ 369,862

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Earnings per Share

12 Months Ended

Dec. 31, 2011

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, 2011. No difference existed between net income used in computing basic and diluted income per Common share for these years.

(Weighted-average shares outstanding)	2011		2010		2009
Basic method		193,409,621		191,830,357		190,767,077
Dilutive stock options		1,102,781		1,327,457		1,701,373
Diluted method		194,512,402		193,157,814		192,468,450

Outstanding options to purchase shares of Common Stock were not included in the computation of diluted earnings per share in 2009 through 2011 because the incremental shares from assumed conversion were antidilutive. These included 1,823,564 shares at a weighted average share price of $69.46 in 2011, 2,220,567 shares at a weighted average share price of $58.78 in 2010 and 1,793,905 shares at a weighted average share price of $56.25 in 2009.

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Capitalized Costs Relating to Oil and Gas Producing Activities

12 Months Ended

Dec. 31, 2011

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			Other			Subtotal			Synthetic– Oil Canada			Total
December 31, 2011
Unproved oil and gas properties	$	868.0			539.9			372.8			0.0			37.4			84.2			1,902.3			0.0			1,902.3
Proved oil and gas properties		2,276.3			3,756.4			4,252.5			556.6			715.3			0.0			11,557.1			1,230.6			12,787.7
Gross capitalized costs		3,144.3			4,296.3			4,625.3			556.6			752.7			84.2			13,459.4			1,230.6			14,690.0
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties		(188.2	)		(223.5	)		(0.0	)		(0.0	)		(6.1	)		(41.0	)		(458.8	)		(0.0	)		(458.8	)
Proved oil and gas properties		(1,255.1	)		(1,493.4	)		(1,474.3	)		(361.9	)		(613.2	)		(0.0	)		(5,197.9	)		(324.3	)		(5,522.2	)
Net capitalized costs	$	1,701.0			2,579.4			3,151.0			194.7			133.4			43.2			7,802.7			906.3			8,709.0
December 31, 2010
Unproved oil and gas properties	$	564.7			729.0			322.4			0.0			57.9			79.6			1,753.6			0.0			1,753.6
Proved oil and gas properties		1,869.1			2,861.1			3,596.0			526.1			657.0			3.3			9,512.6			1,171.6			10,684.2
Gross capitalized costs		2,433.8			3,590.1			3,918.4			526.1			714.9			82.9			11,266.2			1,171.6			12,437.8
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties		(126.5	)		(200.5	)		(0.0	)		(0.0	)		(6.0	)		(13.8	)		(346.8	)		(0.0	)		(346.8	)
Proved oil and gas properties		(1,074.6	)		(1,258.4	)		(1,115.3	)		(347.9	)		(129.8	)		(3.3	)		(3,929.3	)		(280.3	)		(4,209.6	)
Net capitalized costs	$	1,232.7			2,131.2			2,803.1			178.2			579.1			65.8			6,990.1			891.3			7,881.4

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.

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Fair Value of Derivative Instruments Not Designated as Hedging Instruments (Detail) (Nondesignated, USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Commodity Derivative Contracts | Accounts Receivable
Derivatives, Fair Value [Line Items]
Asset Derivatives	$ 197	$ 750
Commodity Derivative Contracts | Accounts Payable
Derivatives, Fair Value [Line Items]
Liability Derivatives	489	626
Foreign Exchange Derivative Contracts | Accounts Receivable
Derivatives, Fair Value [Line Items]
Asset Derivatives		7,261
Foreign Exchange Derivative Contracts | Accounts Payable
Derivatives, Fair Value [Line Items]
Liability Derivatives	$ 8,459

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Results of Operations for Oil and Gas Producing Activities (Detail) (USD $)	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Revenues
Total oil and gas revenues	$ 4,312,100,000	[1]	$ 3,671,700,000	[1]	$ 2,787,500,000	[1]
Other operating revenues	40,500,000	[1]	18,400,000	[1]	248,500,000	[1],[2]
Total revenues	4,352,600,000	[1]	3,690,100,000	[1]	3,036,000,000	[1]
Costs and expenses
Production expenses	1,038,600,000	[1]	879,500,000	[1]	654,500,000	[1]
Exploration costs charged to expense	371,700,000	[1]	184,300,000	[1]	182,000,000	[1]
Undeveloped lease amortization	118,200,000	[1]	108,000,000	[1]	83,200,000	[1]
Depreciation, depletion and amortization	969,700,000	[1]	1,005,000,000	[1]	775,800,000	[1]
Accretion of asset retirement obligations	36,800,000	[1]	31,100,000	[1]	25,500,000	[1]
Impairment of properties	368,600,000	[1]			5,200,000	[1]
Terra Nova working interest redetermination	(5,351,000)	[1]	18,582,000	[1],[3]	83,498,000	[1],[3]
Selling and general expenses	101,100,000	[1]	79,800,000	[1]	58,400,000	[1]
Total costs and expenses	2,999,300,000	[1]	2,306,300,000	[1]	1,868,100,000	[1]
Results of Operations, Income before Income Taxes	1,353,300,000	[1]	1,383,800,000	[1]	1,167,900,000	[1]
Income tax expense (benefits)	727,600,000	[1]	576,900,000	[1]	476,100,000	[1]
Results of operations	625,700,000	[1]	806,900,000	[1]	691,800,000	[1]
Crude Oil and Natural Gas Liquids
Revenues
Sales to unaffiliated enterprises	3,342,400,000	[1]	3,012,500,000	[1]	2,501,200,000	[1]
Transfers to consolidated operations	142,800,000	[1]	118,900,000	[1]	85,300,000	[1]
Natural Gas
Revenues
Sales to unaffiliated enterprises	826,900,000	[1]	540,300,000	[1]	201,000,000	[1]
United States
Costs and expenses
Exploration costs charged to expense	36,500,000		35,700,000		27,500,000
United States | Oil Reserves
Revenues
Total oil and gas revenues	719,900,000	[1]	644,600,000	[1]	455,400,000	[1]
Other operating revenues	17,800,000	[1]	15,300,000	[1]	253,200,000	[1],[2]
Total revenues	737,700,000	[1]	659,900,000	[1]	708,600,000	[1]
Costs and expenses
Production expenses	164,800,000	[1]	131,700,000	[1]	101,200,000	[1]
Exploration costs charged to expense	36,500,000	[1]	35,700,000	[1]	27,500,000	[1]
Undeveloped lease amortization	62,200,000	[1]	68,500,000	[1]	34,700,000	[1]
Depreciation, depletion and amortization	183,000,000	[1]	281,100,000	[1]	246,500,000	[1]
Accretion of asset retirement obligations	9,900,000	[1]	6,900,000	[1]	6,800,000	[1]
Impairment of properties	0	[1]			5,200,000	[1]
Terra Nova working interest redetermination	0	[1]	0	[1]	0	[1]
Selling and general expenses	42,100,000	[1]	33,300,000	[1]	20,300,000	[1]
Total costs and expenses	498,500,000	[1]	557,200,000	[1]	442,200,000	[1]
Results of Operations, Income before Income Taxes	239,200,000	[1]	102,700,000	[1]	266,400,000	[1]
Income tax expense (benefits)	86,500,000	[1]	30,000,000	[1]	88,400,000	[1]
Results of operations	152,700,000	[1]	72,700,000	[1]	178,000,000	[1]
United States | Crude Oil and Natural Gas Liquids | Oil Reserves
Revenues
Sales to unaffiliated enterprises	648,800,000	[1]	557,600,000	[1]	374,800,000	[1]
Transfers to consolidated operations	0	[1]	0	[1]	0	[1]
United States | Natural Gas | Oil Reserves
Revenues
Sales to unaffiliated enterprises	71,100,000	[1]	87,000,000	[1]	80,600,000	[1]
Canada
Costs and expenses
Exploration costs charged to expense	60,800,000		1,900,000		10,000,000
Canada | Conventional
Revenues
Total oil and gas revenues	785,800,000	[1]	520,700,000	[1]	434,200,000	[1]
Other operating revenues	(3,800,000)	[1]	(200,000)	[1]	(2,200,000)	[1],[2]
Total revenues	782,000,000	[1]	520,500,000	[1]	432,000,000	[1]
Costs and expenses
Production expenses	151,200,000	[1]	97,500,000	[1]	97,900,000	[1]
Exploration costs charged to expense	60,800,000	[1]	1,900,000	[1]	10,000,000	[1]
Undeveloped lease amortization	28,800,000	[1]	33,700,000	[1]	44,100,000	[1]
Depreciation, depletion and amortization	273,900,000	[1]	180,300,000	[1]	171,800,000	[1]
Accretion of asset retirement obligations	4,900,000	[1]	4,800,000	[1]	4,300,000	[1]
Impairment of properties	0	[1]			0	[1]
Terra Nova working interest redetermination	(5,400,000)	[1]	18,600,000	[1]	83,500,000	[1]
Selling and general expenses	14,200,000	[1]	10,500,000	[1]	18,000,000	[1]
Total costs and expenses	528,400,000	[1]	347,300,000	[1]	429,600,000	[1]
Results of Operations, Income before Income Taxes	253,600,000	[1]	173,200,000	[1]	2,400,000	[1]
Income tax expense (benefits)	79,700,000	[1]	44,600,000	[1]	1,200,000	[1]
Results of operations	173,900,000	[1]	128,600,000	[1]	1,200,000	[1]
Canada | Synthetic Oil
Revenues
Total oil and gas revenues	506,600,000	[1]	378,600,000	[1]	288,500,000	[1]
Other operating revenues	0	[1]	0	[1]	0	[1],[2]
Total revenues	506,600,000	[1]	378,600,000	[1]	288,500,000	[1]
Costs and expenses
Production expenses	236,100,000	[1]	206,400,000	[1]	171,900,000	[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	52,100,000	[1]	45,200,000	[1]	28,100,000	[1]
Accretion of asset retirement obligations	7,600,000	[1]	6,400,000	[1]	4,300,000	[1]
Impairment of properties	0	[1]			0	[1]
Terra Nova working interest redetermination	0	[1]	0	[1]	0	[1]
Selling and general expenses	900,000	[1]	900,000	[1]	800,000	[1]
Total costs and expenses	296,700,000	[1]	258,900,000	[1]	205,100,000	[1]
Results of Operations, Income before Income Taxes	209,900,000	[1]	119,700,000	[1]	83,400,000	[1]
Income tax expense (benefits)	55,800,000	[1]	34,500,000	[1]	19,800,000	[1]
Results of operations	154,100,000	[1]	85,200,000	[1]	63,600,000	[1]
Canada | Crude Oil and Natural Gas Liquids | Conventional
Revenues
Sales to unaffiliated enterprises	459,200,000	[1]	346,400,000	[1]	310,700,000	[1]
Transfers to consolidated operations	46,400,000	[1]	42,200,000	[1]	54,900,000	[1]
Canada | Crude Oil and Natural Gas Liquids | Synthetic Oil
Revenues
Sales to unaffiliated enterprises	410,200,000	[1]	301,900,000	[1]	258,100,000	[1]
Transfers to consolidated operations	96,400,000	[1]	76,700,000	[1]	30,400,000	[1]
Canada | Natural Gas | Conventional
Revenues
Sales to unaffiliated enterprises	280,200,000	[1]	132,100,000	[1]	68,600,000	[1]
Canada | Natural Gas | Synthetic Oil
Revenues
Sales to unaffiliated enterprises	0	[1]	0	[1]	0	[1]
Malaysia
Costs and expenses
Exploration costs charged to expense	11,100,000		19,800,000		55,800,000
Malaysia | Oil Reserves
Revenues
Total oil and gas revenues	2,044,300,000	[1]	1,838,200,000	[1]	1,523,800,000	[1]
Other operating revenues	1,300,000	[1]	(300,000)	[1]	2,600,000	[1],[2]
Total revenues	2,045,600,000	[1]	1,837,900,000	[1]	1,526,400,000	[1]
Costs and expenses
Production expenses	420,600,000	[1]	355,000,000	[1]	248,200,000	[1]
Exploration costs charged to expense	11,100,000	[1]	19,800,000	[1]	55,800,000	[1]
Undeveloped lease amortization	0	[1]	0	[1]	0	[1]
Depreciation, depletion and amortization	357,300,000	[1]	379,000,000	[1]	304,100,000	[1]
Accretion of asset retirement obligations	10,600,000	[1]	9,800,000	[1]	7,800,000	[1]
Impairment of properties	0	[1]			0	[1]
Terra Nova working interest redetermination	0	[1]	0	[1]	0	[1]
Selling and general expenses	(1,600,000)	[1]	800,000	[1]	(5,500,000)	[1]
Total costs and expenses	798,000,000	[1]	764,400,000	[1]	610,400,000	[1]
Results of Operations, Income before Income Taxes	1,247,600,000	[1]	1,073,500,000	[1]	916,000,000	[1]
Income tax expense (benefits)	434,900,000	[1]	414,100,000	[1]	354,100,000	[1]
Results of operations	812,700,000	[1]	659,400,000	[1]	561,900,000	[1]
Malaysia | Crude Oil and Natural Gas Liquids | Oil Reserves
Revenues
Sales to unaffiliated enterprises	1,583,000,000	[1]	1,531,100,000	[1]	1,478,400,000	[1]
Transfers to consolidated operations	0	[1]	0	[1]	0	[1]
Malaysia | Natural Gas | Oil Reserves
Revenues
Sales to unaffiliated enterprises	461,300,000	[1]	307,100,000	[1]	45,400,000	[1]
United Kingdom
Costs and expenses
Exploration costs charged to expense	500,000		16,200,000		200,000
United Kingdom | Oil Reserves
Revenues
Total oil and gas revenues	106,700,000	[1]	132,900,000	[1]	61,100,000	[1]
Other operating revenues	600,000	[1]	700,000	[1]	500,000	[1],[2]
Total revenues	107,300,000	[1]	133,600,000	[1]	61,600,000	[1]
Costs and expenses
Production expenses	28,300,000	[1]	26,900,000	[1]	19,900,000	[1]
Exploration costs charged to expense	500,000	[1]	16,200,000	[1]	200,000	[1]
Undeveloped lease amortization	0	[1]	0	[1]	0	[1]
Depreciation, depletion and amortization	13,700,000	[1]	22,400,000	[1]	12,400,000	[1]
Accretion of asset retirement obligations	3,000,000	[1]	2,300,000	[1]	1,600,000	[1]
Impairment of properties	0	[1]			0	[1]
Terra Nova working interest redetermination	0	[1]	0	[1]	0	[1]
Selling and general expenses	3,500,000	[1]	2,700,000	[1]	3,000,000	[1]
Total costs and expenses	49,000,000	[1]	70,500,000	[1]	37,100,000	[1]
Results of Operations, Income before Income Taxes	58,300,000	[1]	63,100,000	[1]	24,500,000	[1]
Income tax expense (benefits)	46,800,000	[1]	32,600,000	[1]	11,900,000	[1]
Results of operations	11,500,000	[1]	30,500,000	[1]	12,600,000	[1]
United Kingdom | Crude Oil and Natural Gas Liquids | Oil Reserves
Revenues
Sales to unaffiliated enterprises	92,400,000	[1]	118,800,000	[1]	54,700,000	[1]
Transfers to consolidated operations	0	[1]	0	[1]	0	[1]
United Kingdom | Natural Gas | Oil Reserves
Revenues
Sales to unaffiliated enterprises	14,300,000	[1]	14,100,000	[1]	6,400,000	[1]
Republic of the Congo
Costs and expenses
Exploration costs charged to expense	21,000,000		56,400,000		10,800,000
Republic of the Congo | Oil Reserves
Revenues
Total oil and gas revenues	148,800,000	[1]	156,700,000	[1]	24,500,000	[1]
Other operating revenues	0	[1]	(1,000,000)	[1]	(8,000,000)	[1],[2]
Total revenues	148,800,000	[1]	155,700,000	[1]	16,500,000	[1]
Costs and expenses
Production expenses	37,600,000	[1]	62,000,000	[1]	15,400,000	[1]
Exploration costs charged to expense	21,000,000	[1]	56,400,000	[1]	10,800,000	[1]
Undeveloped lease amortization	0	[1]	0	[1]	0	[1]
Depreciation, depletion and amortization	87,800,000	[1]	95,500,000	[1]	11,500,000	[1]
Accretion of asset retirement obligations	500,000	[1]	400,000	[1]	100,000	[1]
Impairment of properties	368,600,000	[1]			0	[1]
Terra Nova working interest redetermination	0	[1]	0	[1]	0	[1]
Selling and general expenses	2,200,000	[1]	(2,000,000)	[1]	(2,000,000)	[1]
Total costs and expenses	517,700,000	[1]	212,300,000	[1]	35,800,000	[1]
Results of Operations, Income before Income Taxes	(368,900,000)	[1]	(56,600,000)	[1]	(19,300,000)	[1]
Income tax expense (benefits)	16,400,000	[1]	20,600,000	[1]	1,300,000	[1]
Results of operations	(385,300,000)	[1]	(77,200,000)	[1]	(20,600,000)	[1]
Republic of the Congo | Crude Oil and Natural Gas Liquids | Oil Reserves
Revenues
Sales to unaffiliated enterprises	148,800,000	[1]	156,700,000	[1]	24,500,000	[1]
Transfers to consolidated operations	0	[1]	0	[1]	0	[1]
Republic of the Congo | Natural Gas | Oil Reserves
Revenues
Sales to unaffiliated enterprises	0	[1]	0	[1]	0	[1]
Other Regions
Costs and expenses
Exploration costs charged to expense	241,800,000		54,300,000		77,700,000
Other Regions | Oil Reserves
Revenues
Total oil and gas revenues	0	[1]	0	[1]	0	[1]
Other operating revenues	24,600,000	[1]	3,900,000	[1]	2,400,000	[1],[2]
Total revenues	24,600,000	[1]	3,900,000	[1]	2,400,000	[1]
Costs and expenses
Production expenses	0	[1]	0	[1]	0	[1]
Exploration costs charged to expense	241,800,000	[1]	54,300,000	[1]	77,700,000	[1]
Undeveloped lease amortization	27,200,000	[1]	5,800,000	[1]	4,400,000	[1]
Depreciation, depletion and amortization	1,900,000	[1]	1,500,000	[1]	1,400,000	[1]
Accretion of asset retirement obligations	300,000	[1]	500,000	[1]	600,000	[1]
Impairment of properties	0	[1]			0	[1]
Terra Nova working interest redetermination	0	[1]	0	[1]	0	[1]
Selling and general expenses	39,800,000	[1]	33,600,000	[1]	23,800,000	[1]
Total costs and expenses	311,000,000	[1]	95,700,000	[1]	107,900,000	[1]
Results of Operations, Income before Income Taxes	(286,400,000)	[1]	(91,800,000)	[1]	(105,500,000)	[1]
Income tax expense (benefits)	7,500,000	[1]	500,000	[1]	(600,000)	[1]
Results of operations	(293,900,000)	[1]	(92,300,000)	[1]	(104,900,000)	[1]
Other Regions | Crude Oil and Natural Gas Liquids | Oil Reserves
Revenues
Sales to unaffiliated enterprises	0	[1]	0	[1]	0	[1]
Transfers to consolidated operations	0	[1]	0	[1]	0	[1]
Other Regions | Natural Gas | Oil Reserves
Revenues
Sales to unaffiliated enterprises	$ 0	[1]	$ 0	[1]	$ 0	[1]

[1] Results exclude corporate overhead, interest and discontinued operations.

[2] Other operating revenues in the U.S. included $244.4 million for recovery of federal royalties paid on certain properties in the Gulf of Mexico. These royalties related to production for the years 2003 through 2009.

[3] Reclassified to conform to current presentation.

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Assets and Liabilities Measured at Fair Value

12 Months Ended

Dec. 31, 2011

Assets and Liabilities Measured at Fair Value

Note O – 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, 2011 and 2010 are presented in the following table.

				Fair Value Measurements at Reporting Date Using
(Thousands of dollars)	Fair Value  at December 31, 2011			Quoted Prices in Active  Markets for Identical Assets (Liabilities) (Level 1)			Significant Other  Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Assets
Commodity derivative contracts	$	197			0			197			0
Liabilities
Nonqualified employee savings plan		(8,030	)		(8,030	)		0			0
Foreign currency exchange derivative contracts		(8,459	)		0			(8,459	)		0
Commodity derivative contracts		(489	)		0			(489	)		0
Interest rate derivative contracts		(25,927	)		0			(25,927	)		0
Total		(42,905	)		(8,030	)		(34,875	)		0

				Fair Value Measurements at Reporting Date Using
(Thousands of dollars)	Fair Value at December  31, 2010			Quoted Prices in Active  Markets for Identical Assets (Liabilities) (Level 1)			Significant Other  Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Assets
Foreign currency exchange derivative contracts	$	7,261			0			7,261			0
Commodity derivative assets		750			0			750			0
Total		8,011			0			8,011			0
Liabilities
Nonqualified employee savings plan		(7,672	)		(7,672	)		0			0
Commodity derivative contracts		(626	)		0			(626	)		0
Total		(8,298	)		(7,672	)		(626	)		0

At the balance sheet dates the fair value of commodity derivatives contracts for crude oil was determined based on market quotes for WTI crude and the fair value of commodity derivative contracts for corn and wet and dried distillers grain with solubles was determined based on market quotes for No. 2 yellow corn. The fair value of derivative contracts for foreign currency exchange and interest rates was based on quotes from active brokers in the respective markets. 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 interest rate derivative contracts are accounted for under hedge accounting rules; therefore, gains and losses are deferred and are recorded net of income taxes as a component of Accumulated Other Comprehensive Income in the Consolidated Balance Sheet. 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. The fair value of this savings plan liability was based on quoted prices for these equity securities and mutual funds. 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 carrying value of the Company’s Cash and Cash Equivalents, Accounts Receivable and Accounts Payable approximates fair value.

The assets of ethanol plants acquired in 2009 and 2010 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 December 31, 2011 and 2010. 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 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 financial guarantees and letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, was nominal.

	At December 31,
	2011						2010
(Thousands of dollars)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Financial assets (liabilities):
Canadian government securities with maturities greater than 90 days at the date of acquisition	$	532,093			532,899			616,558			617,372
Current and long-term debt		(599,558	)		(715,208	)		(939,391	)		(1,064,225	)

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Long-term Debt (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Debt Instrument [Line Items]
Total debt including current maturities	$ 599,558	$ 939,391
Current maturities	(350,005)	(41)
Total long-term debt	249,553	939,350
6.375% notes, due 2012, net of unamortized discount of $38
Debt Instrument [Line Items]
Notes payable	349,962	349,846
7.05% notes, due 2029, net of unamortized discount of $1,616
Debt Instrument [Line Items]
Notes payable	248,384	248,291
Notes payable to banks, 0.7375%
Debt Instrument [Line Items]
Notes payable	0	340,000
Other, 6%, due through 2028
Debt Instrument [Line Items]
Notes payable	$ 1,212	$ 1,254

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Hurricane and Insurance Related Matters - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009
Insurance coverage income	$ 3,000,000	$ 6,500,000
Pretax income from the insurer final cash settlement		12,718,000
Meraux Refinery
Insurance coverage income		15,398,000
North America
Insurance coverage income		4,500,000
Corporate
Insurance coverage income		$ 2,000,000

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2010
Issue cost of debt facility	$ 0	[1]
Ethanol Plant in Hankinson, North Dakota
Issue cost of debt facility	$ 82,000	[1]

[1] Reclassified to conform to current presentation.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Accounts receivable, allowance for doubtful accounts	$ 7,892	$ 7,954
Property, plant and equipment, accumulated depreciation, depletion and amortization	$ 6,861,494	$ 6,040,996
Cumulative Preferred Stock, par	$ 100	$ 100
Cumulative Preferred Stock, authorized	400,000	400,000
Cumulative Preferred Stock, issued	0	0
Common Stock, par	$ 1.00	$ 1.00
Common Stock, authorized shares	450,000,000	450,000,000
Common Stock, issued shares	193,909,200	193,293,526

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligations

Note H – Asset Retirement Obligations

The majority of the asset retirement obligations liabilities (ARO) recognized by the Company at December 31, 2011 and 2010 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 has not recorded 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 2011 and 2010 is shown in the following table.

(Thousands of dollars)	2011			2010
Balance at beginning of year	$	555,248			476,938
Accretion expense		37,701			31,857
Liabilities incurred		51,858			59,605
Revision of previous estimates		7,608			14,170
Liabilities settled		(32,088	)*		(36,506	)
Changes due to translation of foreign currencies		(4,782	)		9,184
Balance at end of year	$	615,545			555,248

* Includes noncash settlements related to sale of assets in Spain in 2011.

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.

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Other Financial Information - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Inventory Disclosure [Line Items]
Inventories accounted for under the LIFO method	$ 188,390,000	$ 345,449,000
Decrease amount of inventory that would have been valued using the FIFO method	580,238,000	735,091,000
Increased pretax income from discontinued operation derived from fair value exceeding the LIFO carrying value	296,185,000
Income taxes paid	938,944,000	585,759,000	501,506,000
Interest paid, net of amounts capitalized	38,120,000	35,452,000	21,017,000
Foreign currency translation gains(losses), net of tax	496,161,000	587,408,000
Net gains (losses) from foreign currency transactions	22,131,000	(63,861,000)	48,429,000
Currency, Canadian Dollar
Inventory Disclosure [Line Items]
Foreign currency translation gains(losses), net of tax	464,736,000
Currency, British Pound Sterling
Inventory Disclosure [Line Items]
Foreign currency translation gains(losses), net of tax	37,544,000
Other Foreign Currency Instruments
Inventory Disclosure [Line Items]
Foreign currency translation gains(losses), net of tax	$ (6,119,000)

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Employee and Retiree Benefit Plans - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Pension and Other Postretirement Benefits Disclosure [Line Items]
Future annual rate of increase in cost of health care for 2012 to measure postretirement benefit obligations	7.80%
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
Asset performance compared to a benchmark return, percent targeted to outperform the benchmark over three years	0.75%
Amounts charged to expense for U.S. and U.K. plans	10,725,000	11,467,000	11,617,000
Allocations of plan assets to be invested in equity securities, minimum	40.00%
Allocations of plan assets to be invested in equity securities, maximum	70.00%
Allocations of plan assets to be invested in fixed income securities, minimum	30.00%
Allocations of plan assets to be invested in fixed income securities, maximum	60.00%
Allocations of plan assets to be invested in cash and equivalents, minimum	0.00%
Allocations of plan assets to be invested in cash and equivalents, maximum	15.00%
Allocations of plan assets to be invested in long/short equity, maximum	10.00%
Equity securities minimum market capitalization	100,000,000
Weighted average expected return on plan assets	6.48%
Fixed Income Securities
Pension and Other Postretirement Benefits Disclosure [Line Items]
Fixed income portfolio, maximum average maturity years	11
Basis used to determine expected return on plan asset, percentage of expected return (expense)	4.53%
US long/short equity fund
Pension and Other Postretirement Benefits Disclosure [Line Items]
Allocations of plan assets to be invested in long/short equity, minimum	0.00%
Allocations of plan assets to be invested in long/short equity, maximum	15.00%
Equity Securities
Pension and Other Postretirement Benefits Disclosure [Line Items]
Basis used to determine expected return on plan asset, percentage of expected return (expense)	8.29%
Average expected investment expense, net
Pension and Other Postretirement Benefits Disclosure [Line Items]
Basis used to determine expected return on plan asset, percentage of expected return (expense)	0.28%
Foreign Other Postretirement Benefit Plans
Pension and Other Postretirement Benefits Disclosure [Line Items]
Contributions to benefit plans	52,000
Expected benefit plan contributions to be made during next year	45,000
Funded Retirement Plan
Pension and Other Postretirement Benefits Disclosure [Line Items]
Weighted average expected return on plan assets	5.06%
Domestic postretirement benefits plan
Pension and Other Postretirement Benefits Disclosure [Line Items]
Contributions to benefit plans	4,011,000
Expected benefit plan contributions to be made during next year	5,790,000
Domestic postretirement benefits plan | Commingled trust fund | Minimum
Pension and Other Postretirement Benefits Disclosure [Line Items]
Domestic plan, commingled trusts waiting periods for withdrawals (in days)	6 days
Domestic postretirement benefits plan | Commingled trust fund | Maximum
Pension and Other Postretirement Benefits Disclosure [Line Items]
Domestic plan, commingled trusts waiting periods for withdrawals (in days)	30 days
Domestic defined benefit pension plans
Pension and Other Postretirement Benefits Disclosure [Line Items]
Contributions to benefit plans	23,736,000
Expected benefit plan contributions to be made during next year	27,171,000
Foreign Defined Benefit Pension Plans
Pension and Other Postretirement Benefits Disclosure [Line Items]
Contributions to benefit plans	14,621,000
Expected benefit plan contributions to be made during next year	$ 8,311,000
United Kingdom | Foreign Other Postretirement Benefit Plans
Pension and Other Postretirement Benefits Disclosure [Line Items]
Allocations of plan assets to be invested in equity securities	60.00%
Allocations of plan assets to be invested in fixed income securities	40.00%
Allocations of plan assets to be invested in equity securities, minimum	27.00%
Allocations of plan assets to be invested in equity securities, maximum	98.00%
Allocations of plan assets to be invested in fixed income securities, minimum	25.00%
Allocations of plan assets to be invested in fixed income securities, maximum	60.00%
Allocations of plan assets to be invested in cash and equivalents, maximum	5.00%
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 reminder 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.
Canada | Foreign Other Postretirement Benefit Plans
Pension and Other Postretirement Benefits Disclosure [Line Items]
Allocations of plan assets to be invested in equity securities	60.00%
Allocations of plan assets to be invested in fixed income securities	35.00%
Allocations of plan assets to be invested in equity securities, minimum	40.00%
Allocations of plan assets to be invested in equity securities, maximum	75.00%
Allocations of plan assets to be invested in fixed income securities, minimum	25.00%
Allocations of plan assets to be invested in fixed income securities, maximum	45.00%
Allocations of plan assets to be invested in cash and equivalents, minimum	0.00%
Allocations of plan assets to be invested in cash and equivalents, maximum	15.00%
Allocations of plan assets to be invested in cash and equivalents	5.00%

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Weighted-Average Assumptions used in Measurement of Benefit Obligations and Net Periodic Benefit Expense (Detail)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	6.48%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligation, Discount rate	5.00%	5.66%
Expected return on plan assets	6.48%	6.56%
Rate of compensation increase	4.22%	4.19%
Net periodic benefit expense, Discount rate	5.50%	5.88%
Net periodic benefit expense, Rate of compensation increase	4.22%	4.19%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligation, Discount rate	4.87%	5.66%
Expected return on plan assets	0.00%	0.00%
Rate of compensation increase	0.00%	0.00%
Net periodic benefit expense, Discount rate	5.50%	5.90%
Net periodic benefit expense, Rate of compensation increase	0.00%	0.00%

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Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs	$ 562.5	[1]	$ 473.4	[1]	$ 312.6	[1]
Development costs	1,954.3	[1]	1,365.8	[1]	1,419.1	[1]
Total costs incurred	2,819.6		2,104.0		1,849.8
Asset Retirement Obligation Costs
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs	2.3		3.4		5.0
Development costs	49.1		65.9		36.4
Total costs incurred	51.4		69.3		41.4
United States
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs	253.2	[1]	204.1	[1]	89.7	[1]
Development costs	263.9	[1]	98.3	[1]	197.2	[1]
Total costs incurred	750.9		432.2		369.3
United States | Asset Retirement Obligation Costs
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs	2.0		3.4		5.0
Development costs	15.8		23.7		0
Total costs incurred	17.8		27.1		5.0
Canada
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs	76.0	[1]	1.8	[1]	9.9	[1]
Development costs	871.9	[1]	721.0	[1]	321.4	[1]
Total costs incurred	966.4		823.4		362.3
Canada | Asset Retirement Obligation Costs
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs	0.3		0		0
Development costs	20.1		17.1		22.2
Total costs incurred	20.4		17.1		22.2
Malaysia
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs	0.7	[1]	99.6	[1]	114.4	[1]
Development costs	705.5	[1]	396.7	[1]	695.9	[1]
Total costs incurred	706.2		496.3		810.3
Malaysia | Asset Retirement Obligation Costs
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs	0		0		0
Development costs	0.3		8.6		15.5
Total costs incurred	0.3		8.6		15.5
United Kingdom
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs	0.5	[1]	6.7	[1]	0.1	[1]
Development costs	30.5	[1]	15.5	[1]	15.1	[1]
Total costs incurred	31.0		22.2		15.2
United Kingdom | Asset Retirement Obligation Costs
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs	0		0		0
Development costs	10.8		10.7		(2.2)
Total costs incurred	10.8		10.7		(2.2)
Republic of the Congo
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs	0.5	[1]	93.5	[1]	19.1	[1]
Development costs	78.7	[1]	132.3	[1]	187.5	[1]
Total costs incurred	102.7		225.8		206.6
Republic of the Congo | Asset Retirement Obligation Costs
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs	0		0		0
Development costs	2.1		5.8		0.9
Total costs incurred	2.1		5.8		0.9
Other Regions
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration costs	231.6	[1]	67.7	[1]	79.4	[1]
Development costs	3.8	[1]	2.0	[1]	2.0	[1]
Total costs incurred	262.4		104.1		86.1
Other Regions | Asset Retirement Obligation Costs
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 incurred	$ 0		$ 0		$ 0

[1] Includes non-cash asset retirement costs as follows: 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 2010 Exploration costs $ 3.4 0.0 0.0 0.0 0.0 0.0 3.4 Development costs 23.7 17.1 8.6 10.7 5.8 0.0 65.9 $ 27.1 17.1 8.6 10.7 5.8 0.0 69.3 2009 Exploration costs $ 5.0 0.0 0.0 0.0 0.0 0.0 5.0 Development costs 0.0 22.2 15.5 (2.2 ) 0.9 0.0 36.4 $ 5.0 22.2 15.5 (2.2 ) 0.9 0.0 41.4

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Summary of Proved Oil Reserves Based on Year-End Prices for 2008 and Average Prices for 2009 - 2011 (Detail) (Oil Reserves)	12 Months Ended
	Dec. 31, 2011 bbl	Dec. 31, 2010 bbl	Dec. 31, 2009 bbl
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	308,000,000	313,400,000	173,600,000
Synthetic reserves presented as proved under SEC rules			131,600,000
Revisions of previous estimates	21,200,000	22,500,000	5,800,000
Improved recovery	14,200,000	5,800,000	31,000,000
Extensions and discoveries	43,900,000	12,600,000	23,900,000
Production	(37,600,000)	(46,300,000)	(48,200,000)
Sales of properties			(4,300,000)
Proved developed and undeveloped reserves, Ending Balance	349,700,000	308,000,000	313,400,000
Proved developed reserves	238,500,000	248,300,000	270,000,000
Proved undeveloped reserves	111,200,000	59,700,000	43,400,000
Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	178,800,000	183,900,000	173,600,000
Synthetic reserves presented as proved under SEC rules			0
Revisions of previous estimates	16,000,000	18,000,000	3,200,000
Improved recovery	14,200,000	5,800,000	31,000,000
Extensions and discoveries	43,900,000	12,600,000	23,900,000
Production	(32,700,000)	(41,500,000)	(43,500,000)
Sales of properties			(4,300,000)
Proved developed and undeveloped reserves, Ending Balance	220,200,000	178,800,000	183,900,000
Proved developed reserves	118,000,000	129,200,000	150,300,000
Proved undeveloped reserves	102,200,000	49,600,000	33,600,000
Synthetic Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	129,200,000	129,500,000	0
Synthetic reserves presented as proved under SEC rules			131,600,000
Revisions of previous estimates	5,200,000	4,500,000	2,600,000
Improved recovery	0	0	0
Extensions and discoveries	0	0	0
Production	(4,900,000)	(4,800,000)	(4,700,000)
Sales of properties			0
Proved developed and undeveloped reserves, Ending Balance	129,500,000	129,200,000	129,500,000
Proved developed reserves	120,500,000	119,100,000	119,700,000
Proved undeveloped reserves	9,000,000	10,100,000	9,800,000
United States | Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	26,600,000	26,400,000	26,800,000
Synthetic reserves presented as proved under SEC rules			0
Revisions of previous estimates	2,400,000	3,500,000	5,000,000
Improved recovery	0	0	0
Extensions and discoveries	32,600,000	4,100,000	800,000
Production	(6,300,000)	(7,400,000)	(6,200,000)
Sales of properties			0
Proved developed and undeveloped reserves, Ending Balance	55,300,000	26,600,000	26,400,000
Proved developed reserves	20,800,000	15,800,000	18,300,000
Proved undeveloped reserves	34,500,000	10,800,000	8,100,000
Canada | Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	32,800,000	27,800,000	24,300,000
Synthetic reserves presented as proved under SEC rules			0
Revisions of previous estimates	3,100,000	5,400,000	7,200,000
Improved recovery	0	1,000,000	0
Extensions and discoveries	6,700,000	5,000,000	3,300,000
Production	(6,000,000)	(6,400,000)	(7,000,000)
Sales of properties			0
Proved developed and undeveloped reserves, Ending Balance	36,600,000	32,800,000	27,800,000
Proved developed reserves	32,600,000	28,600,000	26,200,000
Proved undeveloped reserves	4,000,000	4,200,000	1,600,000
Canada | Synthetic Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	129,200,000	129,500,000	0
Synthetic reserves presented as proved under SEC rules			131,600,000
Revisions of previous estimates	5,200,000	4,500,000	2,600,000
Improved recovery	0	0	0
Extensions and discoveries	0	0	0
Production	(4,900,000)	(4,800,000)	(4,700,000)
Sales of properties			0
Proved developed and undeveloped reserves, Ending Balance	129,500,000	129,200,000	129,500,000
Proved developed reserves	120,500,000	119,100,000	119,700,000
Proved undeveloped reserves	9,000,000	10,100,000	9,800,000
Malaysia | Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	98,400,000	110,100,000	100,700,000
Synthetic reserves presented as proved under SEC rules			0
Revisions of previous estimates	8,400,000	4,400,000	(4,900,000)
Improved recovery	10,700,000	4,800,000	31,000,000
Extensions and discoveries	4,600,000	3,500,000	11,200,000
Production	(17,700,000)	(24,400,000)	(27,900,000)
Sales of properties			0
Proved developed and undeveloped reserves, Ending Balance	104,400,000	98,400,000	110,100,000
Proved developed reserves	57,200,000	66,500,000	90,000,000
Proved undeveloped reserves	47,200,000	31,900,000	20,100,000
United Kingdom | Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	10,900,000	11,700,000	17,000,000
Synthetic reserves presented as proved under SEC rules			0
Revisions of previous estimates	8,100,000	400,000	(4,100,000)
Improved recovery	3,500,000	0	0
Extensions and discoveries	0	0	0
Production	(900,000)	(1,200,000)	(1,200,000)
Sales of properties			0
Proved developed and undeveloped reserves, Ending Balance	21,600,000	10,900,000	11,700,000
Proved developed reserves	5,100,000	10,900,000	11,700,000
Proved undeveloped reserves	16,500,000	0	0
Republic of the Congo | Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	10,100,000	7,900,000	0
Synthetic reserves presented as proved under SEC rules			0
Revisions of previous estimates	(6,000,000)	4,300,000	0
Improved recovery	0	0	0
Extensions and discoveries	0	0	8,600,000
Production	(1,800,000)	(2,100,000)	(700,000)
Sales of properties			0
Proved developed and undeveloped reserves, Ending Balance	2,300,000	10,100,000	7,900,000
Proved developed reserves	2,300,000	7,400,000	4,100,000
Proved undeveloped reserves	0	2,700,000	3,800,000
Ecuador | Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	0	0	4,800,000
Synthetic reserves presented as proved under SEC rules			0
Revisions of previous estimates	0	0	0
Improved recovery	0	0	0
Extensions and discoveries	0	0	0
Production	0	0	(500,000)
Sales of properties			(4,300,000)
Proved developed and undeveloped reserves, Ending Balance	0	0	0
Proved developed reserves	0	0	0
Proved undeveloped reserves	0	0	0

XML

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2011	Jan. 31, 2012	Jun. 30, 2011
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2011
Document Fiscal Year Focus	2011
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		193,877,158
Entity Public Float			$ 12,706,062,000

XML

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 41,809.9	$ 25,795.9	$ 20,274.2
Future development costs	(5,129.0)	(2,464.1)	(1,272.7)
Future production and abandonment costs	(15,725.6)	(10,569.9)	(8,457.2)
Future income taxes	(6,652.4)	(3,915.6)	(3,081.8)
Future net cash flows	14,302.9	8,846.3	7,462.5
10% annual discount for estimated timing of cash flows	(6,379.7)	(3,152.3)	(2,606.1)
Standardized measure of discounted future net cash flows	7,923.2	5,694.0	4,856.4
United States
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	6,105.4	2,472.8	1,908.1
Future development costs	(1,283.5)	(379.7)	(245.7)
Future production and abandonment costs	(1,417.9)	(631.3)	(523.6)
Future income taxes	(807.2)	(335.0)	(264.8)
Future net cash flows	2,596.8	1,126.8	874.0
10% annual discount for estimated timing of cash flows	(912.0)	(254.2)	(174.8)
Standardized measure of discounted future net cash flows	1,684.8	872.6	699.2
Canada
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	18,835.5	13,440.2	9,571.1
Future development costs	(1,929.5)	(1,244.5)	(191.3)
Future production and abandonment costs	(7,199.7)	(6,923.3)	(5,450.6)
Future income taxes	(2,806.8)	(1,509.8)	(952.3)
Future net cash flows	6,899.5	3,762.6	2,976.9
10% annual discount for estimated timing of cash flows	(3,658.7)	(1,818.0)	(1,521.4)
Standardized measure of discounted future net cash flows	3,240.8	1,944.6	1,455.5
Malaysia
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	14,110.9	8,118.9	7,496.1
Future development costs	(1,559.8)	(756.3)	(726.3)
Future production and abandonment costs	(6,161.2)	(2,379.0)	(1,976.1)
Future income taxes	(2,129.7)	(1,659.4)	(1,531.3)
Future net cash flows	4,260.2	3,324.2	3,262.4
10% annual discount for estimated timing of cash flows	(1,507.4)	(922.2)	(838.0)
Standardized measure of discounted future net cash flows	2,752.8	2,402.0	2,424.4
United Kingdom
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	2,509.5	1,005.1	831.2
Future development costs	(356.2)	(14.0)	(9.7)
Future production and abandonment costs	(763.0)	(305.6)	(330.4)
Future income taxes	(869.0)	(329.0)	(250.2)
Future net cash flows	521.3	356.5	240.9
10% annual discount for estimated timing of cash flows	(304.4)	(123.5)	(64.7)
Standardized measure of discounted future net cash flows	216.9	233.0	176.2
Republic of the Congo
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	248.6	758.9	467.7
Future development costs	0	(69.6)	(99.7)
Future production and abandonment costs	(183.8)	(330.7)	(176.5)
Future income taxes	(39.7)	(82.4)	(83.2)
Future net cash flows	25.1	276.2	108.3
10% annual discount for estimated timing of cash flows	2.8	(34.4)	(7.2)
Standardized measure of discounted future net cash flows	$ 27.9	$ 241.8	$ 101.1

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Income Taxes

12 Months Ended

Dec. 31, 2011

Income Taxes

Note I – Income Taxes

The components of income from continuing operations before income taxes for each of the three years ended December 31, 2011 and income tax expense attributable thereto were as follows.

(Thousands of dollars)	2011		2010			2009
Income from continuing operations before income taxes
United States	$	440,753		188,588			261,005
Foreign		1,110,230		1,200,122			974,408
	$	1,550,983		1,388,710			1,235,413
Income tax expense
Federal – Current	$	99,451		110,142			100,276
Deferred		43,602		(40,981	)		2,078
		143,053		69,161			102,354
State		30,372		15,486			7,087
Foreign – Current		497,446		347,746			318,619
Deferred		139,180		176,758			93,499
		636,626		524,504			412,118
Total	$	810,051		609,151			521,559

Income tax benefits attributable to employee stock option transactions of $8,775,000 in 2011, $15,896,000 in 2010 and $6,035,000 in 2009 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 Company’s income tax expense.

(Thousands of dollars)	2011			2010		2009
Income tax expense based on the U.S. statutory tax rate	$	542,844			486,049		432,395
Foreign income subject to foreign taxes at a rate different than the U.S. statutory rate		10,053			56,367		33,395
State income taxes, net of federal benefit		19,742			10,066		4,607
Increase in deferred tax asset valuation allowance related to foreign exploration expenditures		102,714			47,128		34,431
Impairment of Azurite field with no tax benefit		129,010			0		0
Malaysian tax benefits on prior year costs in Block P		(25,573	)		0		0
Increase in United Kingdom oil and gas tax rate		14,461			0		0
Other, net		16,800			9,541		16,731
Total	$	810,051			609,151		521,559

An analysis of the Company’s deferred tax assets and deferred tax liabilities at December 31, 2011 and 2010 showing the tax effects of significant temporary differences follows.

(Thousands of dollars)	2011			2010
Deferred tax assets
Property and leasehold costs	$	627,093			391,168
Liabilities for dismantlements		114,175			97,149
Postretirement and other employee benefits		164,044			137,709
Foreign tax credit carryforwards		21,368			47,725
Other deferred tax assets		38,341			47,511
Total gross deferred tax assets		965,021			721,262
Less valuation allowance		(445,842	)		(305,349	)
Net deferred tax assets		519,179			415,913
Deferred tax liabilities
Property, plant and equipment		(851,330	)		(729,699	)
Accumulated depreciation, depletion and amortization		(754,295	)		(702,512	)
Deferred major repair costs		(11,257	)		(35,848	)
Other deferred tax liabilities		(67,494	)		(96,838	)
Total gross deferred tax liabilities		(1,684,376	)		(1,564,897	)
Net deferred tax liabilities	$	(1,165,197	)		(1,148,984	)

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 2014 through 2020. The valuation allowance increased $140,493,000 in 2011, 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, 2011, undistributed earnings of the Company’s subsidiaries considered indefinitely invested were approximately $4,895,000,000. 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 $492,469,000. 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 years ended December 31, 2011 and 2010 follows.

(Thousands of dollars)	2011			2010
Balance at January 1	$	23,196			25,978
Additions for tax positions related to current year		1,294			1,225
Settlements due to lapse of time		(5,633	)		(4,007	)
Balance at December 31	$	18,857			23,196

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, 2011 and 2010 for interest and penalties of $976,000 and $1,010,000, respectively, associated with uncertain tax positions. Income tax expense for the years ended December 31, 2011, 2010 and 2009 included (charges)/benefits for interest and penalties of $34,000, $(43,000) and $1,763,000, 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 2012 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 2012.

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, 2011, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2008; Canada – 2007; United Kingdom – 2010; and Malaysia – 2006.

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Changes in Options Outstanding (Detail) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Number of Shares
Exercised	(615,674)	(1,495,926)	(548,659)
Outstanding at end of year	5,434,228
Exercisable at end of year	2,319,735
Stock Options
Number of Shares
Outstanding at beginning of year	5,302,384	5,431,560	5,399,060
Granted at FMV	1,397,312	1,605,628	1,057,000
Exercised	(974,500)	(1,580,950)	(560,500)
Forfeited	(290,968)	(153,854)	(464,000)
Outstanding at end of year	5,434,228	5,302,384	5,431,560
Exercisable at end of year	2,319,735	2,499,610	3,506,310
Average Exercise Price
Outstanding at beginning of year	48.83	42.01	40.90
Granted at FMV	67.64	52.85	43.95
Exercised	39.30	29.04	19.58
Forfeited	52.73	53.33	60.65
Outstanding at end of year	55.17	48.83	42.01
Exercisable at end of year	51.14	45.07	34.86

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Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status Related to Foreign Benefit Plans (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets, Ending Balance	$ 404,350	$ 416,272
Foreign Defined Benefit Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation, Ending Balance	153,947	133,751
Fair value of plan assets, Ending Balance	135,608	126,075
Net plan liabilities recognized	18,339	7,676
Net periodic benefit expense	8,978	9,784
Foreign Other Postretirement Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation, Ending Balance	454	430
Fair value of plan assets, Ending Balance	0	0
Net plan liabilities recognized	454	430
Net periodic benefit expense	$ 82	$ 60

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Revenues
Sales and other operating revenues	$ 27,689,332		$ 20,225,764	[1]	$ 16,800,972	[1]
Gain on sale of assets	22,679		884	[1]	3,709	[1]
Interest and other income (loss)	33,538		(56,930)	[1]	90,502	[1]
Total revenues	27,745,549		20,169,718	[1]	16,895,206	[1]
Costs and Expenses
Crude oil and product purchases	21,875,297		15,351,318	[1]	12,821,305	[1]
Operating expenses	1,993,346		1,678,515	[1]	1,350,658	[1]
Exploration expenses, including undeveloped lease amortization	489,862		292,264	[1]	265,172	[1]
Selling and general expenses	301,005		259,215	[1]	212,376	[1]
Depreciation, depletion and amortization	1,093,406		1,114,529	[1]	870,999	[1]
Impairment of properties	368,600		0	[1]	5,240	[1]
Accretion of asset retirement obligations	37,701		31,857	[1]	26,154	[1]
Redetermination of Terra Nova working interest	(5,351)	[2]	18,582	[1],[2]	83,498	[1],[2]
Interest expense	55,831		53,172	[1]	53,005	[1]
Interest capitalized	(15,131)		(18,444)	[1]	(28,614)	[1]
Total costs and expenses	26,194,566		18,781,008	[1]	15,659,793	[1]
Income from continuing operations before income taxes	1,550,983		1,388,710	[1]	1,235,413	[1]
Income tax expense	810,051		609,151	[1]	521,559	[1]
Income from continuing operations	740,932		779,559	[1]	713,854	[1]
Income from discontinued operations, net of income taxes	131,770		18,522	[1]	123,767	[1]
Net Income	$ 872,702		$ 798,081	[1]	$ 837,621	[1]
Income per Common Share - Basic
Income from continuing operations	$ 3.83		$ 4.06	[1]	$ 3.74	[1]
Income from discontinued operations	$ 0.68		$ 0.10	[1]	$ 0.65	[1]
Net Income - Basic	$ 4.51		$ 4.16	[1]	$ 4.39	[1]
Income per Common Share - Diluted
Income from continuing operations	$ 3.81		$ 4.03	[1]	$ 3.71	[1]
Income from discontinued operations	$ 0.68		$ 0.10	[1]	$ 0.64	[1]
Net Income - Diluted	$ 4.49		$ 4.13	[1]	$ 4.35	[1]
Average Common shares outstanding - basic	193,409,621		191,830,357	[1]	190,767,077	[1]
Average Common shares outstanding - diluted	194,512,402		193,157,814	[1]	192,468,450	[1]

[1] Reclassified to conform to current presentation.

[2] Results exclude corporate overhead, interest and discontinued operations.

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Discontinued Operations

12 Months Ended

Dec. 31, 2011

Discontinued Operations

Note C – Discontinued Operations

In July 2010, the Company announced that it planned to exit the U.S. refining and U.K. refining and marketing businesses. 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 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 began to account for the results of the Superior, Wisconsin and Meraux, Louisiana refineries and associated marketing assets as discontinued operations beginning in the third quarter 2011. All prior periods presented have been reclassified to conform to this presentation of the Superior and Meraux operating results as discontinued operations. The after-tax gain 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 was based on refinery selling prices, plus the sales of all associated inventories at fair value, which was significantly above the last-in, first-out carrying value of the inventories sold. The net gain on sale of the refineries included an after-tax benefit of $179,152,000 from liquidation of inventories formerly carried mostly under the last-in, first-out cost method. The U.S. refineries sold were formerly reported in the U.S. manufacturing segment. The sale process for the U.K. refining and marketing assets continues.

The major assets and liabilities related to the Superior and Meraux refineries and associated marketing assets at the time of their sale are presented in the following table.

(Thousands of dollars)
Current assets:
Accounts receivable	$	1,191
Liquid inventories		115,014
Materials and supplies inventories		39,853
Total current assets – U.S. refineries		156,058
Noncurrent assets:
Property, plant and equipment, net of accumulated depreciation, depletion and amortization		723,980
Other		48,604
Total noncurrent assets – U.S. refineries		772,584
Total assets – U.S. refineries	$	928,642
Liabilities:
Current liabilities	$	2,637
Other noncurrent liabilities		14,133
Liabilities associated with assets sold – U.S. refineries	$	16,770

On March 12, 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 Block 16 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. Ecuador operating results prior to the sale, and the resulting gain on disposal, have been reported as discontinued operations. The major assets and 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 – Ecuador	$	70,075
Current liabilities	$	105,185
Other noncurrent liabilities		35
Liabilities associated with assets sold – Ecuador	$	105,220

The results of operations associated with these discontinued operations are presented in the following table.

(Thousands of dollars)	2011		2010		2009
Revenues:
U.S. refineries	$	3,700,789		3,175,353		2,117,186
Ecuador E&P operations		0		0		125,654
Total revenues	$	3,700,789		3,175,353		2,242,840
Income (loss) from operations before income taxes:
U.S. refineries	$	188,231		25,521		41,760
Ecuador E&P operations		0		0		(7,692	)
		188,231		25,521		34,068
Gain on sale before income taxes:
U.S. refineries		12,684		0		0
Ecuador E&P operations		0		0		117,557
		12,684		0		117,557
Total income from discontinued operations before taxes		200,915		25,521		151,625
Provision for income taxes		69,145		6,999		27,858
Income from discontinued operations	$	131,770		18,522		123,767

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New Accounting Principles and Recent Accounting Pronouncements

12 Months Ended

Dec. 31, 2011

New Accounting Principles and Recent Accounting Pronouncements

Note B – New Accounting Principles and Recent Accounting Pronouncements

Accounting Principles Adopted

The Company adopted guidance issued by the Financial Accounting Standards Board (FASB) regarding accounting for transfers of financial assets effective January 1, 2010. This guidance makes the concept of a qualifying special-purpose entity as defined previously no longer relevant for accounting purposes. Therefore, formerly qualifying special-purpose entities were reevaluated for consolidation by reporting entities in accordance with the applicable consolidation guidance. This adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted, effective January 1, 2010, guidance issued by the FASB that requires a company to perform an analysis to determine whether its variable interests give it a controlling financial interest in a variable interest entity. The primary beneficiary of a variable interest entity has both the power to direct the activities of the entity that most significantly impact the entity’s economic performance and the obligation to absorb potentially significant losses of the entity or the right to receive potentially significant benefits from the entity. A company is required to make ongoing reassessments of whether it is the primary beneficiary of a variable interest entity. This guidance also amended previous guidance for determining whether an entity is considered a variable interest entity. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

In July 2010, the FASB issued accounting guidance that expanded the disclosure requirements about financing receivables and the related allowance for credit losses. This guidance became effective for the Company at December 31, 2010. Because the Company has no significant financing receivables that extend beyond one year, the impact of this guidance did not have a significant effect on its consolidated financial statement disclosures.

The U.S. Securities and Exchange Commission (SEC) adopted revisions to oil and natural gas reserves reporting requirements which were effective for the Company at year-end 2009. In January 2010, the FASB issued guidance that aligned its oil and gas reserves reporting requirements and effective date with the SEC’s guidance. The primary changes to reserves reporting included:

• A revised definition of proved reserves, including the use of unweighted average oil and natural gas prices in effect at the beginning of each month during the year to compute such reserves,

• Expanding the definition of oil and gas producing activities to include non-traditional and unconventional resources, which includes the Company’s Canadian synthetic oil operations at Syncrude,

• Allowing companies to voluntarily disclose probable and possible reserves in SEC filings,

• Amending required proved reserve disclosures to include separate amounts for synthetic oil and gas,

• Expanded disclosures of proved undeveloped reserves, including discussion of such proved undeveloped reserves five years old or more, and

• Disclosure of the qualifications of the chief technical person who oversees the Company’s overall reserve process.

The Company utilized the new SEC and FASB guidance at December 31, 2011, 2010 and 2009 to determine its proved reserves and to develop associated disclosures. The Company chose not to provide voluntary disclosures of probable and possible reserves in this Form 10-K.

Recent Accounting and Reporting Rules

In September 2011, the FASB issued an accounting standards update that simplifies the annual goodwill impairment assessment process by permitting a company to assess whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount before applying the two-step goodwill impairment test. If a company concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the company would be required to conduct the current two-step goodwill impairment test. This change is effective for annual and interim goodwill impairment tests performed in fiscal years beginning in 2012. Early adoption is permitted. The Company does not expect the adoption of this standard in 2012 to have a significant effect on its consolidated financial statements.

In June 2011, the FASB issued an accounting standards update that only permits two options for presentation of Comprehensive Income. Comprehensive Income can be presented in (a) a single continuous Statement of Comprehensive Income, including total comprehensive income, the components of net income, and the components of other comprehensive income, or (b) in two separate but continuous statements for the Statement of Income and the Statement of Comprehensive Income. The new guidance is effective for the Company beginning in the first quarter of 2012. As in prior years, the Company expects to continue to present the Statements of Income and Comprehensive Income in two separate statements, and the adoption of this guidance in 2012 is not expected to have a significant effect on the Company’s consolidated financial statements. In December 2011, the FASB deferred the requirement for reclassification adjustments from accumulated other comprehensive income to be measured and presented by line item in the Statements of Income and Comprehensive Income.

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Other Financial Information

12 Months Ended

Dec. 31, 2011

Other Financial Information

Note N – Other Financial Information

INVENTORIES – Inventories accounted for under the LIFO method totaled $188,390,000 and $345,449,000 at December 31, 2011 and 2010, respectively, and these amounts were $580,238,000 and $735,091,000 less than such inventories would have been valued using the FIFO method. A significant inventory reduction occurred in 2011 associated with sale of the two U.S. refineries. 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.

ACCUMULATED OTHER COMPREHENSIVE INCOME – At December 31, 2011 and 2010, the components of Accumulated Other Comprehensive Income were as follows.

(Thousands of dollars)	2011			2010
Foreign currency translation gains	$	496,161			587,408
Retirement and postretirement plan adjustments, net of tax		(168,889	)		(137,980	)
Loss deferred on interest rate hedges, net of tax		(16,852	)		0
Balance at end of year	$	310,420			449,428

At December 31, 2011, components of the net foreign currency translation gains of $496,161,000 were gains (losses) of $464,736,000 for Canadian dollars, $37,544,000 for pounds sterling and $(6,119,000) 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 $22,131,000 in 2011, $(63,861,000) in 2010 and $48,429,000 in 2009.

CASH FLOW DISCLOSURES – Cash income taxes paid were $938,944,000, $585,759,000 and $501,506,000 in 2011, 2010 and 2009, respectively. Interest paid, net of amounts capitalized, was $38,120,000, $35,452,000 and $21,017,000 in 2011, 2010 and 2009, respectively.

Noncash operating working capital (increased) decreased during each of the three years ended December 31, 2011 as follows.

(Thousands of dollars)	2011			2010			2009
Accounts receivable	$	(43,630	)		(4,363	)		(402,481	)
Inventories		(59,413	)		(28,231	)		(114,569	)
Prepaid expenses		20,548			14,567			7,209
Deferred income tax assets		8,488			(80,073	)		14,772
Accounts payable and accrued liabilities		(478,029	)		766,067			365,257
Current income tax liabilities		(273,118	)		(28,401	)		(64,878	)
Net (increase) decrease in noncash operating working capital	$	(825,154	)		639,566			(194,690	)

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Incentive Plans

12 Months Ended

Dec. 31, 2011

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.

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 certain other employees. Cash awards under the 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 2007 Long-Term Incentive Plan (2007 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units, performance units, performance shares, dividend equivalents and other stock-based incentives. The 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. At December 31, 2011, approximately 5,745,000 shares remained available for issuance under the 2007 Long-Term Plan. 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 Company’s 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)	2011		2010		2009
Compensation charged against income before income tax benefit	$	43,272		41,992		28,618
Related income tax benefit recognized in income		13,053		12,169		7,860

As of December 31, 2011, there was $55,100,000 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, 2011, 2010 and 2009 was $15,551,000, $42,995,000 and $12,746,000, respectively. Total income tax benefits realized from tax deductions related to stock option exercises under share-based payment arrangements were $8,775,000, $15,896,000 and $6,035,000 for the years ended December 31, 2011, 2010 and 2009, 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 2007 Long-Term Plan has been unqualified, with a term of seven years and an option price equal to FMV at date of grant. Under the 2007 Long-Term Plan, one-half of each grant is exercisable after two years and the remainder after three years. Under the Directors 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 using 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 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.

	2011			2010			2009
Fair value per option grant	$	20.34			18.75		$	15.15
Assumptions
Dividend yield		1.80	%		1.80	%		1.40	%
Expected volatility		37.00	%		43.00	%		41.00	%
Risk-free interest rate		2.10	%		2.52	%		1.95	%
Expected life		5.10 yrs.			5.25 yrs.			5.25 yrs.

Changes in options outstanding during the last three years are presented in the following table.

	Number of Shares			Average Exercise Price
Outstanding at December 31, 2008		5,399,060		$	40.90
Granted at FMV		1,057,000			43.95
Exercised		(560,500	)		19.58
Forfeited		(464,000	)		60.65
Outstanding at December 31, 2009		5,431,560			42.01
Granted at FMV		1,605,628			52.85
Exercised		(1,580,950	)		29.04
Forfeited		(153,854	)		53.33
Outstanding at December 31, 2010		5,302,384			48.83
Granted at FMV		1,397,312			67.64
Exercised		(974,500	)		39.30
Forfeited		(290,968	)		52.73
Outstanding at December 31, 2011		5,434,228			55.17
Exercisable at December 31, 2009		3,506,310		$	34.86
Exercisable at December 31, 2010		2,499,610			45.07
Exercisable at December 31, 2011		2,319,735			51.14

Additional information about stock options outstanding at December 31, 2011 is shown below.

	Options Outstanding						Options Exercisable
Range of Exercise Prices per Option	No. of Options		Avg. Life in Years		Aggregate Intrinsic Value		No. of Options		Avg. Life in Years		Aggregate Intrinsic Value
$19.43 to $23.58		393,750		1.0	$	13,571,000		393,750		1.0	$	13,571,000
$30.30 to $45.23		953,610		3.6		11,466,000		541,235		3.2		6,604,000
$51.07 to $57.32		2,067,156		3.9		5,938,000		730,750		1.7		2,069,000
$67.64 to $72.75		2,019,712		5.1		0		654,000		3.1		0
		5,434,228		4.1	$	30,975,000		2,319,735		2.3	$	22,244,000

The total intrinsic value of options exercised during 2011, 2010 and 2009 was $28,145,000, $49,929,000 and $17,932,000, 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.

SAR – SAR may be granted in conjunction with or independent of stock options; if granted, the Committee would determine when SAR may be exercised and the price. No SAR have been granted.

PERFORMANCE-BASED RESTRICTED STOCK UNITS – Restricted stock units (RSU) were granted in each of the last three years under 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. Changes in performance-based RSU outstanding for each of the last three years are presented in the following table.

(Number of shares or share units)	2011			2010			2009
Balance at beginning of year		1,023,492			872,027			806,822
Granted		521,423			449,100			375,050
Awarded		(309,656	)		(252,551	)		0
Forfeited		(60,767	)		(45,084	)		(309,845	)
Balance at end of year		1,174,492			1,023,492			872,027

The fair value of the 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 2011, 2010 and 2009 are presented in the following table.

	2011	2010	2009
Fair value per share at grant date	$38.94 – $64.89	$42.38 – $50.95	$41.18 – $44.94
Assumptions
Expected volatility	51.00%	51.00%	48.00%
Risk-free interest rate	1.04%	1.41%	1.37%
Stock beta	1.006	1.008	0.973
Expected life	3.00 yrs.	3.00 yrs.	3.00 yrs.

TIME-LAPSE RESTRICTED STOCK AND RESTRICTED STOCK UNITS – Restricted stock and 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 fair market value of the Company’s stock on the date of grant, which was $52.66 in 2011, $52.49 per share in 2010 and $43.95 per share in 2009. Changes in time-lapse restricted stock and restricted stock units outstanding for each of the last three years are presented in the following table.

(Number of shares or share units)	2011			2010			2009
Balance at beginning of year		166,173			164,695			132,819
Granted		32,711			43,370			50,290
Expired		(82,160	)		(29,475	)		(18,414	)
Forfeited		0			(12,417	)		0
Balance at end of year		116,724			166,173			164,695

PERFORMANCE UNITS – The Company also awarded performance units in 2011 to certain U.S. retail marketing employees under the 2007 Long-Term Plan. The performance units are 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. Total expense related to these awards was $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 34,612 shares at an average price of $56.08 per share in 2011, 44,361 shares at $51.97 per share in 2010, and 51,271 shares at $44.73 per share in 2009. At December 31, 2011, 321,322 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 $328,000 in 2011, $357,000 in 2010 and $623,000 in 2009. The fair value per share issued under the ESPP was approximately $8.60, $7.51 and $11.47 for the years ended December 31, 2011, 2010 and 2009, respectively.

SAVINGS-RELATED SHARE OPTION PLAN (SOP) – One of the Company’s U.K. subsidiaries has provided a plan that allows shares of the Company’s Common stock to be purchased by eligible employees using payroll withholdings. An eligible employee may elect 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 has a term of three years and employee withholdings are fixed over the life of the plan. At the end of the term of the SOP plan an employee receives interest on withholdings and has 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 is expected to expire in 2012. Compensation costs related to the SOP plan are estimated based on the value of the 10% discount and the fair value of the option that allows the employee to receive a repayment of withholdings plus credited interest. The fair value per share of the SOP plans with holding periods ending in December 2009, August 2010, April 2011 and May 2012 were $19.57, $19.90, $23.77 and $22.85, respectively.

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 $33,035,000, $25,171,000 and $23,073,000 was recorded in 2011, 2010 and 2009, respectively, for these plans.

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Changes in Time-Lapse Restricted Stock and Restricted Stock Units Outstanding (Detail) (Restricted Stock and Restricted Stock Units)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Restricted Stock and Restricted Stock Units
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	166,173	164,695	132,819
Granted	32,711	43,370	50,290
Expired	(82,160)	(29,475)	(18,414)
Forfeited	0	(12,417)	0
Balance at end of year	116,724	166,173	164,695

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Financing Arrangements

12 Months Ended

Dec. 31, 2011

Financing Arrangements

Note F – Financing Arrangements

At December 31, 2011, the Company had a $1.5 billion committed credit facility with a major banking consortium that matures in June 2016. 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 December 31, 2011, the Company had no borrowings under this committed facility. At December 31, 2011, the Company also had no borrowings under uncommitted credit lines that amount to approximately $400,000,000. 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 September 2012.

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Purchase Price Allocation for Hereford Facility Based on Estimated Fair Value of Assets Acquired (Detail) (Ethanol Plant in Hereford, Texas, USD $)	Dec. 31, 2010
Business Acquisition [Line Items]
Total purchase price	$ 40,000,000
Land and Land Improvements
Business Acquisition [Line Items]
Business acquisition, purchase price allocation	2,379,000
Buildings and Improvements
Business Acquisition [Line Items]
Business acquisition, purchase price allocation	639,000
Machinery and Transportation Equipment
Business Acquisition [Line Items]
Business acquisition, purchase price allocation	$ 36,982,000

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Contingencies - Additional Information (Detail) (USD $)	Dec. 31, 2011 Location
Commitments and Contingencies Disclosure [Line Items]
Superfund site the company is considered to be a Potentially Responsible Party (PRP)	1
Financial Guarantee
Commitments and Contingencies Disclosure [Line Items]
Contingent liabilities	7,798,000
Letter of Credit
Commitments and Contingencies Disclosure [Line Items]
Contingent liabilities	162,906,000

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Acquisitions

12 Months Ended

Dec. 31, 2011

Acquisitions

Note D – Acquisitions

In August 2010, a wholly-owned subsidiary of the Company purchased an unfinished ethanol production facility in Hereford, Texas, for $40,000,000. The Company completed construction of the facility and commenced operations near the end of the first quarter of 2011. The Company allocated the purchase price for the Hereford facility based on the fair value of the assets acquired as presented in the following table.

(Thousands of dollars)
Land and land improvements	$	2,379
Buildings and improvements		639
Machinery and transportation equipment		36,982
Total purchase price – Hereford ethanol facility	$	40,000

A wholly-owned subsidiary of the Company purchased an ethanol production facility in Hankinson, North Dakota, on October 1, 2009. The facility has a rated capacity to produce 110 million 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 bore interest at 5.0% per year and was repayable in 2014. This loan was repaid in full in September 2010. Revenue and expenses associated with the facility have been included in the Company’s Consolidated Statement of Income beginning on the date of acquisition. The Company allocated the purchase price for the Hankinson facility based on the 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 – Hankinson ethanol facility	$	92,000

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2011

Property, Plant and Equipment

Note E – Property, Plant and Equipment

	December 31, 2011					December 31, 2010
(Thousands of dollars)	Cost		Net			Cost		Net
Exploration and production1	$	14,766,637		8,730,124	2		12,506,579		7,898,417	2
Refining and marketing		2,456,822		1,688,709			3,794,223		2,409,410
Corporate and other		113,184		56,316			108,041		60,020
	$	17,336,643		10,475,149			16,408,843		10,367,847
1         Includes mineral rights as follows:	$	1,078,770		619,950			779,036		432,051

²  Includes $21,154 in 2011 and $17,067 in 2010 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, 2011, 2010 and 2009, the Company had total capitalized drilling costs pending the determination of proved reserves of $556,412,000, $497,765,000 and $369,862,000, respectively. The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 2011.

(Thousands of dollars)	2011			2010			2009
Beginning balance at January 1	$	497,765			369,862			310,118
Additions to capitalized exploratory well costs pending the determination of proved reserves		86,035			137,403			119,995
Reclassifications to proved properties based on the determination of proved reserves		0			0			(60,251	)
Capitalized exploratory well costs charged to expense or sold		(27,388	)		(9,500	)		0
Ending balance at December 31	$	556,412			497,765			369,862

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.

	2011						2010						2009
(Thousands of dollars)	Amount		No. of Wells		No. of Projects		Amount		No. of Wells		No. of Projects		Amount		No. of Wells		No. of Projects
Aging of capitalized well costs:
Zero to one year	$	69,757		11		5		135,494		15		4	$	117,618		10		6
One to two years		143,611		15		3		115,418		10		4		49,628		4		4
Two to three years		101,696		9		2		42,571		3		3		8,870		5		0
Three years or more		241,348		33		6		204,282		31		4		193,746		27		4
	$	556,412		68		16		497,765		59		15	$	369,862		46		14

Of the $486,655,000 of exploratory well costs capitalized more than one year at December 31, 2011, $306,475,000 is in Malaysia, $138,634,000 is in the U.S., $29,188,000 is in Republic of the Congo and $12,358,000 is in Canada. 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 Republic of the Congo further appraised drilling is planned. In Canada a continuing drilling and development program is underway. The capitalized well costs charged to expense 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 2011, the Company determined that a downward revision of proved oil reserves for the Azurite field, offshore Republic of the Congo, was necessary. The determination was made after 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. Therefore, an impairment charge of $368,600,000 was recorded in 2011 to reduce the carrying value of the field to fair value. Fair value was determined 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 carrying value of the net property, plant and equipment for the Azurite field was reduced at December 31, 2011 to the present value of the net cash inflows for the field based on the results of the discounted cash flow calculation.

In 2010, the Company announced that its Board of Directors had approved plans to exit the U.K. refining and marketing business. These operations are presented as the U.K. refining and marketing segment in Note U. The sale process for the U.K. downstream assets continues. Based on current market conditions, it is possible that the Company could incur a loss if the U.K. downstream assets are sold in a future period. If the sale of the U.K. downstream assets continues to progress, the results of these operations will be presented as discontinued operations in future periods when the criteria for held for sale under U.S. generally accepted accounting principles have been met.

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Long-term Debt

12 Months Ended

Dec. 31, 2011

Long-term Debt

Note G – Long-term Debt

	December 31
(Thousands of dollars)	2011			2010
Notes payable
6.375% notes, due 2012, net of unamortized discount of $38 at December 31, 2011	$	349,962			349,846
7.05% notes, due 2029, net of unamortized discount of $1,616 at December 31, 2011		248,384			248,291
Notes payable to banks, 0.7375% at December 31, 2010		0			340,000
Other, 6%, due through 2028		1,212			1,254
Total debt including current maturities		599,558			939,391
Current maturities		(350,005	)		(41	)
Total long-term debt	$	249,553			939,350

Future amounts repayable under debt agreements are: $350,005,000 in 2012, $46,000 in 2013, $48,000 in 2014, $51,000 in 2015, $55,000 in 2016 and $249,353,000 thereafter.

During 2011, the Company used a portion of the proceeds from the sale of two U.S. refineries to repay notes payable outstanding under committed and uncommitted credit facilities.

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Property, Plant and Equipment - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010		Dec. 31, 2009		Dec. 31, 2008
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Total capitalized exploratory well costs	$ 556,412,000	$ 497,765,000		$ 369,862,000		$ 310,118,000
Exploratory well costs capitalized more than one year	486,655,000
Impairment of long-lived assets	368,600,000	0	[1]	5,240,000	[1]
Malaysia
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized more than one year	306,475,000
United States
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized more than one year	138,634,000
Republic of the Congo
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized more than one year	29,188,000
Canada
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized more than one year	$ 12,358,000

[1] Reclassified to conform to current presentation.

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Summary of Proved Natural Gas Reserves Based on Year-End Prices for 2007 and 2008 and Average Prices for 2009 and 2010 (Detail) (Natural Gas Reserves)	12 Months Ended
	Dec. 31, 2011 cf	Dec. 31, 2010 cf	Dec. 31, 2009 cf
Proved developed and undeveloped natural gas reserves:
Proved developed and undeveloped reserves, Beginning Balance	883,100,000,000	754,600,000,000	585,600,000,000
Revisions of previous estimates	12,600,000,000	15,200,000,000	77,200,000,000
Improved recovery	13,800,000,000	(1,000,000,000)	6,900,000,000
Extensions and discoveries	363,500,000,000	220,500,000,000	153,500,000,000
Purchases of properties		24,000,000,000
Production	(166,900,000,000)	(130,200,000,000)	(68,400,000,000)
Sales of properties			(200,000,000)
Proved developed and undeveloped reserves, Ending Balance	1,106,100,000,000	883,100,000,000	754,600,000,000
Proved developed reserve	711,600,000,000	586,000,000,000	401,600,000,000
Proved undeveloped reserves	394,500,000,000	297,100,000,000	353,000,000,000
United States
Proved developed and undeveloped natural gas reserves:
Proved developed and undeveloped reserves, Beginning Balance	90,800,000,000	89,300,000,000	97,400,000,000
Revisions of previous estimates	(6,300,000,000)	6,600,000,000	9,100,000,000
Improved recovery	0	0	0
Extensions and discoveries	31,100,000,000	14,300,000,000	2,600,000,000
Purchases of properties		0
Production	(17,200,000,000)	(19,400,000,000)	(19,800,000,000)
Sales of properties			0
Proved developed and undeveloped reserves, Ending Balance	98,400,000,000	90,800,000,000	89,300,000,000
Proved developed reserve	58,200,000,000	67,000,000,000	73,200,000,000
Proved undeveloped reserves	40,200,000,000	23,800,000,000	16,100,000,000
Canada
Proved developed and undeveloped natural gas reserves:
Proved developed and undeveloped reserves, Beginning Balance	326,900,000,000	124,700,000,000	62,200,000,000
Revisions of previous estimates	59,400,000,000	15,200,000,000	(600,000,000)
Improved recovery	0	0	0
Extensions and discoveries	321,500,000,000	194,200,000,000	83,300,000,000
Purchases of properties		24,000,000,000
Production	(68,900,000,000)	(31,200,000,000)	(20,000,000,000)
Sales of properties			(200,000,000)
Proved developed and undeveloped reserves, Ending Balance	638,900,000,000	326,900,000,000	124,700,000,000
Proved developed reserve	427,100,000,000	210,100,000,000	89,700,000,000
Proved undeveloped reserves	211,800,000,000	116,800,000,000	35,000,000,000
Malaysia
Proved developed and undeveloped natural gas reserves:
Proved developed and undeveloped reserves, Beginning Balance	434,000,000,000	511,800,000,000	405,200,000,000
Revisions of previous estimates	(32,500,000,000)	(11,200,000,000)	59,400,000,000
Improved recovery	14,800,000,000	(1,000,000,000)	6,900,000,000
Extensions and discoveries	10,900,000,000	12,000,000,000	67,600,000,000
Purchases of properties		0
Production	(79,400,000,000)	(77,600,000,000)	(27,300,000,000)
Sales of properties			0
Proved developed and undeveloped reserves, Ending Balance	347,800,000,000	434,000,000,000	511,800,000,000
Proved developed reserve	210,500,000,000	277,500,000,000	209,900,000,000
Proved undeveloped reserves	137,300,000,000	156,500,000,000	301,900,000,000
United Kingdom
Proved developed and undeveloped natural gas reserves:
Proved developed and undeveloped reserves, Beginning Balance	31,400,000,000	28,800,000,000	20,800,000,000
Revisions of previous estimates	(8,000,000,000)	4,600,000,000	9,300,000,000
Improved recovery	(1,000,000,000)	0	0
Extensions and discoveries	0	0	0
Purchases of properties		0
Production	(1,400,000,000)	(2,000,000,000)	(1,300,000,000)
Sales of properties			0
Proved developed and undeveloped reserves, Ending Balance	21,000,000,000	31,400,000,000	28,800,000,000
Proved developed reserve	15,800,000,000	31,400,000,000	28,800,000,000
Proved undeveloped reserves	5,200,000,000	0	0

XML

Reconciliation of Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status (Detail) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Change in plan assets
Fair value of plan assets, Ending Balance	$ 404,350,000	$ 416,272,000
Pension Benefits
Change in benefit obligation
Obligations, Beginning Balance	575,300,000	521,471,000
Service cost	22,406,000	20,706,000	17,052,000
Interest cost	30,785,000	30,144,000	28,767,000
Plan amendments	483,000	0
Participant contributions	35,000	33,000
Actuarial loss	66,010,000	30,544,000
Medicare Part D subsidy	0	0
Exchange rate changes	(2,109,000)	(1,357,000)
Benefits paid	(27,745,000)	(26,241,000)
Reduction due to sale of the Superior refinery	(23,021,000)	0
Special termination benefits	695,000	0	1,867,000
Curtailments	(13,271,000)	0
Obligations, Ending Balance	629,568,000	575,300,000	521,471,000
Change in plan assets
Fair value of plan assets, Beginning Balance	416,272,000	375,947,000
Actual return on plan assets	(1,415,000)	46,792,000
Employer contributions	38,357,000	20,651,000
Participant contributions	35,000	33,000
Medicare Part D subsidy	0	0
Exchange rate changes	(1,786,000)	(422,000)
Benefits paid	(27,745,000)	(26,241,000)
Distribution to acquirer of the Superior refinery	(18,720,000)	0
Other	(648,000)	(488,000)
Fair value of plan assets, Ending Balance	404,350,000	416,272,000	375,947,000
Funded status and amounts recognized in the Consolidated Balance Sheets at end of the period
Deferred charges and other assets	10,621,000	14,191,000
Other accrued liabilities	(3,488,000)	(3,378,000)
Deferred credits and other liabilities	(232,351,000)	(169,841,000)
Funded status and net plan liability recognized at the end of the period	(225,218,000)	(159,028,000)
Other Postretirement Benefits
Change in benefit obligation
Obligations, Beginning Balance	122,879,000	101,750,000
Service cost	4,547,000	4,133,000	3,121,000
Interest cost	6,141,000	6,211,000	5,688,000
Plan amendments	0	0
Participant contributions	1,049,000	956,000
Actuarial loss	4,791,000	14,646,000
Medicare Part D subsidy	555,000	528,000
Exchange rate changes	(11,000)	22,000
Benefits paid	(5,667,000)	(5,367,000)
Reduction due to sale of the Superior refinery	0	0
Special termination benefits	0	0	0
Curtailments	(19,322,000)	0
Obligations, Ending Balance	114,962,000	122,879,000	101,750,000
Change in plan assets
Fair value of plan assets, Beginning Balance	0	0
Actual return on plan assets	0	0
Employer contributions	4,063,000	3,883,000
Participant contributions	1,049,000	956,000
Medicare Part D subsidy	555,000	528,000
Exchange rate changes	0	0
Benefits paid	(5,667,000)	(5,367,000)
Distribution to acquirer of the Superior refinery	0	0
Other	0	0
Fair value of plan assets, Ending Balance	0	0	0
Funded status and amounts recognized in the Consolidated Balance Sheets at end of the period
Deferred charges and other assets	0	0
Other accrued liabilities	(5,022,000)	(5,223,000)
Deferred credits and other liabilities	(109,940,000)	(117,656,000)
Funded status and net plan liability recognized at the end of the period	$ (114,962,000)	$ (122,879,000)

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Aging of Capitalized Exploratory Well Costs (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 Well Project	Dec. 31, 2010 Well Project	Dec. 31, 2009 Well Project	Dec. 31, 2008
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount	$ 556,412	$ 497,765	$ 369,862	$ 310,118
No. of Wells	68	59	46
No. of Projects	16	15	14
Zero to one year
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount	69,757	135,494	117,618
No. of Wells	11	15	10
No. of Projects	5	4	6
One to two years
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount	143,611	115,418	49,628
No. of Wells	15	10	4
No. of Projects	3	4	4
Two to three years
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount	101,696	42,571	8,870
No. of Wells	9	3	5
No. of Projects	2	3	0
Three years or more
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount	$ 241,348	$ 204,282	$ 193,746
No. of Wells	33	31	27
No. of Projects	6	4	4

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Earnings per Share - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Earnings Per Share Disclosure [Line Items]
Options to purchase shares of common stock, incremental shares excluded from the computation of diluted EPS	1,823,564	2,220,567	1,793,905
Options to purchase shares of common stock, weighted average exercise price of incremental shares excluded from the computation of diluted EPS	$ 69.46	$ 58.78	$ 56.25

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Property, Plant and Equipment (Parenthetical) (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Property, Plant and Equipment [Line Items]
Property, plant and equipment, Net	$ 10,475,149	$ 10,367,847
Property, plant and equipment, Cost	17,336,643	16,408,843
Mining Properties and Mineral Rights
Property, Plant and Equipment [Line Items]
Property, plant and equipment, Net	619,950	432,051
Property, plant and equipment, Cost	1,078,770	779,036
Administrative assets and support equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment, Net	$ 21,154	$ 17,067

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Benefit Payments Reflecting Expected Future Service as Appropriate which are Expected to be Paid in Future Years from Assets of Plans or by Company (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2012	$ 28,688
2013	29,911
2014	31,237
2015	32,001
2016	32,738
2017-2021	185,062
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2012	5,835
2013	6,072
2014	6,262
2015	6,449
2016	6,747
2017-2021	$ 38,516

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VALUATION ACCOUNTS AND RESERVES (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Allowance for Doubtful Accounts
Valuation and Qualifying Accounts Disclosure [Line Items]
Beginning Balance	$ 8.0		$ 7.8		$ 7.3
Charged (credited) to Expense	0.2		0.5		0.9
Deductions	(0.3)		(0.2)		(0.2)
Other	0	[1]	(0.1)	[1]	(0.2)	[1]
Ending Balance	7.9		8.0		7.8
Deferred tax asset valuation allowance
Valuation and Qualifying Accounts Disclosure [Line Items]
Beginning Balance	305.3		290.2		266.8
Charged (credited) to Expense	140.5		15.1		23.4
Deductions	0		0		0
Other	0	[1]	0	[1]	0	[1]
Ending Balance	$ 445.8		$ 305.3		$ 290.2

[1] Amounts primarily represent changes in foreign currency exchange rates.

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Results of Operations for Oil and Gas Producing Activities

12 Months Ended

Dec. 31, 2011

Results of Operations for Oil and Gas Producing Activities

Schedule 4 – Results of Operations for Oil and Gas Producing Activities*

	United States		Canada					Malaysia			United Kingdom		Republic of the Congo			Other			Total
(Millions of dollars)			Conven- tional			Synthetic
Year Ended December 31, 2011
Revenues
Crude oil and natural gas liquids
Sales to unaffiliated enterprises	$	648.8		459.2			410.2		1,583.0			92.4		148.8			0.0			3,342.4
Transfers to consolidated operations		0.0		46.4			96.4		0.0			0.0		0.0			0.0			142.8
Natural gas
Sales to unaffiliated enterprises		71.1		280.2			0.0		461.3			14.3		0.0			0.0			826.9
Total oil and gas revenues		719.9		785.8			506.6		2,044.3			106.7		148.8			0.0			4,312.1
Other operating revenues		17.8		(3.8	)		0.0		1.3			0.6		0.0			24.6			40.5
Total revenues		737.7		782.0			506.6		2,045.6			107.3		148.8			24.6			4,352.6
Costs and expenses
Production expenses		164.8		151.2			236.1		420.6			28.3		37.6			0.0			1,038.6
Exploration costs charged to expense		36.5		60.8			0.0		11.1			0.5		21.0			241.8			371.7
Undeveloped lease amortization		62.2		28.8			0.0		0.0			0.0		0.0			27.2			118.2
Depreciation, depletion and amortization		183.0		273.9			52.1		357.3			13.7		87.8			1.9			969.7
Accretion of asset retirement obligations		9.9		4.9			7.6		10.6			3.0		0.5			0.3			36.8
Impairment of properties		0.0		0.0			0.0		0.0			0.0		368.6			0.0			368.6
Terra Nova working interest redetermination		0.0		(5.4	)		0.0		0.0			0.0		0.0			0.0			(5.4	)
Selling and general expenses		42.1		14.2			0.9		(1.6	)		3.5		2.2			39.8			101.1
Total costs and expenses		498.5		528.4			296.7		798.0			49.0		517.7			311.0			2,999.3
		239.2		253.6			209.9		1,247.6			58.3		(368.9	)		(286.4	)		1,353.3
Income tax expense		86.5		79.7			55.8		434.9			46.8		16.4			7.5			727.6
Results of operations	$	152.7		173.9			154.1		812.7			11.5		(385.3	)		(293.9	)		625.7
Year Ended December 31, 2010
Revenues
Crude oil and natural gas liquids
Sales to unaffiliated enterprises	$	557.6		346.4			301.9		1,531.1			118.8		156.7			0.0			3,012.5
Transfers to consolidated operations		0.0		42.2			76.7		0.0			0.0		0.0			0.0			118.9
Natural gas
Sales to unaffiliated enterprises		87.0		132.1			0.0		307.1			14.1		0.0			0.0			540.3
Total oil and gas revenues		644.6		520.7			378.6		1,838.2			132.9		156.7			0.0			3,671.7
Other operating revenues		15.3		(0.2	)		0.0		(0.3	)		0.7		(1.0	)		3.9			18.4
Total revenues		659.9		520.5			378.6		1,837.9			133.6		155.7			3.9			3,690.1
Costs and expenses
Production expenses		131.7		97.5			206.4		355.0			26.9		62.0			0.0			879.5
Exploration costs charged to expense		35.7		1.9			0.0		19.8			16.2		56.4			54.3			184.3
Undeveloped lease amortization		68.5		33.7			0.0		0.0			0.0		0.0			5.8			108.0
Depreciation, depletion and amortization		281.1		180.3			45.2		379.0			22.4		95.5			1.5			1,005.0
Accretion of asset retirement obligations		6.9		4.8			6.4		9.8			2.3		0.4			0.5			31.1
Terra Nova working interest redetermination		0.0		18.6			0.0		0.0			0.0		0.0			0.0			18.6
Selling and general expenses		33.3		10.5			0.9		0.8			2.7		(2.0	)		33.6			79.8
Total costs and expenses		557.2		347.3			258.9		764.4			70.5		212.3			95.7			2,306.3
		102.7		173.2			119.7		1,073.5			63.1		(56.6	)		(91.8	)		1,383.8
Income tax expense		30.0		44.6			34.5		414.1			32.6		20.6			0.5			576.9
Results of operations	$	72.7		128.6			85.2		659.4			30.5		(77.2	)		(92.3	)		806.9

* Results exclude corporate overhead, interest and discontinued operations.

Schedule 4 – Results of Operations for Oil and Gas Producing Activities (Continued)¹

(Millions of dollars)	United States		Canada					Malaysia			United Kingdom		Republic of the Congo			Other			Total
			Conven- tional			Synthetic
Year Ended December 31, 2009
Revenues
Crude oil and natural gas liquids
Sales to unaffiliated enterprises	$	374.8		310.7			258.1		1,478.4			54.7		24.5			0.0			2,501.2
Transfers to consolidated operations		0.0		54.9			30.4		0.0			0.0		0.0			0.0			85.3
Natural gas
Sales to unaffiliated enterprises		80.6		68.6			0.0		45.4			6.4		0.0			0.0			201.0
Total oil and gas revenues		455.4		434.2			288.5		1,523.8			61.1		24.5			0.0			2,787.5
Other operating revenues2		253.2		(2.2	)		0.0		2.6			0.5		(8.0	)		2.4			248.5
Total revenues		708.6		432.0			288.5		1,526.4			61.6		16.5			2.4			3,036.0
Costs and expenses
Production expenses		101.2		97.9			171.9		248.2			19.9		15.4			0.0			654.5
Exploration costs charged to expense		27.5		10.0			0.0		55.8			0.2		10.8			77.7			182.0
Undeveloped lease amortization		34.7		44.1			0.0		0.0			0.0		0.0			4.4			83.2
Depreciation, depletion and amortization		246.5		171.8			28.1		304.1			12.4		11.5			1.4			775.8
Accretion of asset retirement obligations		6.8		4.3			4.3		7.8			1.6		0.1			0.6			25.5
Impairment of properties		5.2		0.0			0.0		0.0			0.0		0.0			0.0			5.2
Terra Nova working interest redetermination		0.0		83.5			0.0		0.0			0.0		0.0			0.0			83.5
Selling and general expenses		20.3		18.0			.8		(5.5	)		3.0		(2.0	)		23.8			58.4
Total costs and expenses		442.2		429.6			205.1		610.4			37.1		35.8			107.9			1,868.1
		266.4		2.4			83.4		916.0			24.5		(19.3	)		(105.5	)		1,167.9
Income tax expense (benefits)		88.4		1.2			19.8		354.1			11.9		1.3			(0.6	)		476.1
Results of operations	$	178.0		1.2			63.6		561.9			12.6		(20.6	)		(104.9	)		691.8

¹  Results exclude corporate overhead, interest and discontinued operations.

²  Other operating revenues in the U.S. included $244.4 million for recovery of federal royalties paid on certain properties in the Gulf of Mexico. These royalties related to production for the years 2003 through 2009.

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Assets and Liabilities Measured at Fair Value (Tables)

12 Months Ended

Dec. 31, 2011

Fair Value Measurements of Assets and Liabilities

The fair value measurements for these assets and liabilities at December 31, 2011 and 2010 are presented in the following table.

				Fair Value Measurements at Reporting Date Using
(Thousands of dollars)	Fair Value  at December 31, 2011			Quoted Prices in Active  Markets for Identical Assets (Liabilities) (Level 1)			Significant Other  Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Assets
Commodity derivative contracts	$	197			0			197			0
Liabilities
Nonqualified employee savings plan		(8,030	)		(8,030	)		0			0
Foreign currency exchange derivative contracts		(8,459	)		0			(8,459	)		0
Commodity derivative contracts		(489	)		0			(489	)		0
Interest rate derivative contracts		(25,927	)		0			(25,927	)		0
Total		(42,905	)		(8,030	)		(34,875	)		0

				Fair Value Measurements at Reporting Date Using
(Thousands of dollars)	Fair Value at December  31, 2010			Quoted Prices in Active  Markets for Identical Assets (Liabilities) (Level 1)			Significant Other  Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Assets
Foreign currency exchange derivative contracts	$	7,261			0			7,261			0
Commodity derivative assets		750			0			750			0
Total		8,011			0			8,011			0
Liabilities
Nonqualified employee savings plan		(7,672	)		(7,672	)		0			0
Commodity derivative contracts		(626	)		0			(626	)		0
Total		(8,298	)		(7,672	)		(626	)		0

Carrying Amounts and Estimated Fair Values of Financial Instruments

The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 2011 and 2010. 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 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 financial guarantees and letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, was nominal.

	At December 31,
	2011						2010
(Thousands of dollars)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Financial assets (liabilities):
Canadian government securities with maturities greater than 90 days at the date of acquisition	$	532,093			532,899			616,558			617,372
Current and long-term debt		(599,558	)		(715,208	)		(939,391	)		(1,064,225	)

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Financial Instruments and Risk Management

12 Months Ended

Dec. 31, 2011

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 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 are accounted for as hedges and the gain or loss associated with recording the fair value of these contracts has been deferred in Accumulated Other Comprehensive Income until the anticipated transactions occur.

• Commodity Purchase Price Risks – The Company is subject to commodity price risks at its ethanol production facilities in the United States related to corn that it will purchase in the future for feedstock and to wet and dried distillers grain that it will sell in the future. At December 31, 2011 and 2010, the Company had open physical delivery fixed-price commitment contracts for purchase of approximately 8.0 million and 7.0 million bushels of corn, respectively, for processing at its ethanol plants. The Company also had outstanding derivative contracts to sell a similar volume of these fixed-price quantities and buy them back at future prices in effect on the expected date of delivery under the purchase commitment contracts. Also, at December 31, 2011, the Company had open physical delivery fixed-price commitment contracts to sell approximately 1.1 million equivalent bushels of wet and dried distillers grain with solubles; it also had outstanding derivative contracts to purchase a similar volume of these fixed-price quantities and sell them back at future prices in effect on the expected date of delivery under the sale commitment contracts. Additionally, at December 31, 2011, the Company had outstanding derivative contracts to sell 2.9 million bushels of corn and buy them back when certain corn inventories are expected to be processed at the Hankinson, North Dakota, and Hereford, Texas facilities. The fair value of these open commodity derivative contracts was a liability of $292,000 at December 31, 2011 and an asset of $750,000 at December 31, 2010.

The Company was formerly subject to commodity price risk related to crude oil feedstocks it held in inventory at its U.S. refineries. Short-term derivative instruments were outstanding at December 31, 2010 to manage the 2011 purchase price of 118,000 barrels of crude oil at the Company’s Superior, Wisconsin refinery. The fair value of these open crude oil derivative contracts was a liability of $335,000 at December 31, 2010. The Superior refinery was sold in 2011 and has been accounted for as discontinued operations. There were no open crude oil feedstock derivative contracts at December 31, 2011.

• 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, 2011 and 2010, short-term derivative instruments were outstanding to manage the currency risk of approximately $16,000,000 and $38,000,000, respectively, of U.S. dollar accounts receivable balances associated with the Company’s sale of Canadian crude oil. Also short-term derivative instruments were outstanding at December 31, 2011 and 2010 to manage the currency risk of approximately $472,000,000 and $366,000,000 equivalent, respectively, of ringgit denominated income tax liability balances in the Company’s Malaysian operations. The fair value of open foreign currency derivative contracts was a liability of $8,459,000 at December 31, 2011 and an asset of $7,261,000 at December 31, 2010.

At December 31, 2011 and 2010, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

December 31, 2011

December 31, 2010

Asset Derivatives

Liability Derivatives

Asset Derivatives

Liability Derivatives

(Thousands of dollars)

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Type of derivative contract

Commodity

Accounts Receivable

$197

Accounts Payable

$489

Accounts Receivable

$750

Accounts Payable

$626

Foreign exchange

—

—

Accounts Payable

$8,459

Accounts Receivable

$7,261

—

—

For the years ended December 31, 2011 and 2010, 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, 2011					Year Ended December 31, 2010
(Thousands of dollars)	Location of Gain (Loss) Recognized in Income on Derivative		Amount of Gain (Loss) Recognized in Income on Derivative			Location of Gain (Loss) Recognized in Income on Derivative		Amount of Gain (Loss) Recognized in Income on Derivative
Type of derivative contract
Commodity		Crude Oil and Product Purchases	$	5,659			Crude Oil and Product Purchases	$	(7,577	)
Foreign exchange		Interest and Other Income (Loss)		(305	)		Interest and Other Income (Loss)		34,215
			$	5,354				$	26,638

• Interest Rate Risks – The Company has ten-year notes totaling $350,000,000 that mature on May 1, 2012. The Company currently anticipates replacing these notes at maturity with new ten-year notes, and it therefore has risk associated with the interest rate related to the anticipated sale of these notes in 2012. To manage this risk, in 2011 the Company entered into a series of derivative contracts known as forward starting interest rate swaps that mature in May 2012. The Company utilizes hedge accounting to defer any gain or loss on these contracts until the payment of interest on these anticipated notes occurs. There was no impact in the 2011 Consolidated Statements of Income associated with accounting for these interest rate derivative contracts.

At December 31, 2011, the fair value of these interest rate derivative contracts, which have been designated as hedging instruments for accounting purposes, are presented in the following table.

	December 31, 2011
	Liability Derivatives
(Thousands of dollars)	Balance Sheet Location		Fair Value
Type of derivative contract
Interest rate		Accounts Payable	$	25,927

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 crude oil, natural gas and petroleum products to a large number of customers in the United States and the United Kingdom. The Company also has credit risk for sales of crude oil and natural gas to various customers in Canada, and sales of crude oil to various customers in Malaysia and Republic of the Congo. Natural gas produced in Malaysia is essentially all sold to the country’s national oil company. 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 limits 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.

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Geographic Information on Certain Long-Lived Assets (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	$ 10,481.9	$ 10,374.6	$ 9,071.8
United States
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	2,953.1	3,178.8	2,907.2
Canada
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	3,493.4	3,028.8	2,324.6
Malaysia
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	3,154.8	2,807.0	2,714.9
United Kingdom
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	694.7	706.3	704.7
Republic of the Congo
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	133.7	579.4	399.9
Other
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	$ 52.2	$ 74.3	$ 20.5

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Commitments

12 Months Ended

Dec. 31, 2011

Commitments

Note Q – Commitments

The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2012 natural gas sales volumes from the Tupper and Tupper West areas in Western Canada. The contract calls for natural gas deliveries of approximately 50 million cubic feet per day during 2012 at an average price of Cdn$4.43 per thousand cubic feet at the AECO “C” sales point. These contracts have 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, production facilities at the Thunder Hawk and West Patricia fields, certain motor fuel stations in the U.K. and land under a portion of gasoline stations in the U.S. During the next five years, expected future rental payments under all operating leases are approximately $161,752,000 in 2012, $138,121,000 in 2013, $127,044,000 in 2014, $115,708,000 in 2015 and $34,525,000 in 2016. Rental expense for noncancellable operating leases, including contingent payments when applicable, was $185,016,000 in 2011, $178,410,000 in 2010 and $124,693,000 in 2009.

The Company has entered into contracts to hire various drilling rigs and associated equipment for periods beyond December 31, 2011. These rigs will primarily be utilized for drilling operations in the Gulf of Mexico, onshore U.S. and Canada, offshore Malaysia, Kurdistan, Australia and Republic of the Congo. Future commitments under these contracts, all of which expire by 2015, total approximately $515,292,000. 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 agreements providing for processing, production handling and transportation services for natural gas in 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 $23,823,000 in 2012, $18,146,000 in 2013, $18,452,000 in 2014, $16,676,000 in 2015 and $11,800,000 in 2016. 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 $24,791,000 in 2011, $10,337,000 in 2010 and $11,860,000 in 2009.

Additionally, the Company has a Reserved Capacity Service Agreement providing for the availability of needed crude oil storage capacity for certain oil fields through 2020. Under the agreement, the Company must make specified minimum payments monthly. Future required minimum annual payments are approximately $1,000,000 in 2012 through 2016. In addition, the Company is required to pay additional amounts depending on actual crude oil quantities stored under the agreement. Total payments under the agreement were $918,000 in 2011, $3,202,000 in 2010 and $2,743,000 in 2009.

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 from 2007 to 2016 to provide scholarships for a specified amount of college expenses for eligible graduates of El Dorado High School in Arkansas. The first six payments have been made through January 2012. 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 included in Selling and General Expense was $1,317,000 in 2011, $1,534,000 in 2010 and $1,739,000 in 2009.

Commitments for capital expenditures were approximately $1,849,100,000 at December 31, 2011, including $839,500,000 for field development and future work commitments in Malaysia, $149,700,000 for costs to develop deepwater Gulf of Mexico fields, $124,500,000 for work in the Eagle Ford Shale and $127,500,000 for future work commitments offshore Brunei.

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Weighted Average Asset Allocation for Funded Pension Benefit Plans (Detail) (Funded Defined Benefit Pension Plans)	Dec. 31, 2011	Dec. 31, 2010
Funded Defined Benefit Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Equity securities	62.30%	62.70%
Fixed income securities	36.50%	36.20%
Cash equivalents	1.20%	1.10%
Defined Benefit Plan, Actual Plan Asset Allocations, Total	100.00%	100.00%

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Earnings per Share (Tables)

12 Months Ended

Dec. 31, 2011

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, 2011. No difference existed between net income used in computing basic and diluted income per Common share for these years.

(Weighted-average shares outstanding)	2011		2010		2009
Basic method		193,409,621		191,830,357		190,767,077
Dilutive stock options		1,102,781		1,327,457		1,701,373
Diluted method		194,512,402		193,157,814		192,468,450

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Noncash Operating Working Capital (Increased) Decreased (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010		Dec. 31, 2009
Accounts receivable	$ (43,630)	$ (4,363)		$ (402,481)
Inventories	(59,413)	(28,231)		(114,569)
Prepaid expenses	20,548	14,567		7,209
Deferred income tax assets	8,488	(80,073)		14,772
Accounts payable and accrued liabilities	(478,029)	766,067		365,257
Current income tax liabilities	(273,118)	(28,401)		(64,878)
Net (increase) decrease in noncash operating working capital	$ (825,154)	$ 639,566	[1]	$ (194,690)	[1]

[1] Reclassified to conform to current presentation.

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Acquisitions (Tables)

12 Months Ended

Dec. 31, 2011

Ethanol Plant in Hereford, Texas

Purchase Price Allocation for Based on Estimated Fair Value of Assets Acquired

the first quarter of 2011. The Company allocated the purchase price for the Hereford facility based on the fair value of the assets acquired as presented in the following table.

(Thousands of dollars)
Land and land improvements	$	2,379
Buildings and improvements		639
Machinery and transportation equipment		36,982
Total purchase price – Hereford ethanol facility	$	40,000

Ethanol Plant in Hankinson, North Dakota

Purchase Price Allocation for Based on Estimated Fair Value of Assets Acquired

Statement of Income beginning on the date of acquisition. The Company allocated the purchase price for the Hankinson facility based on the 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 – Hankinson ethanol facility	$	92,000

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Carrying Amounts and Estimated Fair Values of Financial Instruments (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Financial assets (liabilities), Carrying value
Canadian government securities with maturities greater than 90 days at the date of acquisition	$ 532,093	$ 616,558
Current and long-term debt	(599,558)	(939,391)
Financial assets (liabilities), Fair value
Canadian government securities with maturities greater than 90 days at the date of acquisition	532,899	617,372
Current and long-term debt	$ (715,208)	$ (1,064,225)

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010		Dec. 31, 2009
Net income	$ 872,702	$ 798,081	[1]	$ 837,621	[1]
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation	(91,247)	165,940		375,951
Retirement and postretirement benefit plan adjustments	(30,909)	(3,699)		(1,067)
Loss deferred on interest rate hedges	(16,852)	0		0
Other comprehensive income (loss)	(139,008)	162,241		374,884
Comprehensive Income	$ 733,694	$ 960,322		$ 1,212,505

[1] Reclassified to conform to current presentation.

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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 $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Funded Defined Benefit Pension Plans | Qualified Pension Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Plans where accumulated benefit obligation exceeds fair value of plan assets, Projected benefit obligation	$ 513,444	$ 478,234
Plans where accumulated benefit obligation exceeds fair value of plan assets, Aggregate accumulated benefit Obligation	459,556	431,668
Plans where accumulated benefit obligation exceeds fair value of plan assets, Aggregate fair value of plan assets	374,360	383,683
Unfunded Defined Benefit Pension Plans | Non-Qualified Pension Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Plans where accumulated benefit obligation exceeds fair value of plan assets, Projected benefit obligation	96,754	78,667
Plans where accumulated benefit obligation exceeds fair value of plan assets, Aggregate accumulated benefit Obligation	82,642	69,104
Plans where accumulated benefit obligation exceeds fair value of plan assets, Aggregate fair value of plan assets	0	0
Unfunded Other Postretirement Benefit Plans
Defined Benefit Plan Disclosure [Line Items]
Plans where accumulated benefit obligation exceeds fair value of plan assets, Projected benefit obligation	114,962	122,879
Plans where accumulated benefit obligation exceeds fair value of plan assets, Aggregate accumulated benefit Obligation	114,962	122,879
Plans where accumulated benefit obligation exceeds fair value of plan assets, Aggregate fair value of plan assets	$ 0	$ 0

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Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

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. Murphy markets petroleum products under various brand names and to unbranded wholesale customers in the United States and United Kingdom. It owns two ethanol production facilities in the United States and one petroleum refinery in the United Kingdom. In 2011, the Company sold two U.S. petroleum refineries and certain associated marketing assets. The Company has announced its intention to sell the U.K. refining and marketing 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. 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 Company’s 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 December 31, 2011 and 2010, 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-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. 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, 2011, the Company owned Canadian government securities with maturities greater than 90 days at date of acquisition that had a carrying value of $532,093,000.

ACCOUNTS RECEIVABLE – The Company’s accounts receivable primarily consists of amounts owed to the Company by customers for sales of crude oil, natural gas and refined products under varying credit arrangements. 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.

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 are generally 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 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. Refineries, certain marketing facilities and certain common 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.

Turnarounds for major processing units at refineries 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 refineries and Syncrude varies depending on operating requirements and events. Murphy defers turnaround costs incurred and amortizes such costs through Operating Expenses over the period until the next scheduled turnaround. All other maintenance and repairs are expensed as incurred. Renewals and betterments are capitalized. Major turnarounds occurred in 2010 at both the Meraux, Louisiana, and Milford Haven, Wales, refineries.

INVENTORIES – 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 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 is generally carried at average cost and is included in Finished Products Inventory. Materials and supplies are valued at the lower of average cost or estimated value and generally consist of tubulars and other drilling equipment as well as 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.

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 at least 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 2011 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, 2011. 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. See Note B for accounting changes applicable to goodwill recoverability testing beginning in 2012.

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. Petroleum revenue taxes are provided using the estimated effective tax rate over the life of applicable U.K. properties. 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 Spain 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 currency into U.S. dollars are included in Accumulated Other Comprehensive Income (Loss) in Stockholders’ Equity.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES – The fair value of a derivative instrument is recognized as an asset or liability in the Company’s Consolidated Balance Sheet. Upon entering into a derivative contract, the Company may designate the derivative as either a fair value hedge or a cash flow hedge, or decide that the contract is not a hedge, 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 used 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. Changes in the fair value of a qualifying fair value hedge are recorded in earnings along with the gain or loss on the hedged item. Changes in the fair value of a qualifying cash flow hedge are 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 Statement of Income, the fair value of the associated cash flow hedge is reclassified from other comprehensive income into earnings. Ineffective portions of a cash flow hedge derivative’s change in fair value are 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.

STOCK-BASED COMPENSATION – The fair value of awarded stock options, restricted stock and restricted stock units 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 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 and restricted stock units and expense is recognized over the three-year vesting period. The fair value of time-lapse restricted stock 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 and 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.

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.

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Results of Operations Associated with Discontinued Operations (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010		Dec. 31, 2009
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues	$ 3,700,789	$ 3,175,353		$ 2,242,840
Income (loss) from operations before income taxes	188,231	25,521		34,068
Gain on sale before income taxes	12,684	0		117,557
Total income from discontinued operations before taxes	200,915	25,521		151,625
Provision for income taxes	69,145	6,999		27,858
Income from discontinued operations	131,770	18,522	[1]	123,767	[1]
United States
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues	3,700,789	3,175,353		2,117,186
Income (loss) from operations before income taxes	188,231	25,521		41,760
Gain on sale before income taxes	12,684	0		0
Ecuador
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues	0	0		125,654
Income (loss) from operations before income taxes	0	0		(7,692)
Gain on sale before income taxes	$ 0	$ 0		$ 117,557

[1] Reclassified to conform to current presentation.

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Changes in Performance-Based RSU Outstanding (Detail) (Performance-Based Restricted Stock)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Performance-Based Restricted Stock
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	1,023,492	872,027	806,822
Granted	521,423	449,100	375,050
Awarded	(309,656)	(252,551)	0
Forfeited	(60,767)	(45,084)	(309,845)
Balance at end of year	1,174,492	1,023,492	872,027

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Fair Value of Assets and Liabilities (Detail) (Fair Value, Measurements, Recurring, USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		$ 8,011
Derivative liabilities	(42,905)	(8,298)
Foreign Exchange Derivative Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		7,261
Derivative liabilities	(8,459)
Commodity Derivative Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	197	750
Derivative liabilities	(489)	(626)
Nonqualified employee savings plans
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	(8,030)	(7,672)
Interest rate derivative contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	(25,927)
Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		0
Derivative liabilities	(8,030)	(7,672)
Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign Exchange Derivative Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		0
Derivative liabilities	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity Derivative Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) | Nonqualified employee savings plans
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	(8,030)	(7,672)
Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest rate derivative contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0
Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		8,011
Derivative liabilities	(34,875)	(626)
Significant Other Observable Inputs (Level 2) | Foreign Exchange Derivative Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		7,261
Derivative liabilities	(8,459)
Significant Other Observable Inputs (Level 2) | Commodity Derivative Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	197	750
Derivative liabilities	(489)	(626)
Significant Other Observable Inputs (Level 2) | Nonqualified employee savings plans
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0	0
Significant Other Observable Inputs (Level 2) | Interest rate derivative contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	(25,927)
Significant Unobservable Inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		0
Derivative liabilities	0	0
Significant Unobservable Inputs (Level 3) | Foreign Exchange Derivative Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets		0
Derivative liabilities	0
Significant Unobservable Inputs (Level 3) | Commodity Derivative Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Significant Unobservable Inputs (Level 3) | Nonqualified employee savings plans
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0	0
Significant Unobservable Inputs (Level 3) | Interest rate derivative contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	$ 0

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Long-term Debt (Parenthetical) (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011
6.375% notes, due 2012, net of unamortized discount of $38
Debt Instrument [Line Items]
Notes payable, unamortized discount	$ 38
7.05% notes, due 2029, net of unamortized discount of $1,616
Debt Instrument [Line Items]
Notes payable, unamortized discount	$ 1,616

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Contingencies

12 Months Ended

Dec. 31, 2011

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. With the sale of the U.S. refineries in 2011, the Company retained certain liabilities related to environmental matters. The Company also obtained insurance covering certain levels of environmental exposures. 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 Company’s liability for remedial obligations includes certain amounts that are based on anticipated regulatory approval for proposed remediation of former refinery waste sites. Although regulatory authorities may require more costly alternatives than the proposed processes, the cost of such potential alternative processes is not expected to exceed the accrued liability by a material amount. Certain environmental expenditures are likely to be recovered by the Company from other sources, primarily environmental funds maintained by certain states. Since no assurance can be given that future recoveries from other sources will occur, the Company has not recorded a benefit for likely recoveries at December 31, 2011.

The U.S. Environmental Protection Agency (EPA) currently considers the Company to be a Potentially Responsible Party (PRP) at one Superfund site. The potential total cost to all parties to perform necessary remedial work at this site may be substantial. However, based on current negotiations and available information, the Company believes that it is a de minimis party as to ultimate responsibility at the Superfund site. Accordingly, the Company has not recorded a liability for remedial costs at the Superfund site at December 31, 2011. 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 this site or other Superfund sites. The Company believes that its share of the ultimate costs to clean-up this Superfund site will be immaterial and will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.

LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

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, 2011, the Company had contingent liabilities of $7,798,000 under a financial guarantee and $162,906,000 on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to the guarantee and the letters of credit because it is believed that the likelihood of having these drawn is remote.

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SUMMARY OF OIL RESERVES AND SUMMARY OF NATURAL GAS RESERVES - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2011 MetricTon
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
Minimum
Reserve Quantities [Line Items]
Catalytic cracking process efficiency level	85.00%
Maximum
Reserve Quantities [Line Items]
Catalytic cracking process efficiency level	90.00%
Canada | Synthetic Oil
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 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% - 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 reserves in this filing are the final synthetic crude oil product.
Malaysia | Oil Reserves
Reserve Quantities [Line Items]
Oil and natural gas reserves associated with the production sharing contracts	104,400,000
Malaysia | Natural Gas Reserves
Reserve Quantities [Line Items]
Oil and natural gas reserves associated with the production sharing contracts	347,800,000,000
Malaysia | Natural Gas Reserves | Kikeh Field
Reserve Quantities [Line Items]
Oil and natural gas reserves associated with the production sharing contracts	94,000,000,000
Natural gas proved reserves expected to receive sale proceeds, per thousand cubic foot	0.24
Republic of the Congo | Oil Reserves
Reserve Quantities [Line Items]
Oil and natural gas reserves associated with the production sharing contracts	2,300,000

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Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Inclusion of synthetic oil reserves beginning in 2009	$ 0	[1]	$ 0	[1]	$ 378.9	[1]
Net changes in prices, production costs and development costs	(370.5)		240.1		675.1
Sales and transfers of oil and gas produced, net of production costs	(3,273.5)		(2,792.2)		(2,381.5)
Net change due to extensions and discoveries	3,300.9		1,022.2		1,976.2
Net change due to purchases and sales of proved reserves	0		48.7		(36.7)
Development costs incurred	1,881.5		1,271.3		1,344.1
Accretion of discount	827.7		698.9		422.1
Revisions of previous quantity estimates	892.5		798.8		267.8
Net change in income taxes	(1,029.4)		(450.2)		(454.8)
Net increase	2,229.2		837.6		2,191.2
Standardized measure	7,923.2		5,694.0		4,856.4
Beginning of Period
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Standardized measure	5,694.0		4,856.4		2,665.2
End of Period
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Standardized measure	$ 7,923.2		$ 5,694.0		$ 4,856.4

[1] Prior to 2009, discounted future net cash flows from synthetic oil operations were excluded from this report. With the SEC's change in the definition of proved reserves to include synthetic oil as proved reserves, the Company has included synthetic oil reserves in this table beginning in 2009.

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Reconciliation of Income Taxes Based on U.S. Statutory Tax Rate to Income Tax Expense (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010		Dec. 31, 2009
Reconciliation of Statutory Federal Tax Rate [Line Items]
Income tax expense based on the U.S. statutory tax rate	$ 542,844	$ 486,049		$ 432,395
Foreign income subject to foreign taxes at a rate different than the U.S. statutory rate	10,053	56,367		33,395
State income taxes, net of federal benefit	19,742	10,066		4,607
Increase in deferred tax asset valuation allowance related to foreign exploration expenditures	102,714	47,128		34,431
Impairment of Azurite field with no tax benefit	129,010	0		0
Malaysian tax benefits on prior year costs in Block P	(25,573)	0		0
Increase in United Kingdom oil and gas tax rate	14,461	0		0
Other, net	16,800	9,541		16,731
Total	$ 810,051	$ 609,151	[1]	$ 521,559	[1]

[1] Reclassified to conform to current presentation.

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VALUATION ACCOUNTS AND RESERVES

12 Months Ended

Dec. 31, 2011

VALUATION ACCOUNTS AND RESERVES

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

SCHEDULE II – VALUATION ACCOUNTS AND RESERVES

(Millions of dollars)	Balance at January 1		Charged (Credited) to Expense		Deductions			Other*			Balance at December 31
2011
Deducted from asset accounts:
Allowance for doubtful accounts	$	8.0		0.2		(0.3	)		0.0			7.9
Deferred tax asset valuation allowance		305.3		140.5		0.0			0.0			445.8
2010
Deducted from asset accounts:
Allowance for doubtful accounts	$	7.8		0.5		(0.2	)		(0.1	)		8.0
Deferred tax asset valuation allowance		290.2		15.1		0.0			0.0			305.3
2009
Deducted from asset accounts:
Allowance for doubtful accounts	$	7.3		0.9		(0.2	)		(0.2	)		7.8
Deferred tax asset valuation allowance		266.8		23.4		0.0			0.0			290.2

*Amounts primarily represent changes in foreign currency exchange rates.

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Employee and Retiree Benefit Plans

12 Months Ended

Dec. 31, 2011

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 the overfunded or underfunded status as of year-end of its defined benefit plans as an asset or liability in its consolidated balance sheet and to recognize changes in that funded status between periods through comprehensive income.

The tables that follow provide a reconciliation of the changes in the plans’ benefit obligations and fair value of assets for the years ended December 31, 2011 and 2010 and a statement of the funded status as of December 31, 2011 and 2010.

	Pension Benefits						Other Postretirement Benefits
(Thousands of dollars)	2011			2010			2011			2010
Change in benefit obligation
Obligation at January 1	$	575,300			521,471			122,879			101,750
Service cost		22,406			20,706			4,547			4,133
Interest cost		30,785			30,144			6,141			6,211
Plan amendments		483			0			0			0
Participant contributions		35			33			1,049			956
Actuarial loss		66,010			30,544			4,791			14,646
Medicare Part D subsidy		0			0			555			528
Exchange rate changes		(2,109	)		(1,357	)		(11	)		22
Benefits paid		(27,745	)		(26,241	)		(5,667	)		(5,367	)
Reduction due to sale of the Superior refinery		(23,021	)		0			0			0
Special termination benefits		695			0			0			0
Curtailments		(13,271	)		0			(19,322	)		0
Obligation at December 31		629,568			575,300			114,962			122,879
Change in plan assets
Fair value of plan assets at January 1		416,272			375,947			0			0
Actual return on plan assets		(1,415	)		46,792			0			0
Employer contributions		38,357			20,651			4,063			3,883
Participant contributions		35			33			1,049			956
Medicare Part D subsidy		0			0			555			528
Exchange rate changes		(1,786	)		(422	)		0			0
Benefits paid		(27,745	)		(26,241	)		(5,667	)		(5,367	)
Distribution to acquirer of the Superior refinery		(18,720	)		0			0			0
Other		(648	)		(488	)		0			0
Fair value of plan assets at December 31		404,350			416,272			0			0
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets		10,621			14,191			0			0
Other accrued liabilities		(3,488	)		(3,378	)		(5,022	)		(5,223	)
Deferred credits and other liabilities		(232,351	)		(169,841	)		(109,940	)		(117,656	)
Funded status and net plan liability recognized at December 31		$(225,218)			(159,028	)		(114,962	)		(122,879	)

The Company sold the Meraux, Louisiana and Superior, Wisconsin refineries in 2011. These sales reduced the pension benefit obligation due to a curtailment whereby no additional future benefits will be earned by the employees at the refineries after the sales. Additionally, the acquirer of the Superior refinery assumed the retirement plan covering the union employees. Therefore during 2011, the pension benefit obligation was reduced and certain applicable retirement plan assets were distributed to the acquirer related to the plan liabilities assumed by the acquirer.

At December 31, 2011, 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 Benefits			Other Postretirement Benefits
Net actuarial loss	$	(216,276	)		(35,336	)
Prior service (cost) credit		(5,262	)		1,130
Transitional asset (liability)		1,609			(17	)
	$	(219,929	)		(34,223	)

Amounts included in AOCI at December 31, 2011 that are expected to be amortized into net periodic benefit expense during 2012 are shown in the following table.

(Thousands of dollars)	Pension Benefits			Other Postretirement Benefits
Net actuarial loss	$	(16,872	)		(1,846	)
Prior service (cost) credit		(1,258	)		173
Transitional asset (liability)		535			(8	)
	$	(17,595	)		(1,681	)

The table that follows includes projected benefit obligations, accumulated benefit obligations and fair value of plan assets for plans where the accumulated benefit obligation exceeded the fair value of plan assets.

	Projected Benefit Obligations				Accumulated Benefit Obligations				Fair Value of Plan Assets
(Thousands of dollars)	2011		2010		2011		2010		2011		2010
Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets	$	513,444		478,234		459,556		431,668		374,360		383,683
Unfunded nonqualified and directors’ plans where accumulated benefit obligation exceeds fair value of plan assets		96,754		78,667		82,642		69,104		0		0
Unfunded other postretirement plans		114,962		122,879		114,962		122,879		0		0

The table that follows provides the components of net periodic benefit expense for each of the three years ended December 31, 2011.

	Pension Benefits									Other Postretirement Benefits
(Thousands of dollars)	2011			2010			2009			2011			2010			2009
Service cost	$	22,406			20,706			17,052			4,547			4,133			3,121
Interest cost		30,785			30,144			28,767			6,141			6,211			5,688
Expected return on plan assets		(25,919	)		(24,199	)		(20,375	)		0			0			0
Amortization of prior service cost		1,314			1,558			1,635			(240	)		(263	)		(263	)
Amortization of transitional asset (liability)		(536	)		(514	)		(466	)		8			8			0
Recognized actuarial loss		12,484			12,257			10,305			2,329			2,790			1,551
		40,534			39,952			36,918			12,785			12,879			10,097
Termination benefits expense		695			0			1,867			0			0			0
Curtailment expense		1,036			0			575			(605	)		0			397
Net periodic benefit expense	$	42,265			39,952			39,360			12,180			12,879			10,494

The increase in net periodic benefit expense in 2011 compared to prior years was primarily attributable to additional employees covered by retirement plans for most of 2011, plus termination and curtailment expenses related to sale of two U.S. petroleum refineries in 2011.

The preceding tables in this note include the following amounts related to foreign benefit plans.

	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)	2011		2010		2011		2010
Benefit obligation at December 31	$	153,947		133,751		454		430
Fair value of plan assets at December 31		135,608		126,075		0		0
Net plan liabilities recognized		18,339		7,676		454		430
Net periodic benefit expense		8,978		9,784		82		60

The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2011 and 2010 and net periodic benefit expense for 2011 and 2010.

	Benefit Obligations												Net Periodic Benefit Expense
	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
	December 31						December 31						Year						Year
	2011			2010			2011			2010			2011			2010			2011			2010
Discount rate		5.00	%		5.66	%		4.87	%		5.66	%		5.50	%		5.88	%		5.50	%		5.90	%
Expected return on plan assets		6.48	%		6.56	%		0	%		0	%		6.48	%		6.56	%		0	%		0	%
Rate of compensation increase		4.22	%		4.19	%		0	%		0	%		4.22	%		4.19	%		0	%		0	%

The discount rates used for purposes of determining the plan obligations and expense are based on the universe of high-quality corporate bonds that are available within each country. Cash flow analyses are performed in which a spot yield curve is used to discount projected benefit payment streams for the most significant plans. The discounted cash flows are used to determine an equivalent single rate which is the basis for selecting the discount rate within each country. Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics. Expected compensation increases are based on anticipated future averages for the Company.

Benefit payments, reflecting expected future service as appropriate, which are expected to be paid in future years from the assets of the plans or by the Company are shown in the following table.

(Thousands of dollars)	Pension Benefits		Other Postretirement Benefits
2012	$	28,688		5,835
2013		29,911		6,072
2014		31,237		6,262
2015		32,001		6,449
2016		32,738		6,747
2017-2021		185,062		38,516

For purposes of measuring postretirement benefit obligations at December 31, 2011, the future annual rates of increase in the cost of health care were assumed to be 7.8% for 2012 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, 2011	$	2,033		(1,594	)
Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2011		17,041		(13,810	)

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) 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.

The Company provides a health care benefit plan to eligible U.S. employees and most U.S. retired employees. The new law did not significantly affect the Company’s consolidated financial statements as of December 31, 2011 and 2010 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 the evaluation performed 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 reminder 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, 2011 and 2010 are presented in the following table.

	December 31,
	2011			2010.
Equity securities		62.3	%		62.7	%
Fixed income securities		36.5			36.2
Cash equivalents		1.2			1.1
		100.0	%		100.0	%

The Company’s weighted average expected return on plan assets was 6.48% in 2011 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 6.48% expected return was based on an expected average future equity securities return of 8.29% and a fixed income securities return of 4.53% and is net of average expected investment expenses of 0.28%. Over the last 10 years, the return on funded retirement plan assets has averaged 5.06%.

At December 31, 2011 and 2010, the fair value measurements of retirement plan assets within the fair value hierarchy were as follows:

			Fair Value Measurements Using
(Thousands of dollars)	Fair Value at December 31, 2011		Quoted Prices in Active  Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Domestic Plans
Equity securities:
U.S. core equity	$	73,986		73,986		0		0
U.S. small/midcap		18,236		18,236		0		0
U.S. long/short equity fund		13,860		0		13,860		0
International commingled trust fund		56,156		0		56,156		0
Emerging market commingled equity fund		6,980		0		6,980		0
Fixed income securities:
U.S. fixed income		76,764		0		76,764		0
International commingled trust fund		13,109		0		13,109		0
Emerging market mutual fund		6,448		0		6,448		0
Cash and equivalents		3,203		3,203		0		0
Total Domestic Plans		268,742		95,425		173,317		0
Foreign Plans
Equity securities funds		59,349		0		59,349		0
Fixed income securities funds		44,442		0		44,442		0
Diversified pooled fund		29,990		0		29,990		0
Cash and equivalents		1,827		1,827		0		0
Total Foreign Plans		135,608		1,827		133,781		0
Total	$	404,350		97,252		307,098		0

			Fair Value Measurements Using
(Thousands of dollars)	Fair Value at December  31, 2010		Quoted Prices in Active  Markets for Identical Assets (Level 1)		Significant Other  Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Domestic Plans
Equity securities:
U.S. core equity	$	79,550		79,550		0		0
U.S. small/midcap		17,324		17,324		0		0
U.S. long/short equity fund		14,205		0		14,205		0
International commingled trust fund		61,531		0		61,531		0
Emerging market commingled equity fund		7,131		0		7,131		0
Fixed income securities:
U.S. fixed income		81,989		0		81,989		0
International commingled trust fund		19,833		0		19,833		0
Emerging market mutual fund		7,045		0		7,045		0
Cash and equivalents		1,589		1,589		0		0
Total Domestic Plans		290,197		98,463		191,734		0
Foreign Plans
Equity securities funds		58,353		0		58,353		0
Fixed income securities funds		31,948		0		31,948		0
Diversified pooled fund		32,590		0		32,590		0
Cash and equivalents		3,184		3,184		0		0
Total Foreign Plans		126,075		3,184		122,891		0
Total	$	416,272		101,647		314,625		0

The definition of levels within the fair value hierarchy in the tables above is included in Note O.

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, while U.S. long/short equity funds permit withdrawals annually for the first year and then semi-annually thereafter. 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.

During 2011, the Company made contributions of $23,736,000 to its domestic defined benefit pension plans, $14,621,000 to its foreign defined benefit pension plans, $4,011,000 to its domestic postretirement benefits plan and $52,000 to its foreign postretirement benefits plan. The Company currently expects during 2012 to make contributions of $27,171,000 to its domestic defined benefit pension plans, $8,311,000 to its foreign defined benefit pension plans, $5,790,000 to its domestic postretirement benefits plan and $45,000 to its foreign postretirement benefits plan.

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. 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 $10,725,000 in 2011, $11,467,000 in 2010 and $11,617,000 in 2009.

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Weighted-Average Shares Outstanding for Computation of Basic and Diluted Income Per Common Share (Detail)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010		Dec. 31, 2009
Earnings Per Share Disclosure [Line Items]
Basic method	193,409,621	191,830,357	[1]	190,767,077	[1]
Dilutive stock options	1,102,781	1,327,457		1,701,373
Diluted method	194,512,402	193,157,814	[1]	192,468,450	[1]

[1] Reclassified to conform to current presentation.