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.