Murphy Oil (MUR) 8-K Murphy Oil Announces Preliminary Quarterly Earnings

Exhibit 99.1

MURPHY OIL ANNOUNCES PRELIMINARY QUARTERLY EARNINGS

EL DORADO, Arkansas, October 31, 2012 – Murphy Oil Corporation (NYSE: MUR) announced today that income from continuing operations in the third quarter of 2012 was $228.9 million ($1.17 per diluted share) compared to $347.3 million ($1.79 per diluted share) in the third quarter of 2011. Net income, which includes the results of discontinued operations, was $226.7 million ($1.16 per diluted share) in the third quarter 2012 compared to $406.1 million ($2.09 per diluted share) in the 2011 third quarter. Earnings in the 2012 quarter were below prior year levels primarily due to the effects of lower North American natural gas sales prices, weaker U.S. retail marketing margins, an income tax benefit in the 2011 quarter, and an unfavorable variance from foreign exchange.

During the third quarter of 2012, the Company’s Board of Directors agreed to sell the Company’s exploration and production operations in the United Kingdom. The sale of these assets is expected to be completed near year-end 2012. The results of these operations in both years, as well as the results of U.S. refining operations in 2011, are presented as discontinued operations. The results of discontinued operations was a loss of $2.2 million ($0.01 per diluted share) in the 2012 third quarter compared to income of $58.8 million ($0.30 per diluted share) in the 2011 quarter.

For the first nine months of 2012, income from continuing operations was $801.7 million ($4.12 per diluted share) compared to $847.4 million ($4.36 per diluted share) in 2011. The decline in continuing operations income in 2012 was primarily attributable to weaker U.S. retail marketing margins and an unfavorable variance in the effects of foreign exchange in the current year. Net income in 2012 totaled $812.2 million ($4.17 per diluted share) compared to $986.6 million ($5.07 per diluted share) for the same period in 2011. Net income in the current year included discontinued operations income of $10.5 million ($0.05 per diluted share) compared to discontinued operations income of $139.2 million ($0.71 per diluted share) in 2011.

Net Income

	Three Months Ended September 30					Nine Months Ended September 30
(Millions of Dollars)	2012			2011		2012			2011
Exploration and Production	$	221.1			273.4		760.0			758.8
Refining and Marketing		42.8			68.9		119.1			129.3
Corporate		(35.0	)		5.0		(77.4	)		(40.7	)
Income from continuing operations		228.9			347.3		801.7			847.4
Income (loss) from discontinued operations		(2.2	)		58.8		10.5			139.2
Net income	$	226.7			406.1		812.2			986.6
Income per Common share – Diluted:
Income from continuing operations	$	1.17			1.79		4.12			4.36
Net income		1.16			2.09		4.17			5.07

Third Quarter 2012 vs. Third Quarter 2011

Exploration and Production (E&P)

The Company’s income contribution from E&P continuing operations was $221.1 million in the third quarter of 2012 compared to $273.4 million in the same quarter of 2011. The decline in earnings in the 2012 quarter compared to 2011 was primarily attributable to lower sales prices for North American natural gas, higher depreciation expense related to oil and natural gas volumes sold, and lower income tax benefits. Higher crude oil sales volumes in the current quarter partially offset these unfavorable variances. Depreciation expense rose in 2012 due to higher sales volumes, primarily in the Eagle Ford Shale of South Texas and at the Kikeh field, offshore Malaysia. The 2011 quarter included a tax benefit of $25.6 million in Malaysia based on a determination that past costs incurred in Block P are deductible against taxable income of Block K.

E&P Metrics

	Three Mos. Ended September 30				Nine Mos. Ended September 30
	2012		2011		2012		2011
Oil Production Volume – Bbls. per day		105,796		96,437		105,766		101,269
Natural Gas Sales Volume – MCF per day		454,573		470,183		495,711		447,044
Total BOE Production Volume – BOE per day		181,558		174,801		188,385		175,776
Average Realized Oil Sales Price – Per Bbl.	$	96.09		95.95		97.13		94.36
Average Realized North American Natural Gas Sales Price – Per MCF	$	2.61		4.20		2.43		4.26
Average Realized Sarawak Natural Gas Sales Price – Per MCF	$	7.59		7.54		7.79		6.76

Exploration expenses totaled $94.0 million in the third quarter 2012, up from $85.5 million in the 2011 quarter. The increase was primarily attributable to dry holes on the Central Dohuk license in the Kurdistan region of Iraq and in Malaysia during the 2012 quarter. These dry holes were partially offset by prior year costs that did not repeat for 3D seismic acquisition on Block CA-2, offshore Brunei, and other geophysical costs for licenses in the Kurdistan region of Iraq.

Worldwide production totaled 181,558 barrels of oil equivalent per day in the 2012 third quarter, up from 174,801 barrels of oil equivalent per day in the 2011 quarter. Crude oil, condensate and gas liquids production was 105,796 barrels per day in the 2012 quarter compared to 96,437 barrels per day in 2011. Higher oil volume produced in the 2012 quarter was mostly attributable to the Eagle Ford Shale area and the Kikeh field; development drilling operations are ongoing in the Eagle Ford Shale and new wells have been brought on production at Kikeh. These increases were partially offset by lower production in 2012 at Terra Nova, offshore Newfoundland, where the field was shut-in for maintenance during the quarter, and at the Azurite field, offshore Republic of the Congo, primarily due to a well that was offline awaiting a fourth quarter rig workover. Natural gas sales volumes averaged 454 million cubic feet per day in the 2012 quarter, down from 470 million cubic feet per day in the prior year’s quarter. Lower gas volumes were produced in 2012 at the Tupper area in British Columbia, where voluntary shut-ins have occurred and development activities have been deferred due to depressed North American natural gas sales prices. Additionally, gas sales volumes were lower offshore Sarawak, Malaysia mainly due to maintenance at the third party onshore receiving facilities. U.S. natural gas sales volumes rose in the third quarter 2012 due to higher production at Eagle Ford Shale properties.

The average sales price for the Company’s crude oil, condensate and gas liquids was $96.09 per barrel in the 2012 third quarter, compared to $95.95 per barrel in the 2011 quarter. Natural gas sales prices in North America averaged $2.61 per thousand cubic feet (MCF) in the 2012 quarter, down significantly from the $4.20 per MCF realized during the 2011 quarter. Natural gas sold from fields offshore Sarawak, Malaysia averaged $7.59 per MCF in the 2012 quarter compared to $7.54 per MCF a year ago.

Refining and Marketing (Downstream)

The Company’s refining and marketing business generated a profit from continuing operations of $42.8 million in the third quarter 2012 compared to a profit of $68.9 million in the 2011 third quarter. As previously noted, the Company sold two U.S. refineries and certain associated marketing terminals in 2011 and has reported these as discontinued operations. Those results are excluded from the Downstream results from continuing operations above. Continuing operations for the U.S. Downstream segment now includes the retail marketing business, two ethanol production facilities and wholesale marketing and trading operations retained after the sale of U.S. refining operations. On October 16, 2012, the Company announced a plan to separate its U.S. Downstream business into an independent company in 2013.

U.S. Downstream continuing operations generated a profit of $17.3 million in the third quarter of 2012 compared to a profit of $88.0 million in the 2011 quarter. The earnings decline for this business in 2012 was principally a result of weaker margins for both retail marketing and ethanol production operations compared to the prior year. U.S. retail marketing margins averaged 10.3 cents per gallon in the 2012 quarter compared to 20.0 cents per gallon in the 2011 quarter. Wholesale gasoline prices rose significantly in the third quarter 2012 and the retail marketing operation was unable to fully pass on this cost increase to its retail customers. The operating results at the two U.S. ethanol production facilities in 2012 were significantly weaker than the prior year due to crush spreads that were squeezed by high corn prices in the just completed quarter. The U.K. Downstream operations benefited from much stronger refining margins in the 2012 quarter compared to the prior year, as this business generated income of $25.5 million in the 2012 quarter compared to a loss of $19.1 million in the 2011 quarter. Unit margins in the U.K. in the 2012 quarter were more than $5.00 per barrel better than the prior year.

Downstream Metrics

	Three Mos. Ended September 30					Nine Mos. Ended September 30
	2012		2011			2012		2011
U.S. Retail Fuel Margins – Per gallon	$	0.103		0.200			0.125		0.165
U.S. Retail Merchandise Sales – Per store month	$	159,424		164,953			157,004		158,385
U.K. Refinery Inputs – Bbls. per day		132,932		138,041			132,282		134,346
U.K. R&M Unit Margins – Per Bbl.	$	3.44		(1.66	)		1.85		(1.37	)
Total Petroleum and Other Product Sales – Bbls. per day*		471,119		594,619			468,416		586,928

* Includes 170,609 bbls. per day in the 2011 three-month period and 163,597 bbls. per day in the 2011 nine-month period related to discontinued operations.

Corporate

The Corporate function incurred net costs of $35.0 million in the third quarter of 2012, significantly unfavorable to the net benefit of $5.0 million in the 2011 third quarter. The unfavorable variance in 2012 was primarily related to after-tax losses of $12.6 million in the current quarter for transactions denominated in foreign currencies. The 2011 quarter included an after-tax benefit of $28.3 million from foreign currency transactions. The foreign currency charge in the current year was primarily attributable to a strengthening of the Malaysian ringgit against the U.S. dollar, which led to increased costs in U.S. dollar terms for income tax liabilities that are to be paid in the local currency. The Malaysian ringgit weakened against the U.S. dollar in the 2011 third quarter, which lowered income tax liabilities in U.S. dollar terms in the prior year. The 2012 quarter had lower net interest expense compared to the prior year quarter, primarily associated with less interest expense incurred coupled with higher amounts of interest capitalized to oil development projects. Administrative costs were also higher in 2012 than 2011, with the increase primarily related to additional costs for employee compensation.

Discontinued Operations

Discontinued operations results were a loss of $2.2 million in the third quarter 2012, compared to income of $58.8 million in the third quarter 2011. Beginning in the third quarter 2012, the results of operations for the U.K. E&P operations have been reported as discontinued operations due to the anticipated sale of this business in the coming months. The 2011 results for these U.K. operations have been reclassified to conform to this presentation. Discontinued operations in 2011 included a loss of $11.6 million for the U.K. E&P operations and income of $70.4 million related to the two U.S. refineries sold in late 2011. The U.S. refining income from discontinued operations in 2011 included a net gain on sale of $16.9 million. Discontinued operations in both years included tax charges for enacted tax rate changes in the U.K.; these tax charges totaled $5.5 million in 2012 and $14.5 million in 2011.

First Nine Months 2012 vs. First Nine Months 2011

Exploration and Production (E&P)

The Company’s E&P continuing operations earned $760.0 million in the first nine months of 2012 compared to $758.8 million in the same period of 2011. The year-to-date 2012 earnings were essentially flat with the prior year as higher crude oil and natural gas sales volumes, higher sales prices for oil and Sarawak natural gas and lower exploration expenses in the current period were mostly offset by lower North American natural gas prices, higher production and depreciation expenses, and prior year income items that did not recur. These 2011 income items included $25.6 million of income tax benefits in Malaysia and a $13.1 million after-tax gain on sale of gas storage assets in Spain. Production and depreciation expenses rose in 2012 primarily due to higher production levels in the Eagle Ford Shale and at the Kikeh field.

Total exploration expense was $243.7 million in 2012, down from $303.8 million in 2011. The prior year had higher costs associated with unsuccessful wildcat drilling in Indonesia, Suriname and Brunei, plus higher geophysical and lease amortization costs for licenses in the Kurdistan region of Iraq. These were partially offset by higher dry hole costs in 2012 in the Gulf of Mexico, Malaysia and the Kurdistan region of Iraq.

Total worldwide production in 2012 was 188,385 barrels of oil equivalent per day, up from 175,776 barrel equivalents in 2011. Total crude oil, condensate and gas liquids production averaged 105,766 barrels per day in 2012, compared to 101,269 barrels per day in 2011. The increase in oil volumes was mostly attributable to higher

production at the Eagle Ford Shale and Kikeh. Oil volumes were lower in 2012 at the Terra Nova and Azurite fields. Natural gas sales volumes increased from 447 million cubic feet per day in 2011 to almost 496 million cubic feet per day in 2012, with the growth primarily attributable to higher gas volumes produced in the Tupper area. Future production in the Tupper area is expected to decline as drilling and production activities have been curtailed in this area due to weak North American natural gas sales prices.

The average sales price for crude oil and other liquids was $97.13 per barrel in 2012, up from $94.36 per barrel in 2011. North American natural gas was sold at an average price of $2.43 per MCF in 2012, down from the 2011 average of $4.26 per MCF. However, natural gas volumes produced offshore Sarawak were sold for $7.79 per MCF in 2012, compared to $6.76 per MCF in the prior year.

Refining and Marketing (Downstream)

The Company’s refining and marketing continuing operations generated a profit of $119.1 million in the first nine months of 2012 compared to a profit of $129.3 million in 2011. U.S. profits were $83.4 million in the first nine months of 2012, down from $172.9 million in the 2011 period. Income for the U.S. business declined in 2012 versus the prior year due to weaker margins for retail marketing and ethanol production operations. Per gallon margins for U.S. retail operations were 12.5 cents in 2012 compared to 16.5 cents in 2011. The U.K. Downstream business had a net profit of $35.7 million in the 2012 nine months compared to a net loss of $43.6 million in 2011, with the current year improvement fueled by significantly better refining margins.

Corporate

Corporate after-tax costs were $77.4 million in the first nine months of 2012 compared to costs of $40.7��million in the 2011 period. The higher net cost in the current year was mostly attributable to an unfavorable variance for transactions denominated in foreign currencies; these transactions led to after-tax costs of $3.5 million in the 2012 nine months compared to after-tax benefits of $32.2 million in 2011. The 2012 period also had higher administrative costs compared to 2011, primarily associated with more employee compensation expense in the later period. However, net interest expense was lower in the 2012 nine months, primarily due to higher amounts of interest costs capitalized to ongoing oil development projects.

Discontinued Operations

Income from discontinued operations of $10.5 million in the nine months of 2012 was associated with exploration and production operations in the U.K. Income from discontinued operations totaled $139.2 million in 2011, and included income of $6.8 million for U.K. E&P operations, plus a profit of $132.4 million associated with two U.S. refineries sold near the end of the third quarter 2011. The 2011 refinery profit included a $16.9 million net gain on sale of the two plants and associated marketing assets and inventories.

Steven A. Cossé, President and Chief Executive Officer, commented, “Our Company has recently made a number of key moves that are expected to enhance shareholder value when completed. As previously announced, the Board of Directors has set in place a plan to separate our U.S. Downstream business, which principally consists of over 1,150 retail service stations throughout the South and Midwest United States. We expect that this separation will occur in 2013. This action will allow the two key businesses – worldwide Upstream and U.S. Downstream – to gain sharper focus by fully concentrating on their own specific priorities, including strategic initiatives, allocation of

resources and deployment of capital. Additionally, the Company will pay a special dividend of $2.50 per share on December 3 and has authorized a share buyback program of up to $1 billion. Furthermore, we are reviewing our portfolio of assets to rationalize their strategic fit within the organization; as part of this process, we have decided to sell our three oil and gas fields in the United Kingdom. This asset sale is expected to be completed by year-end.

“We anticipate total worldwide production volumes of 207,000 barrels of oil equivalent per day in the fourth quarter of 2012. Sales volumes of oil and natural gas are projected to average 206,000 barrels of oil equivalent per day in the fourth quarter 2012. At the present time, we expect income from continuing operations in the fourth quarter to range between $1.10 and $1.70 per diluted share. The fourth quarter estimate includes projected exploration expense of between $60 million and $190 million, and earnings from our downstream businesses of approximately $63 million. Results could vary based on the risk factors described below.”

The public is invited to access the Company’s conference call to discuss third quarter 2012 results on Thursday, November 1 at 12:00 p.m. CDT either via the Internet through the Investor Relations section of Murphy Oil’s Web site athttp://www.murphyoilcorp.com/ir or via the telephone by dialing1-888-515-2880. The telephone reservation number for the call is1084159. Replays of the call will be available through the same address on Murphy Oil’s Web site, and a recording of the call will be available through November 5 by calling 1-888-203-1112 and referencing reservation number 1084159. Audio downloads will also be available on the Murphy Web site through December 3 and via Thomson StreetEvents for their service subscribers.

Summary financial data and operating statistics for the third quarter and nine months of 2012 with comparisons to 2011 are contained in the attached tables.

This press release 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, including Murphy’s plans to separate its U.S. downstream business, to pay a special dividend, to repurchase shares of its common stock and to divest its U.K. downstream operations, are subject to inherent risks and uncertainties. Factors that could cause one or more of these forecasted events not to occur include, but are not limited to, a failure to obtain necessary regulatory approvals, a failure to obtain assurances of anticipated tax treatment, a deterioration in the business or prospects of the U.S. downstream business, adverse developments in the U.S. downstream operation’s markets, adverse developments in the U.S. or global capital markets, credit markets or economies generally or a failure to execute a sale of the U.K. downstream operations on acceptable terms. 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, adverse foreign exchange movements, political and regulatory instability, and uncontrollable natural hazards. For further discussion of risk factors, see Murphy’s 2011 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission. Murphy undertakes no duty to publicly update or revise any forward-looking statements.

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MURPHY OIL CORPORATION

FUNCTIONAL RESULTS OF OPERATIONS (Unaudited)

(Millions of dollars)

	Three Months Ended September 30, 2012						Three Months Ended September 30, 2011*
	Revenues			Income			Revenues			Income
Exploration and production
United States	$	248.8			33.5			173.2			38.2
Canada		232.8			29.3			350.1			102.3
Malaysia		602.2			215.7			484.8			197.7
Republic of the Congo		—			(4.7	)		43.7			(.7	)
Other		—			(52.7	)		—			(64.1	)
		1,083.8			221.1			1,051.8			273.4
Refining and marketing
United States		4,475.5			17.3			4,629.2			88.0
United Kingdom		1,571.4			25.5			1,552.1			(19.1	)
		6,046.9			42.8			6,181.3			68.9
		7,130.7			263.9			7,233.1			342.3
Intersegment transfers elimination		—			—			(42.7	)		—
		7,130.7			263.9			7,190.4			342.3
Corporate		(8.5	)		(35.0	)		29.8			5.0
Revenues/income from continuing operations		7,122.2			228.9			7,220.2			347.3
Discontinued operations, net of tax		—			(2.2	)		—			58.8
Total revenues/net income	$	7,122.2			226.7			7,220.2			406.1
	Nine Months Ended September 30, 2012						Nine Months Ended September 30, 2011*
	Revenues			Income			Revenues			Income
Exploration and production
United States	$	671.6			83.1			539.7			106.8
Canada		804.7			146.3			965.1			284.5
Malaysia		1,777.5			662.9			1,442.1			559.5
Republic of the Congo		57.6			(8.4	)		111.4			(.4	)
Other		.1			(123.9	)		24.4			(191.6	)
		3,311.5			760.0			3,082.7			758.8
Refining and marketing
United States		13,251.8			83.4			13,356.1			172.9
United Kingdom		4,668.1			35.7			4,499.0			(43.6	)
		17,919.9			119.1			17,855.1			129.3
		21,231.4			879.1			20,937.8			888.1
Intersegment transfers elimination		—			—			(137.4	)		—
		21,231.4			879.1			20,800.4			888.1
Corporate		5.4			(77.4	)		43.7			(40.7	)
Revenues/income from continuing operations		21,236.8			801.7			20,844.1			847.4
Discontinued operations, net of tax		—			10.5			—			139.2
Total revenues/net income	$	21,236.8			812.2			20,844.1			986.6

* Reclassified to conform to current presentation.

MURPHY OIL CORPORATION

OIL AND GAS OPERATING RESULTS (Unaudited)

THREE MONTHS ENDED SEPTEMBER 30, 2012 AND 2011

			Canada								Republic
(Millions of dollars)	United States		Conven- tional			Syn- thetic		Malaysia			of the Congo			Other			Total
Three Months Ended September 30, 2012
Oil and gas sales and other revenues	$	248.8		108.0			124.8		602.2			—			—			1,083.8
Production expenses		74.2		43.7			55.8		93.4			3.3			—			270.4
Depreciation, depletion and amortization		82.5		65.8			14.7		133.6			—			.7			297.3
Accretion of asset retirement obligations		2.9		1.3			2.1		3.2			.2			—			9.7
Exploration expenses
Dry holes		—		—			—		26.2			—			29.2			55.4
Geological and geophysical		1.4		(3.1	)		—		.4			.2			(.5	)		(1.6	)
Other		1.0		.2			—		—			—			6.9			8.1
		2.4		(2.9	)		—		26.6			.2			35.6			61.9
Undeveloped lease amortization		20.8		7.4			—		—			—			3.9			32.1
Total exploration expenses		23.2		4.5			—		26.6			.2			39.5			94.0
Selling and general expenses		11.9		4.7			.3		(2.5	)		1.0			12.5			27.9
Results of operations before taxes		54.1		(12.0	)		51.9		347.9			(4.7	)		(52.7	)		384.5
Income tax provisions (benefits)		20.6		(2.6	)		13.2		132.2			—			—			163.4
Results of operations (excluding corporate overhead and interest)	$	33.5		(9.4	)		38.7		215.7			(4.7	)		(52.7	)		221.1
Three Months Ended September 30, 2011
Oil and gas sales and other revenues	$	173.2		219.6			130.5		484.8			43.7			—			1,051.8
Production expenses		41.4		43.7			59.2		116.5			11.4			—			272.2
Depreciation, depletion and amortization		40.8		75.1			13.5		83.0			26.7			.5			239.6
Accretion of asset retirement obligations		2.5		1.2			1.8		2.7			.1			.1			8.4
Exploration expenses
Dry holes		—		—			—		—			—			13.3			13.3
Geological and geophysical		3.8		.9			—		3.7			.9			24.5			33.8
Other		.8		.3			—		—			—			7.2			8.3
		4.6		1.2			—		3.7			.9			45.0			55.4
Undeveloped lease amortization		14.0		7.4			—		—			—			8.7			30.1
Total exploration expenses		18.6		8.6			—		3.7			.9			53.7			85.5
Selling and general expenses		10.4		3.9			.3		(1.1	)		.5			9.9			23.9
Results of operations before taxes		59.5		87.1			55.7		280.0			4.1			(64.2	)		422.2
Income tax provisions (benefits)		21.3		26.9			13.6		82.3			4.8			(.1	)		148.8
Results of operations (excluding corporate overhead and interest)	$	38.2		60.2			42.1		197.7			(.7	)		(64.1	)		273.4

MURPHY OIL CORPORATION

OIL AND GAS OPERATING RESULTS (Unaudited)

NINE MONTHS ENDED SEPTEMBER 30, 2012 AND 2011

			Canada								Republic
(Millions of dollars)	United States		Conven- tional			Syn- thetic		Malaysia			of the Congo			Other			Total
Nine Months Ended September 30, 2012
Oil and gas sales and other revenues	$	671.6		469.5			335.2		1,777.5			57.6			.1			3,311.5
Production expenses		177.7		128.6			167.1		306.7			24.1			—			804.2
Depreciation, depletion and amortization		210.8		219.9			40.4		368.7			33.8			1.8			875.4
Accretion of asset retirement obligations		8.6		3.9			6.3		8.9			.6			—			28.3
Exploration expenses
Dry holes		32.2		.8			—		26.2			—			30.4			89.6
Geological and geophysical		4.9		1.2			—		.6			.4			10.9			18.0
Other		6.7		.7			—		—			.2			21.3			28.9
		43.8		2.7			—		26.8			.6			62.6			136.5
Undeveloped lease amortization		60.3		21.8			—		—			—			25.1			107.2
Total exploration expenses		104.1		24.5			—		26.8			.6			87.7			243.7
Selling and general expenses		37.1		13.2			.7		(3.6	)		3.1			34.5			85.0
Results of operations before taxes		133.3		79.4			120.7		1,070.0			(4.6	)		(123.9	)		1,274.9
Income tax provisions		50.2		23.2			30.6		407.1			3.8			—			514.9
Results of operations (excluding corporate overhead and interest)	$	83.1		56.2			90.1		662.9			(8.4	)		(123.9	)		760.0
Nine Months Ended September 30, 2011
Oil and gas sales and other revenues	$	539.7		574.8			390.3		1,442.1			111.4			24.4			3,082.7
Production expenses		118.9		112.0			176.0		304.3			28.2			—			739.4
Depreciation, depletion and amortization		132.1		199.3			40.1		254.7			64.5			1.3			692.0
Accretion of asset retirement obligations		7.4		3.7			5.7		8.0			.4			.3			25.5
Exploration expenses
Dry holes		.6		—			—		—			2.9			115.1			118.6
Geological and geophysical		24.4		3.4			—		9.5			2.5			27.0			66.8
Other		8.1		.9			—		—			.1			18.7			27.8
		33.1		4.3			—		9.5			5.5			160.8			213.2
Undeveloped lease amortization		52.3		21.4			—		—			—			16.9			90.6
Total exploration expenses		85.4		25.7			—		9.5			5.5			177.7			303.8
Terra Nova working interest redetermination		—		(5.4	)		—		—			—			—			(5.4	)
Selling and general expenses		30.8		10.5			.7		(1.1	)		.8			28.0			69.7
Results of operations before taxes		165.1		229.0			167.8		866.7			12.0			(182.9	)		1,257.7
Income tax provisions		58.3		68.6			43.7		307.2			12.4			8.7			498.9
Results of operations (excluding corporate overhead and interest)	$	106.8		160.4			124.1		559.5			(.4	)		(191.6	)		758.8

MURPHY OIL CORPORATION

SUMMARIZED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

(Thousands of dollars, except per share amounts)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011*			2012			2011*
Revenues	$	7,122,277			7,220,220			21,236,818			20,844,088
Costs and expenses
Crude oil and product purchases		5,667,359			5,727,873			16,813,044			16,633,221
Operating expenses		526,969			512,511			1,547,828			1,448,063
Exploration expenses		94,063			85,505			243,714			303,827
Selling and general expenses		85,509			72,858			261,287			218,337
Depreciation, depletion and amortization		330,253			271,270			972,663			783,531
Accretion of asset retirement obligations		10,005			8,638			29,052			26,162
Redetermination of Terra Nova working interest		—			—			—			(5,351	)
Interest expense		12,941			17,329			36,278			41,648
Interest capitalized		(11,461	)		(2,475	)		(27,360	)		(11,547	)
		6,715,638			6,693,509			19,876,506			19,437,891
Income from continuing operations before income taxes		406,639			526,711			1,360,312			1,406,197
Income tax expense		177,728			179,401			558,657			558,773
Income from continuing operations		228,911			347,310			801,655			847,424
Income (loss) from discontinued operations, net of income taxes		(2,230	)		58,804			10,534			139,206
Net income	$	226,681			406,114			812,189			986,630
Income (loss) per Common share—Basic
Continuing operations	$	1.18			1.80			4.13			4.38
Discontinued operations		(0.01	)		0.30			0.05			0.72
Net income	$	1.17			2.10			4.18			5.10
Income (loss) per Common share—Diluted
Continuing operations	$	1.17			1.79			4.12			4.36
Discontinued operations		(0.01	)		0.30			0.05			0.71
Net income	$	1.16			2.09			4.17			5.07
Cash dividends per Common share	$	0.3125			0.275			0.8625			0.825
Average Common shares outstanding (thousands)
Basic		194,290			193,518			194,126			193,343
Diluted		195,058			194,411			194,875			194,549

* Reclassified to conform to current presentation.

MURPHY OIL CORPORATION

SUMMARIZED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			20111			2012			20111
Operating Activities
Net income	$	226,681			406,114			812,189			986,630
Adjustments to reconcile net income to net cash provided by operating activities:
(Income) loss from discontinued operations		2,230			(58,804	)		(10,534	)		(139,206	)
Depreciation, depletion and amortization		330,253			271,270			972,663			783,531
Amortization of deferred major repair costs		5,927			5,717			16,876			17,357
Expenditures for asset retirements		(10,186	)		(3,075	)		(22,949	)		(15,171	)
Dry hole costs		55,428			13,278			89,645			118,585
Amortization of undeveloped leases		32,079			30,093			107,151			90,623
Accretion of asset retirement obligations		10,005			8,638			29,052			26,162
Deferred and noncurrent income tax charges		111,671			100,221			155,616			110,670
Pretax gain from disposition of assets		31			(60	)		(94	)		(23,192	)
Net (increase) decrease in operating working capital other than cash and cash equivalents		(113,895	)		149,027			(217,240	)		(305,221	)
Other—net		88,776			(33,659	)		120,862			36,121
Net cash provided by continuing operations		739,000			888,760			2,053,237			1,686,889
Net cash provided by discontinued operations		15,109			70,045			47,990			189,858
Net cash provided by operating activities		754,109			958,805			2,101,227			1,876,747
Investing Activities
Property additions and dry holes		(917,478	)		(621,492	)		(2,232,067	)		(1,845,000	)
Proceeds from sale of assets		225			91			388			27,629
Purchases of investment securities2		(524,274	)		(557,715	)		(1,360,746	)		(1,233,321	)
Proceeds from maturity of investment securities2		503,442			602,093			1,401,235			1,356,175
Expenditures for major repairs		(3,927	)		(2,826	)		(11,367	)		(2,826	)
Investing activities of discontinued operations, including proceeds from sale of Superior refinery and associated inventories in 2011		(14,094	)		378,775			(36,524	)		345,299
Other—net		3,026			2,824			8,898			7,150
Net cash required by investing activities		(953,080	)		(198,250	)		(2,230,183	)		(1,344,894	)
Financing Activities
Increase (decrease) in notes payable		393,003			(210,010	)		584,899			384,970
Proceeds from exercise of stock options and employee stock purchase plans		2,386			345			11,138			8,245
Excess tax benefits related to exercise of stock options		629			51			1,957			4,119
Withholding tax on stock-based incentive awards		181			—			(3,522	)		(8,014	)
Issue cost of debt facility		(343	)		(947	)		(4,285	)		(8,619	)
Cash dividends paid		(60,722	)		(53,217	)		(167,520	)		(159,529	)
Net cash provided (required) by financing activities		335,134			(263,778	)		422,667			221,172
Effect of exchange rate changes on cash and cash equivalents		8,889			(19,042	)		9,110			(9,869	)
Net increase in cash and cash equivalents		145,052			477,735			302,821			743,156
Cash and cash equivalents at beginning of period		671,642			801,246			513,873			535,825
Cash and cash equivalents at end of period	$	816,694			1,278,981			816,694			1,278,981

¹  Reclassified to conform to current presentation.

²  Represents cash invested in Canadian government securities with maturities greater than 90 days at the date of acquisition.

MURPHY OIL CORPORATION

OTHER FINANCIAL DATA

(Unaudited, except for December 31, 2011)

(Millions of dollars)

	Sept. 30,		Dec. 31,
	2012		2011
Total current assets	$	4,102.0		3,447.7
Total current liabilities		3,224.6		2,824.9
Total assets		16,589.8		14,138.1
Long-term debt		1,184.6		249.6
Stockholders’ equity		9,616.8		8,778.4

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2012			2011		2012		2011
Capital expenditures—continuing operations
Exploration and production
United States	$	581.1			144.1		1,132.4		516.5
Canada		189.0			232.1		479.9		657.6
Malaysia		384.0			176.9		1,042.4		419.1
Other		28.6			81.2		96.3		292.3
		1,182.7			634.3		2,751.0		1,885.5
Refining and marketing
United States		30.1			21.2		75.4		70.5
United Kingdom		5.3			5.9		15.4		13.5
		35.4			27.1		90.8		84.0
Corporate		2.0			0.9		5.4		4.4
Total capital expenditures—continuing operations		1,220.1			662.3		2,847.2		1,973.9
Charged to exploration expenses*
United States		2.4			4.6		43.8		33.1
Canada		(2.9	)		1.2		2.7		4.3
Malaysia		26.6			3.7		26.8		9.5
Other		35.8			45.9		63.2		166.3
Total charged to exploration expenses		61.9			55.4		136.5		213.2
Total capitalized—continuing operations	$	1,158.2			606.9		2,710.7		1,760.7
*  Excludes amortization of undeveloped leases of	$	32.1			30.1		107.2		90.6

MURPHY OIL CORPORATION

STATISTICAL SUMMARY

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
Net crude oil, condensate and gas liquids produced – barrels per day		105,796		96,437		105,766		101,269
Continuing operations		102,111		94,935		102,354		98,956
United States		26,193		16,388		22,088		16,750
Canada – light		249		107		251		74
– heavy		6,175		7,097		7,148		6,875
– offshore		3,392		9,758		7,105		9,284
– synthetic		15,111		14,022		13,297		13,878
Malaysia		49,055		42,976		50,175		46,684
Republic of the Congo		1,936		4,587		2,290		5,411
Discontinued operations – United Kingdom		3,685		1,502		3,412		2,313
Net crude oil, condensate and gas liquids sold – barrels per day		105,640		93,394		106,322		98,663
Continuing operations		102,704		91,751		103,262		96,292
United States		26,193		16,388		22,088		16,750
Canada – light		249		107		251		74
– heavy		6,175		7,097		7,148		6,875
– offshore		3,324		10,262		7,417		9,381
– synthetic		15,111		14,022		13,297		13,878
Malaysia		51,652		39,329		51,100		45,374
Republic of the Congo		—		4,546		1,961		3,960
Discontinued operations – United Kingdom		2,936		1,643		3,060		2,371
Net natural gas sold – thousands of cubic feet per day		454,573		470,183		495,711		447,044
Continuing operations		451,798		467,081		492,541		442,638
United States		48,755		38,790		50,611		47,789
Canada		197,434		210,735		227,144		174,635
Malaysia – Sarawak		160,419		181,265		175,412		176,067
– Kikeh		45,190		36,291		39,374		44,147
Discontinued operations – United Kingdom		2,775		3,102		3,170		4,406
Total net hydrocarbons produced – equivalent barrels per day1		181,558		174,801		188,385		175,776
Total net hydrocarbons sold – equivalent barrels per day1		181,402		171,758		188,941		173,170
Weighted average sales prices
Crude oil, condensate and natural gas liquids – dollars per barrel2
United States	$	99.71		102.05		103.69		102.33
Canada3 – light		77.78		90.24		82.03		93.85
– heavy		45.89		49.78		47.67		55.08
– offshore		110.67		112.47		112.55		110.08
– synthetic		89.99		101.18		92.12		103.08
Malaysia4		100.52		93.85		99.12		89.86
Republic of the Congo4		—		104.43		107.26		103.05
United Kingdom – Discontinued operations		108.09		113.82		111.37		110.51
Natural gas – dollars per thousand cubic feet
United States2	$	2.74		4.36		2.47		4.32
Canada3		2.58		4.17		2.42		4.24
Malaysia – Sarawak		7.59		7.54		7.79		6.76
– Kikeh		0.24		0.23		0.24		0.24
United Kingdom3– Discontinued operations		9.84		10.06		9.75		10.00

¹  Natural gas converted on an energy equivalent basis of 6:1.

²  Includes intracompany transfers at market prices.

³  U.S. dollar equivalent.

⁴  Prices are net of payments under terms of the respective production sharing contracts.

MURPHY OIL CORPORATION

STATISTICAL SUMMARY (Continued)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Refining and Marketing
United States retail marketing:
Fuel margin per gallon1	$	0.103			0.200			0.125			0.165
Gallons sold per store month		279,505			279,997			270,067			278,442
Merchandise sales revenue per store month	$	159,424			164,953			157,004			158,385
Merchandise margin as a percentage of merchandise sales		14.4	%		13.1	%		13.6	%		13.2	%
Store count at end of period		1,151			1,120			1,151			1,120
United Kingdom refining and marketing—unit margins per barrel	$	3.44			(1.66	)		1.85			(1.37	)
Petroleum and other products sold—barrels per day		471,119			594,619			468,416			586,928
United States		333,930			457,729	2		332,778			451,644	2
Gasoline		287,347			320,520			285,347			323,812
Kerosine		3			15,015			78			14,929
Diesel and home heating oils		46,580			84,586			47,353			84,134
Residuals		—			18,424			—			16,870
Asphalt, LPG and other		—			19,184			—			11,899
United Kingdom		137,189			136,890			135,638			135,284
Gasoline		41,053			36,643			44,226			34,459
Kerosine		15,360			18,625			16,933			16,961
Diesel and home heating oils		49,840			47,614			47,599			47,409
Residuals		11,035			14,493			14,457			14,526
LPG and other		19,901			19,515			12,423			21,929
U.K. refinery inputs—barrels per day		132,932			138,041			132,282			134,346
Milford Haven, Wales - crude oil		129,948			135,053			129,006			130,986
- other feedstocks		2,984			2,988			3,276			3,360
U.K. refinery yields—barrels per day		132,932			138,041			132,282			134,346
Gasoline		38,656			34,496			42,715			32,670
Kerosine		16,245			17,459			16,771			17,183
Diesel and home heating oils		47,056			46,714			45,392			46,360
Residuals		11,072			15,048			14,166			13,862
LPG and other		15,954			21,049			9,550			21,183
Fuel and loss		3,949			3,275			3,688			3,088

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

²  Includes 170,609 bbls. per day in the three-month period in 2011 and 163,597 bbls. per day in the nine-month period in 2011 related to discontinued operations in the United States. Subsequent to the sale of the U.S. refineries in late 2011, a portion of the reduction in refined products produced and sold by these discontinued operations were offset by higher finished products purchased and sold by the Company’s ongoing marketing operations.