Property, Plant and Equipment

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment

Note D – Property, Plant and Equipment

	December 31, 2012					December 31, 2011
(Thousands of dollars)	Cost		Net			Cost		Net
Exploration and production1	$	18,408,904		11,294,933	2		14,766,637		8,730,124	2
Refining and marketing		2,619,844		1,661,081			2,456,822		1,688,709
Corporate and other		121,445		55,592			113,184		56,316
	$	21,150,193		13,011,606			17,336,643		10,475,149
1         Includes mineral rights as follows:	$	1,051,153		556,399			1,078,770		619,950
2        Includes $26,611 in 2012 and $21,154 in 2011 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, 2012, 2011 and 2010, the Company had total capitalized drilling costs pending the determination of proved reserves of $445,697,000, $556,412,000 and $497,765,000, respectively. The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 2012.

(Thousands of dollars)	2012			2011			2010
Beginning balance at January 1	$	556,412			497,765			369,862
Additions to capitalized exploratory well costs pending the determination of proved reserves		135,849			86,035			137,403
Reclassifications to proved properties based on the determination of proved reserves		(165,377	)		0			0
Capitalized exploratory well costs charged to expense or sold		(81,187	)		(27,388	)		(9,500	)
Ending balance at December 31	$	445,697			556,412			497,765

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.

	2012						2011						2010
(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	$	59,833		7		2	$	69,757		11		5	$	135,494		15		4
One to two years		18,335		2		3		143,611		15		3		115,418		10		4
Two to three years		83,314		9		4		101,696		9		2		42,571		3		3
Three years or more		284,215		26		6		241,348		33		6		204,282		31		4
	$	445,697		44		15	$	556,412		68		16	$	497,765		59		15

Of the $385,864,000 of exploratory well costs capitalized more than one year at December 31, 2012, $270,093,000 is in Malaysia and $115,771,000 is in the U.S. 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. The capitalized well costs charged to expense in 2012 included a suspended well in the northern block of the Republic of the Congo that was written off following unsuccessful wildcat drilling in 2012 at a nearby prospect, two suspended wells offshore Sarawak Malaysia that were written off following a government denial of a request to delay the timing of an oil development project, and a well drilled in the Gulf of Mexico in 2010 that the owners decided not to develop. The capitalized well costs expensed in 2011 related to exploration costs offshore Republic of the Congo and Brunei. The costs in Republic of the Congo were written off following an impairment charge at the nearby Azurite field, and the Brunei costs were written off based on unsuccessful wells drilled in the area in late 2011.

At year-end 2012, Murphy determined that the Azurite field, offshore Republic of the Congo, was impaired due to removal of all proved oil reserves after an unsuccessful redrill of a key well in the field. The impairment charge in 2012 totaled $200,000,000 and included a write-off of the remaining book value of the Azurite field plus other anticipated losses related to operations of the field. At year-end 2011, an impairment charge of $368,600,000 was recorded to reduce the carrying value of the Azurite field to fair value. The Company determined that a downward revision of proved oil reserves for Azurite was necessary at year-end 2011. 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. Fair value was determined each year at Azurite using a discounted cash flow model based on certain key assumptions, including future estimated net production levels, future estimated oil prices for the field based on year-end futures prices, and future estimated operating and capital expenditures. The 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.

At year-end 2012, the Company also wrote down its net investment in the ethanol production facility in Hereford, Texas, taking an impairment charge of $60,988,000. The write down was required based on expected weak ethanol production margins at the plant in future periods. Fair value was determined using a discounted cash flow model for three years, plus an estimated terminal value based on a multiple of the last year’s cash flow. Certain key assumptions used in the cash flow model included use of available futures prices for corn and ethanol products. Additional key assumptions included estimated future ethanol and distillers grain production levels, estimated future operating expenses, and estimated sales prices for distillers grain.

In 2012, the Company announced that its Board of Directors had approved a plan to separate its U.S. downstream subsidiary into a separate publicly owned company. 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.S. and U.K. refining and marketing segments in Note T. The separation of the U.S. downstream subsidiary is expected to be completed during 2013. The sale process for the U.K. downstream assets continues in 2013. Based on current market conditions, it is possible that the Company could incur a loss when the U.K. downstream assets are sold. If the separation of the U.S. downstream subsidiary and the sale of the U.K. downstream assets continue to progress, the results of these operations are likely to be presented as discontinued operations in future periods when the operations no longer qualify as continuing operations under U.S. generally accepted accounting principles.