Note E – Property, Plant and Equipment



	December 31, 2016				December 31, 2015
(Thousands of dollars)	Cost		Net		Cost	Net
Exploration and production1	$	20,767,772	8,214,740	2	21,607,962	9,723,222	2
Corporate and other		156,231	101,448		134,596	95,143
	$	20,924,003	8,316,188		21,742,558	9,818,365
1 Includes mineral rights as follows:	$	595,138	188,689		1,075,040	612,518

2. Includes $48,053 in 2016 and $50,924 in 2015

related to administrative assets and support equipment.

Divestments

In 2016, a Canadian subsidiary of the Company completed the sale of its five percent, non-operated working interest in Syncrude Canada Ltd. (“Syncrude”) asset to Suncor Energy Inc. (“Suncor”). The Company received net cash proceeds of $739,100,000 and recorded an after-tax gain of $71,700,000 in 2016 associated with the Syncrude divestiture.

In 2016, a Canadian subsidiary of the Company completed its transaction to divest natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia. Total cash consideration received by Murphy upon closing of the transaction was $414,100,000. A gain on sale of approximately $187,000,000 is being deferred and recognized over the next 20 years in the Canadian operating segment. The Company has amortized approximately $5,108,000 of the deferred gain during 2016. The remaining deferred gain is included as a component of deferred credits and other liabilities in the Company’s Consolidated Balance Sheets.

In January 2015, the Company sold 10% of its oil and gas assets in Malaysia and received net cash proceeds of $417,200,000. The Company recorded an after-tax gain of $218,800,000 in 2015 on the 10% sale. In December 2014, the Company sold 20% of its oil and gas assets in Malaysia and received net cash proceeds of $1,460,425,000. The Company recorded an after-tax gain on this sale of $321,454,000 in 2014.

Acquisition

In 2016, a Canadian subsidiary acquired a 70 percent operated working interest (WI) of Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30 percent non-operated WI of Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta, the majority of which is unproved. Under the terms of the joint venture the total consideration amounts to approximately $375,000,000 of which Murphy paid $206,700,000 in cash at closing, subject to normal closing adjustments, and the remaining $168,000,000 in the form of a carried interest on the Kaybob Duvernay property. The carry is to be paid over a period of up to five years.

Impairments

During 2016 and 2015, declines in future oil and gas prices led to impairments in certain of the Company’s producing properties. During 2016, the Company recorded pretax noncash impairment charges of $95,088,000 to reduce the carrying values to their estimated fair values for Terra Nova field offshore Canada and the Western Canada onshore heavy oil producing properties. In 2015, the Company recognized pretax noncash impairment charges of $2,493,156,000 to reduce the carrying value of certain offshore producing and non-producing properties in the Gulf of Mexico, producing offshore properties in Malaysia and for Western Canada onshore heavy oil producing properties. During 2014, the Company recorded an impairment writedown in the amount of $14,267,000 related to one gas well in the Gulf of Mexico. The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, costs, and a discount rate believed to be consistent with those used by principal market participants in the applicable region. The following table reflects the recognized impairments for the three years ended December 31, 2016.


	December 31,
(Thousands of dollars)		2016	2015	2014
Gulf of Mexico	$	–	328,982	14,267
Canada		95,088	683,574	37,047	*
Malaysia		–	1,480,600	–
	$	95,088	2,493,156	51,314

* This amount represented the writeoff of goodwill associated with an oil and gas company acquired in 2000.

Other

The Company had an 8.6% interest in the Kakap field in Block K Malaysia. The Kakap field in Block K is operated by another company and was jointly developed with the Gumusut field owned by others. In 2016 the Company recorded a $24 million after tax estimated redetermination expense related to an expected reduction in the Company’s working interest covering the period from inception through year-end 2016 at Kakap. The Company expects to incur additional redetermination expense during 2017 for the period from the beginning of the year until the redetermination process is finalized, and the final adjustment will be settled in cash. In February 2017, PETRONAS officially approved the redetermination that reduces the Company’s working interest effective April 1, 2017.

Exploratory Wells

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, 2016, 2015 and 2014, the Company had total capitalized drilling costs pending the determination of proved reserves of $148,500,000, $130,514,000 and $120,455,000, respectively. The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 2016.



(Thousands of dollars)	2016		2015	2014
Beginning balance at January 1	$	130,514	120,455	393,030
Additions to capitalized exploratory well costs pending the determination of proved reserves		17,986	64,578	2,874
Reclassifications to proved properties based on the determination of proved reserves		–	–	(91,236)
Reduction of capitalized exploratory well costs due to partial asset sale in Malaysia		–	–	(122,175)
Capitalized exploratory well costs charged to expense		–	(54,519)	(62,038)
Ending balance at December 31	$	148,500	130,514	120,455

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs has been capitalized. The projects are aged based on the last well drilled in the project.



	2016				2015				2014
(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	$	20,481	1	1	$	66,032	7	6	$	–	–	–
One to two years		63,527	5	5		–	–	–		59,330	3	1
Two to three years		–	–	–		57,876	3	–		6,606	3	–
Three years or more		64,492	6	–		6,606	3	–		54,519	2	2
	$	148,500	12	6	$	130,514	13	6	$	120,455	8	3

Of the $128,019,000 of exploratory well costs capitalized more than one year at December 31, 2016, $64,492,000 is in Brunei, and $63,527,000 is in Malaysia. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. The capitalized well costs charged to expense in 2015 included one well in the Gulf of Mexico in which development of the well could not be justified due to noncommercial hydrocarbon quantities found in the sidetrack and one project in the Gulf of Mexico deemed unlikely to be developed due to distressed commodity prices. The capitalized well costs charged to expense in 2014 included four gas wells in Peninsula Malaysia and one well in the Gulf of Mexico. The Company’s application to extend the gas holding period for the Malaysia wells was denied by the Malaysian government in 2014. Development of the well in the Gulf of Mexico could not be justified due to the low prices for natural gas at year-end 2014,