Note E – Property, Plant and Equipment



	December 31, 2017				December 31, 2016
(Thousands of dollars)	Cost		Net		Cost	Net
Exploration and production1	$	20,329,930	8,120,293	2	20,767,772	8,214,740	2
Corporate and other		170,842	99,738		156,231	101,448
	$	20,500,772	8,220,031		20,924,003	8,316,188
1 Includes unproved mineral rights as follows:	$	600,423	198,349		595,138	188,689

2. Includes $38,670 in 2017 and $48,053 in 2016 related to administrative assets and support equipment.

Divestments

In January 2017, a Canadian subsidiary of the Company completed its disposition of the Seal field in Western Canada. Total cash consideration to Murphy upon closing of the transaction was $48.8 million. Additionally, the buyer assumed the asset retirement obligation of approximately $85.9 million. A $129.0 million pretax gain was reported in 2017 related to the sale. Also, in 2017, a U.S. subsidiary of the Company completed its disposition of certain non-core properties in the Eagle Ford Shale area. Total cash consideration to Murphy upon closing of the transaction was approximately $19.6 million. There were no gains or losses recorded related to the non-core Eagle Ford Shale sales.

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 $739.1 million and recorded an after-tax gain of $71.7 million associated with the Syncrude divestiture.

In 2016, a Canadian subsidiary of the Company completed a divestiture of 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 upon closing was $414.1 million. A gain on sale of approximately $187.0 million was

deferred and is being recognized over approximately the next 18 years in the Canadian operating segment. The Company amortized approximately $7.1 million and $5.1 million of the deferred gain during 2017 and 2016, respectively. The remaining deferred gain of $181.7 million was included as a component of Deferred credits and other liabilities in the Company’s Consolidated Balance Sheet as of December 31, 2017.

Acquisition

In 2016, a Canadian subsidiary of Murphy Oil acquired a 70% operated working interest (WI) of Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30% non-operated WI of Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta, the majority of which was unproved. Under the terms of the joint venture, the total consideration amounts to approximately $375.0 million of which Murphy paid $206.7 million in cash at closing, subject to normal closing adjustments, and an additional $168.0 million in the form of a carried interest on the Kaybob Duvernay property. As of December 31, 2017, $44.8 million of the carried interest had been paid. The carry is to be paid over a period of up to five years from 2016.

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 $95.1 million to reduce the carrying values to their estimated fair values for the Terra Nova field offshore Canada and the Western Canada onshore heavy oil producing properties. In 2015, the Company recognized pretax noncash impairment charges of $2.49 billion 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. 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, 2017.


	December 31,
(Thousands of dollars)		2017	2016	2015
Gulf of Mexico	$	–	–	328,982
Canada		–	95,088	683,574
Malaysia		–	–	1,480,600
	$	–	95,088	2,493,156

Other

In 2006, the Kakap field in Block K was unitized with the Gumusut field in an adjacent block under a Unitization and Unit Operating Agreement (UUOA) between the owners. The Gumusut-Kakap Unit is operated by another company. In the fourth quarter 2016, the owners completed the first redetermination process for a revision to the blocks’ tract participation interest, and the operator of the unitized field sought the approval of Petronas to effect the change in 2017. In 2016, the Company recorded an estimated redetermination expense of $39.1 million ($24.1 million after taxes) related to an expected revision in the Company’s working interest covering the period from inception through year-end 2016 at Kakap. In February 2017, the Company received Petronas official approval to the redetermination change that reduced the Company’s working interest in oil operations to 6.67% effective at April 1, 2017. Working interest redeterminations are required at different points within the life of the unitized field.

Following a further Unitization Framework Agreement (UFA) between the governments of Brunei and Malaysia, the Company now has a 6.35% interest in the Kakap field in Block K Malaysia as of December 31, 2017. The UFA unitized the Gumusut/Kakap (GK) and Geronggong/Jagus East fields effective November 23, 2017. In the fourth quarter 2017, the Company recorded an estimated redetermination expense of $15.0 million ($9.3 million after tax) related to Company’s revised working interest.

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, 2017, 2016 and 2015, the Company had total capitalized drilling costs pending the determination of proved reserves of $175.6 million, $148.5 million and $130.5 million, respectively. The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 2017.



(Thousands of dollars)	2017		2016	2015
Beginning balance at January 1	$	148,500	130,514	120,455
Additions pending the determination of proved reserves		51,488	17,986	64,578
Reclassifications to proved properties based on the determination of proved reserves		(15,988)	–	–
Capitalized exploratory well costs charged to expense		(8,360)	–	(54,519)
Ending balance at December 31	$	175,640	148,500	130,514

The capitalized well costs charged to expense in 2017 included the Marakas-01 well in Block SK314A, offshore Malaysia in which development of the well could not be justified due to noncommercial hydrocarbon quantities found. The capitalized well costs charged to expense in 2015 included one well in the Gulf of Mexico in which development of the well also 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 low commodity prices.

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.



	2017				2016				2015
(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	$	41,480	3	2	$	20,481	1	1	$	66,032	7	6
One to two years		5,812	1	1		63,527	5	5		–	–	–
Two to three years		43,200	2	2		–	–	–		57,876	3	–
Three years or more		85,148	7	1		64,492	6	–		6,606	3	–
	$	175,640	13	6	$	148,500	12	6	$	130,514	13	6

Of the $134.1 million of exploratory well costs capitalized more than one year at December 31, 2017, $70.4 million is in Brunei, $43.2 million is in Vietnam and $20.5 million 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.