Note D – Property, Plant and Equipment

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 March 31, 2019, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $227.1 million. The following table reflects the net changes in capitalized exploratory well costs during the three-month periods ended March 31, 2019 and 2018.



(Thousands of dollars)	2019		2018
Beginning balance at January 1	$	207,855	155,103
Additions pending the determination of proved reserves		32,416	549
Capitalized exploratory well costs charged to expense		(13,145)	–
Balance at March 31	$	227,126	155,652

The capitalized well costs charged to expense during the first three months of 2019 included the CM-1X and the CT-1X wells in Vietnam Block 11-2/11. The wells were originally drilled in 2017. There were no capitalized well costs charged to expense during the first three months of 2018.

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 have been capitalized. The projects are aged based on the last well drilled in the project.



		March 31,
	2019				2018
(Thousands of dollars)	Amount		No. of Wells	No. of Projects	Amount		No. of Wells	No. of Projects
Aging of capitalized well costs:
Zero to one year	$	78,016	3	2	$	13,642	2	1
One to two years		–	–	–		27,757	1	1
Two to three years		27,270	1	1		49,642	2	2
Three years or more		121,840	5	1		64,611	6	–
	$	227,126	9	4	$	155,652	11	4

Of the $149.1 million of exploratory well costs capitalized more than one year at March 31, 2019, $57.0 million is in Brunei, $64.9 million is in Vietnam, and $27.3 million is in the U.S. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

Divestments

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, up to December 31, 2018, and was being recognized straight line over the life of the contract in the Canadian operating segment. The remaining deferred gain of $116 million, net of tax, was included as a component of Deferred credits and other liabilities in the Company’s Consolidated Balance Sheet as of December 31, 2018. As required by ASC 842, the previously deferred gain related to the sale and leaseback transaction have been transferred to equity upon adoption, lowering liabilities but increasing retained earnings by approximately $116 million, net of tax. The Company amortized approximately $1.9 million of the deferred gain during the first three months of 2018.

Note D – Property, Plant and Equipment (Contd.)

Acquisitions

In 2016, a Canadian subsidiary of Murphy Oil acquired a 70% operated working interest (WI) in Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30% non-operated WI in Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta, the majority of which was unproved. As part of the transaction, Murphy agreed to pay an additional $168.0 million in the form of a carried interest on the Kaybob Duvernay property. As of March 31, 2019, $124.0 million of the carried interest had been paid. The remaining carry is to be paid over a period through 2019.

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 operators. The Gumusut-Kakap Unit is operated by another company. In the fourth quarter 2016, the operators 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 tax) 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’ approval to the redetermination change that reduced the Company’s working interest in oil operations to 6.67% effective April 1, 2017. Working interest redeterminations are required at different points within the life of the unitized field. Following a partial payment, the remaining redetermination liability of $17.3 million was included as a component of Liabilities associated with held for sale in the Company’s Consolidated Balance Sheet as of March 31, 2019.

Following a further Unitization Framework Agreement (UFA) between the governments of Brunei and Malaysia, the Company now has a 6.37% interest in the Kakap field in Block K Malaysia. 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 liability of $15.0 million related to Company’s revised working interest, which was included as a component of Liabilities associated with held for sale in the Company’s Consolidated Balance Sheet as of March 31, 2019.