View Filing Data

(3,737)

COMPREHENSIVE INCOME (LOSS)

35,626

(147,544)

165,969

$ 1,288,928

$ 271,942

$ (145,820)

[1]	¹ Reclassified to conform with current presentation (see Notes C and E). 2017 revenue is presented net of $58.9 million of transportation, gathering and processing costs as historically shown prior to the adoption of ASC 606 on January 1, 2018. See Notes to Consolidated Financial Statements, page 58.
[2]	Reclassified to conform with current presentation (see Note E)

Common Stock Issued and Outstanding (Tables)

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Activity in Number of Shares of Common Stock Issued and Outstanding

Activity in the number of shares of Common Stock issued and outstanding for the three years ended December 31, 2019 is shown below.



(Number of shares outstanding)	2019		2018	2017
Beginning of year	173,058,829		172,572,873	172,202,177
Stock options exercised ¹	12,345		21,200	—
Restricted stock awards ¹	561,729		464,756	368,132
Employee stock purchase and thrift plans	—		—	2,564
Treasury shares purchased	(20,697,542	)	—	—
End of year	152,935,361		173,058,829	172,572,873

¹Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note K due to withholdings for statutory income taxes owed upon issuance of shares.

Financing Arrangements and Long-Term Debt - Schedule of Long Term Debt (Details) - USD ($)
$ in Thousands

Dec. 31, 2019

Nov. 30, 2019

Oct. 31, 2019

Dec. 31, 2018

Unamortized debt issuance cost and discount on notes payable

$ 2,828,668

$ 2,800,000

(25,287)

(23,627)

Total notes payable, net of unamortized discount

2,803,381

2,776,373

Capitalized lease obligation, due through March 2029 ¹

8,613

Total debt including current maturities

2,803,381

2,784,986

Senior Unsecured Revolving Credit Facility

325,000

Current maturities ²

(668)

^[1]

Total long-term debt

2,803,381

3,109,318

^[1]

4.00% notes, due June 2022

260,251

$ 500,000

4.45% notes, due December 2022 ¹

4.00%

318,417

$ 600,000

6.875% notes, due August 2024

4.45%

3.70%

4.45%

550,000

$ 550,000

5.75% notes, due August 2025

6.875%

550,000

$ 550,000

5.875% notes, due December 2027

5.75%

550,000

$ 0

7.05% notes, due May 2029

5.875%

250,000

$ 250,000

5.875% notes, due December 2042 ¹

7.05%

$ 350,000

5.875%

[1]	Reclassified to conform with current presentation (see Note E)

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Stockholders' Equity [Abstract]
Cumulative Preferred Stock, par value (in USD per share)	$ 100	$ 100	$ 100
Cumulative preferred stock, authorized shares (in shares)	400,000	400,000	400,000
Cumulative preferred stock, shares issued (in shares)	0	0	0
Common Stock, par value (in USD per share)	$ 1.00	$ 1.00	$ 1.00
Common stock, authorized shares (in shares)	450,000,000	450,000,000	450,000,000
Common stock, shares issued (in shares)	195,089,269	195,076,924	195,055,724
Treasury stock, shares (in shares)	42,153,908	22,018,095	22,482,851

Property, Plant and Equipment - Narrative (Details)

1 Months Ended

3 Months Ended

7 Months Ended

12 Months Ended

13 Months Ended

Jun. 30, 2019

USD ($)

Dec. 31, 2018

USD ($)

MMBoe

Dec. 31, 2019

USD ($)

Dec. 31, 2019

USD ($)

Dec. 31, 2019

USD ($)

Dec. 31, 2018

USD ($)

MMBoe

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2019

USD ($)

Jul. 31, 2019

USD ($)

May 31, 2019

MMBoe

Proceeds from sales of property, plant and equipment

$ 20,382,000

$ 1,175,000

^[1]

$ 69,506,000

^[1]

Asset retirement obligation settled

25,544,000

11,510,000

Gain (loss) on sale of assets

227,000

54,000

^[1]

127,434,000

^[1]

1,280,100,000

797,300,000

71,100,000

Total capitalized exploratory well costs

20,000,000

^[1],[2]

$ 207,855,000

$ 217,326,000

217,326,000

$ 207,855,000

155,103,000

$ 101,546,000

$ 217,326,000

Exploratory well costs capitalized more than one year

153,900,000

MP Gulf of Mexico LLC

Parent ownership interest

80.00%

MP Gulf of Mexico LLC | PAI (Final)

Noncontrolling ownership interest

20.00%

LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C. [Member]

LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C. [Member] | Sales Thresholds 2019 to 2025

$ 1,238,400,000

1,238,353,000

LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C. [Member] | Net crude oil and condensate revenue

200,000,000

50,000,000

PAI (Final)

PAI (Final) | Sales Thresholds 2019 to 2025

$ 780,700,000

780,678,000

PAI (Final) | Enhanced Oil Recovery Projects

150,000,000

$ 150,000,000

150,000,000

Athabasca Oil Corporation

$ 50,000,000

50,000,000

Cost of acquired assets, cash paid

206,700,000

Athabasca Oil Corporation | Canadian Subsidiary

375,000,000.0

Western Canada

Proceeds from sales of property, plant and equipment

48,800,000

Asset retirement obligation settled

85,900,000

Gain (loss) on sale of assets

129,000,000.0

Kaybob Duvernay Lands, Alberta | Athabasca Oil Corporation

Cost of acquired assets, carried interest

$ 168,000,000.0

Carried interest paid

152,700,000

Kaybob Duvernay Lands, Alberta | Athabasca Oil Corporation | Canadian Subsidiary

Interest in assets acquired

70.00%

United States - Onshore

Placid Montney Lands, Alberta | Athabasca Oil Corporation | Canadian Subsidiary

20,000,000.0

Interest in assets acquired

30.00%

Brunei

Exploratory well costs capitalized more than one year

57,500,000

Vietnam

Exploratory well costs capitalized more than one year

69,100,000

Exploratory well costs capitalized more than one year

1,266,900,000

797,100,000

58,100,000

27,400,000

$ 27,400,000

27,400,000

$ 27,400,000

Malaysia

Disposal group including discontinued operation, consideration

$ 2,000,000,000.0

Gain (loss) on disposition of business

$ 985,400,000

985,400,000

Disposal group including discontinued operation, contingent consideration paid

$ 100,000,000.0

Income tax expense (benefit) based on the U.S. statutory tax rate

$ 0

[1]	Reclassified to conform with current presentation (see Note E)
[2]	¹ Reclassified to conform with current presentation (see Notes C and E). 2017 revenue is presented net of $58.9 million of transportation, gathering and processing costs as historically shown prior to the adoption of ASC 606 on January 1, 2018. See Notes to Consolidated Financial Statements, page 58.

Income Taxes - Effective Income Tax Rates (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Income Tax Disclosure [Abstract]

$ 42,735

$ 9,031

$ (98,868)

Revaluation of deferred tax (U.S. tax reform)

118,004

Alberta tax rate reduction and tax impact of deemed repatriation of foreign invested earnings (U.S. tax reform)

(17,019)

(135,700)

156,000

Deferred tax effect on Canadian earnings no longer indefinitely invested

65,000

Foreign income (loss) subject to foreign tax rates different than the U.S.statutory rate

(1,122)

5,822

2,032

State income taxes, net of federal benefit

4,060

2,607

2,438

U.S. tax benefit on certain foreign upstream investments

(14,975)

(14,702)

(32,926)

Increase in deferred tax asset valuation allowance related to other foreign exploration expenditures

10,927

3,283

18,601

Tax effect on income attributable to noncontrolling interest

(21,750)

(1,753)

Other, net

11,827

5,276

39,850

Total income tax expense (benefit)

$ 14,683

$ (126,136)

^[1]

$ 270,131

^[1]

[1]

¹ Reclassified to conform with current presentation (see Notes C and E). 2017 revenue is presented net of $58.9 million of transportation, gathering and processing costs as historically shown prior to the adoption of ASC 606 on January 1, 2018. See Notes to Consolidated Financial Statements, page 58.

Accumulated Other Comprehensive Loss (Tables)

12 Months Ended

Dec. 31, 2019

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Components of Accumulated Other Comprehensive Loss

The components of Accumulated other comprehensive loss on the Consolidated Balance Sheets at December 31, 2019 and December 31, 2018 and the changes during 2019 and 2018 are presented net of taxes in the following table.



(Thousands of dollars)	Foreign Currency Translation Gains (Losses)			Retirement and Postretirement Benefit Plan Adjustments			Deferred Loss on Interest Rate Derivative Hedges			Total
Balance at December 31, 2017	(274,830		)	(178,987	)		(8,426	)		(462,243	)
2017 components of other comprehensive income (loss):
Before reclassifications to income	(145,022		)	(16,839	)		(1,815	)		(163,676	)
Reclassifications to income	—			13,790			2,342			16,132
Net other comprehensive income	(145,022		)	(3,049	)		527			(147,544	)
Balance at December 31, 2018	(419,852		)	(182,036	)		(7,899	)		(609,787	)
2018 components of other comprehensive income (loss):
Before reclassifications to income	66,600			(47,264	)		—			19,336
Reclassifications to income	—			11,285		^¹	5,005		^²	16,290
Net other comprehensive income (loss)	66,600			(35,979	)		5,005			35,626
Balance at December 31, 2019	$	(353,252	)	(218,015	)		(2,894	)		(574,161	)

¹Reclassifications before taxes of $14,380 and $17,313 are included in the computation of net periodic benefit expense in 2019 and 2018, respectively. See Note L for additional information. Related income taxes of $3,095 and $3,523 are included in income tax expense in 2019 and 2018, respectively.

²Reclassifications before taxes of $6,335 and $2,963 are included in Interest expense in 2019 and 2018. Related income taxes of $1,330 and $622 are included in income tax expense in 2019 and 2018. See Note M for additional information.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2019

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

໿



	December 31, 2019				December 31, 2018
(Thousands of dollars)	Cost		Net		Cost	Net
Exploration and production ¹	$	19,096,323	9,875,727	₂	16,309,149	8,329,514	₂
Corporate and other	207,066		94,016		193,471	102,619
Property, plant and equipment	$	19,303,389	9,969,743		16,502,620	8,432,133
¹ Includes unproved mineral rights as follows:	$	508,526	121,163		512,025	144,912

²Includes $24,698 in 2019 and $27,915 in 2018 related to administrative assets and support equipment.

Divestments

In July 2019, the Company completed a divestiture of its two subsidiaries conducting Malaysian operations, Murphy Sabah Oil Co., Ltd. and Murphy Sarawak Oil Co., Ltd., in a transaction with PTT Exploration and Production Public Company Limited (PTTEP) which was effective January 1, 2019. Total cash consideration received upon closing was $2.0 billion. A gain on sale of $985.4 million was recorded as part of discontinued operations on the Consolidated Statement of Operations in 2019. The Company does not anticipate tax liabilities related to the sales proceeds. Murphy is entitled to receive a $100.0 million bonus payment contingent upon certain future exploratory drilling results prior to October 2020.

In 2017, a Canadian subsidiary of the Company completed its disposition of the Seal field in onshore 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 on the Consolidated Statement of Operations related to the sale.

Acquisitions

In June 2019, the Company announced the completion of a transaction with LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C., (LLOG) which was effective January 1, 2019. Through this transaction, Murphy acquired strategic deepwater Gulf of Mexico assets which added approximately 67 MMBOE of proven reserves at May 31, 2019.

In 2018, a wholly owned subsidiary, Murphy Exploration & Production Company - USA, entered into a definitive agreement with Petrobras America Inc. (PAI), a subsidiary of Petrobras. The transaction was comprised of all of the Gulf of Mexico producing assets from Murphy and PAI with Murphy overseeing the operations. Both companies contributed all their current producing Gulf of Mexico assets to MP Gulf of Mexico, LLC, a subsidiary of Murphy, which following closing of the transaction is owned 80% by Murphy and 20% by PAI. The transaction excluded Murphy’s exploration blocks. However, PAI’s blocks that hold deep exploration rights were part of the transaction. Murphy paid net cash consideration of $780.7 million, after adjustments provided for in the sale and purchase agreement. Additionally, PAI received a 20% interest in MP GOM and will earn an additional contingent consideration of up to $150 million if certain price and production thresholds are exceeded beginning in 2019 through 2025. Also, Murphy will carry $50 million of PAI development costs in the St. Malo Field if certain enhanced oil recovery projects are undertaken.

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, 2019, $152.7 million of the carried interest had been paid and the remainder is expected to be paid in the first quarter of 2020.

Impairments

During 2018, declines in future oil and natural gas prices led to impairments in certain of the Company’s producing properties. During 2018, the Company recorded pretax noncash impairment charges of $20.0 million to reduce the carrying values to their estimated fair values at select Midland properties.

The following table reflects the recognized impairments for the three years ended December 31, 2019.



	December 31,
(Thousands of dollars)	2019		2018	2017
U.S. Onshore (Midland)	$	—	20,000	—
	$	—	20,000	—

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, 2019, 2018 and 2017, the Company had total capitalized drilling costs pending the determination of proved reserves of $217.3 million, $207.9 million and $155.1 million, respectively. The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 2019.



(Thousands of dollars)	2019			2018		2017
Beginning balance at January 1	$	207,855		155,103		101,546
Additions pending the determination of proved reserves	83,712			59,487		53,557
Reclassifications to proved properties based on the determination of proved reserves	(61,096		)	(2,214	)	—
Capitalized exploration well costs charged to expense	(13,145		)	(4,521	)	—
Ending balance at December 31	$	217,326		207,855		155,103

The capitalized well costs charged to expense during 2019 included the CM-1X and the CT-1X wells in Vietnam Block 11-2/11. The wells were originally drilled in 2017. The capitalized well costs charged to expense during 2018 included the Julong East well in Block CA-1, offshore Brunei in which further development of the well has not been sanctioned by the operator and the contract term for development sanctions was reached. This well was originally drilled in 2012.

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.



	2019				2018				2017
(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	$	63,409	5	5	$	61,096	1	1	$	41,480	3	2
One to two years	—		—	—	40,523		3	2	5,812		1	1
Two to three years	27,396		1	—	5,208		1	1	43,200		2	2
Three years or more	126,521		5	—	101,028		4	1	64,611		6	1
	$	217,326	11	5	$	207,855	9	5	$	155,103	12	6

Of the $153.9 million of exploratory well costs capitalized more than one year at December 31, 2019, $57.5 million is in Brunei, $69.1 million is in Vietnam, and $27.4 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.

Discontinued Operations and Assets Held for Sale - Results of Operations Associated with Discontinued Operations (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Discontinued Operations and Disposal Groups [Abstract]

Revenues 1

$ 1,364,943

$ 854,251

$ 781,995

Lease operating expense

127,138

202,062

168,903

Other costs and expenses (benefits)

33,697

196,287

205,841

81,538

70,088

53,409

Total income from discontinued operations before taxes

1,122,570

385,814

353,842

Income tax expense

(58,083)

(135,466)

(112,616)

Income from discontinued operations

$ 1,064,487

$ 250,348

^[1],[2]

$ 241,226

^[1],[2]

[1]	¹ Reclassified to conform with current presentation (see Notes C and E). 2017 revenue is presented net of $58.9 million of transportation, gathering and processing costs as historically shown prior to the adoption of ASC 606 on January 1, 2018. See Notes to Consolidated Financial Statements, page 58.
[2]	Reclassified to conform with current presentation (see Note E)

- Definition

Amount before tax of income (loss) from a discontinued operation. Includes, but is not limited to, the income (loss) from operations during the phase-out period, gain (loss) on disposal, gain (loss) for reversal of write-down (write-down) to fair value, less cost to sell, and adjustments to a prior period gain (loss) on disposal.

+ References + Details

- Definition

Amount of tax expense (benefit) related to a discontinued operation. Includes, but is not limited to, tax expense (benefit) related to income (loss) from operations during the phase-out period, tax expense (benefit) related to gain (loss) on disposal, tax expense (benefit) related to gain (loss) for reversal of write-down (write-down) to fair value, less cost to sell, and tax expense (benefit) related to adjustments of a prior period gain (loss) on disposal.

+ References + Details

- Definition

Amount after tax of income (loss) from a discontinued operation including the portion attributable to the noncontrolling interest. Includes, but is not limited to, the income (loss) from operations during the phase-out period, gain (loss) on disposal, gain (loss) for reversal of write-down (write-down) to fair value, less cost to sell, and adjustments to a prior period gain (loss) on disposal.

+ References + Details

Incentive Plans - Changes in Stock Options Outstanding (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Number of Shares
Exercised	(12,345)	(21,200)	0
Outstanding at end of year	2,920,410
Exercisable at end of year	2,694,410
Stock Options
Number of Shares
Outstanding at beginning of year	3,994,595	4,901,269	5,757,435
Granted at FMV	0	0	(603,000)
Exercised	(57,500)	(72,000)	0
Forfeited	(1,016,685)	(834,674)	(1,459,166)
Outstanding at end of year	2,920,410	3,994,595	4,901,269	5,757,435
Exercisable at end of year	2,694,410	3,182,345	3,197,269	3,830,535
Average Exercise Price
Outstanding at beginning of year	$ 44.66	$ 45.74	$ 48.46
Granted at FMV	0	0	28.51
Exercised	17.57	17.57	0
Forfeited	48.29	53.36	49.34
Outstanding at end of year	43.93	44.66	45.74	$ 48.46
Exercisable at end of year	$ 43.51	$ 49.10	$ 54.22	$ 53.80

Leases Summary of Other Lease Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($)
Cash Flow, Lessee [Abstract]
Operating cash flows from operating leases	$ 193,968
Operating cash flows from finance leases	408
Financing cash flows from finance leases	688
Right-Of-Use Asset Obtained in Exchange For Lease Liability [Abstract]
Operating leases	$ 125,026

Employee and Retiree Benefit Plans - Narrative (Details) $ in Thousands	12 Months Ended					120 Months Ended
	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2018
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Future annual rate of increase in cost of health care for 2016 to measure postretirement benefit obligations		6.50%
Ultimate rate of health care cost in 2028 and thereafter		4.50%
Plan asset, maximum investment in any one issuer		10.00%
Equity securities minimum market capitalization		$ 100,000
Fixed income portfolio, maximum average maturity years		11 years
Weighted average expected return on plan asset			5.51%
Basis used to determine expected return on plan asset, average expected investment expenses			0.60%
Perentage return on plan assets over the last ten years						7.56%
Number of investments in hedge funds and other alternative investments		3
Defined benefit plan, percentage of employer's matching contribution		6.00%
Thrift plan expense			$ 8,400	$ 5,200	$ 7,800
Third investment
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Domestic plan, investment lock up period		2 years
Equity Securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted average expected return on plan asset			6.30%
Defined Benefit Plan, Fixed Income Securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted average expected return on plan asset			3.95%
Defined Benefit Plan, Equity Funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Domestic plan, investment notice period		10 days
Pension Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans		$ 25,915	$ 24,357
Weighted average expected return on plan asset			5.05%	5.37%
Pension Benefits \| United States
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans		25,700
Pension Benefits \| Foreign Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans		200
Other Postretirement Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans		2,333	$ 3,044
Weighted average expected return on plan asset			0.00%	0.00%
Other Postretirement Benefits \| United States
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans		$ 2,300
Subsequent Event \| Pension Benefits \| United States
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	$ 30,600
Subsequent Event \| Pension Benefits \| Foreign Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	600
Subsequent Event \| Other Postretirement Benefits \| United States
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	$ 5,200
Second Investment
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Domestic plan, investment notice period		90 days
Third investment
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Domestic plan, investment notice period		95 days

Incentive Plans - Narrative (Details) - USD ($)	12 Months Ended
Incentive Plans - Narrative (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested share-based compensation arrangements, compensation costs to be expensed		$ 50,400,000
Related income tax benefit recognized in income	$ 7,389,000	$ 4,383,000	$ 5,017,000
Stock options exercised	12,345	21,200	0
Option term	7 years
Total intrinsic value of options exercised	$ 500,000		$ 0	$ 0
Vesting scheme		Under these plans, one-half of each grant is generally exercisable after two years and the remainder after three years.
Cash settled awards		$ 16,900,000	6,500,000	12,900,000
Incentive compensation plan expense		$ 34,100,000	$ 30,000,000.0	30,500,000
Share-based Compensation Award, Tranche One
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	2 years
Share-based Compensation Award, Tranche Two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
2012 Long-Term Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum number of shares available for issuance		6,750,000
Maximum number of shares available for issuance, annual rate		1.00%
Number of shares available		2,100,000
Option term	7 years
Employee Stock Purchase Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation costs estimation		Compensation costs related to the ESPP were estimated based on the value of the 10% discount and the fair value of the option that provided for the refund of participant withholdings
Annual Incentive Plan \| Share-based Compensation Award, Tranche One
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage		50.00%
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Settlement period of phantom units	3 years
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Settlement period of phantom units	5 years
Employee Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Related income tax benefit recognized in income		$ 0		$ 0
Stock options exercised		0		0
Time Lapse Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date			$ 28.51
Time Lapse Restricted Stock \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date	$ 21.68	$ 25.69
Time Lapse Restricted Stock \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date	$ 28.16	$ 28.43	$ 28.84

Supplemental Oil and Gas Information - Narrative (Details) MMBbls in Millions	12 Months Ended
	Dec. 31, 2019 $ / bbl $ / Mcf MMBbls ft³	Dec. 31, 2018 $ / bbl $ / Mcf MMBbls ft³	Dec. 31, 2017 MMBbls ft³	Dec. 31, 2016 MMBbls ft³
Reserve Quantities [Line Items]
Future net cash flows annual discount factor, percentage	10.00%
U.S. statutory rate		21.00%	35.00%
Equity Method Investee
Reserve Quantities [Line Items]
Reserves attributable to investees accounted for my the equity method	0
Net crude oil and condensate revenue
Reserve Quantities [Line Items]
Average production costs per barrel of oil (in dollars per barrel) \| $ / bbl	55.69	65.56
Proved undeveloped reserve development window		5 years	5 years
Associated assets, percentage interests acquired	80.00%
Net natural gas liquids revenue
Reserve Quantities [Line Items]
Proved reserves \| MMBbls	56.1	54.2	48.9	42.5
Proved undeveloped reserve development window	5 years		5 years
Associated assets, percentage interests acquired	80.00%
Net natural gas revenue
Reserve Quantities [Line Items]
Average production costs per volume of natural gas (in dollars per cubic foot) \| $ / Mcf	2.57	3.10
Proved reserves	2,069,700,000,000	2,143,600,000,000	1,927,100,000,000	1,878,000,000,000.0
Proved undeveloped reserve development window	5 years
Associated assets, percentage interests acquired	80.00%
Malaysia & Other \| Net natural gas liquids revenue
Reserve Quantities [Line Items]
Proved reserves \| MMBbls	0.0	0.7	0.3	0.5
Malaysia & Other \| Net natural gas revenue
Reserve Quantities [Line Items]
Proved reserves	0	468,200,000,000	491,400,000,000	539,700,000,000
Canada \| Net natural gas liquids revenue
Reserve Quantities [Line Items]
Proved reserves \| MMBbls	3.3	5.9	5.6	5.6
Canada \| Net natural gas revenue
Reserve Quantities [Line Items]
Proved reserves	1,652,900,000,000	1,366,400,000,000	1,212,400,000,000	1,118,900,000,000

Assets and Liabilities Measured at Fair Value - Carrying Amounts and Estimated Fair Values of Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Financial assets (liabilities), Carrying value
Current and long-term debt	$ (2,803,381)	$ (3,109,986)
Financial assets (liabilities), Fair value
Current and long-term debt	$ (3,074,929)	$ (2,899,912)

Business Segments - Segment Information (Details) - USD ($)

3 Months Ended

12 Months Ended

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Revenues from External Customers and Long-Lived Assets [Line Items]

Net income (loss) including noncontrolling interest

$ (54,400,000)

$ 1,111,700,000

$ 123,200,000

$ 72,800,000

$ 111,800,000

$ 93,900,000

$ 45,500,000

$ 168,300,000

$ 1,253,302,000

$ 419,486,000

^[1],[2]

$ (311,789,000)

^[1],[2]

2,829,053,000

1,791,401,000

^[1]

1,443,988,000

^[1]

(22,520,000)

7,774,000

^[1]

(78,302,000)

^[1]

(219,275,000)

(180,359,000)

^[1]

(178,263,000)

^[1]

14,683,000

(126,136,000)

^[1]

270,131,000

^[1]

1,147,842,000

775,614,000

^[1],[2]

751,878,000

^[1],[2]

40,506,000

27,119,000

^[1],[2]

25,282,000

^[1],[2]

28,000,000.0

40,100,000

61,800,000

20,000,000

^[1],[2]

28,500,000

(183,200,000)

264,100,000

2,560,800,000

1,894,500,000

870,800,000

Mark to market of crude contracts

11,718,504,000

11,052,587,000

^[2]

11,718,504,000

11,052,587,000

^[2]

9,860,900,000

(227,000)

(54,000)

^[2]

(127,434,000)

^[2]

Revenues from External Customers and Long-Lived Assets [Line Items]

Revenues from External Customers and Long-Lived Assets [Line Items]

2,370,400,000

1,300,300,000

958,300,000

Canada

447,100,000

468,900,000

485,700,000

Revenues from External Customers and Long-Lived Assets [Line Items]

Revenues from External Customers and Long-Lived Assets [Line Items]

11,600,000

22,200,000

Discontinued Operations

Net income (loss) including noncontrolling interest

1,064,500,000

250,300,000

241,200,000

138,600,000

16,000,000.0

Revenues from External Customers and Long-Lived Assets [Line Items]

16,700,000

1,691,200,000

16,700,000

1,691,200,000

1,693,000,000.0

Operating Segments

Exploration and Production

2,829,100,000

1,791,400,000

1,444,000,000.0

Revenues from External Customers and Long-Lived Assets [Line Items]

Net income (loss) including noncontrolling interest

460,600,000

277,400,000

66,100,000

2,825,600,000

1,825,400,000

1,429,800,000

(15,800,000)

(500,000)

200,000

100,300,000

57,300,000

7,400,000

1,125,200,000

755,400,000

735,300,000

40,500,000

27,100,000

25,300,000

28,000,000.0

40,100,000

61,800,000

112,400,000

58,900,000

21,600,000

2,547,200,000

1,733,200,000

840,000,000.0

Exploration and Production | United States

10,655,600,000

8,242,900,000

10,655,600,000

8,242,900,000

7,066,200,000

Revenues from External Customers and Long-Lived Assets [Line Items]

Net income (loss) including noncontrolling interest

518,400,000

242,900,000

(8,900,000)

2,367,000,000.0

1,332,700,000

944,300,000

(13,400,000)

115,600,000

68,100,000

(800,000)

878,700,000

519,500,000

546,100,000

34,400,000

19,500,000

17,400,000

23,100,000

36,800,000

60,200,000

111,800,000

68,100,000

2,500,000

2,193,300,000

1,343,500,000

534,800,000

Exploration and Production | Canada

8,043,300,000

6,342,900,000

8,043,300,000

6,342,900,000

5,186,200,000

Revenues from External Customers and Long-Lived Assets [Line Items]

Net income (loss) including noncontrolling interest

(4,300,000)

51,100,000

112,500,000

447,000,000.0

470,500,000

485,500,000

(1,500,000)

(100,000)

(2,900,000)

14,500,000

44,400,000

243,000,000.0

232,400,000

185,400,000

6,100,000

7,600,000

7,900,000

1,300,000

800,000

1,600,000

14,000,000.0

16,500,000

55,300,000

284,100,000

373,800,000

267,600,000

Exploration and Production | Other

2,303,700,000

1,711,900,000

2,303,700,000

1,711,900,000

1,725,800,000

Revenues from External Customers and Long-Lived Assets [Line Items]

Net income (loss) including noncontrolling interest

(53,500,000)

(16,600,000)

(37,500,000)

11,600,000

22,200,000

(900,000)

(400,000)

200,000

(12,400,000)

(25,300,000)

(36,200,000)

3,500,000

3,800,000

3,600,000

2,500,000

(13,400,000)

(25,700,000)

(36,200,000)

69,800,000

15,900,000

37,600,000

Revenues from External Customers and Long-Lived Assets [Line Items]

308,600,000

188,100,000

308,600,000

188,100,000

154,200,000

Corporate and other

Net income (loss) including noncontrolling interest

(271,800,000)

(108,200,000)

(619,100,000)

3,500,000

(34,000,000.0)

14,200,000

(6,700,000)

7,800,000

(78,300,000)

(218,800,000)

(180,600,000)

(178,300,000)

(85,600,000)

(183,400,000)

262,700,000

22,600,000

20,200,000

16,600,000

(83,900,000)

(242,100,000)

242,500,000

13,600,000

22,700,000

14,800,000

Summary of Lease Related Expenses

$ 1,046,200,000

$ 1,118,500,000

$ 1,046,200,000

$ 1,118,500,000

$ 1,101,700,000

[1]	¹ Reclassified to conform with current presentation (see Notes C and E). 2017 revenue is presented net of $58.9 million of transportation, gathering and processing costs as historically shown prior to the adoption of ASC 606 on January 1, 2018. See Notes to Consolidated Financial Statements, page 58.
[2]	Reclassified to conform with current presentation (see Note E)

Supplemental Oil and Gas Information - Capitalized Costs Relating to Oil and Gas Producing Activities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and natural gas properties	$ 1,570.7	$ 821.1
Proved oil and natural gas properties	17,490.4	15,371.3
Gross capitalized costs	19,061.1	16,192.4
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	(387.7)	(368.2)
Proved oil and natural gas properties	(8,739.9)	(7,522.5)
Net capitalized costs	9,933.5	8,301.7
United States
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and natural gas properties	1,116.6	394.2
Proved oil and natural gas properties	13,292.6	11,678.3
Gross capitalized costs	14,409.2	12,072.5
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	(136.4)	(129.3)
Proved oil and natural gas properties	(6,298.9)	(5,433.7)
Net capitalized costs	7,973.9	6,509.5
Canada
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and natural gas properties	243.7	250.0
Proved oil and natural gas properties	4,176.7	3,693.0
Gross capitalized costs	4,420.4	3,943.0
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	(225.4)	(213.5)
Proved oil and natural gas properties	(2,438.6)	(2,088.8)
Net capitalized costs	1,756.4	1,640.7
Other
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and natural gas properties	210.4	176.9
Proved oil and natural gas properties	21.1	0.0
Gross capitalized costs	231.5	176.9
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	(25.9)	(25.4)
Proved oil and natural gas properties	(2.4)	0.0
Net capitalized costs	$ 203.2	$ 151.5

Leases (Tables)

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Related Expenses

Expenses related to finance and operating leases included in the Consolidated Financial Statements are as follows:



(Thousands of dollars)	Financial Statement Category	Year Ended December 31, 2019
Operating lease ^1,2	Lease operating expenses	$	249,787
Operating lease ²	Selling and general expense	12,325
Operating lease ²	Other operating expense	2,588
Operating lease ²	Property, plant and equipment	133,837
Operating lease ²	Asset retirement obligations	3,024
Finance lease
Amortization of asset	Depreciation, depletion and amortization	420
Interest on lease liabilities	Interest expense, net	202
Sublease income	Other income	(1,419		)
Net lease expense		$	400,764

¹ For the year ended December 31, 2019, includes variable lease expenses of $28.7 million, primarily related to additional volumes processed at a natural gas processing plant.

² For the year ended December 31, 2019, includes $56.3 million in Lease operating expense, $4.3 million in Selling and general expense, $2.6 million in Other operating expense, $102.7 million in Property, plant and equipment, net and $3.0 million in Asset retirement obligations relating to short-term leases due within 12 months. Expenses primarily relate to drilling rigs and other oil and natural gas field equipment.

Schedule of Maturity of Lease Liabilities

Maturity of Lease Liabilities໿



(Thousands of dollars)	Operating Leases ¹			Finance Leases		Total
2020	$	124,267		1,069		125,336
2021	74,978			1,069		76,047
2022	56,756			1,069		57,825
2023	54,986			1,069		56,055
2024	50,640			1,069		51,709
Remaining	493,833			4,541		498,374
Total future minimum lease payments	855,460			9,886		865,346
Less imputed interest	(241,850		)	(1,941	)	(243,791	)
Present value of lease liabilities²	$	613,610		7,945		621,555

¹ Excludes $278.7 million of minimum lease payments for leases entered but not yet commenced. These payments relate to an expansion of an existing natural gas processing plant and payments are planned to commence at the end of 2020 for 20 years.

² Includes both the current and long-term portion of the lease liabilities. Financing lease pertains to Brunei, which is classified as held for sale on the Consolidated Balance Sheet as of December 31, 2019.

Summary Of Lease Term and Discount Rate

Lease Term and Discount Rate



	December 31, 2019
Weighted average remaining lease term:
Operating leases	10 years
Finance leases	9 years
Weighted average discount rate:
Operating leases	4.7	%
Finance leases	4.7	%

Summary of Other Lease Information

Other Information໿



(Thousands of dollars)	Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	193,968
Operating cash flows from finance leases	408
Financing cash flows from finance leases	688
Right-of-use assets obtained in exchange for lease liabilities:
Operating leases	$	125,026

Property, Plant and Equipment - Schedule of Recognized Impairments (Details) - USD ($)

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

$ 0

$ 20,000,000

^[1],[2]

$ 0

^[1],[2]

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

$ 0

$ 20,000,000.0

$ 0

[1]	¹ Reclassified to conform with current presentation (see Notes C and E). 2017 revenue is presented net of $58.9 million of transportation, gathering and processing costs as historically shown prior to the adoption of ASC 606 on January 1, 2018. See Notes to Consolidated Financial Statements, page 58.
[2]	Reclassified to conform with current presentation (see Note E)

Accumulated Other Comprehensive Loss

12 Months Ended

Dec. 31, 2019

Accumulated Other Comprehensive Loss



(Thousands of dollars)	Foreign Currency Translation Gains (Losses)			Retirement and Postretirement Benefit Plan Adjustments			Deferred Loss on Interest Rate Derivative Hedges			Total
Balance at December 31, 2017	(274,830		)	(178,987	)		(8,426	)		(462,243	)
2017 components of other comprehensive income (loss):
Before reclassifications to income	(145,022		)	(16,839	)		(1,815	)		(163,676	)
Reclassifications to income	—			13,790			2,342			16,132
Net other comprehensive income	(145,022		)	(3,049	)		527			(147,544	)
Balance at December 31, 2018	(419,852		)	(182,036	)		(7,899	)		(609,787	)
2018 components of other comprehensive income (loss):
Before reclassifications to income	66,600			(47,264	)		—			19,336
Reclassifications to income	—			11,285		^¹	5,005		^²	16,290
Net other comprehensive income (loss)	66,600			(35,979	)		5,005			35,626
Balance at December 31, 2019	$	(353,252	)	(218,015	)		(2,894	)		(574,161	)

Employee and Retiree Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2019

Defined Benefit Plan Disclosure [Line Items]

Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status

The tables that follow provide a reconciliation of the changes in the plans’ benefit obligations and fair value of assets for the years ended December 31, 2019 and 2018 and a statement of the funded status as of December 31, 2019 and 2018.



	Pension Benefits					Other Postretirement Benefits
(Thousands of dollars)	2019			2018		2019		2018
Change in benefit obligation
Obligation at January 1	$	777,645		881,932		94,779		106,276
Service cost	7,964			8,994		1,559		1,965
Interest cost	27,835			26,168		3,864		3,427
Participant contributions	11			—		1,930		2,104
Actuarial loss (gain)	103,374			(57,378	)	10,503		(13,778	)
Medicare Part D subsidy	—			—		234		325
Exchange rate changes	7,687			(12,742	)	30		(67	)
Benefits paid	(41,247		)	(41,132	)	(4,498	)	(5,473	)
Prior Service Cost	—			737		—		—
Other	—			(28,934	)	—		—
Obligation at December 31	883,269			777,645		108,401		94,779
Change in plan assets
Fair value of plan assets at January 1	487,094			563,825		—		—
Actual return on plan assets	70,893			(18,951	)	—		—
Employer contributions	25,915			24,357		2,333		3,044
Participant contributions	11			—		1,930		2,104
Medicare Part D subsidy	—			—		234		325
Exchange rate changes	7,328			(12,071	)	—		—
Benefits paid	(41,247		)	(41,132	)	(4,497	)	(5,473	)
Other	(2,510		)	(28,934	)	—		—
Fair value of plan assets at December 31	547,484			487,094		—		—
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets	5,353			11,039		—		—
Other accrued liabilities	(8,810		)	(9,175	)	(5,234	)	(5,101	)
Deferred credits and other liabilities	(332,328		)	(292,415	)	(103,167	)	(89,678	)
Fund Status and net plan liability recognized at December 31	$	(335,785	)	(290,551	)	(108,401	)	(94,779	)

Amounts Included in Accumulated Other Comprehensive Income Not Recognized in Net Periodic Benefit Expense

At December 31, 2019, amounts included in Accumulated other comprehensive loss (AOCL) in the Consolidated Balance Sheets, before reduction for associated deferred income taxes, which have not been recognized in net periodic benefit expense are shown in the following table.



(Thousands of dollars)	Pension Benefits			Other Postretirement Benefits
Net actuarial gain (loss)	$	(269,391	)	3,307
Prior service cost	(4,090		)	—
	$	(273,481	)	3,307

Amounts Included in Accumulated Other Comprehensive Income Expected to be Amortized into Net Periodic Benefit Expense

Amounts included in AOCL at December 31, 2019 that are expected to be amortized into net periodic benefit expense during 2020 are shown in the following table.



(Thousands of dollars)	Pension Benefits			Other Postretirement Benefits
Net actuarial loss	$	(17,096	)	—
Prior service cost	(734		)	—
	$	(17,830	)	—

Projected Benefit Obligations, Accumulated Benefit Obligations and Fair Value of Plan Assets

The table that follows includes projected benefit obligations, accumulated benefit obligations and fair value of plan assets for plans where the accumulated benefit obligation exceeded the fair value of plan assets.



	Projected Benefit Obligations			Accumulated Benefit Obligations		Fair Value of Plan Assets
(Thousands of dollars)	2019		2018	2019	2018	2019	2018
Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets	$	688,249	457,446	676,177	447,793	525,108	316,543
Unfunded nonqualified and directors’ plans where accumulated benefit obligation exceeds fair value of plan assets	177,999		158,228	171,934	150,586	—	—
Unfunded other postretirement plans	108,401		94,808	108,401	94,808	—	—

Components of Net Periodic Benefit Expense

The table that follows provides the components of net periodic benefit expense for each of the three years ended December 31, 2019.



	Pension Benefits							Other Postretirement Benefits
(Thousands of dollars)	2019			2018		2017		2019		2018		2017
Service cost	$	7,964		8,994		8,279		1,559		1,965		1,601
Interest cost	27,835			26,168		27,047		3,864		3,427		3,444
Expected return on plan assets	(25,719		)	(29,236	)	(28,941	)	—		—		—
Amortization of prior service cost (credit)	964			1,021		1,026		—		(38	)	(74	)
Recognized actuarial loss	14,106			21,893		16,691		(193	)	—		—
Net periodic benefit expense	$	25,150		28,840		24,102		5,230		5,354		4,971

Weighted-Average Assumptions used in Measurement of Benefit Obligations and Net Periodic Benefit Expense

The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2019 and 2018 and net periodic benefit expense for 2019 and 2018 .



	Benefit Obligations								Net Periodic Benefit Expense
	Pension Benefits				Other Postretirement Benefits				Pension Benefits				Other Postretirement Benefits
	December 31,				December 31,				Year				Year
	2019		2018		2019		2018		2019		2018		2019		2018
Discount rate	3.85	%	4.07	%	3.42	%	3.73	%	3.35	%	3.54	%	4.42	%	4.32	%
Expected return on plan assets	5.05	%	5.37	%	—		—		5.05	%	5.37	%	—		—
Rate of compensation increase	3.28	%	3.28	%	—		—		3.52	%	3.52	%	—		—

Benefit Payments Expected to be Paid in Future Years

Benefit payments, reflecting expected future service as appropriate, which are expected to be paid in future years from the assets of the plans or by the Company are shown in the following table.



(Thousands of dollars)	Pension Benefits		Other Postretirement Benefits
2020	$	42,399	5,233
2021	43,500		5,360
2022	44,824		5,428
2023	44,850		5,421
2024	45,557		5,505
2025-2030	233,751		27,847

One Percent Change in Assumed Health Care Cost Trend Rates

Assumed health care cost trend rates have a significant effect on the expense and obligation reported for the postretirement benefit plan. A one percent change in assumed health care cost trend rates would have the following effects.



(Thousands of dollars)	1% Increase		1% Decrease
Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31	$	930	(737	)
Effect on the health care component of the accumulated postretirement benefit obligation at December 31	15,257		(12,291	)

Weighted Average Asset Allocation for Funded Pension Benefit Plans

The weighted average asset allocation for the Company’s funded pension benefit plans at December 31, 2019 and 2018 are presented in the following table.



	December 31,
	2019		2018
Equity securities	54.9	%	56.0	%
Fixed income securities	26.2		42.2
Alternatives	17.3		—
Cash equivalents	1.6		1.8
	100.0	%	100.0	%

The following table provides the asset allocation of each plan on December 31, 2019.



	Allocation of Plan Assets
	Domestic Plan		Canadian Plan		U.K. Plan
	Target	Allocation at	Target	Allocation at	Target	Allocation at
	Allocation	December 31, 2019	Allocation	December 31, 2019	Allocation	December 31, 2019
Equity securities	40-70%	54.0%	28-38%	34.5%	N/A	59.2%
Fixed income securities	25-60%	27.8%	60-70%	63.5%	N/A	18.4%
Alternatives	0-20%	16.9%	—%	—%	N/A	20.2%
Cash and equivalents	0-15%	1.3%	0-10%	2.0%	N/A	2.2%

Fair Value Measurements of Retirement Plan Assets

At December 31, 2019, the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows.



			Fair Value Measurements Using
(Thousands of dollars)	Fair Value at December 31, 2019		Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
Domestic Plans
Equity securities:
U.S. core equity	$	63,169	63,169	—	—
U.S. small/midcap	26,062		26,062	—	—
Hedged funds and other alternative strategies	58,864		—	—	58,864
International commingled trust fund	73,783		924	55,798	17,061
Emerging market commingled equity fund	25,911		8,011	17,900	—
Fixed income securities:
U.S. fixed income	88,525		—	88,525	—
International commingled trust fund	8,720		—	8,720	—
Cash and equivalents	4,485		4,485	—	—
Total Domestic Plans	349,519		102,651	170,943	75,925
Foreign Plans
Equity securities funds	68,878		—	68,840	—
Fixed income securities funds	46,582		—	46,390	—
Diversified pooled fund	42,582		—	42,582	—
Other	35,661		—	—	35,661
Cash and equivalents	4,262		—	4,256	—
Total Foreign Plans	197,965		—	162,068	35,661
Total	$	547,484	102,651	333,011	111,586

At December 31, 2018, the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows.



			Fair Value Measurements Using
(Thousands of dollars)	Fair Value at December 31, 2018		Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
Domestic Plans
Equity securities:
U.S. core equity	$	62,105	62,105	—	—
U.S. small/midcap	19,436		19,436	—	—
Hedged funds and other alternative strategies	45,844		—	10,789	35,055
International commingled trust fund	63,089		—	63,089	—
Emerging market commingled equity fund	15,355		—	15,355	—
Fixed income securities:
U.S. fixed income	87,526		—	87,526	—
International commingled trust fund	13,274		—	13,274	—
Emerging market mutual fund	4,570		—	4,570	—
Cash and equivalents	5,344		5,344	—	—
Total Domestic Plans	316,543		86,885	194,603	35,055
Foreign Plans
Equity securities funds	67,165		—	67,165	—
Fixed income securities funds	89,417		—	89,417	—
Diversified pooled fund	10,762		—	10,762	—
Cash and equivalents	3,207		—	3,207	—
Total Foreign Plans	170,551		—	170,551	—
Total	$	487,094	86,885	365,154	35,055

Effects of Fair Value Measurements Using Significant Unobservable Inputs on Changes in Level 3 Plan Assets

The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below:



(Thousands of dollars)	Hedged Funds and Other Alternative Strategies
Total at December 31, 2017	$	37,950
Actual return on plan assets:
Relating to assets held at the reporting date	(2,921		)
Total at December 31, 2018	35,029
Actual return on plan assets:
Relating to assets held at the reporting date	20,811
Purchases, sales and settlements	55,746
Total at December 31, 2019	$	111,586

Foreign Plans

Defined Benefit Plan Disclosure [Line Items]

Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status



	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)	2019			2018	2019	2018
Benefit obligation at December 31	$	209,923		173,860	387	812
Fair value of plan assets at December 31	197,965			170,551	—	—
Net plan liabilities recognized	(11,957		)	3,309	387	812
Net periodic benefit expense (benefit)	(933		)	3,983	147	146

Inventories - Schedule of Inventory (Details) - USD ($)
$ in Thousands

Dec. 31, 2019

Dec. 31, 2018

Inventory Disclosure [Abstract]

Unsold crude oil

$ 27,634

$ 17,318

Materials and supplies

48,489

62,706

Inventory, net, total

$ 76,123

$ 80,024

^[1]

[1]	Reclassified to conform with current presentation (see Note E)

Other Financial Information

12 Months Ended

Dec. 31, 2019

Other Financial Information [Abstract]

Other Financial Information

GAIN FROM FOREIGN CURRENCY TRANSACTIONS – Net gains (losses) from foreign currency transactions, including the effects of foreign currency contracts, included in the Consolidated Statements of Operations were $(6.0) million in 2019, $16.1 million in 2018 and $(82.7) million in 2017.

Noncash operating working capital (increased) decreased during each of the three years ended December 31, 2019 as shown in the following table.



(Thousands of dollars)	2019			2018		2017
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable ¹	$	(232,037	)	(30,212	)	(15,462	)
(Increase) decrease in inventories	10,258			16,794		15,429
(Increase) decrease in prepaid expenses	4,650			(10,011	)	15,752
Increase (decrease) in accounts payable and accrued liabilities ¹	196,773			8,784		70,376
Increase (decrease) in income taxes payable	3,469			(1,458	)	(7,249	)
Net (increase) decrease in noncash operating working capital	$	(16,887	)	(16,103	)	78,846
Supplementary disclosures:
Cash income taxes paid, net of refunds	$	(6,645	)	(7,603	)	(5,969	)
Interest paid, net of amounts capitalized of $1.8 million in 2019 and $0.2 million in 2018	179,722			158,071		144,455

Non-cash investing activities:
Asset retirement costs capitalized ²	$	33,874		346,387		126
(Increase) decrease in capital expenditure accrual	(73,426		)	9,817		16,325

¹ Excludes receivable/payable balances relating to mark-to-market of crude contracts.

²Includes asset retirement obligations assumed as part of the LLOG acquisition of $37.3 million.

Assets and Liabilities Measured at Fair Value (Tables)

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Carrying Value of Assets and Liabilities Recorded at Fair Value on Recurring Basis

The fair value measurements for these assets and liabilities at December 31, 2019 and 2018 are presented in the following table



	December 31, 2019					December 31, 2018
(Thousands of dollars)	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
Assets:
Commodity derivative contracts	$	—	—	—	—	—	3,837	—	3,837
	$	—	—	—	—	—	3,837	—	3,837

Liabilities:
Nonqualified employee savings plans	$	17,035	—	—	17,035	13,845	—	—	13,845
Commodity derivative contracts	—		33,364	—	33,364	—	—	—	—
Contingent consideration	—		—	146,787	146,787	—	—	47,730	47,730
	$	17,035	33,364	146,787	197,186	13,845	—	47,730	61,575

Carrying Amounts and Estimated Fair Values of Financial Instruments

The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 2019 and 2018. The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties. The table excludes cash and cash equivalents, trade accounts receivable, trade accounts payable and accrued expenses, all of which had fair values approximating carrying amounts. The fair value of current and long-term debt was estimated based on rates offered to the Company at that time for debt of the same

maturities. The Company has off-balance sheet exposures relating to certain letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, was nominal.



	December 31,
	2019					2018
(Thousands of dollars)	Carrying Amount			Fair Value		Carrying Amount		Fair Value
Financial assets (liabilities):
Current and long-term debt	$	(2,803,381	)	(3,074,929	)	(3,109,986	)	(2,899,912	)

Nonrecurring Fair Value Measurements

The fair value information associated with these impaired properties is presented in the following table

Year Ended December 31, 2018

Net Book

Value

Prior to

Impairment

Total

Pretax

Impairment

Fair Value

(Thousands of dollars)

Level 1

Level 2

Level 3

Assets:

Impaired proved properties

United States Midland

—

37,690

57,690

20,000

Supplemental Quarterly Information (Tables)

12 Months Ended

Dec. 31, 2019

Quarterly Financial Information Disclosure [Abstract]

Schedule of Supplemental Quarterly Information



(Millions of dollars except per share amounts)	First Quarter			Second Quarter		Third Quarter	Fourth Quarter		Year
Year ended December 31, 2019
Revenue from contracts with customers	$	629.4		680.4		750.3	757.0		2,817.1
Income (loss) from continuing operations before income taxes	33.7			107.9		177.1	(115.3	)	203.5
Income (loss) from continuing operations	22.9			98.8		158.3	(91.3	)	188.8
Net income (loss) including noncontrolling interest	72.8			123.2		1,111.7	(54.4	)	1,253.3
Net income (loss) attributable to Murphy	40.2			92.3		1,089.0	(71.7	)	1,149.7
Income (loss) from continuing operations per Common share
Basic	(0.06		)	0.40		0.85	(0.71	)	0.52
Diluted	(0.06		)	0.40		0.84	(0.70	)	0.52
Net income (loss) per Common share
Basic	0.23			0.55		6.79	(0.71	)	7.01
Diluted	0.23			0.54		6.76	(0.47	)	6.98
Cash dividend per Common share	0.25			0.25		0.25	0.25		1.00
Year ended December 31, 2018
Revenue from contracts with customers	$	411.9		443.0		475.5	476.1		1,806.5
Income (loss) from continuing operations before income taxes	(21.1		)	(22.6	)	74.0	12.7		43.0
Income (loss) from continuing operations	90.6			(25.2	)	56.1	47.6		169.1
Net income including noncontrolling interest	168.3			45.5		93.9	111.8		419.5
Net income attributable to Murphy	168.3			45.5		93.9	103.4		411.1
Income (loss) from continuing operations per Common share
Basic	0.52			(0.14	)	0.32	0.23		0.92
Diluted	0.52			(0.15	)	0.32	0.22		0.92
Net income (loss) per Common share
Basic	0.97			0.27		0.54	0.60		2.38
Diluted	0.96			0.25		0.54	0.59		2.36
Cash dividend per Common share	0.25			0.25		0.25	0.25		1.00

Includes noncontrolling interest in MP GOM.

Employee and Retiree Benefit Plans - Components of Net Periodic Benefit Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Recognized actuarial loss	$ (193)	$ 0
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	7,964	8,994	$ 8,279
Interest cost	27,835	26,168	27,047
Expected return on plan assets	(25,719)	(29,236)	(28,941)
Amortization of prior service cost (credit)	964	1,021	1,026
Recognized actuarial loss	14,106	21,893	16,691
Net periodic benefit expense	25,150	28,840	24,102
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	1,559	1,965	1,601
Interest cost	3,864	3,427	3,444
Expected return on plan assets	0	0	0
Amortization of prior service cost (credit)	0	(38)	(74)
Recognized actuarial loss			0
Net periodic benefit expense	$ 5,230	$ 5,354	$ 4,971

Significant Accounting Policies - Narrative (Details) - USD ($)

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

^[1],[2]

Dec. 31, 2017

^[1],[2]

Withholding tax on amounts repatriated

$ 0

$ 20,000,000

$ 0

5.00%

PAI (Final)

Percentage of acquired entity reported

100.00%

Percentage of acquired entity noncontrolling interest reported

20.00%

Performance Based Restricted Stock

Stock-based compensation, vesting period

3 years

Minimum

Equity method investment, ownership percentage

20.00%

Minimum | Stock Options

Stock-based compensation, vesting period

2 years

Maximum

Equity method investment, ownership percentage

50.00%

Maximum | Stock Options

Stock-based compensation, vesting period

3 years

[1]	¹ Reclassified to conform with current presentation (see Notes C and E). 2017 revenue is presented net of $58.9 million of transportation, gathering and processing costs as historically shown prior to the adoption of ASC 606 on January 1, 2018. See Notes to Consolidated Financial Statements, page 58.
[2]	Reclassified to conform with current presentation (see Note E)

Earnings per Share (Tables)

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

Weighted-Average Shares Outstanding for Computation of Basic and Diluted Income per Common Share

The following table reconciles the weighted-average shares outstanding used for these computations.



(Weighted-average shares)	2019	2018	2017
Basic method	163,992,427	172,974,491	172,524,061
Dilutive stock options ¹	820,001	1,234,274	—
Diluted method	164,812,428	174,208,765	172,524,061

¹ Due to a net loss recognized by the Company for the year ended December 31, 2017, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive.

Anti Dilutive Securities not Included in Computation of Diluted EPS

The following table reflects certain options to purchase shares of common stock that were outstanding during the three years ended December 31, 2019, but were not included in the computation of dilutive earnings per share because the incremental shares from the assumed conversion were antidilutive.



	2019		2018		2017
Antidilutive stock options excluded from diluted shares	2,974,401		3,942,296		4,901,269
Weighted average price of these options		$45.26		$46.77		$45.74

Acquisitions - Preliminary Purchase Price Allocation (Details) - USD ($) $ in Thousands	1 Months Ended		7 Months Ended	13 Months Ended
	Jun. 30, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2019
PAI (Final)
Business Acquisition [Line Items]
Cash consideration paid		$ 780,700		$ 780,678
Fair value of net assets contributed				154,468
Contingent consideration				52,540
NCI in acquired assets				246,922
Total purchase consideration				1,234,608
Fair value of Property, plant and equipment			$ 1,617,371	1,617,371
Other assets			5,628	5,628
Less: Asset retirement obligations			(388,391)	(388,391)
Total net assets			1,234,608	$ 1,234,608
LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C. [Member]
Business Acquisition [Line Items]
Cash consideration paid	$ 1,238,400		1,238,353
Fair value of net assets contributed			0
Contingent consideration			89,444
NCI in acquired assets			0
Total purchase consideration			$ 1,327,797
Fair value of Property, plant and equipment		1,358,372
Other assets		6,697
Less: Asset retirement obligations		(37,272)
Total net assets		$ 1,327,797

Financing Arrangements and Long-Term Debt - Narrative (Details) - USD ($)	1 Months Ended	12 Months Ended
	Nov. 30, 2019	Dec. 31, 2019	Oct. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
Line of Credit Facility [Line Items]
Amount outstanding		$ 0			$ 325,000,000
Cost of debt extinguishment		32,100,000
Gain (loss) on extinguishment of debt		26,600,000
Future maturities of long term debt in 2019		0
Future maturities of long term debt in 2020		0
Future maturities of long term debt in 2021		578,700,000
Future maturities of long term debt in 2022		0
Future maturities of long term debt in 2023		550,000,000.0
Thereafter		$ 1,700,000,000
Revolving Credit Facility
Line of Credit Facility [Line Items]
Interest rate		3.21%
5.875% notes, due December 2027
Line of Credit Facility [Line Items]
Face amount of notes	$ 550,000,000
Transaction costs	$ 7,400,000
Interest rate	5.875%				5.875%
4.00% notes, due June 2022
Line of Credit Facility [Line Items]
Repayments of debt	$ 239,700,000
Interest rate	4.00%				4.00%
4.45% notes, due December 2022 ¹
Line of Credit Facility [Line Items]
Repayments of debt	$ 281,600,000
Interest rate	4.45%		3.70%		4.45%
5.875% notes, due December 2042 ¹
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate		25.00%
Interest rate					5.875%
2018 Revolving Credit Facility
Line of Credit Facility [Line Items]
Credit facility maximum borrowing capacity		$ 1,600,000,000
Amount outstanding		0
2018 Revolving Credit Facility \| Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding		$ 3,700,000
New Term Credit Facility
Line of Credit Facility [Line Items]
Credit facility maximum borrowing capacity				$ 500,000,000

Financial Instruments and Risk Management - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($) barrels_per_day contract $ / bbl	Dec. 31, 2018 USD ($) contract	Dec. 31, 2017 USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of foreign currency derivatives \| contract	0
Amount of loss reclassified to interest expense	$ 6.3
Loss deferred for fair value of interest rate derivative contracts, net of tax		$ 0.8
Income taxes on deferred loss on fair value of interest rate derivative contracts	$ 2.9
Amount of loss expected to be reclassified to interest expense in the next 12 months		$ 3.0	$ 3.0
Commodity derivative contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Daily production commitment (barrels per day) \| barrels_per_day	45,000
Derivative, Swap Type, Average Fixed Price \| $ / bbl	56.42
Number of WTI crude oil swap financial contracts \| contract		0

Income Taxes

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Income Taxes

The components of income (loss) from continuing operations before income taxes for each of the three years presented and income tax expense (benefit) attributable thereto were as follows.



(Thousands of dollars)	2019			2018		2017
Income (loss) from continuing operations before income taxes
United States	$	282,199		14,907		(299,349	)
Foreign	(78,701		)	28,095		16,465
Total	$	203,498		43,002		(282,884	)
Income tax expense (benefit)
U.S. Federal – Current	$	—		(9,765	)	—
– Deferred	30,598			(131,200	)	156,065
Total U.S. Federal	30,598			(140,965	)	156,065
State	5,139			3,299		4,230
Foreign – Current	(17,823		)	61,257		59
– Deferred	(3,231		)	(49,727	)	109,777
Total Foreign	(21,054		)	11,530		109,836
Total	$	14,683		(126,136	)	270,131

The following table reconciles income taxes based on the U.S. statutory tax rate to the Company’s income tax expense.



(Thousands of dollars)	2019			2018		2017
Income tax expense (benefit) based on the U.S. statutory tax rate	$	42,735		9,031		(98,868	)
Revaluation of deferred tax (U.S. tax reform)	—			—		118,004
Alberta tax rate reduction and tax impact of deemed repatriation of foreign invested earnings (U.S. tax reform)	(17,019		)	(135,700	)	156,000
Deferred tax effect on Canadian earnings no longer indefinitely invested	—			—		65,000
Foreign income (loss) subject to foreign tax rates different than the U.S.statutory rate	(1,122		)	5,822		2,032
State income taxes, net of federal benefit	4,060			2,607		2,438
U.S. tax benefit on certain foreign upstream investments	(14,975		)	(14,702	)	(32,926	)
Increase in deferred tax asset valuation allowance related to other foreign exploration expenditures	10,927			3,283		18,601
Tax effect on income attributable to noncontrolling interest	(21,750		)	(1,753	)	—
Other, net	11,827			5,276		39,850
Total	$	14,683		(126,136	)	270,131

The Tax Cuts and Jobs Act

On December 22, 2017, the U.S. enacted into legislation the Tax Cuts and Jobs Act (2017 Tax Act). For the year ended December 31, 2017, the Company recorded a provisional tax expense of $274.0 million directly related to the impacts of the 2017 Tax Act. The charge included the impact of a deemed repatriation of foreign earnings and the re-measurement of deferred tax assets and liabilities. During 2018, the Company completed the accounting for the income tax effects related to the 2017 Tax Act before the end of the measurement period. The Company revised the provisional amount recorded in 2017 and recognized a favorable income tax adjustment of $135.7 million primarily related to the reinstatement of a deferred tax asset for 2017 net operating losses, which in 2017 was assumed utilized against the deemed repatriation. This reinstatement followed April 2, 2018 Internal Revenue Service guidance which allowed the Company to preserve the 2017 tax net operating loss as a carryforward and allowed previously unused foreign tax credits to be credited against all but $26 million of current income tax on the deemed inclusion of foreign earnings. The $26 million tax is further reduced by $16 million of post-2017 foreign tax credits allowed to be carried back as an offset, which results in a net $10.1 million tax on the deemed repatriation. This tax is fully offset by $29.7 million of AMT credit carryforwards to 2017, with half of the $19.6 million remainder expected to be

refunded in 2020, and the balance to be refunded or available to offset future U.S. income tax obligations over the next three years.

An analysis of the Company’s deferred tax assets and deferred tax liabilities at December 31, 2019 and 2018 showing the tax effects of significant temporary differences follows.



(Thousands of dollars)	2019			2018
Deferred tax assets
Property and leasehold costs	$	233,351		231,389
Liabilities for dismantlements	78,361			88,075
Postretirement and other employee benefits	125,250			113,826
Alternative minimum tax	9,765			9,765
U. S. net operating loss	495,252			496,629
Other deferred tax assets	66,795			19,974
Total gross deferred tax assets	1,008,774			959,658
Less valuation allowance	(103,113		)	(166,991	)
Net deferred tax assets	905,661			792,667
Deferred tax liabilities
Deferred tax on undistributed foreign earnings	(5,000		)	(5,000	)
Accumulated depreciation, depletion and amortization	(938,614		)	(710,384	)
Investment in partnership	(14,250		)	(32,178	)
Other deferred tax liabilities	(25,708		)	(28,802	)
Total gross deferred tax liabilities	(983,572		)	(776,364	)
Net deferred tax (liabilities) assets	$	(77,911	)	16,303

In management’s judgment, the net deferred tax assets in the preceding table are more likely than not to be realized based on the consideration of deferred tax liability reversals and future taxable income. The valuation allowance for deferred tax assets relate primarily to tax assets arising in foreign tax jurisdictions that in the judgment of management at the present time are more likely than not to be unrealized. The valuation allowance decreased $63.6 million in 2019 primarily due to the movement of Brunei assets to held for sale. Subsequent reductions of the valuation allowance are expected to be reported as reductions of tax expense assuming no offsetting change in the deferred tax asset.

The Company has an estimated U.S. net operating loss of $2.4 billion at year-end 2019 with a corresponding deferred tax asset of $495.3 million. The Company believes the U.S. net operating loss being carried forward will be utilized in future periods prior to expirations in 2036 and 2037.

Other Information

During 2018 the Company repatriated $1.2 billion to the U.S. and paid $60 million of related Canadian withholding tax. $1.3 billion was identified as not permanently reinvested as of December 31, 2017, with an accompanying $65.0 million liability recorded on the balance sheet as of December 31, 2017. Currently the Company considers $100.0 million of Canada’s past foreign earnings not permanently reinvested, with an accompanying $5.0 million liability. At December 31, 2019, $1.4 billion of past foreign earnings are considered permanently reinvested. The Company closely and routinely monitors these reinvestment positions considering underlying facts and circumstances pertinent to our business and the future operation of the company.

Uncertain Income Tax Positions

The financial statement recognition of the benefit for a tax position is dependent upon the benefit being more likely than not to be sustainable upon ultimate settlement. If this threshold is met, the tax benefit is then measured and recognized at the largest amount that is greater than 50% likely of being realized upon ultimate settlement. Liabilities associated with uncertain income tax positions are included in Deferred credits and other liabilities in the Consolidated Balance Sheets. A reconciliation of the beginning and ending amount of the consolidated liability for unrecognized income tax benefits during the three years presented is shown in the following table.



(Thousands of dollars)	2019			2018		2017
Balance at January 1	$	2,903		3,437		7,417
Additions for tax positions related to current year	456			454		769
Settlements due to lapse of time	(821		)	(988	)	(4,834	)
Foreign currency translation effect	—			—		85
Balance at December 31	$	2,538		2,903		3,437

All additions or settlements to the above liability affect the Company’s effective income tax rate in the respective period of change. The Company accounts for any applicable interest and penalties on uncertain tax positions as a component of income tax expense. The Company also had other recorded liabilities as of December 31, 2019, 2018 and 2017 for interest and penalties of $0.1 million, $0.2 million and $0.1 million, respectively, associated with uncertain tax positions. Income tax expense for the years ended December 31, 2019, 2018 and 2017 included net benefits for interest and penalties of $0.1 million, $0.1 million and $0.2 million, respectively, associated with uncertain tax positions.

In 2020, the Company currently expects to add between $0.2 million and $1.0 million to the provision for uncertain tax positions. Although existing liabilities could be reduced by settlement with taxing authorities or lapse due to statute of limitations, the Company believes that the changes in its unrecognized tax benefits due to these events will not have a material impact on the Consolidated Statement of Operations during 2020.

The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. As of December 31, 2019, the earliest years remaining open for audit and/or settlement in the Company’s major taxing jurisdictions are as follows: United States – 2016; Canada – 2015; Malaysia – 2012; and United Kingdom – 2017. The Company has retained certain possible liabilities and rights to income tax receivables relating to Malaysia for the years prior to 2019. The Company believes current recorded liabilities are adequate.

Incentive Plans - Share-Based Plans, Amounts Recognized (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Compensation charged against income (loss) before income tax benefit	$ 50,170	$ 34,467	$ 40,365
Related income tax benefit recognized in income	$ 7,389	$ 4,383	$ 5,017

Assets and Liabilities Measured at Fair Value - Nonrecurring Fair Value Measurements (Details) - USD ($)

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

^[1],[2]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Net Book Value Prior to Impairment

$ 57,690,000

Total Pretax Impairment

$ 0

20,000,000

^[1],[2]

$ 0

Level 1 | United States Midland

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair value impaired charges

Level 2 | United States Midland

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair value impaired charges

Level 3 | United States Midland

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair value impaired charges

$ 37,690,000

[1]	¹ Reclassified to conform with current presentation (see Notes C and E). 2017 revenue is presented net of $58.9 million of transportation, gathering and processing costs as historically shown prior to the adoption of ASC 606 on January 1, 2018. See Notes to Consolidated Financial Statements, page 58.
[2]	Reclassified to conform with current presentation (see Note E)

Earnings per Share - Anti Dilutive Securities Not Included in Computation of Diluted EPS (Details) - $ / shares	9 Months Ended		12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2017
Earnings Per Share [Abstract]
Antidilutive stock options excluded from diluted shares (in shares)	2,974,401	3,942,296	4,901,269
Weighted average price of these options (in USD per share)	$ 45.26	$ 46.77	$ 45.74

Leases Summary of Lease Term and Discount Rate (Details)	Dec. 31, 2019
Weighted Average Remaining Lease Term [Abstract]
Operating leases	10 years
Finance leases	9 years
Leases, Weighted Average Discount Rate [Abstract]
Operating leases	4.70%
Finance leases	4.70%

Other Financial Information (Tables)

12 Months Ended

Dec. 31, 2019

Other Financial Information [Abstract]

Noncash Operating Working Capital (Increase) Decrease

Noncash operating working capital (increased) decreased during each of the three years ended December 31, 2019 as shown in the following table.



(Thousands of dollars)	2019			2018		2017
Net (increase) decrease in operating working capital, excluding cash and cash equivalents:
(Increase) decrease in accounts receivable ¹	$	(232,037	)	(30,212	)	(15,462	)
(Increase) decrease in inventories	10,258			16,794		15,429
(Increase) decrease in prepaid expenses	4,650			(10,011	)	15,752
Increase (decrease) in accounts payable and accrued liabilities ¹	196,773			8,784		70,376
Increase (decrease) in income taxes payable	3,469			(1,458	)	(7,249	)
Net (increase) decrease in noncash operating working capital	$	(16,887	)	(16,103	)	78,846
Supplementary disclosures:
Cash income taxes paid, net of refunds	$	(6,645	)	(7,603	)	(5,969	)
Interest paid, net of amounts capitalized of $1.8 million in 2019 and $0.2 million in 2018	179,722			158,071		144,455

Non-cash investing activities:
Asset retirement costs capitalized ²	$	33,874		346,387		126
(Increase) decrease in capital expenditure accrual	(73,426		)	9,817		16,325

¹ Excludes receivable/payable balances relating to mark-to-market of crude contracts.

²Includes asset retirement obligations assumed as part of the LLOG acquisition of $37.3 million.

Incentive Plans - Changes in Performance-Based RSU Outstanding (Details) - Equity-Settled Restricted Stock Units - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Roll Forward]
Outstanding at beginning of year	1,660,417	1,187,921	992,573
Granted	957,600	905,500	560,000
Vested and issued	(331,917)	(311,866)	(272,725)
Forfeited	(156,367)	(121,138)	(91,927)
Outstanding at end of year	2,129,733	1,660,417	1,187,921

Supplemental Oil and Gas Information - Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($) $ / Mcf	Dec. 31, 2018 USD ($) $ / Mcf	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 28,533.4	$ 34,423.0	$ 21,992.1
Future development costs	(4,861.8)	(5,159.2)	(3,793.5)
Future production costs	(11,566.0)	(12,785.9)	(9,577.7)
Future income taxes	(2,137.9)	(2,924.9)	(1,287.0)
Future net cash flows	9,967.7	13,553.0	7,333.9
10% annual discount for estimated timing of cash flows	(4,140.1)	(5,273.1)	(3,411.0)
Net changes in prices and production costs	(2,993.9)	2,972.6	2,428.4
Net changes in development costs	(675.7)	(1,891.1)	(724.4)
Sales and Transfers of Oil and Gas Produced, Net of Production Costs	2,163.8	1,978.6	1,576.0
Net change due to extensions and discoveries	1,221.9	1,930.3	807.9
Increase Decrease Due To Purchases And Sales Of Minerals In Place	628.1	(3,152.4)	(85.9)
Development costs incurred	1,282.4	1,017.3	802.7
Accretion of discount	1,002.0	469.5	270.9
Revisions of previous quantity estimates	(71.2)	(347.8)	(109.5)
Net change in income taxes	574.1	(967.6)	(643.0)
Standardized Measure of Discounted Future Net Cash Flow of Proved Oil and Gas Reserves, Period Increase (Decrease)	(2,452.3)	4,357.0	1,342.9
Standardized measure of discounted future net cash flows	5,827.6	8,279.9	3,922.9	$ 2,580.0
United States
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	23,565.6	23,473.9	12,885.8
Future development costs	(4,137.8)	(3,279.1)	(2,079.5)
Future production costs	(8,986.2)	(7,279.5)	(4,765.3)
Future income taxes	(1,709.3)	(2,216.5)	(893.7)
Future net cash flows	8,732.3	10,698.8	5,147.3
10% annual discount for estimated timing of cash flows	(3,633.1)	(4,295.4)	(2,698.2)
Standardized measure of discounted future net cash flows	5,099.2	6,403.4	2,449.1
Canada
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	4,912.1	5,437.5	4,714.3
Future development costs	(723.7)	(1,362.7)	(1,081.7)
Future production costs	(2,549.9)	(2,693.0)	(2,507.4)
Future income taxes	(414.5)	(236.4)	(161.1)
Future net cash flows	1,224.0	1,145.4	964.1
10% annual discount for estimated timing of cash flows	(504.0)	(531.4)	(394.6)
Standardized measure of discounted future net cash flows	720.0	614.0	569.5
Malaysia & Other
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	55.7	5,511.6	4,392.0
Future development costs	(0.3)	(517.4)	(632.3)
Future production costs	(29.9)	(2,813.4)	(2,305.0)
Future income taxes	(14.1)	(472.0)	(232.2)
Future net cash flows	11.4	1,708.8	1,222.5
10% annual discount for estimated timing of cash flows	(3.0)	(446.3)	(318.2)
Standardized measure of discounted future net cash flows	$ 8.4	$ 1,262.5	$ 904.3
Net natural gas revenue
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Average production costs per volume of natural gas (in dollars per cubic foot) \| $ / Mcf	2.57	3.10

Employee and Retiree Benefit Plans - Projected Benefit Obligations, Accumulated Benefit Obligations and Fair Value of Plan Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Funded Plan \| Qualified Plan
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations	$ 688,249	$ 457,446
Accumulated Benefit Obligations	676,177	447,793
Fair Value of Plan Assets	525,108	316,543
Unfunded Plan \| Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations	108,401	94,808
Accumulated Benefit Obligations	108,401	94,808
Fair Value of Plan Assets	0	0
Unfunded Plan \| Nonqualified Plan
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations	177,999	158,228
Accumulated Benefit Obligations	171,934	150,586
Fair Value of Plan Assets	$ 0	$ 0

Discontinued Operations and Assets Held for Sale

12 Months Ended

Dec. 31, 2019

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations and Assets Held for Sale

Assets Held for Sale and Discontinued Operations

The following table presents the carrying value of the major categories of assets and liabilities of the Brunei exploration and production and the U.K. refining and marketing operations reflected as held for sale on the Company’s Consolidated Balance Sheets at December 31, 2019. As of December 31, 2018, Malaysia exploration and production business was also held for sale. The Malaysia sale closed on July 10, 2019.



(Thousands of dollars)	2019		2018
Current assets
Cash	$	25,185	44,669
Accounts receivable	4,834		103,158
Inventories	406		7,887
Prepaid expenses and other	1,882		18,151
Property, Plant, and Equipment, net	82,116		—
Deferred income taxes and other assets	9,441		—
Total current assets associated with assets held for sale	123,864		173,865
Non-current assets
Property, Plant, and Equipment, net	—		1,325,431
Deferred income taxes and other assets	—		219,577
Total non-current assets associated with assets held for sale	—		1,545,008
Current liabilities
Accounts payable	3,702		203,236
Other accrued liabilities	—		55,273
Current maturities of long-term debt (finance lease)	705		9,915
Taxes payable	1,411		18,034
Asset retirement obligation	240		—
Long-term debt (finance lease)	7,240		—
Total current liabilities associated with assets held for sale	13,298		286,458
Non-current liabilities
Long-term debt	—		117,816
Asset retirement obligation	—		274,904
Total non-current liabilities associated with assets held for sale	$	—	392,720

The Company has accounted for its former Malaysian exploration and production operations, along with its former U.K. and U.S. refining and marketing operations as discontinued operations for all periods presented. The results of operations associated with discontinued operations are presented in the following table.



(Thousands of dollars)	2019		2018	2017
Revenues ¹	$	1,364,943	854,251	781,995
Costs and expenses
Lease operating expense	127,138		202,062	168,903
Depreciation, depletion and amortization	33,697		196,287	205,841
Other costs and expenses (benefits)	81,538		70,088	53,409
Total income from discontinued operations before taxes	1,122,570		385,814	353,842
Income tax expense	58,083		135,466	112,616
Income from discontinued operations	$	1,064,487	250,348	241,226

¹ 2019 includes a $985.4 million gain on sale of the Malaysia operations.

Incentive Plans - Assumptions used in Valuation Performance Awards Granted (Details) - Performance Based Restricted Stock - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Assumptions
Expected volatility	46.00%	48.00%	47.00%
Risk-free interest rate	2.50%	2.30%	1.46%
Stock beta	1.037	1.103	1.058
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date		$ 22.99	$ 24.10	$ 12.21
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per share at grant date		$ 30.56	$ 28.28	$ 16.34

Income Taxes - Reconciliation of Beginning and Ending Amount of Consolidated Liability for Unrecognized Income Tax Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at January 1	$ 2,903	$ 3,437	$ 7,417
Additions for tax positions related to current year	456	454	769
Settlements due to lapse of time	(821)	(988)	(4,834)
Foreign currency translation effect	0	0	85
Balance at December 31	$ 2,538	$ 2,903	$ 3,437

Financial Instruments and Risk Management

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Financial Instruments and Risk Management

DERIVATIVE INSTRUMENTS – Murphy often uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX). The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations. Certain interest rate derivative contracts were accounted for as hedges and the gain or loss associated with recording the fair value of these contracts was deferred in AOCL and amortized to Interest expense over the life of the related liability.

Commodity Purchase Price Risks

The Company is subject to commodity price risk related to crude oil it produces and sells. During the last three years, the Company had West Texas Intermediate (WTI) crude oil price swap financial contracts to economically hedge a portion of its United States production. Under these contracts, which matured monthly, the Company paid the average monthly price in effect and received the fixed contract prices.

At December 31, 2019, the Company had 45,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2020 at an average price of $56.42. At December 31, 2018, the Company had no open WTI crude oil swap financial contracts.

At December 31, 2019 and 2018, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

December 31, 2019

December 31, 2018

(Thousands of dollars)

Asset (Liability) Derivatives

Type of Derivative Contract

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Commodity

Accounts payable

(33,364

)

Accounts receivable

3,837

For the years ended December 31, 2019, 2018, and 2017, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.



		Gain (Loss)
(Thousands of dollars)		Year Ended December 31,
Type of Derivative Contract	Statement of Operations Locations	2019			2018		2017
Commodity	Gain (loss) on crude contracts	$	(856	)	(41,975	)	9,566

Interest Rate Risks

Under hedge accounting rules, the Company deferred the net cost associated with derivative contracts purchased to manage interest rate risk associated with 10-year notes sold in May 2012 to match the payment of interest on these notes through 2022. During the year ended December 31, 2019, $6.3 million of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statements of Operations as a result of normal amortization and the early extinguishment of a portion of the deferred loss related to notes due 2022 (see Note H). During each of the years ended December 31, 2018 and 2017, $3.0 million of the deferred loss was recognized in Interest expense in the Consolidated Statements of Operations. The remaining loss (net of tax) deferred on these matured contracts at December 31, 2019 was $2.9 million, which is recorded, net of income taxes of $0.8 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheets.

Foreign Currency Exchange Risks

The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange short-term derivative instruments outstanding as of December 31, 2019 and 2018.

CREDIT RISKS – The Company’s primary credit risks are associated with trade accounts receivable, cash equivalents and derivative instruments. Trade receivables arise mainly from sales of oil and natural gas in the U.S., Canada and Malaysia, and cost sharing amounts of operating and capital costs billed to partners for oil and natural gas fields operated by Murphy. The credit history and financial condition of potential customers are reviewed before credit is extended, security is obtained when deemed appropriate based on a potential customer’s financial condition, and routine follow-up evaluations are made. The combination of these evaluations and the large number of customers tends to limit the risk of credit concentration to an acceptable level. Cash equivalents are placed with several major financial institutions, which limit the Company’s exposure to credit risk. The Company controls credit risk on derivatives through credit approvals and monitoring procedures and believes that such risks are minimal because counterparties to the majority of transactions are major financial institutions.

Employee and Retiree Benefit Plans - Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Change in plan assets
Total beginning balance	$ 547,484	$ 487,094
Total ending balance		547,484	$ 487,094
Pension Benefits
Change in benefit obligation
Obligation at January 1	777,645	881,932
Service cost	7,964	8,994	8,279
Interest cost	27,835	26,168	27,047
Participant contributions	11	0
Actuarial loss (gain)	103,374	(57,378)
Medicare Part D subsidy	0	0
Exchange rate changes	7,687	(12,742)
Benefits paid	(41,247)	(41,132)
Prior Service Cost	0	737
Other	0	(28,934)
Obligation at December 31	883,269	777,645	881,932
Change in plan assets
Total beginning balance	487,094	563,825
Actual return on plan assets	70,893	(18,951)
Employer contributions	25,915	24,357
Participant contributions	11	0
Medicare Part D subsidy	0	0
Exchange rate changes	7,328	(12,071)
Benefits paid	(41,247)	(41,132)
Other	(2,510)	(28,934)
Total ending balance	547,484	487,094	563,825
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets	5,353	11,039
Other accrued liabilities	(8,810)	(9,175)
Deferred credits and other liabilities	(332,328)	(292,415)
Funded status and net plan liability recognized at December 31	(335,785)	(290,551)
Other Postretirement Benefits
Change in benefit obligation
Obligation at January 1	94,779	106,276
Service cost	1,559	1,965	1,601
Interest cost	3,864	3,427	3,444
Participant contributions	1,930	2,104
Actuarial loss (gain)	10,503	(13,778)
Medicare Part D subsidy	234	325
Exchange rate changes	30	(67)
Benefits paid	(4,498)	(5,473)
Prior Service Cost	0	0
Other	0	0
Obligation at December 31	108,401	94,779	106,276
Change in plan assets
Total beginning balance	0	0
Actual return on plan assets	0	0
Employer contributions	2,333	3,044
Participant contributions	1,930	2,104
Medicare Part D subsidy	234	325
Exchange rate changes	0	0
Benefits paid	(4,497)	(5,473)
Other	0	0
Total ending balance	0	0	$ 0
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets	0	0
Other accrued liabilities	(5,234)	(5,101)
Deferred credits and other liabilities	(103,167)	(89,678)
Funded status and net plan liability recognized at December 31	$ (108,401)	$ (94,779)

Inventories

12 Months Ended

Dec. 31, 2019

Inventory Disclosure [Abstract]

Inventories

Inventories consisted of the following at December 31, 2019 and 2018.



	December 31,
(Thousands of dollars)	2019		2018
Unsold crude oil	$	27,634	17,318
Materials and supplies	48,489		62,706
Inventories	$	76,123	80,024

Income Taxes - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
Income Taxes - Narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2016
Income Tax Disclosure [Line Items]
Provisional tax expense		$ 274,000
2017 Tax Act measurement adjustment	$ 135,700
Income tax expense (benefit), after foreign tax aredits	26,000
Decrease in income tax expense, foreign tax credits	16,000
Transition tax on deemed repatriation	10,100
Alternative minimum tax	9,765	29,700	$ 9,765
Alternative minimum tax expected to be refunded next fiscal year			19,600
Increase (decrease) in deferred tax asset valuation allowance	63,600
Operating loss carryforwards	2,400,000
Deferred tax asset. operating loss carryforward	496,629		495,252
Earnings repatriated	1,200,000
Deferred tax expense, undistributed foreign earnings	60,000
Earnings expected to be repatriated in next fiscal year		1,300,000	100,000
Deferred tax liability, undistributed foreign earnings	5,000	65,000	5,000
Undistributed foreign earnings	1,400,000
Other recorded liabilities for interest and penalties	100	200		$ 100
Income tax expense (benefit) related to interest and penalties	$ (100)	$ (100)		$ (200)
Minimum
Income Tax Disclosure [Line Items]
Expected liability to be added for uncertain taxes during next twelve months			200
Maximum
Income Tax Disclosure [Line Items]
Expected liability to be added for uncertain taxes during next twelve months			$ 1,000

Other Financial Information - Noncash Opearting Working Capital (Increase) Decrease (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Other Financial Information [Abstract]

(Increase) decrease in accounts receivable

$ (232,037)

$ (30,212)

$ (15,462)

(Increase) decrease in inventories

10,258

16,794

15,429

(Increase) decrease in prepaid expenses

4,650

(10,011)

15,752

Increase (decrease) in accounts payable and accrued liabilities

196,773

8,784

70,376

Increase (decrease) in income taxes payable

3,469

(1,458)

(7,249)

Net (increase) decrease in noncash operating working capital

(16,887)

(16,103)

^[1]

78,846

^[1]

Cash income taxes paid, net of refunds

(6,645)

(7,603)

(5,969)

Interest paid, net of amounts capitalized of $1.8 million in 2019 and $0.2 million in 2018

179,722

158,071

144,455

Asset retirement costs capitalized

33,874

346,387

126

(Increase) decrease in capital expenditure accrual

(73,426)

9,817

$ 16,325

Interest paid, net of amounts capitalized

$ 1,800

$ 200

[1]	Reclassified to conform with current presentation (see Note E)

Supplemental Oil and Gas Information (Tables)

12 Months Ended

Dec. 31, 2019

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities



	Equivalents
(Millions of barrels of oil equivalent)	Total		United States		Canada		Malaysia and Other
Proved developed and undeveloped reserves:
December 31, 2016	684.5		287.4		241.0		156.2
Revisions of previous estimates	(5.6	)	(5.4	)	4.9		(5.2	)
Improved recovery	2.0		—		—		2.0
Extensions and discoveries	71.2		39.6		31.3		0.3
Purchases of properties	5.9		5.9		—		—
Production	(59.8	)	(22.5	)	(18.1	)	(19.2	)
December 31, 2017	698.2		304.9		259.2		134.1
Revisions of previous estimates	(21.8	)	(14.0	)	(18.1	)	10.4
Improved recovery	0.9		—		—		0.9
Extensions and discoveries	122.6		60.1		61.8		0.8
Purchases of properties	106.9		98.7		6.9		1.3
Production	(62.8	)	(24.0	)	(21.1	)	(17.7	)
December 31, 2018	844.0		425.6		288.6		129.7
Revisions of previous estimates	28.4		(17.9	)	46.1		0.3
Extensions and discoveries	73.3		62.2		11.1		—
Purchases of properties	76.2		76.2		—		—
Sales of properties	(121.5	)	(0.1	)	—		(121.4	)
Production	(75.4	)	(45.9	)	(21.7	)	(7.8	)
December 31, 2019 ¹	825.0		500.1		324.1		0.8
Proved developed reserves:
December 31, 2016	343.5		157.8		103.3		82.4
December 31, 2017	346.7		170.9		114.1		61.7
December 31, 2018	430.2		247.0		124.2		59.1
December 31, 2019 ²	472.3		273.4		198.1		0.8
Proved undeveloped reserves:
December 31, 2016	341.1		129.6		137.7		73.8
December 31, 2017	351.5		134.0		145.1		72.4
December 31, 2018	413.8		178.7		164.5		70.7
December 31, 2019 ³	352.7		226.7		126.0		—

¹ Includes proved reserves of 24.6 MMBOE, consisting of 22.1 MMBBL oil, 0.9 MMBBL NGLs, and 9.5 BCF natural gas attributable to the noncontrolling interest in MP GOM.

² Includes proved developed reserves of 19.6 MMBOE, consisting of 17.7 MMBBL oil, 0.7 MMBBL NGLs, and 7.1 BCF natural gas attributable to the noncontrolling interest in MP GOM.

³ Includes proved undeveloped reserves of 5.0 MMBOE, consisting of 4.4 MMBBL oil, 0.2 MMBBL NGLs, and 2.4 BCF natural gas attributable to the noncontrolling interest in MP GOM.



(Millions of dollars)	United States			Canada	Malaysia		Other		Total
Year ended December 31, 2019
Property acquisition costs
Unproved	$	533.8		0.2	—		13.0		547.0
Proved	733.1			—	—		—		733.1
Total acquisition costs	1,266.9			0.2	—		13.0		1,280.1
Exploration costs ¹	44.8			6.4	—		67.4		118.6
Development costs ¹	979.0			281.8	—		21.6		1,282.4
Total costs incurred	2,290.7			288.4	—		102.0		2,681.1
Charged to expense
Geophysical and other costs	21.6			0.5	—		32.2		54.3
Total charged to expense	21.6			0.5	—		32.2		54.3
Property additions	$	2,269.1		287.9	—		69.8		2,626.8
Year ended December 31, 2018
Property acquisition costs
Unproved	$	2.8		—	—		0.2		3.0
Proved	794.3			—	—		—		794.3
Total acquisition costs	797.1			—	—		0.2		797.3
Exploration costs ¹	88.1			0.6	2.2		35.1		126.0
Development costs ¹	853.7			373.8	145.9		16.6		1,390.0
Total costs incurred	1,738.9			374.4	148.1		51.9		2,313.3
Charged to expense
Dry hole expense	16.0			—	0.1		4.5		20.6
Geophysical and other costs	13.4			0.6	2.1		31.3		47.4
Total charged to expense	29.4			0.6	2.2		35.8		68.0
Property additions	$	1,709.5		373.8	145.9		16.1		2,245.3
Year ended December 31, 2017
Property acquisition costs
Unproved	$	50.4		—	—		13.0		63.4
Proved	7.7			—	—		—		7.7
Total acquisition costs	58.1			—	—		13.0		71.1
Exploration costs ¹	13.7			0.6	(8.9	)	73.8		79.2
Development costs ¹	508.4			273.8	35.7		1.1		819.0
Total costs incurred	580.2			274.4	26.8		87.9		969.3
Charged to expense
Dry hole expense	(1.9		)	—	0.7		(3.0	)	(4.2	)
Geophysical and other costs	9.7			0.5	1.7		53.3		65.2
Total charged to expense	7.8			0.5	2.4		50.3		61.0
Property additions	$	572.4		273.9	24.4		37.6		908.3

¹Includes noncash asset retirement costs as follows:



2019
Exploration costs	$	—	—	—	—	—
Development costs	75.8		3.8	—	—	79.6
	$	75.8	3.8	—	—	79.6
2018
Exploration costs	$	—	—	—	—	—
Development costs	366.0		—	7.3	0.2	373.5
	$	366.0	—	7.3	0.2	373.5
2017
Exploration costs	$	—	—	—	—	—
Development costs	37.6		6.3	8.4	—	52.3
	$	37.6	6.3	8.4	—	52.3

Results of Operations for Oil andGas Producing Activities



(Millions of dollars)	United States		Canada		Other		Total
Year ended December 31, 2019
Revenues
Crude oil and natural gas liquids sales	$	2,285.8	287.4		11.6		2,584.8
Natural gas sales	73.9		158.4		—		232.3
Total oil and natural gas revenues	2,359.7		445.8		11.6		2,817.1
Other operating revenues	7.3		1.2		—		8.5
Total revenues	2,367.0		447.0		11.6		2,825.6
Costs and expenses
Lease operating expenses	461.5		142.4		1.3		605.2
Severance and ad valorem taxes	46.6		1.4		—		48.0
Transportation, gathering and processing	140.8		35.5		—		176.3
Exploration costs charged to expense	21.4		0.6		45.3		67.3
Undeveloped lease amortization	23.1		1.3		3.6		28.0
Depreciation, depletion and amortization	878.7		243.0		3.5		1,125.2
Accretion of asset retirement obligations	34.4		6.1		—		40.5
Selling and general expenses	74.3		30.0		22.5		126.8
Other expenses (benefits)	52.2		(6.1	)	1.3		47.4
Total costs and expenses	1,733.0		454.2		77.5		2,264.7
Results of operations before taxes	634.0		(7.2	)	(65.9	)	560.9
Income tax expense (benefit)	115.6		(2.9	)	(12.4	)	100.3
Results of operations	$	518.4	(4.3	)	(53.5	)	460.6
Year ended December 31, 2018
Revenues
Crude oil and natural gas liquids sales	$	1,277.7	302.8		6.1		1,586.6
Natural gas sales	53.6		166.3		—		219.9
Total oil and natural gas revenues	1,331.3		469.1		6.1		1,806.5
Other operating revenues	1.4		1.4		16.1		18.9
Total revenues	1,332.7		470.5		22.2		1,825.4
Costs and expenses
Lease operating expenses	230.5		122.6		0.7		353.8
Severance and ad valorem taxes	50.9		1.2		—		52.1
Transportation, gathering and processing	43.1		31.9		—		75.0
Exploration costs charged to expense	29.4		0.6		31.6		61.6
Undeveloped lease amortization	36.8		0.8		2.5		40.1
Depreciation, depletion and amortization	519.5		232.4		3.5		755.4
Accretion of asset retirement obligations	19.5		7.7		—		27.2
Impairment of assets	20.0		—		—		20.0
Selling and general expenses	49.0		26.8		23.5		99.3
Other expenses	23.0		(19.1	)	2.3		6.2
Total costs and expenses	1,021.7		404.9		64.1		1,490.7
Results of operations before taxes	311.0		65.6		(41.9	)	334.7
Income tax expense (benefit)	68.1		14.5		(25.3	)	57.3
Results of operations	$	242.9	51.1		(16.6	)	277.4

¹Results exclude corporate overhead, interest and discontinued operations. 2019 and 2018 include noncontrolling interest in MP GOM.

໿



(Millions of dollars)	United States			Canada	Other		Total
Year ended December 31, 2017
Revenues
Crude oil and natural gas liquids sales	$	903.7		203.7	—		1,107.4
Natural gas sales	37.9			155.1	—		193.0
Total oil and natural gas revenues	941.6			358.8	—		1,300.4
Other operating revenues	2.7			126.7	—		129.4
Total revenues	944.3			485.5	—		1,429.8
Costs and expenses
Lease operating expenses	198.5			101.1	—		299.6
Severance and ad valorem taxes	42.2			1.5	—		43.7
Exploration costs charged to expense	7.8			0.5	50.3		58.6
Undeveloped lease amortization	60.2			1.6	—		61.8
Depreciation, depletion and amortization	546.1			185.4	3.8		735.3
Accretion of asset retirement obligations	17.4			7.9	—		25.3
Selling and general expenses	61.8			28.3	19.6		109.7
Other expenses	20.0			2.3	73.7		96.0
Total costs and expenses	954.0			328.6	73.7		1,356.3
Results of operations before taxes	(9.7		)	156.9	(73.7	)	73.5
Income tax expense (benefit)	(0.8		)	44.4	(36.2	)	7.4
Results of operations	$	(8.9	)	112.5	(37.5	)	66.1

¹Results exclude corporate overhead, interest and discontinued operations.

Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves



(Millions of dollars)	United States			Canada		Malaysia & Other		Total
December 31, 2019
Future cash inflows	$	23,565.6		4,912.1		55.7		28,533.4
Future development costs	(4,137.8		)	(723.7	)	(0.3	)	(4,861.8	)
Future production costs	(8,986.2		)	(2,549.9	)	(29.9	)	(11,566.0	)
Future income taxes	(1,709.3		)	(414.5	)	(14.1	)	(2,137.9	)
Future net cash flows	8,732.3			1,224.0		11.4		9,967.7
10% annual discount for estimated timing of cash flows	(3,633.1		)	(504.0	)	(3.0	)	(4,140.1	)
Standardized measure of discounted future net cash flows	$	5,099.2		720.0		8.4		5,827.6
December 31, 2018
Future cash inflows	$	23,473.9		5,437.5		5,511.6		34,423.0
Future development costs	(3,279.1		)	(1,362.7	)	(517.4	)	(5,159.2	)
Future production costs	(7,279.5		)	(2,693.0	)	(2,813.4	)	(12,785.9	)
Future income taxes	(2,216.5		)	(236.4	)	(472.0	)	(2,924.9	)
Future net cash flows	10,698.8			1,145.4		1,708.8		13,553.0
10% annual discount for estimated timing of cash flows	(4,295.4		)	(531.4	)	(446.3	)	(5,273.1	)
Standardized measure of discounted future net cash flows	$	6,403.4		614.0		1,262.5		8,279.9
December 31, 2017
Future cash inflows	$	12,885.8		4,714.3		4,392.0		21,992.1
Future development costs	(2,079.5		)	(1,081.7	)	(632.3	)	(3,793.5	)
Future production costs	(4,765.3		)	(2,507.4	)	(2,305.0	)	(9,577.7	)
Future income taxes	(893.7		)	(161.1	)	(232.2	)	(1,287.0	)
Future net cash flows	5,147.3			964.1		1,222.5		7,333.9
10% annual discount for estimated timing of cash flows	(2,698.2		)	(394.6	)	(318.2	)	(3,411.0	)
Standardized measure of discounted future net cash flows	$	2,449.1		569.5		904.3		3,922.9

¹ 2019 and 2018 include noncontrolling interest in MP GOM.

Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows



(Millions of dollars)	2019		2018		2017
Net changes in prices and production costs²	(2,993.9	)	2,972.6		2,428.4
Net changes in development costs	(675.7	)	(1,891.1	)	(724.4	)
Sales and transfers of oil and natural gas produced, net of production costs	(2,163.8	)	(1,978.6	)	(1,576.0	)
Net change due to extensions and discoveries	1,221.9		1,930.3		807.9
Net change due to purchases and sales of proved reserves	(628.1	)	3,152.4		85.9
Development costs incurred	1,282.4		1,017.3		802.7
Accretion of discount	1,002.0		469.5		270.9
Revisions of previous quantity estimates	(71.2	)	(347.8	)	(109.5	)
Net change in income taxes	574.1		(967.6	)	(643.0	)
Net increase (decrease)	(2,452.3	)	4,357.0		1,342.9
Standardized measure at January 1	8,279.9		3,922.9		2,580.0
Standardized measure at December 31	5,827.6		8,279.9		3,922.9

Capitalized Costs Relating to Oil and Gas Producing Activities



(Millions of dollars)	United States			Canada		Other		Total
December 31, 2019
Unproved oil and natural gas properties	$	1,116.6		243.7		210.4		1,570.7
Proved oil and natural gas properties	13,292.6			4,176.7		21.1		17,490.4
Gross capitalized costs	14,409.2			4,420.4		231.5		19,061.1
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	(136.4		)	(225.4	)	(25.9	)	(387.7	)
Proved oil and natural gas properties	(6,298.9		)	(2,438.6	)	(2.4	)	(8,739.9	)
Net capitalized costs	$	7,973.9		1,756.4		203.2		9,933.5
December 31, 2018
Unproved oil and natural gas properties	$	394.2		250.0		176.9		821.1
Proved oil and natural gas properties	11,678.3			3,693.0		—		15,371.3
Gross capitalized costs	12,072.5			3,943.0		176.9		16,192.4
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	(129.3		)	(213.5	)	(25.4	)	(368.2	)
Proved oil and natural gas properties	(5,433.7		)	(2,088.8	)	—		(7,522.5	)
Net capitalized costs	$	6,509.5		1,640.7		151.5		8,301.7

Net natural gas liquids revenue

Net crude oil and condensate revenue



(Millions of barrels)	Total		United States		Canada		Malaysia and Other
Proved developed and undeveloped NGL reserves:
December 31, 2016	42.5		36.4		5.6		0.5
Revisions of previous estimates	1.3		2.0		(0.6	)	(0.1	)
Extensions and discoveries	7.8		7.0		0.8		—
Purchase of properties	0.5		0.5		—		—
Production	(3.2	)	(2.9	)	(0.2	)	(0.1	)
December 31, 2017	48.9		43.0		5.6		0.3
Revisions of previous estimates	(6.2	)	(5.3	)	(1.6	)	0.7
Extensions and discoveries	12.0		9.7		2.3		—
Purchases of properties	3.0		3.0		—		—
Production	(3.5	)	(2.8	)	(0.4	)	(0.3	)
December 31, 2018	54.2		47.6		5.9		0.7
Revisions of previous estimates	(5.0	)	(2.5	)	(2.5	)	—
Extensions and discoveries	6.8		6.4		0.4		—
Purchases of properties	5.2		5.2		—		—
Sales of properties	(0.6	)	—		—		(0.6	)
Production	(4.5	)	(3.9	)	(0.5	)	(0.1	)
December 31, 2019 ¹	56.1		52.8		3.3		—
Proved developed NGL reserves:
December 31, 2016	22.2		20.8		0.9		0.5
December 31, 2017	24.6		23.3		1.0		0.3
December 31, 2018	27.3		24.9		1.7		0.7
December 31, 2019 ²	28.1		26.2		1.9		—
Proved undeveloped NGL reserves:
December 31, 2016	20.3		15.6		4.7		—
December 31, 2017	24.3		19.7		4.6		—
December 31, 2018	26.9		22.7		4.2		—
December 31, 2019 ³	28.0		26.6		1.4		—

¹ Includes total proved reserves of 0.9 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

² Includes proved developed reserves of 0.7 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

³ Includes proved undeveloped reserves of 0.2 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.



(Millions of barrels)	Total		United States		Canada		Malaysia and Other
Proved developed and undeveloped crude oil reserves:
December 31, 2016	329.0		214.4		48.9		65.7
Revisions of previous estimates	(6.0	)	(4.7	)	2.3		(3.6	)
Improved recovery	2.0		—		—		2.0
Extensions and discoveries	31.6		27.2		4.4		—
Purchases of properties	4.7		4.7		—		—
Production	(33.2	)	(16.9	)	(4.1	)	(12.2	)
December 31, 2017	328.1		224.7		51.5		51.9
Revisions of previous estimates	(15.3	)	(15.0	)	(8.0	)	7.7
Improved recovery	0.8		—		—		0.8
Extensions and discoveries	58.9		42.9		16.0		—
Purchases of properties	93.6		92.3		—		1.3
Production	(33.6	)	(18.4	)	(4.5	)	(10.7	)
December 31, 2018	432.5		326.5		55.0		51.0
Revisions of previous estimates	(31.0	)	(17.1	)	(14.0	)	0.1
Extensions and discoveries	58.2		49.2		9.0		—
Purchases of properties	56.3		56.3		—		—
Sales of properties	(45.8	)	(0.1	)	—		(45.7	)
Production	(46.3	)	(37.0	)	(4.7	)	(4.6	)
December 31, 2019 ¹	423.9		377.8		45.3		0.8
Proved developed crude oil reserves:
December 31, 2016	184.9		113.9		19.2		51.8
December 31, 2017	185.5		126.3		21.9		37.3
December 31, 2018	249.3		189.0		23.3		37.0
December 31, 2019 ²	230.9		205.0		25.1		0.8
Proved undeveloped crude oil reserves:
December 31, 2016	144.1		100.5		29.7		13.9
December 31, 2017	142.6		98.4		29.6		14.6
December 31, 2018	183.2		137.5		31.7		14.0
December 31, 2019 ³	193.0		172.8		20.2		—

¹ Includes total proved reserves of 22.1 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.

²Includes proved developed reserves of 17.7 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.

³Includes proved undeveloped reserves of 4.4 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.

Net natural gas revenue

Property, Plant and Equipment [Abstract]



(Billions of cubic feet)	Total		United States		Canada		Malaysia and Other
Proved developed and undeveloped natural gas reserves:
December 31, 2016	1,878.0		219.4		1,118.9		539.7
Revisions of previous estimates	(5.4	)	(16.0	)	19.4		(8.8	)
Extensions and discoveries	190.6		32.2		156.7		1.7
Purchases of properties	4.0		4.0		—		—
Production	(140.1	)	(16.3	)	(82.6	)	(41.2	)
December 31, 2017	1,927.1		223.3		1,212.4		491.4
Revisions of previous estimates	(1.8	)	37.6		(51.2	)	11.8
Improved recovery	0.6		—		—		0.6
Extensions and discoveries	310.3		44.7		261.0		4.6
Purchases of properties	61.7		20.3		41.4		—
Production	(154.3	)	(16.9	)	(97.2	)	(40.2	)
December 31, 2018	2,143.6		309.0		1,366.4		468.2
Revisions of previous estimates	386.5		10.3		375.3		0.9
Extensions and discoveries	49.8		39.5		10.3		—
Purchases of properties	88.3		88.3		—		—
Sales of properties	(450.7	)	(0.1	)	—		(450.6	)
Production	(147.8	)	(30.2	)	(99.1	)	(18.5	)
December 31, 2019 ¹	2,069.7		416.8		1,652.9		—
Proved developed natural gas reserves:
December 31, 2016	818.1		138.7		498.9		180.5
December 31, 2017	819.3		127.7		547.0		144.6
December 31, 2018	921.6		198.3		595.0		128.3
December 31, 2019 ²	1,279.8		253.1		1,026.7		—
Proved undeveloped natural gas reserves:
December 31, 2016	1,059.9		80.7		620.0		359.2
December 31, 2017	1,107.8		95.6		665.5		346.7
December 31, 2018	1,222.0		110.7		771.4		339.9
December 31, 2019 ³	789.9		163.7		626.2		—

¹ Includes total proved reserves of 9.5 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

² Includes proved developed reserves of 7.1 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

³ Includes proved undeveloped reserves of 2.4 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2019

Schedule of Property, Plant and Equipment



	December 31, 2019				December 31, 2018
(Thousands of dollars)	Cost		Net		Cost	Net
Exploration and production ¹	$	19,096,323	9,875,727	₂	16,309,149	8,329,514	₂
Corporate and other	207,066		94,016		193,471	102,619
Property, plant and equipment	$	19,303,389	9,969,743		16,502,620	8,432,133
¹ Includes unproved mineral rights as follows:	$	508,526	121,163		512,025	144,912

²Includes $24,698 in 2019 and $27,915 in 2018 related to administrative assets and support equipment.

Schedule of Recognized Impairments

The following table reflects the recognized impairments for the three years ended December 31, 2019.



	December 31,
(Thousands of dollars)	2019		2018	2017
U.S. Onshore (Midland)	$	—	20,000	—
	$	—	20,000	—

Net Changes in Capitalized Exploratory Well Costs

The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 2019.



(Thousands of dollars)	2019			2018		2017
Beginning balance at January 1	$	207,855		155,103		101,546
Additions pending the determination of proved reserves	83,712			59,487		53,557
Reclassifications to proved properties based on the determination of proved reserves	(61,096		)	(2,214	)	—
Capitalized exploration well costs charged to expense	(13,145		)	(4,521	)	—
Ending balance at December 31	$	217,326		207,855		155,103

Aging of Capitalized Exploratory Well Costs



	2019				2018				2017
(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	$	63,409	5	5	$	61,096	1	1	$	41,480	3	2
One to two years	—		—	—	40,523		3	2	5,812		1	1
Two to three years	27,396		1	—	5,208		1	1	43,200		2	2
Three years or more	126,521		5	—	101,028		4	1	64,611		6	1
	$	217,326	11	5	$	207,855	9	5	$	155,103	12	6

Employee and Retiree Benefit Plans - Effects of Fair Value Measurements Using Significant Unobservable Inputs on Changes in Level 3 Plan Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Total beginning balance	$ 547,484	$ 487,094
Total ending balance		547,484
Level 3
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Total beginning balance	111,586	35,055
Total ending balance		111,586
Defined Benefit Plan, Hedged Funds and Other Alternative Strategies \| Level 3
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Total beginning balance	35,029	37,950
Relating to assets held at the reporting date	20,811	(2,921)
Purchases, sales and settlements	55,746
Total ending balance	$ 111,586	$ 35,029

Significant Accounting Policies (Policies)	12 Months Ended
Significant Accounting Policies (Policies)	Dec. 31, 2019
Accounting Policies [Abstract]
Nature of Business	NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and natural gas company that conducts its business through various operating subsidiaries. The Company primarily produces oil and natural gas in the United States and Canada and conducts oil and natural gas exploration activities worldwide. The Company sold its Canadian heavy oil assets in early 2017 and Malaysian assets in 2019. See Notes E and G for more information regarding the sale of these assets.
Principles of Consolidation	PRINCIPLES OF CONSOLIDATION – The consolidated financial statements include the accounts of Murphy Oil Corporation and all majority-owned subsidiaries. Undivided interests in oil and natural gas joint ventures are consolidated on a proportionate basis. Investments in affiliates in which the Company owns from 20% to 50% are accounted for by the equity method. Beginning in the fourth quarter of 2018, Murphy reports 100% of the sales volume, revenues, costs, assets and liabilities including the 20% noncontrolling interest (NCI), of MP GOM in accordance with accounting for noncontrolling interest as prescribed by ASC 810-10-45 (see Note D). Other investments are generally carried at cost. All significant intercompany accounts and transactions have been eliminated.
Revenue Recognition	REVENUE RECOGNITION – Revenues from sales of crude oil, natural gas liquids and natural gas are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer; the amount of revenue recognized reflects the consideration expected in exchange for those commodities. The Company measures revenue based on consideration specified in a contract and excludes taxes and other amounts collected on behalf of third parties. Revenues from the production of oil and natural gas properties in which Murphy shares in the undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period. Natural gas imbalances occur when the Company’s actual natural gas sales volumes differ from its proportional share of production from the well. The company follows the sales method of accounting for these natural gas imbalances. The Company records a liability for natural gas imbalances when it has sold more than its working interest of natural gas production and the estimated remaining reserves make it doubtful that partners can recoup their share of production from the field. At December 31, 2019 and 2018, the liabilities for natural gas balancing were immaterial. Gains and losses on asset disposals or retirements are included in net income/(loss) as a component of revenues. See Note B for further discussion on revenue recognition.
Cash Equivalents	CASH EQUIVALENTS – Short-term investments, which include government securities and other instruments with government securities as collateral, that are highly liquid and have a maturity of three months or less from the date of purchase are classified as cash equivalents.
Marketable Securities	MARKETABLE SECURITIES – The Company classifies investments in marketable securities as available-for-sale or held-to-maturity. The Company does not have any investments classified as trading securities. Available-for-sale securities are carried at fair value with the unrealized gain or loss, net of tax, reported in other comprehensive loss. Held-to-maturity securities are recorded at amortized cost. Premiums and discounts are amortized or accreted into earnings over the life of the related available-for-sale or held-to-maturity security. Dividend and interest income is recognized when earned. Unrealized losses considered to be other than temporary are recognized in earnings. The cost of securities sold is based on the specific identification method. The fair value of investment securities is determined by available market prices.
Accounts Receivable	ACCOUNTS RECEIVABLE – At December 31, 2019 and 2018, the Company’s accounts receivable primarily consisted of amounts owed to the Company by customers for sales of crude oil and natural gas. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses on these receivables. The Company reviews this allowance for adequacy at least quarterly and bases its assessment on a combination of current information about its customers and historical write-off experience. Any trade accounts receivable balances written off are charged against the allowance for doubtful accounts. The Company has not experienced any significant credit-related losses in the past three years.
Inventories	INVENTORIES – Amounts included in the Consolidated Balance Sheets include unsold crude oil production and materials and supplies associated with oil and natural gas production operations. Unsold crude oil production is carried in inventory at the lower of cost (applied on a first-in, first-out basis and includes costs incurred to bring the inventory to its existing condition), or market. Materials and supplies inventories are valued at the lower of average cost or estimated market value and generally consist of tubulars and other drilling equipment.
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT – The Company uses the successful efforts method to account for exploration and development expenditures. Leasehold acquisition costs are capitalized. If proved reserves are found on undeveloped property, the leasehold cost is transferred to proved properties. Costs of undeveloped leases associated with unproved properties are expensed over the life of the leases. Exploratory well costs are capitalized pending determination about whether proved reserves have been found. In certain cases, a determination of whether a drilled exploratory well has found proved reserves cannot be made immediately. This is generally due to the need for major capital expenditure to produce and/or evacuate the hydrocarbon(s) found. The determination of whether to make such capital expenditure is usually dependent on whether further exploratory or appraisal wells find a sufficient quantity of additional reserves. The Company continues to capitalize exploratory well costs in Property, Plant and Equipment 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. The Company reevaluates its capitalized drilling costs at least annually to ascertain whether drilling costs continue to qualify for ongoing capitalization. Other exploratory costs, including geological and geophysical costs, are charged to expense as incurred. Development costs, including unsuccessful development wells, are capitalized. Interest is capitalized on significant development projects that are expected to take one year or more to complete. Oil and natural gas properties are evaluated by field for potential impairment. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets as applicable. An impairment is recognized when there are indications that the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to fair value. There were no impairments in 2019. As a result of management’s assessments during 2018, the Company recognized a pretax, noncash impairment charge of $20.0 million at select Midland properties. There were no impairments recorded during 2017. See also Note G for further discussion of impairment charges. The Company records a liability for asset retirement obligations (ARO) equal to the fair value of the estimated cost to retire an asset. The ARO liability is initially recorded in the period in which the obligation meets the definition of a liability, which is generally when a well is drilled or the asset is placed in service. The ARO liability is estimated by the Company’s engineers using existing regulatory requirements and anticipated future inflation rates. When the liability is initially recorded, the Company increases the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is increased over time to reflect the change in its present value, and the capitalized cost is depreciated over the useful life of the related long-lived asset. The Company reevaluates the adequacy of its recorded ARO liability at least annually. Actual costs of asset retirements such as dismantling oil and natural gas production facilities and site restoration are charged against the related liability. Any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability is recognized as a gain or loss in the Company’s earnings. Depreciation and depletion of producing oil and natural gas properties are recorded based on units of production. Unit rates are computed for unamortized development drilling and completion costs using proved developed reserves and acquisition costs are amortized over proved reserves. Proved reserves are estimated by the Company’s engineers and are subject to future revisions based on the availability of additional information.
Capitalized Interest	CAPITALIZED INTEREST– Interest associated with borrowings from third parties is capitalized on significant oil and natural gas development projects when the expected development period extends for one year or more. Interest capitalized is credited in the Consolidated Statements of Operations and is added to the cost of the underlying asset for the development project in Property, plant and equipment in the Consolidated Balance Sheets. Capitalized interest is amortized over the useful life of the asset in the same manner as other development costs.
Leases	LEASES - At inception, contracts are assessed for the presence of a lease according to criteria laid out by ASC 842. If a lease is present, further criteria is assessed to determine if the lease should be classified as an operating or finance lease. Operating leases are presented on the Consolidated Balance Sheet as Operating lease assets with the corresponding lease liabilities presented in Operating lease liabilities and Non-current operating lease liabilities. Finance lease assets are presented on the Consolidated Balance Sheet within Assets held for sale with the corresponding liabilities presented in Current maturities of long-term debt and Long-term debt. Generally, lease liabilities are recognized at commencement and based on the present value of the future minimum lease payments to be made over the lease term. Lease assets are then recognized based on the value of the lease liabilities. Where implicit lease rates are not determinable, the minimum lease payments are discounted using the Company’s collateralized incremental borrowing rates. Operating leases are expensed according to their nature and recognized in Lease operating expenses, Selling and general expenses or capitalized in the Consolidated Financial Statements. Finance leases are depreciated with the relevant expenses recognized in Depreciation, depletion, and amortization and Interest expense, net on the Consolidated Statement of Operations.
Environmental Liabilities	ENVIRONMENTAL LIABILITIES – A liability for environmental matters is established when it is probable that an environmental obligation exists and the cost can be reasonably estimated. If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used. Related expenditures are charged against the liability. Environmental remediation liabilities have not been discounted for the time value of future expected payments. Environmental expenditures that have future economic benefit are capitalized.
Income Taxes	INCOME TAXES – The Company accounts for income taxes using the asset and liability method. Under this method, income taxes are provided for amounts currently payable and for amounts deferred as tax assets and liabilities based on differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Deferred income taxes are measured using the enacted tax rates that are assumed will be in effect when the differences reverse. The Company routinely assesses the realizability of deferred tax assets based on available evidence including assumptions of future taxable income, tax planning strategies and other pertinent factors. A deferred tax asset valuation allowance is recorded when evidence indicates that it is more likely than not that all or a portion of these deferred tax assets will not be realized in a future period. On December 22, 2017 the Tax Cuts and Jobs Act (2017 Tax Act) was enacted which triggered the transitional tax on a deemed repatriation of all past foreign earnings (see Note J) and a provision for this impact has been recorded. Deferred tax liabilities are recorded for relevant withholding taxes when undistributed earnings of foreign subsidiaries are not considered indefinitely invested. Under present law, the Company would incur a 5% withholding tax on any earnings repatriated from Canada to the U.S. The accounting rules for income tax uncertainties permit recognition of income tax benefits only when they are more likely than not to be realized, and then only for the largest amount that is greater than 50% likely of being realized. The Company includes potential penalties and interest for uncertain income tax positions in income tax expense.
Foreign Currency	FOREIGN CURRENCY – Local currency is the functional currency used for recording operations in Canada and former refining and marketing activities in the United Kingdom. The U.S. dollar is the functional currency used to record all other operations. Exchange gains or losses from transactions in a currency other than the functional currency are included in earnings as part of Interest and other income (loss). Gains or losses from translating foreign functional currencies into U.S. dollars are included in Accumulated Other Comprehensive Loss in Consolidated Statements of Stockholders’ Equity.
Derivative Instruments and Hedging Activities	DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES – The fair value of a derivative instrument is recognized as an asset or liability in the Company’s Consolidated Balance Sheets. Upon entering into a derivative contract, the Company may designate the derivative as either a fair value hedge or a cash flow hedge or decide that the contract is not a hedge for accounting purposes, and thenceforth, recognize changes in the fair value of the contract in earnings. The Company documents the relationship between the derivative instrument designated as a hedge and the hedged items as well as its objective for risk management and strategy for the use of the hedging instrument to manage the risk. Derivative instruments designated as fair value or cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions. The Company assesses at inception and on an ongoing basis whether a derivative instrument accounted for as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting. The change in the fair value of a qualifying fair value hedge is recorded in earnings along with the gain or loss on the hedged item. The effective portion of the change in the fair value of a qualifying cash flow hedge is recorded in Accumulated other comprehensive loss in the Consolidated Balance Sheets until the hedged item is recognized currently in earnings. If a derivative instrument no longer qualifies as a cash flow hedge and the underlying forecasted transaction is no longer probable of occurring, hedge accounting is discontinued, and the gain or loss recorded in Accumulated other comprehensive loss is recognized immediately in earnings.
Fair Value Measurements	FAIR VALUE MEASUREMENTS– The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. Fair value is determined using various techniques depending on the availability of observable inputs. Level 1 inputs include quoted prices in active markets for identical assets or liabilities. Level 2 inputs include observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants. See Note Q.
Stock-based Compensation	STOCK-BASED COMPENSATION Equity-Settled Awards – The fair value of awarded stock options, restricted stock units and other stock-based compensation that are settled with Company shares is determined based on a combination of management assumptions and the market value of the Company’s common stock. The Company uses the Black-Scholes option pricing model for computing the fair value of equity-settled stock options. The primary assumptions made by management include the expected life of the stock option award and the expected volatility of Murphy’s common stock price. The Company uses both historical data and current information to support its assumptions. Stock option expense is recognized on a straight-line basis over the respective vesting period of two or three years. The Company uses a Monte Carlo valuation model to determine the fair value of performance-based restricted stock units that are equity settled and expense is recognized over the three-year vesting period. The fair value of time-lapse restricted stock units is determined based on the price of Company stock on the date of grant and expense is recognized over the vesting period. The Company estimates the number of stock options and performance-based restricted stock units that will not vest and adjusts its compensation expense accordingly. Differences between estimated and actual vested amounts are accounted for as an adjustment to expense when known. Cash-Settled Awards – The Company accounts for stock appreciation rights (SAR), cash-settled restricted stock units (CRSU) and phantom stock units as liability awards. Expense associated with these awards are recognized over the vesting period based on the latest available estimate of the fair value of the awards, which is generally determined using a Black-Scholes method for SAR, a Monte Carlo method for performance-based CRSU, and the period-end price of the Company’s common stock for time-based CRSU and phantom units. When SAR are exercised and when CRSU and phantom units settle, the Company adjusts previously recorded expense to the final amounts paid out in cash for these awards. See Note K.
Pension and Other Postretirement Benefit Plans	PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS – The Company recognizes the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of its defined benefit and other postretirement benefit plans in the Consolidated Balance Sheets. Changes in the funded status which have not yet been recognized in the Consolidated Statement of Operations are recorded net of tax in Accumulated other comprehensive loss. The remaining amounts in Accumulated other comprehensive loss include net actuarial losses and prior service (cost) credit. See Note L.
Net Income (Loss) Per Common Share	NET INCOME (LOSS) PER COMMON SHARE – Basic income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period. Diluted income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period plus the effects of all potentially dilutive common shares. Dilutive securities are not included in the computation of diluted income (loss) per share when a net loss occurs as the inclusion would have the effect of reducing the diluted loss per share.
Use of Estimates	USE OF ESTIMATES – In preparing the financial statements of the Company in conformity with U.S. generally accepted accounting principles (GAAP), management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.
New accounting pronouncements	Recent Accounting Pronouncements Financial Instruments – Credit Losses. In June 2016, the FASB issued ASU 2016-13 which replaces the impairment model for most financial assets, including trade receivables, from the incurred loss methodology to a forward-looking expected loss model that will result in earlier recognition of credit losses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. The Company adopted this accounting standard in the first quarter of 2020 and it did not have a material impact on its consolidated financial statements. Fair Value Measurement. In August 2018, the FASB issued ASU 2018-13 which modifies disclosure requirements related to fair value measurement. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Implementation on a prospective or retrospective basis varies by specific disclosure requirement. Early adoption is permitted. The standard also allows for early adoption of any removed or modified disclosures upon issuance of this ASU while delaying adoption of the additional disclosures until their effective date. The Company adopted this accounting standard in the first quarter of 2020 and it did not have a material impact on its consolidated financial statements. Income Taxes. In December 2019, the FASB issued ASU 2019-12, which removes certain exceptions for investments, intraperiod allocations and interim calculations, and adds guidance to reduce complexity in accounting for income taxes. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. Implementation on a prospective or retrospective basis varies by specific topics within the ASU. Early adoption is permitted. The Company is currently assessing the potential impact of this ASU to its consolidated financial statements. Compensation-Retirement Benefits-Defined Benefit Plans-General. In August 2018, the FASB issued ASU 2018-14 which modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. For public companies, the amendments in this ASU are effective for fiscal years beginning after December 15, 2020, with early adoption permitted, and is to be applied on a retrospective basis to all periods presented. The Company is currently assessing the potential impact of this ASU to its consolidated financial statements.

Financial Instruments and Risk Management - Fair Value of Derivative Instruments Not Designated as Hedging Instruments (Details) - Not Designated as Hedging Instrument - Commodity derivative contracts - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accounts payable
Derivatives, Fair Value [Line Items]
Liabilities	$ (33,364)
Accounts receivable
Derivatives, Fair Value [Line Items]
Asset		$ 3,837

Incentive Plans - Fair Value of Option Award Estimated on Date of Grant using Black-Scholes Pricing Model (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Assumptions
Expected life	3 years
Performance Based Restricted Stock
Assumptions
Expected volatility	46.00%	48.00%	47.00%
Risk-free interest rate	2.50%	2.30%	1.46%
Expected life	3 years	3 years	3 years
Stock Options
Assumptions
Expected life			5 years 3 months 18 days
Minimum \| Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value per option grant			$ 7.96
Assumptions
Dividend yield			3.60%
Expected volatility			41.00%
Risk-free interest rate			1.97%

Employee and Retiree Benefit Plans - One Percent Change in Assumed Health Care Cost Trend Rates (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($)
Retirement Benefits [Abstract]
1% Increase, Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 2018	$ 930
1% Increase, Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2018	15,257
1% Decrease, Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 2018	(737)
1% Decrease, Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2018	$ (12,291)

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2019

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Reconciliation of Beginning and Ending Aggregate Carrying Amount of Asset Retirement Obligations

A reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligation for 2019 and 2018 is shown in the following table.



(Thousands of dollars)	2019			2018
Balance at beginning of year	$	800,117		447,270
Accretion expense	40,506			27,119
Liabilities incurred	14,759			6,572
Liabilities assumed from acquisitions	64,810			359,643
Revisions of previous estimates	(34,371		)	(20,012	)
Liabilities settled	(25,544		)	(11,510	)
Liabilities associated with assets held for sale	(240		)	—
Changes due to translation of foreign currencies	5,072			(8,965	)
Balance at end of year	865,109			800,117
Current portion of liability at end of year ¹	(39,315		)	(47,598	)
Noncurrent portion of liability at end of year	$	825,794		752,519

¹Included in Other accrued liabilities on the Consolidated Balance Sheet.

Cover Page - USD ($)	12 Months Ended
Cover Page - USD ($)	Dec. 31, 2019	Jan. 31, 2020	Jun. 30, 2019
Cover Page [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	1-8590
Entity Registrant Name	MURPHY OIL CORP
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	71-0361522
Entity Address, Address Line One	300 Peach Street, P.O. Box 7000,
Entity Address, Postal Zip Code	71731-7000
Entity Address, City or Town	El Dorado,
Entity Address, State or Province	AR
City Area Code	(870)
Local Phone Number	862-6411
Title of 12(b) Security	Common Stock, $1.00 Par Value
Trading Symbol	MUR
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 2,748,431,387
Entity Common Stock, Shares Outstanding		153,169,317
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Central Index Key	0000717423
Current Fiscal Year End Date	--12-31
Amendment Flag	false

Supplemental Oil and Gas Information

12 Months Ended

Dec. 31, 2019

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental Oil and Gas Information

The following unaudited schedules are presented in accordance with required disclosures about Oil and Natural gas Producing Activities to provide users with a common base for preparing estimates of future cash flows and comparing reserves among companies. Additional background information concerning some of the schedules follows:

SCHEDULE 1 – SUMMARY OF TOTAL PROVED EQUIVALENT RESERVES

SCHEDULE 2 – SUMMARY OF PROVED CRUDE OIL RESERVES

SCHEDULE 3 – SUMMARY OF PROVED NATURAL GAS LIQUIDS RESERVES

SCHEDULE 4 – SUMMARY OF PROVED NATURAL GAS RESERVES

Reserves of crude oil, condensate, natural gas liquids and natural gas are estimated by the Company’s or independent engineers and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and judgmental decisions are required to estimate reserves. Reserve estimates and future cash flows are based on the average market prices for sales of oil and natural gas on the first calendar day of each month during the year. The average prices used for 2019 were $55.69 per barrel for NYMEX crude oil (WTI), and $2.57 per Mcf for natural gas (Henry Hub). The average prices used for 2018 were $65.56 per barrel for NYMEX crude oil (WTI), and $3.10 per Mcf for natural gas (Henry Hub). Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors.

Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data and commercially available technologies to establish “reasonable certainty” of economic producibility. As defined by the SEC, reasonable certainty of proved reserves describes a high degree of confidence that the quantities will be recovered. In estimating proved reserves, Murphy uses common industry-accepted methods for subsurface evaluations, including performance, volumetric and analog-based studies. Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves. Reliable geologic and engineering technology is a method or combination of methods that are field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. This integrated approach increases the quality of and confidence in Murphy’s proved reserves estimates. The approach was utilized in certain undrilled acreage at distances greater than the directly offsetting development spacing areas and in certain reservoirs developed with the application of improved recovery techniques. Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, historic production and pressure data and commercially available seismic processing and numerical reservoir simulation programs. Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available.

Production quantities shown are net volumes withdrawn from reservoirs. These may differ from sales quantities due to inventory changes, volumes consumed for fuel and/or shrinkage from the extraction of natural gas liquids.

All crude oil, natural gas liquid reserves and natural gas reserves are from consolidated subsidiaries (including noncontrolling interest) and proportionately consolidated joint ventures. The Company has no proved reserves attributable to investees accounted for by the equity method.

SCHEDULE 7 – STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND NATURAL GAS RESERVES

GAAP requires calculation of future net cash flows using a 10% annual discount factor, an unweighted average of oil and natural gas prices in effect at the beginning of each month of the year, and year-end costs and statutory tax rates, except for known future changes such as contracted prices and legislated tax rates. On December 22, 2017, the U.S. enacted into legislation the Tax Cuts and Jobs Act (2017 Tax Act); as a result, the company’s statutory U.S. tax rate was 21% in 2018 and a decrease from the previous rate of 35% in 2017 and 2016.

The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future cash flows because prices, costs and governmental policies do not remain static; appropriate discount rates may vary; and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts.

Schedule 7 also presents the principal reasons for change in the standardized measure of discounted future net cash flows for each of the three years ended December 31, 2019.

s proved reserves of 24.6 MMBOE, consisting of 22.1 MMBBL oil, 0.9 MMBBL NGLs, and 9.5 BCF natural gas attributable to the noncontrolling interest in MP GOM.

² Includes proved developed reserves of 19.6 MMBOE, consisting of 17.7 MMBBL oil, 0.7 MMBBL NGLs, and 7.1 BCF natural gas attributable to the noncontrolling interest in MP GOM.

³ Includes proved undeveloped reserves of 5.0 MMBOE, consisting of 4.4 MMBBL oil, 0.2 MMBBL NGLs, and 2.4 BCF natural gas attributable to the noncontrolling interest in MP GOM.

2019 Comments for Proved Equivalent Reserves Changes

Revisions of previous estimates - The positive Canadian equivalents reserves revisions in 2019 resulted from improved performance in the Tupper Montney asset which offset reserves reductions from deferrals of capital expenditures at Kaybob Duvernay. The 2019 negative equivalents revision in the U.S. was primarily attributable to changes in well performance in the Eagle Ford Shale, primarily the Tilden area.

Extensions and discoveries - In 2019, proved equivalent reserves were added in the U.S. for drilling activities in both the Eagle Ford Shale and in Canada at Kaybob Duvernay. Proved equivalent reserves were also added for drilling activities in both the U.S. offshore and Canada offshore.

Purchases and sales of properties - In 2019, the Company acquired deepwater Gulf of Mexico producing assets from LLOG. In addition, the Company acquired incremental ownership in the Chinook field in the Gulf of Mexico and partial ownership in the Jagus East field in Brunei (which is now held for sale). The Company’s Malaysia assets were divested in 2019.

2018 Comments for Proved Equivalent Reserves Changes

Revisions of previous estimates - The 2018 negative proved equivalents revision in the U.S. was primarily attributable to revised type curves and the removal of proved undeveloped locations outside the 5-year development window. The negative Canadian equivalent reserves revisions in 2018 resulted from deferrals of capital expenditures of the Kaybob Duvernay as well as locations removed in Hibernia Offshore Canada due to updated operator development plans. The positive revisions for proved equivalent reserves in Malaysia were principally attributable to continued development in Kakap field and improved performance in South Acis field.

Improved recovery - The 2018 Malaysia proved equivalent reserve addition was due to favorable impacts from gas lift activity at the Kikeh field.

Extensions and discoveries - In 2018, proved equivalent reserves were added in the U.S. for drilling activities in the Eagle Ford Shale, and in Canada for drilling activities in the Kaybob Duvernay. Proved equivalent reserves were also added for drilling activities in the U.S. offshore.

Purchases of properties - In 2018, the Company acquired producing assets from PAI, which were contributed to MP GOM, for which Murphy owns 80% of the associated assets and oversees operations. In addition, the Company acquired partial ownership in the Jagus East field in Brunei.

2017 Comments for Proved Equivalent Reserves Changes

Revisions of previous estimates - The 2017 negative proved equivalent reserves revision in the U.S. was primarily attributable to the removal of proved undeveloped locations within the 5-year development window as capital was reallocated to higher performing drilling locations within the Company’s Eagle Ford Shale fields, partially offset by improved Eagle Ford Shale costs and performance results in the Gulf of Mexico. The positive Canadian proved equivalent reserves revisions in 2017 resulted from improved performance at Tupper Montney assets in onshore Canada, and offshore Canada fields, Hibernia and Terra Nova. The negative revisions for proved equivalent reserves in Malaysia were principally attributable to the redetermination of Kakap participation that lowered the Company’s entitlement, and higher government entitlement under the terms of the respective production sharing contracts due to higher oil prices, offsetting positive performance revisions at the Company’s Sarawak projects.

Improved recovery - The 2017 Malaysia proved equivalent reserve addition was primarily due to favorable impacts for waterflood activity at certain Sarawak oil fields.

Extensions and discoveries - In 2017, proved equivalent reserves were added in the U.S. for drilling activities in the Eagle Ford Shale concurrent with the reallocation of capital to higher performing drilling areas moving well locations within the 5-year development window for proved undeveloped reserves, and in Canada for drilling activities in the Montney and Duvernay. Proved equivalent reserves were also added for drilling activities in the U.S. offshore. In Malaysia, proved equivalent reserves were added in Sarawak from field development activities.

total proved reserves of 22.1 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.

²Includes proved developed reserves of 17.7 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.

³Includes proved undeveloped reserves of 4.4 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.

2019 Comments for Proved Crude Oil Reserves Changes

Revisions of previous estimates – The 2019 negative crude oil revision in the U.S. was primarily attributable to changes in well performance in the Eagle Ford Shale, primarily in the Tilden area. The negative Canadian oil reserves revisions in 2019 resulted from deferrals of capital expenditures at Kaybob Duvernay.

Extensions and discoveries – In 2019, proved oil reserves were added in the U.S. for drilling activities both in the Eagle Ford Shale and in Canada at Kaybob Duvernay. Proved oil reserves were also added for drilling activities in both the U.S. offshore and Canada offshore.

Purchases and sales of properties – In 2019, the Company acquired deepwater Gulf of Mexico producing assets from LLOG. In addition, the Company acquired incremental ownership in the Chinook field in the Gulf of Mexico. The Company’s Malaysia assets were divested in 2019.

2018 Comments for Proved Crude Oil Reserves Changes

Revisions of previous estimates – The 2018 negative crude oil revision in the U.S. was primarily attributable to revised type curves and the removal of proved undeveloped locations outside the 5-year development window. The negative Canadian oil reserves revisions in 2018 resulted from deferrals of capital expenditures at Kaybob Duvernay as well as locations removed in Hibernia Offshore Canada due to updated operator development plans. The positive revisions for crude oil reserves in Malaysia were principally attributable to continued development in Kakap field and improved performance in South Acis field.

Improved recovery – The 2018 Malaysia crude oil proved reserve addition was due to favorable impacts from natural gas lift activity at the Kikeh field.

Extensions and discoveries – In 2018, proved oil reserves were added in the U.S. for drilling activities in the Eagle Ford Shale, and in Canada for drilling activities in the Kaybob Duvernay. Proved oil reserves were also added for drilling activities in the U.S. offshore.

Purchases of properties – In 2018, the Company acquired producing assets from PAI, which were contributed to MP GOM, for which Murphy owns 80% of the associated assets and oversees operations. In addition, the Company acquired partial ownership in the Jagus East field in Brunei.

2017 Comments for Proved Crude Oil Reserves Changes

Revisions of previous estimates – The 2017 negative crude oil revision in the U.S. was primarily attributable to the removal of proved undeveloped locations within the 5-year development window as capital was reallocated to higher performing drilling locations within the Company’s Eagle Ford Shale fields, partially offset by improved Eagle Ford Shale costs and performance results in the Gulf of Mexico. The positive Canadian oil reserves revisions in 2017 resulted from improved performance at Tupper Montney assets in onshore Canada, and offshore Canada fields, Hibernia and Terra Nova. The negative revisions for crude oil reserves in Malaysia were principally attributable to the redetermination of Kakap participation that lowered the Company’s entitlement, and higher government entitlement under the terms of the respective production sharing contracts due to higher oil prices, offsetting positive performance revisions at the Company’s Sarawak projects.

Improved recovery – The 2017 Malaysia crude oil proved reserve addition was primarily due to favorable impacts for waterflood activity at certain Sarawak oil fields.

Extensions and discoveries – In 2017, proved oil reserves were added in the U.S. for drilling activities in the Eagle Ford Shale concurrent with the reallocation of capital to higher performing drilling areas moving well locations within the 5-year development window for proved undeveloped reserves, and in Canada for drilling activities in the Montney and Duvernay. Proved oil reserves were also added for drilling activities in the U.S. offshore.

Purchases of properties – In 2017, the Company acquired greater working interests in two of its operated Gulf of Mexico fields. In U.S. onshore, the Company acquired acreage in the Permian area of west Texas. Additional Eagle Ford Shale acreage was acquired through joint venture agreements with other operators within its core acreage position.

ludes total proved reserves of 0.9 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

² Includes proved developed reserves of 0.7 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

³ Includes proved undeveloped reserves of 0.2 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

2019 Comments for Proved Natural Gas Liquids Reserves Changes

Revisions of previous estimates – The negative 2019 NGL proved reserves revision in the U.S. was primarily due to midstream elections in the Eagle Ford Shale resulting in lower NGL yields. The negative Canadian NGL reserves revisions in 2019 resulted from deferrals of capital expenditures at Kaybob Duvernay.

Extensions and discoveries – In 2019, proved NGL reserves were added in the U.S. for drilling activities in both the Eagle Ford Shale and in Canada at Kaybob Duvernay area in onshore Canada. Proved NGL reserves were also added for drilling activities in the U.S. offshore.

2018 Comments for Proved Natural Gas Liquids Reserves Changes

Revisions of previous estimates – The negative 2018 NGL proved reserves revision in the U.S. was primarily in the Company’s Eagle Ford Shale fields based on removal of proved undeveloped locations outside the 5-year development window. The negative Canadian NGL reserves revisions in 2018 resulted from deferrals of capital expenditures at Kaybob Duvernay. The positive revisions for NGL reserves in Malaysia were principally attributable to improved performance for natural gas fields offshore Sarawak.

Extensions and discoveries – In 2018, proved NGL reserves were added in the U.S. for drilling activities in the Eagle Ford Shale, and in Canada for drilling activities in the Kaybob Duvernay.

Purchases of properties – In 2018, the Company acquired producing assets from PAI, which were contributed to MP GOM, for which Murphy owns 80% of the associated assets and oversees operations.

2017 Comments for Proved Natural Gas Liquids Reserves Changes

Revisions of previous estimates – The positive 2017 NGL proved reserves revision in the U.S. was primarily in the Company’s Eagle Ford Shale fields based on an updated shrinkage ratio of liquids rich natural gas production combined with improved costs, offsetting removal of proved undeveloped locations from within the 5-year development window as capital was reallocated to higher performing drilling locations within the Eagle Ford Shale.

Extensions and discoveries – Proved NGL reserves were added primarily from drilling activities in the Eagle Ford Shale area concurrent with the reallocation of capital to higher performing drilling areas moving well locations within the 5-year development window for proved undeveloped reserves.

Purchase of properties – In U.S., proved NGL reserves were added following the acquisition of acreage in both the Eagle Ford Shale and Permian areas, and increased working interest in two Gulf of Mexico fields.

total proved reserves of 9.5 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

² Includes proved developed reserves of 7.1 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

³ Includes proved undeveloped reserves of 2.4 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

2019 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates – In 2019, the positive natural gas revisions in Canada resulted from improved performance in the Tupper Montney asset and adjustments relating to royalties. The positive revision for natural gas reserves in the Eagle Ford Shale was primarily attributable to producing well performance.

Extensions and discoveries – In 2019, proved natural gas reserves were added in the U.S. for development drilling activities in both the Eagle Ford Shale and in Canada at Tupper Montney and Kaybob Duvernay. Proved natural gas reserves were also added for drilling activities in both the U.S. offshore and Canada offshore.

2018 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates – In 2018, the U.S. positive natural gas revision was primarily due to drilling within the Eagle Ford Shale. The 2018 negative natural gas revisions in Canada resulted from deferrals of capital expenditures at Kaybob Duvernay partially offset by positive performance revisions in the Tupper Montney asset. The positive revision for natural gas reserves in Malaysia was primarily attributable to positive performance revisions at the Company’s Sarawak projects offset somewhat by negative Block H revisions attributable to higher government entitlement under the terms of the respective production sharing contracts due to higher natural gas prices.

Improved recovery – The 2018 Malaysia natural gas proved reserve addition was due to favorable impacts from natural gas lift activity at the Kikeh field.

Extensions and discoveries – In 2018, the U.S. added natural gas reserves primarily for developmental drilling activities in the Eagle Ford Shale. Natural gas reserve additions in Canada were attributable to developmental drilling activities in the Tupper Montney and Kaybob Duvernay areas in onshore Canada. In Malaysia, proved natural gas reserves were added in the Merapuh field in Sarawak from field development activities.

Purchases of properties – In 2018, the Company acquired producing assets from PAI, which were contributed to MP GOM, for which Murphy owns 80% of the associated assets and overseas operations. In addition, the Company acquired acreage in Tupper Montney in onshore Canada.

2017 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates – In the U.S., the negative natural gas revision was primarily due to shutting in a natural gas well located in the Gulf of Mexico due to early water break through, and in the Company’s Eagle Ford Shale fields proved undeveloped locations were removed from within the 5-year development window as capital was reallocated to higher performing drilling locations within the Eagle Ford Shale. The negative revision for natural gas reserves in Malaysia was primarily attributable to higher government entitlement under the terms of the respective production sharing contracts due to higher natural gas prices, offsetting positive performance revisions at the Company’s Sarawak projects. The 2017 positive natural gas revisions in Canada were attributable to updated well type curves and field performance at the Tupper Montney assets in onshore Canada.

Extensions and discoveries – In 2017, the U.S. added natural gas reserves primarily for developmental drilling activities in the Eagle Ford Shale concurrent with the reallocation of capital to higher performing drilling areas moving well locations within the 5-year development window for proved undeveloped reserves, and field development drilling in the Gulf of Mexico. Natural gas reserve additions in Canada were attributable to developmental drilling activities in the Montney and Kaybob Duvernay areas in onshore Canada. In Malaysia, proved natural gas reserves were added in Sarawak from field development activities.

Purchase of properties – In the U.S., proved natural gas reserves were added following the acquisition of acreage in both the Eagle Ford Shale and Permian areas, and increased working interest in two Gulf of Mexico fields.

ludes noncash asset retirement costs as follows:



2019
Exploration costs	$	—	—	—	—	—
Development costs	75.8		3.8	—	—	79.6
	$	75.8	3.8	—	—	79.6
2018
Exploration costs	$	—	—	—	—	—
Development costs	366.0		—	7.3	0.2	373.5
	$	366.0	—	7.3	0.2	373.5
2017
Exploration costs	$	—	—	—	—	—
Development costs	37.6		6.3	8.4	—	52.3
	$	37.6	6.3	8.4	—	52.3

Results of Operations for Oil and Natural Gas Producing Activities ¹



(Millions of dollars)	United States		Canada		Other		Total
Year ended December 31, 2019
Revenues
Crude oil and natural gas liquids sales	$	2,285.8	287.4		11.6		2,584.8
Natural gas sales	73.9		158.4		—		232.3
Total oil and natural gas revenues	2,359.7		445.8		11.6		2,817.1
Other operating revenues	7.3		1.2		—		8.5
Total revenues	2,367.0		447.0		11.6		2,825.6
Costs and expenses
Lease operating expenses	461.5		142.4		1.3		605.2
Severance and ad valorem taxes	46.6		1.4		—		48.0
Transportation, gathering and processing	140.8		35.5		—		176.3
Exploration costs charged to expense	21.4		0.6		45.3		67.3
Undeveloped lease amortization	23.1		1.3		3.6		28.0
Depreciation, depletion and amortization	878.7		243.0		3.5		1,125.2
Accretion of asset retirement obligations	34.4		6.1		—		40.5
Selling and general expenses	74.3		30.0		22.5		126.8
Other expenses (benefits)	52.2		(6.1	)	1.3		47.4
Total costs and expenses	1,733.0		454.2		77.5		2,264.7
Results of operations before taxes	634.0		(7.2	)	(65.9	)	560.9
Income tax expense (benefit)	115.6		(2.9	)	(12.4	)	100.3
Results of operations	$	518.4	(4.3	)	(53.5	)	460.6
Year ended December 31, 2018
Revenues
Crude oil and natural gas liquids sales	$	1,277.7	302.8		6.1		1,586.6
Natural gas sales	53.6		166.3		—		219.9
Total oil and natural gas revenues	1,331.3		469.1		6.1		1,806.5
Other operating revenues	1.4		1.4		16.1		18.9
Total revenues	1,332.7		470.5		22.2		1,825.4
Costs and expenses
Lease operating expenses	230.5		122.6		0.7		353.8
Severance and ad valorem taxes	50.9		1.2		—		52.1
Transportation, gathering and processing	43.1		31.9		—		75.0
Exploration costs charged to expense	29.4		0.6		31.6		61.6
Undeveloped lease amortization	36.8		0.8		2.5		40.1
Depreciation, depletion and amortization	519.5		232.4		3.5		755.4
Accretion of asset retirement obligations	19.5		7.7		—		27.2
Impairment of assets	20.0		—		—		20.0
Selling and general expenses	49.0		26.8		23.5		99.3
Other expenses	23.0		(19.1	)	2.3		6.2
Total costs and expenses	1,021.7		404.9		64.1		1,490.7
Results of operations before taxes	311.0		65.6		(41.9	)	334.7
Income tax expense (benefit)	68.1		14.5		(25.3	)	57.3
Results of operations	$	242.9	51.1		(16.6	)	277.4

¹Results exclude corporate overhead, interest and discontinued operations. 2019 and 2018 include noncontrolling interest in MP GOM.

໿



(Millions of dollars)	United States			Canada	Other		Total
Year ended December 31, 2017
Revenues
Crude oil and natural gas liquids sales	$	903.7		203.7	—		1,107.4
Natural gas sales	37.9			155.1	—		193.0
Total oil and natural gas revenues	941.6			358.8	—		1,300.4
Other operating revenues	2.7			126.7	—		129.4
Total revenues	944.3			485.5	—		1,429.8
Costs and expenses
Lease operating expenses	198.5			101.1	—		299.6
Severance and ad valorem taxes	42.2			1.5	—		43.7
Exploration costs charged to expense	7.8			0.5	50.3		58.6
Undeveloped lease amortization	60.2			1.6	—		61.8
Depreciation, depletion and amortization	546.1			185.4	3.8		735.3
Accretion of asset retirement obligations	17.4			7.9	—		25.3
Selling and general expenses	61.8			28.3	19.6		109.7
Other expenses	20.0			2.3	73.7		96.0
Total costs and expenses	954.0			328.6	73.7		1,356.3
Results of operations before taxes	(9.7		)	156.9	(73.7	)	73.5
Income tax expense (benefit)	(0.8		)	44.4	(36.2	)	7.4
Results of operations	$	(8.9	)	112.5	(37.5	)	66.1

¹Results exclude corporate overhead, interest and discontinued operations.

Schedule 7 – Standardized Measure of Discounted Future Net Cash Flows Relating to

Proved Oil and Natural Gas Reserves¹



(Millions of dollars)	United States			Canada		Malaysia & Other		Total
December 31, 2019
Future cash inflows	$	23,565.6		4,912.1		55.7		28,533.4
Future development costs	(4,137.8		)	(723.7	)	(0.3	)	(4,861.8	)
Future production costs	(8,986.2		)	(2,549.9	)	(29.9	)	(11,566.0	)
Future income taxes	(1,709.3		)	(414.5	)	(14.1	)	(2,137.9	)
Future net cash flows	8,732.3			1,224.0		11.4		9,967.7
10% annual discount for estimated timing of cash flows	(3,633.1		)	(504.0	)	(3.0	)	(4,140.1	)
Standardized measure of discounted future net cash flows	$	5,099.2		720.0		8.4		5,827.6
December 31, 2018
Future cash inflows	$	23,473.9		5,437.5		5,511.6		34,423.0
Future development costs	(3,279.1		)	(1,362.7	)	(517.4	)	(5,159.2	)
Future production costs	(7,279.5		)	(2,693.0	)	(2,813.4	)	(12,785.9	)
Future income taxes	(2,216.5		)	(236.4	)	(472.0	)	(2,924.9	)
Future net cash flows	10,698.8			1,145.4		1,708.8		13,553.0
10% annual discount for estimated timing of cash flows	(4,295.4		)	(531.4	)	(446.3	)	(5,273.1	)
Standardized measure of discounted future net cash flows	$	6,403.4		614.0		1,262.5		8,279.9
December 31, 2017
Future cash inflows	$	12,885.8		4,714.3		4,392.0		21,992.1
Future development costs	(2,079.5		)	(1,081.7	)	(632.3	)	(3,793.5	)
Future production costs	(4,765.3		)	(2,507.4	)	(2,305.0	)	(9,577.7	)
Future income taxes	(893.7		)	(161.1	)	(232.2	)	(1,287.0	)
Future net cash flows	5,147.3			964.1		1,222.5		7,333.9
10% annual discount for estimated timing of cash flows	(2,698.2		)	(394.6	)	(318.2	)	(3,411.0	)
Standardized measure of discounted future net cash flows	$	2,449.1		569.5		904.3		3,922.9

¹ 2019 and 2018 include noncontrolling interest in MP GOM.

Following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown.



(Millions of dollars)	2019		2018		2017
Net changes in prices and production costs²	(2,993.9	)	2,972.6		2,428.4
Net changes in development costs	(675.7	)	(1,891.1	)	(724.4	)
Sales and transfers of oil and natural gas produced, net of production costs	(2,163.8	)	(1,978.6	)	(1,576.0	)
Net change due to extensions and discoveries	1,221.9		1,930.3		807.9
Net change due to purchases and sales of proved reserves	(628.1	)	3,152.4		85.9
Development costs incurred	1,282.4		1,017.3		802.7
Accretion of discount	1,002.0		469.5		270.9
Revisions of previous quantity estimates	(71.2	)	(347.8	)	(109.5	)
Net change in income taxes	574.1		(967.6	)	(643.0	)
Net increase (decrease)	(2,452.3	)	4,357.0		1,342.9
Standardized measure at January 1	8,279.9		3,922.9		2,580.0
Standardized measure at December 31	5,827.6		8,279.9		3,922.9

¹2019 and 2018 include noncontrolling interest in MP GOM.

² The average prices used for 2019 were $55.69 per barrel for NYMEX crude oil (WTI), and $2.57 per Mcf for natural gas (Henry Hub). The average prices used for 2018 were $65.56 per barrel for NYMEX crude oil (WTI), and $3.10 per Mcf for natural gas (Henry Hub).

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

໿



(Millions of dollars)	United States			Canada		Other		Total
December 31, 2019
Unproved oil and natural gas properties	$	1,116.6		243.7		210.4		1,570.7
Proved oil and natural gas properties	13,292.6			4,176.7		21.1		17,490.4
Gross capitalized costs	14,409.2			4,420.4		231.5		19,061.1
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	(136.4		)	(225.4	)	(25.9	)	(387.7	)
Proved oil and natural gas properties	(6,298.9		)	(2,438.6	)	(2.4	)	(8,739.9	)
Net capitalized costs	$	7,973.9		1,756.4		203.2		9,933.5
December 31, 2018
Unproved oil and natural gas properties	$	394.2		250.0		176.9		821.1
Proved oil and natural gas properties	11,678.3			3,693.0		—		15,371.3
Gross capitalized costs	12,072.5			3,943.0		176.9		16,192.4
Accumulated depreciation, depletion and amortization
Unproved oil and natural gas properties	(129.3		)	(213.5	)	(25.4	)	(368.2	)
Proved oil and natural gas properties	(5,433.7		)	(2,088.8	)	—		(7,522.5	)
Net capitalized costs	$	6,509.5		1,640.7		151.5		8,301.7

Note:

Unproved oil and natural gas properties above include costs and associated accumulated amortization of properties that do not have proved reserves; these costs include mineral interests, uncompleted exploratory wells, and exploratory wells capitalized pending further evaluation.

Employee and Retiree Benefit Plans

12 Months Ended

Dec. 31, 2019

Retirement Benefits [Abstract]

Employee and Retiree Benefit Plans

PENSION AND OTHER POSTRETIREMENT PLANS – The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors’ plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.

Upon the disposal of Murphy’s former U.K. downstream assets, the Company retained all vested defined benefit pension obligations associated with former employees of this business. No additional benefits will accrue to these former U.K. employees under the Company’s retirement plan after the date of their separation from Murphy.

GAAP requires the Company to recognize the overfunded or underfunded status of its defined benefit plans as an asset or liability in its consolidated balance sheet and to recognize changes in that funded status between periods through accumulated other comprehensive loss.



	Pension Benefits					Other Postretirement Benefits
(Thousands of dollars)	2019			2018		2019		2018
Change in benefit obligation
Obligation at January 1	$	777,645		881,932		94,779		106,276
Service cost	7,964			8,994		1,559		1,965
Interest cost	27,835			26,168		3,864		3,427
Participant contributions	11			—		1,930		2,104
Actuarial loss (gain)	103,374			(57,378	)	10,503		(13,778	)
Medicare Part D subsidy	—			—		234		325
Exchange rate changes	7,687			(12,742	)	30		(67	)
Benefits paid	(41,247		)	(41,132	)	(4,498	)	(5,473	)
Prior Service Cost	—			737		—		—
Other	—			(28,934	)	—		—
Obligation at December 31	883,269			777,645		108,401		94,779
Change in plan assets
Fair value of plan assets at January 1	487,094			563,825		—		—
Actual return on plan assets	70,893			(18,951	)	—		—
Employer contributions	25,915			24,357		2,333		3,044
Participant contributions	11			—		1,930		2,104
Medicare Part D subsidy	—			—		234		325
Exchange rate changes	7,328			(12,071	)	—		—
Benefits paid	(41,247		)	(41,132	)	(4,497	)	(5,473	)
Other	(2,510		)	(28,934	)	—		—
Fair value of plan assets at December 31	547,484			487,094		—		—
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets	5,353			11,039		—		—
Other accrued liabilities	(8,810		)	(9,175	)	(5,234	)	(5,101	)
Deferred credits and other liabilities	(332,328		)	(292,415	)	(103,167	)	(89,678	)
Fund Status and net plan liability recognized at December 31	$	(335,785	)	(290,551	)	(108,401	)	(94,779	)



(Thousands of dollars)	Pension Benefits			Other Postretirement Benefits
Net actuarial gain (loss)	$	(269,391	)	3,307
Prior service cost	(4,090		)	—
	$	(273,481	)	3,307

Amounts included in AOCL at December 31, 2019 that are expected to be amortized into net periodic benefit expense during 2020 are shown in the following table.



(Thousands of dollars)	Pension Benefits			Other Postretirement Benefits
Net actuarial loss	$	(17,096	)	—
Prior service cost	(734		)	—
	$	(17,830	)	—



	Projected Benefit Obligations			Accumulated Benefit Obligations		Fair Value of Plan Assets
(Thousands of dollars)	2019		2018	2019	2018	2019	2018
Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets	$	688,249	457,446	676,177	447,793	525,108	316,543
Unfunded nonqualified and directors’ plans where accumulated benefit obligation exceeds fair value of plan assets	177,999		158,228	171,934	150,586	—	—
Unfunded other postretirement plans	108,401		94,808	108,401	94,808	—	—

The table that follows provides the components of net periodic benefit expense for each of the three years ended December 31, 2019.



	Pension Benefits							Other Postretirement Benefits
(Thousands of dollars)	2019			2018		2017		2019		2018		2017
Service cost	$	7,964		8,994		8,279		1,559		1,965		1,601
Interest cost	27,835			26,168		27,047		3,864		3,427		3,444
Expected return on plan assets	(25,719		)	(29,236	)	(28,941	)	—		—		—
Amortization of prior service cost (credit)	964			1,021		1,026		—		(38	)	(74	)
Recognized actuarial loss	14,106			21,893		16,691		(193	)	—		—
Net periodic benefit expense	$	25,150		28,840		24,102		5,230		5,354		4,971

The preceding tables in this note include the following amounts related to foreign benefit plans.



	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)	2019			2018	2019	2018
Benefit obligation at December 31	$	209,923		173,860	387	812
Fair value of plan assets at December 31	197,965			170,551	—	—
Net plan liabilities recognized	(11,957		)	3,309	387	812
Net periodic benefit expense (benefit)	(933		)	3,983	147	146



	Benefit Obligations								Net Periodic Benefit Expense
	Pension Benefits				Other Postretirement Benefits				Pension Benefits				Other Postretirement Benefits
	December 31,				December 31,				Year				Year
	2019		2018		2019		2018		2019		2018		2019		2018
Discount rate	3.85	%	4.07	%	3.42	%	3.73	%	3.35	%	3.54	%	4.42	%	4.32	%
Expected return on plan assets	5.05	%	5.37	%	—		—		5.05	%	5.37	%	—		—
Rate of compensation increase	3.28	%	3.28	%	—		—		3.52	%	3.52	%	—		—

The discount rates used for determining the plan obligations and expense are based on the universe of high-quality corporate bonds that are available within each country. Cash flow analyses are performed in which a spot yield curve is used to discount projected benefit payment streams for the most significant plans. The discounted cash flows are used to determine an equivalent single rate which is the basis for selecting the discount rate within each country. Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics. Expected compensation increases are based on anticipated future averages for the Company.

Benefit payments, reflecting expected future service as appropriate, which are expected to be paid in future years from the assets of the plans or by the Company are shown in the following table.



(Thousands of dollars)	Pension Benefits		Other Postretirement Benefits
2020	$	42,399	5,233
2021	43,500		5,360
2022	44,824		5,428
2023	44,850		5,421
2024	45,557		5,505
2025-2030	233,751		27,847

For purposes of measuring postretirement benefit obligations at December 31, 2019, the future annual rates of increase in the cost of health care were assumed to be 6.5% for 2019 decreasing each year to an ultimate rate of 4.5% in 2038 and thereafter.



(Thousands of dollars)	1% Increase		1% Decrease
Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31	$	930	(737	)
Effect on the health care component of the accumulated postretirement benefit obligation at December 31	15,257		(12,291	)

During 2019, the Company made contributions of $25.7 million to its domestic defined benefit pension plans, $0.2 million to its foreign defined benefit pension plans and $2.3 million to its domestic postretirement benefits plan. During 2020, Company

currently expects to make contributions of $30.6 million to its domestic defined benefit pension plans, $0.6 million to its foreign defined benefit pension plans and $5.2 million to its domestic postretirement benefits plan.

Plan Investments – Murphy Oil Corporation maintains an Investment Policy Statement (Statement) that establishes investment standards related to its funded domestic qualified retirement plan. The Statement specifies that all assets will be held in a Trust sponsored by the Company, which is administrated by a trustee appointed by the Investment Committee (Committee). Members of the Committee are appointed by the Chief Executive Officer of Murphy. The Committee hires Investment Managers to invest trust assets within the guidelines established by the Committee as allowed by the Statement. The investment goals call for a portfolio of assets consisting of equity, fixed income and cash equivalent securities. The primary consideration for investments is the preservation of capital, and investment growth should exceed the rate of inflation. The Committee has directed the asset investment advisors of its benefit plans to maintain a portfolio consisting of both equity and fixed income securities. The Company believes that over time a balanced to slightly heavier weighting of the portfolio in equity securities compared to fixed income securities represents the most appropriate long-term mix for future investment return on assets held by domestic plans.

Generally, no more than 10% of an Investment Manager’s portfolio is to be held in equity securities of any one issuer, and equity securities should have a minimum market capitalization of $100.0 million. Equities held in the trust should be listed on the New York or American Stock Exchanges, principal U.S. regional exchanges, major foreign exchanges or quoted in significant over-the-counter markets. Equity or fixed income securities issued by the Company may not be held in the trust. Fixed income securities include maturities greater than one year to maturity. The fixed income portfolio should not exceed an average maturity of 11 years. The portfolio may include investment grade corporate bonds, issues of the U.S. government, its agencies and government sponsored entities, government agency issued collateralized mortgage backed securities, agency issued mortgage backed securities, municipal bonds, asset backed securities, commercial mortgage backed securities and international and emerging markets bond funds. The Committee routinely reviews the investment performance of Investment Managers.

For the U.K. retirement plan, trustees have been appointed by the wholly-owned subsidiary that sponsors the plan for U.K. employees. The trustees have hired Hewitt Risk Management Services Limited (Manager) as fiduciary investment manager of the plan’s assets. The trustees have adopted a de-risking strategy which permits the Manager discretion to vary the investment allocation as needed to meet a target return. The target return is reduced over time as pre-determined funding level triggers are met in proportion to pension liability changes. As of December 31, 2019, one of seven funding level triggers have been met which led to a reduction in growth assets to more low-risk assets. The plan primarily invests in two funds, the Delegated Growth Fund DGF and the Delegated Liability Fund DLF. The DGF is diversified by style, strategy and asset class by investing with underlying funds that may include equity funds, fixed income funds, debt funds, currency funds, hedge funds, fund of hedge funds and other collective investment schemes covering a broad range of asset classes and strategies. The DLF aims to provide returns in line with the liabilities of typical pension plans on an exposure basis in the relevant tenures and instruments (long/short, real/nominal). The DLF also holds cash as collateral for the leveraged positions along with small working cash balances to facilitate daily management of payments and receipts within the plan. The trustee routinely reviews the investment performance of the plan.

For the Canadian retirement plan, the wholly-owned subsidiary that sponsors the plan has a Statement of Investment Policies and Procedures (Policy) applicable to the plan assets. A pension committee appointed by the board of directors of the subsidiary oversees the plan, selects the investment advisors and routinely reviews performance of the asset portfolio. The Policy permits assets to be invested in various Canadian and foreign equity securities, various fixed income securities, real estate, natural resource properties or participation rights and cash. The objective for plan investments is to achieve a total rate of return equal to the long-term interest rate assumption used for the going-concern actuarial funding valuation.

The following table provides the asset allocation of each plan on December 31, 2019.



	Allocation of Plan Assets
	Domestic Plan		Canadian Plan		U.K. Plan
	Target	Allocation at	Target	Allocation at	Target	Allocation at
	Allocation	December 31, 2019	Allocation	December 31, 2019	Allocation	December 31, 2019
Equity securities	40-70%	54.0%	28-38%	34.5%	N/A	59.2%
Fixed income securities	25-60%	27.8%	60-70%	63.5%	N/A	18.4%
Alternatives	0-20%	16.9%	—%	—%	N/A	20.2%
Cash and equivalents	0-15%	1.3%	0-10%	2.0%	N/A	2.2%

The weighted average asset allocation for the Company’s funded pension benefit plans at December 31, 2019 and 2018 are presented in the following table.



	December 31,
	2019		2018
Equity securities	54.9	%	56.0	%
Fixed income securities	26.2		42.2
Alternatives	17.3		—
Cash equivalents	1.6		1.8
	100.0	%	100.0	%

The Company’s weighted average expected return on plan assets was 5.51% in 2019 and the return was determined based on an assessment of actual long-term historical returns and expected future returns for a portfolio with investment characteristics similar to that maintained by the plans. The 5.51% expected return was based on an expected average future equity securities return of 6.30% and a fixed income securities return of 3.95% and is net of average expected investment expenses of 0.60%. Over the last 10 years, the return on funded retirement plan assets has averaged 7.56%.

At December 31, 2019, the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows.



			Fair Value Measurements Using
(Thousands of dollars)	Fair Value at December 31, 2019		Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
Domestic Plans
Equity securities:
U.S. core equity	$	63,169	63,169	—	—
U.S. small/midcap	26,062		26,062	—	—
Hedged funds and other alternative strategies	58,864		—	—	58,864
International commingled trust fund	73,783		924	55,798	17,061
Emerging market commingled equity fund	25,911		8,011	17,900	—
Fixed income securities:
U.S. fixed income	88,525		—	88,525	—
International commingled trust fund	8,720		—	8,720	—
Cash and equivalents	4,485		4,485	—	—
Total Domestic Plans	349,519		102,651	170,943	75,925
Foreign Plans
Equity securities funds	68,878		—	68,840	—
Fixed income securities funds	46,582		—	46,390	—
Diversified pooled fund	42,582		—	42,582	—
Other	35,661		—	—	35,661
Cash and equivalents	4,262		—	4,256	—
Total Foreign Plans	197,965		—	162,068	35,661
Total	$	547,484	102,651	333,011	111,586

At December 31, 2018, the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows.



			Fair Value Measurements Using
(Thousands of dollars)	Fair Value at December 31, 2018		Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
Domestic Plans
Equity securities:
U.S. core equity	$	62,105	62,105	—	—
U.S. small/midcap	19,436		19,436	—	—
Hedged funds and other alternative strategies	45,844		—	10,789	35,055
International commingled trust fund	63,089		—	63,089	—
Emerging market commingled equity fund	15,355		—	15,355	—
Fixed income securities:
U.S. fixed income	87,526		—	87,526	—
International commingled trust fund	13,274		—	13,274	—
Emerging market mutual fund	4,570		—	4,570	—
Cash and equivalents	5,344		5,344	—	—
Total Domestic Plans	316,543		86,885	194,603	35,055
Foreign Plans
Equity securities funds	67,165		—	67,165	—
Fixed income securities funds	89,417		—	89,417	—
Diversified pooled fund	10,762		—	10,762	—
Cash and equivalents	3,207		—	3,207	—
Total Foreign Plans	170,551		—	170,551	—
Total	$	487,094	86,885	365,154	35,055

The definition of levels within the fair value hierarchy in the tables above is included in Note Q – Assets and Liabilities Measured at Fair Value .

For domestic plans, U.S. core and small/midcap equity securities are valued based on daily market prices as quoted on national stock exchanges or in the over-the-counter market. Hedge funds and other alternative strategies funds consist of three investments. One of these investments is valued based on daily market prices as quoted on national stock exchanges, another investment is valued monthly based on net asset value and permits withdrawals semi-annually after a 90-day notice, and the third investment is also valued monthly based on net asset values and has a two-year lock-up period and a 95-day notice following the lock-up period. International equities held in a commingled trust are valued monthly based on prices as quoted on various international stock exchanges. The emerging market commingled equity fund is valued monthly based on net asset value. These commingled equity funds can be withdrawn monthly and have a 10-day notice period. U.S. fixed income securities are valued daily based on bids for the same or similar securities or using net asset values. International fixed income securities held in a commingled trust are valued on a monthly basis using net asset values. The fixed income emerging market mutual fund is valued daily based on net asset value. For foreign plans, the equity securities funds are comprised of U.K. and foreign equity funds valued daily based on fund net asset values. Fixed income securities funds are U.K. securities valued daily at net asset values. The diversified pooled fund is valued daily at net asset value and contains a combination of Canadian and foreign equity securities, Canadian fixed income securities and cash.

The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below:



(Thousands of dollars)	Hedged Funds and Other Alternative Strategies
Total at December 31, 2017	$	37,950
Actual return on plan assets:
Relating to assets held at the reporting date	(2,921		)
Total at December 31, 2018	35,029
Actual return on plan assets:
Relating to assets held at the reporting date	20,811
Purchases, sales and settlements	55,746
Total at December 31, 2019	$	111,586

THRIFT PLANS – Most full-time U.S. employees of the Company may participate in thrift or similar savings plans by allotting up to a specified percentage of their base pay. The Company matches contributions at a stated percentage of each employee’s allotment based on years of participation in the plans, with a maximum match of 6%. Amounts charged to expense for the Company’s match to these plans were $8.4 million in 2019, $5.2 million in 2018 and $7.8 million in 2017.

Supplemental Oil and Gas Information - Results of Operations for Oil and Gas Producing Activities (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Revenues

$ 2,817,100

$ 1,806,500

$ 1,300,400

8,500

18,900

129,400

2,825,600

1,825,400

1,429,800

605,200

353,800

299,600

48,000

52,100

43,700

176,315

75,043

^[1]

67,300

61,600

58,600

28,000

40,100

61,800

1,125,200

755,400

735,300

40,500

27,200

25,300

20,000

126,800

99,300

109,700

96,000

47,400

6,200

2,264,700

1,490,700

1,356,300

560,900

334,700

73,500

100,300

57,300

7,400

Crude Oil and Natural Gas Liquids

460,600

277,400

66,100

Revenues

2,584,800

1,586,600

1,107,400

Natural Gas

Revenues

232,300

219,900

193,000

Revenues

2,359,700

1,331,300

941,600

7,300

1,400

2,700

2,367,000

1,332,700

944,300

461,500

230,500

198,500

46,600

50,900

42,200

140,800

43,100

21,400

29,400

7,800

23,100

36,800

60,200

878,700

519,500

546,100

34,400

19,500

17,400

20,000

74,300

49,000

61,800

20,000

52,200

23,000

1,733,000

1,021,700

954,000

634,000

311,000

(9,700)

115,600

68,100

(800)

United States | Crude Oil and Natural Gas Liquids

518,400

242,900

(8,900)

Revenues

United States | Natural Gas

2,285,800

1,277,700

903,700

Revenues

73,900

53,600

37,900

Canada | Canada

Revenues

445,800

469,100

358,800

1,200

1,400

126,700

447,000

470,500

485,500

142,400

122,600

101,100

1,400

1,200

1,500

35,500

31,900

600

500

1,300

800

1,600

243,000

232,400

185,400

6,100

7,700

7,900

30,000

26,800

28,300

2,300

(6,100)

(19,100)

454,200

404,900

328,600

(7,200)

65,600

156,900

(2,900)

14,500

44,400

Canada | Crude Oil and Natural Gas Liquids | Canada

(4,300)

51,100

112,500

Revenues

Canada | Natural Gas | Canada

287,400

302,800

203,700

Revenues

158,400

166,300

155,100

Revenues

11,600

6,100

16,100

11,600

22,200

1,300

700

45,300

31,600

50,300

3,600

2,500

3,500

3,800

22,500

23,500

19,600

73,700

1,300

2,300

77,500

64,100

73,700

(65,900)

(41,900)

(73,700)

(12,400)

(25,300)

(36,200)

Other | Crude Oil and Natural Gas Liquids

(53,500)

(16,600)

(37,500)

Revenues

11,600

6,100

Other | Natural Gas

Revenues

Income (loss) from continuing operations before income taxes

$ 0

[1]

Leases (Details)	12 Months Ended
Leases (Details)	Dec. 31, 2019
Minimum
Lessee, Lease, Description [Line Items]
Remaining lease terms	1 year
Period of lease termination option	1 month
Maximum
Lessee, Lease, Description [Line Items]
Remaining lease terms	20 years

Income Taxes - Components of Income (Loss) from Continuing Operations Before Income Taxes and Income Tax Expense (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Income (loss) from continuing operations before income taxes

$ 282,199

$ 14,907

$ (299,349)

Foreign

(78,701)

28,095

16,465

$ (115,300)

$ 177,100

$ 107,900

$ 33,700

$ 12,700

$ 74,000

$ (22,600)

$ (21,100)

203,498

43,002

^[1]

(282,884)

^[1]

Income tax expense (benefit)

U.S. Federal – Current

(9,765)

Federal - Deferred

30,598

(131,200)

156,065

Total U.S. Federal

30,598

(140,965)

156,065

State

5,139

3,299

4,230

Foreign – Current

(17,823)

61,257

Foreign - Deferred

(3,231)

(49,727)

109,777

Total Foreign

(21,054)

11,530

109,836

Total income tax expense (benefit)

$ 14,683

$ (126,136)

^[1]

$ 270,131

^[1]

[1]

Employee and Retiree Benefit Plans - Weighted Average Asset Allocation for Funded Pension Benefit Plans (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Retirement plan assets		$ 547,484	$ 487,094
Weighted average asset allocation		100.00%	100.00%
Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation		54.90%	56.00%
Defined Benefit Plan, Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation		26.20%	42.20%
Other
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation		17.30%
Defined Benefit Plan, Cash and Equivalents
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation		1.60%	1.80%
Domestic Plan \| Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	54.00%
Domestic Plan \| Defined Benefit Plan, Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	27.80%
Domestic Plan \| Other
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	16.90%
Domestic Plan \| Defined Benefit Plan, Cash and Equivalents
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	1.30%
Domestic Plan \| Minimum \| Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Target allocations of plan assets	40.00%
Domestic Plan \| Minimum \| Defined Benefit Plan, Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Target allocations of plan assets	25.00%
Domestic Plan \| Minimum \| Other
Defined Benefit Plan Disclosure [Line Items]
Target allocations of plan assets	0.00%
Domestic Plan \| Minimum \| Defined Benefit Plan, Cash and Equivalents
Defined Benefit Plan Disclosure [Line Items]
Target allocations of plan assets	0.00%
Domestic Plan \| Maximum \| Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Target allocations of plan assets	70.00%
Domestic Plan \| Maximum \| Defined Benefit Plan, Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Target allocations of plan assets	60.00%
Domestic Plan \| Maximum \| Other
Defined Benefit Plan Disclosure [Line Items]
Target allocations of plan assets	20.00%
Domestic Plan \| Maximum \| Defined Benefit Plan, Cash and Equivalents
Defined Benefit Plan Disclosure [Line Items]
Target allocations of plan assets	15.00%
Canadian Plan \| Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	34.50%
Canadian Plan \| Defined Benefit Plan, Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	63.50%
Canadian Plan \| Other
Defined Benefit Plan Disclosure [Line Items]
Target allocations of plan assets	0.00%
Weighted average asset allocation	0.00%
Canadian Plan \| Defined Benefit Plan, Cash and Equivalents
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	2.00%
Canadian Plan \| Minimum \| Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Target allocations of plan assets	28.00%
Canadian Plan \| Minimum \| Defined Benefit Plan, Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Target allocations of plan assets	60.00%
Canadian Plan \| Minimum \| Defined Benefit Plan, Cash and Equivalents
Defined Benefit Plan Disclosure [Line Items]
Target allocations of plan assets	0.00%
Canadian Plan \| Maximum \| Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Target allocations of plan assets	38.00%
Canadian Plan \| Maximum \| Defined Benefit Plan, Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Target allocations of plan assets	70.00%
Canadian Plan \| Maximum \| Defined Benefit Plan, Cash and Equivalents
Defined Benefit Plan Disclosure [Line Items]
Target allocations of plan assets	10.00%
U.K. Plan \| Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	59.20%
U.K. Plan \| Defined Benefit Plan, Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	18.40%
U.K. Plan \| Other
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	20.20%
U.K. Plan \| Defined Benefit Plan, Cash and Equivalents
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	2.20%

Business Segments - Narrative (Details) - Sales Revenue	12 Months Ended
Business Segments - Narrative (Details) - Sales Revenue	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Concentration risk	25.00%
Phillips 66 and Affiliated Companies
Segment Reporting Information [Line Items]
Concentration risk	17.00%	12.00%	14.00%

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Allowance for doubtful accounts on accounts receivable	$ 1,605	$ 1,605
Allowance for doubtful accounts and accumulated depreciation, depletion and amortization	$ 9,333,646	$ 8,070,487
Cumulative Preferred Stock, par value (in USD per share)	$ 100	$ 100
Cumulative preferred stock, authorized shares (in shares)	400,000	400,000
Cumulative preferred stock, shares issued (in shares)	0	0
Common Stock, par value (in USD per share)	$ 1.00	$ 1.00
Common stock, authorized shares (in shares)	450,000,000	450,000,000
Common stock, shares issued (in shares)	195,089,269	195,076,924

Business Segments - Geographic Information on Certain Long-Lived Assets (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Revenues from External Customers and Long-Lived Assets [Line Items]

$ 2,829,053

$ 1,791,401

^[1]

$ 1,443,988

^[1]

9,969,700

8,432,100

6,827,700

Revenues from External Customers and Long-Lived Assets [Line Items]

2,370,400

1,300,300

958,300

Revenues from External Customers and Long-Lived Assets [Line Items]

8,003,900

6,634,300

5,050,500

Canada

447,100

468,900

485,700

1,761,200

1,644,600

1,635,900

Revenues from External Customers and Long-Lived Assets [Line Items]

11,600

22,200

Revenues from External Customers and Long-Lived Assets [Line Items]

204,600

153,200

141,300

Operating Segments

Balance at beginning of year at Dec. 31, 2016

$ 2,829,100

$ 1,791,400

$ 1,444,000

[1]

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($)
$ in Thousands

Total

Common Stock

Capital in Excess of Par Value

Retained Earnings

Accumulated Other Comprehensive Loss

Treasury Stock

Parent

Noncontrolling Interest

$ 195,056

$ 916,799

$ 5,729,596

$ (628,212)

$ (1,296,560)

$ 0

Exercise of stock options, including income tax benefits

Restricted stock transactions and other

(26,553)

Stock-based compensation

27,496

Fair value increase in common controlled assets

Reclassification of certain tax effects

(77)

Net income (loss)

$ (311,789)

^[1]

(311,789)

Cash dividends

(172,565)

Foreign currency translation gains (losses), net of income taxes

171,725

Retirement and postretirement benefit plans, net of income taxes

(7,682)

Deferred loss on interest rate hedge reclassified to interest expense, net of income taxes

1,926

Purchase of treasury shares

Sale of stock under employee stock purchase plans

146

Awarded restricted stock, net of forfeitures

20,885

Acquisition closing adjustments

Distributions to noncontrolling interest owners

Balance at end of year at Dec. 31, 2017

4,620,191

195,056

917,665

5,245,242

(462,243)

(1,275,529)

$ 4,620,191

Exercise of stock options, including income tax benefits

(362)

Restricted stock transactions and other

(33,920)

Stock-based compensation

27,920

Fair value increase in common controlled assets

68,339

Reclassification of certain tax effects

Net income (loss)

411,094

^[1]

411,094

8,392

(30,237)

30,237

(30,237)

Sale and leaseback gain recognized upon adoption of ASC 842, net of tax impact

Cash dividends

(173,044)

Foreign currency translation gains (losses), net of income taxes

(145,022)

Retirement and postretirement benefit plans, net of income taxes

29,110

Deferred loss on interest rate hedge reclassified to interest expense, net of income taxes

2,342

Purchase of treasury shares

(3,737)

Sale of stock under employee stock purchase plans

Awarded restricted stock, net of forfeitures

26,367

Acquisition closing adjustments

359,951

Distributions to noncontrolling interest owners

Balance at end of year at Dec. 31, 2018

5,197,642

^[2]

195,077

979,642

5,513,529

(609,787)

(1,249,162)

4,829,299

368,343

Exercise of stock options, including income tax benefits

(182)

Restricted stock transactions and other

(38,731)

Stock-based compensation

33,235

Fair value increase in common controlled assets

(24,519)

Reclassification of certain tax effects

Net income (loss)

1,149,732

103,570

Sale and leaseback gain recognized upon adoption of ASC 842, net of tax impact

114,712

Cash dividends

(163,669)

Foreign currency translation gains (losses), net of income taxes

66,600

Retirement and postretirement benefit plans, net of income taxes

(35,979)

Deferred loss on interest rate hedge reclassified to interest expense, net of income taxes

5,005

Purchase of treasury shares

(499,924)

Sale of stock under employee stock purchase plans

Awarded restricted stock, net of forfeitures

31,869

Acquisition closing adjustments

(6,604)

Distributions to noncontrolling interest owners

(128,158)

Balance at end of year at Dec. 31, 2019

$ 5,804,611

$ 195,089

$ 949,445

$ 6,614,304

$ (574,161)

$ (1,717,217)

$ 5,467,460

$ 337,151

[1]	¹ Reclassified to conform with current presentation (see Notes C and E). 2017 revenue is presented net of $58.9 million of transportation, gathering and processing costs as historically shown prior to the adoption of ASC 606 on January 1, 2018. See Notes to Consolidated Financial Statements, page 58.
[2]	Reclassified to conform with current presentation (see Note E)

Inventories (Tables)

12 Months Ended

Dec. 31, 2019

Inventory Disclosure [Abstract]

Schedule of Inventory

Inventories consisted of the following at December 31, 2019 and 2018.



	December 31,
(Thousands of dollars)	2019		2018
Unsold crude oil	$	27,634	17,318
Materials and supplies	48,489		62,706
Inventories	$	76,123	80,024

Assets and Liabilities Measured at Fair Value

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Assets and Liabilities Measured at Fair Value

Fair Values – Recurring

The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheet. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.

The fair value measurements for these assets and liabilities at December 31, 2019 and 2018 are presented in the following table



	December 31, 2019					December 31, 2018
(Thousands of dollars)	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
Assets:
Commodity derivative contracts	$	—	—	—	—	—	3,837	—	3,837
	$	—	—	—	—	—	3,837	—	3,837

Liabilities:
Nonqualified employee savings plans	$	17,035	—	—	17,035	13,845	—	—	13,845
Commodity derivative contracts	—		33,364	—	33,364	—	—	—	—
Contingent consideration	—		—	146,787	146,787	—	—	47,730	47,730
	$	17,035	33,364	146,787	197,186	13,845	—	47,730	61,575

The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and general expenses in the Consolidated Statements of Operations.

The fair value of West Texas Intermediate (WTI) crude oil contracts in 2019 and 2018 was based on active market quotes for WTI crude oil. The income effect of changes in fair value of crude oil derivative contracts is recorded in Gain (loss) on crude contracts in the Consolidated Statements of Operations, while the effects of changes in fair value of foreign exchange derivative contracts is recorded in Interest and other income (loss).

The Company’s contingent consideration liabilities (with PAI and LLOG, as further described in Note D) are measured at fair value on a recurring basis and are categorized as Level 3 in the fair value hierarchy. The contingent consideration liabilities are valued using a Monte Carlo simulation model, which used the following assumptions as of December 31, 2019: (i) the remaining expected life of 3 years for LLOG and 6 years for PAI, (ii) West Texas Intermediate forward strip pricing with historical volatility of 30.0%, and (iii) a risk-free interest rate of 1.66%. The income effect of changes in the fair value of the contingent consideration is recorded in Other (income) expense in the Consolidated Statements of Operations.

The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were no offsetting positions recorded at December 31, 2019 and 2018.

maturities. The Company has off-balance sheet exposures relating to certain letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, was nominal.



	December 31,
	2019					2018
(Thousands of dollars)	Carrying Amount			Fair Value		Carrying Amount		Fair Value
Financial assets (liabilities):
Current and long-term debt	$	(2,803,381	)	(3,074,929	)	(3,109,986	)	(2,899,912	)

Fair Values – Nonrecurring

In 2018, as a result of our assessment of market value and our expected recoverable value of select Midland properties in the U.S., the Company recognized a pretax noncash impairment charge of $20.0 million.

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 fair value information associated with these impaired properties is presented in the following table

Year Ended December 31, 2018

Net Book

Value

Prior to

Impairment

Total

Pretax

Impairment

Fair Value

(Thousands of dollars)

Level 1

Level 2

Level 3

Assets:

Impaired proved properties

United States Midland

—

37,690

57,690

20,000

Schedule II - Valuation Accounts and Reserves

12 Months Ended

Dec. 31, 2019

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

Schedule II - Valuation Accounts and Reserves



(Millions of dollars)	Balance at January 1		Charged to Expense	Deductions	Other ¹		Balance at December 31
2019
Deducted from asset accounts:
Allowance for doubtful accounts	$	1.6	—	—	—		1.6
Deferred tax asset valuation allowance	166.9		10.9	—	(74.7	)	103.1
2018
Deducted from asset accounts:
Allowance for doubtful accounts	$	1.6	—	—	—		1.6
Deferred tax asset valuation allowance	407.3		3.3	—	(243.7	)	166.9
2017
Deducted from asset accounts:
Allowance for doubtful accounts	$	1.6	—	—	—		1.6
Deferred tax asset valuation allowance	236.4		18.6	—	152.3		407.3

¹ The amounts in 2019 and 2018 for deferred tax asset valuation allowance are primarily associated with utilization of foreign tax credit carryforwards. The amount in 2017 for deferred tax asset valuation are primarily associated with an increase in foreign tax credit carryforwards.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2019

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

The asset retirement obligations liabilities (ARO) recognized by the Company at December 31, 2019 and 2018 are related to the estimated costs to dismantle and abandon its producing oil and natural gas properties and related equipment.

A reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligation for 2019 and 2018 is shown in the following table.



(Thousands of dollars)	2019			2018
Balance at beginning of year	$	800,117		447,270
Accretion expense	40,506			27,119
Liabilities incurred	14,759			6,572
Liabilities assumed from acquisitions	64,810			359,643
Revisions of previous estimates	(34,371		)	(20,012	)
Liabilities settled	(25,544		)	(11,510	)
Liabilities associated with assets held for sale	(240		)	—
Changes due to translation of foreign currencies	5,072			(8,965	)
Balance at end of year	865,109			800,117
Current portion of liability at end of year ¹	(39,315		)	(47,598	)
Noncurrent portion of liability at end of year	$	825,794		752,519

¹Included in Other accrued liabilities on the Consolidated Balance Sheet.

The estimation of future ARO is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that may be required in future periods due to the availability of additional information such as: prices for oil field services, technological changes, governmental requirements and other factors.

Liabilities assumed in 2019, primarily represent obligations assumed as part of the LLOG acquisition. Liabilities assumed in 2018 primarily represent obligations from the MP GOM acquisition. (see Note D).

Commitments	12 Months Ended
Commitments	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments	Commitments The Company has operating, production handling and transportation service agreements for oil and/or natural gas operations in the U.S. and Western Canada. The U.S. Onshore and Gulf of Mexico transportation contracts require minimum monthly payments through 2044, while the Western Canada processing contracts call for minimum monthly payments through 2035. In the U.S. and Western Canada, future required minimum monthly payments for the next five years are $128.7 million in 2020, $154.7 million in 2021, $160.8 million in 2022, $149.7 million in 2023 and $139.8 million in 2024. Under certain circumstances, the Company is required to pay additional amounts depending on the actual hydrocarbon quantities processed under the agreement. Total costs incurred under these service arrangements were $117.7 million in 2019, $52.2 million in 2018, and $53.8 million in 2017. Commitments for capital expenditures were approximately $574.5 million at December 31, 2019, including $518.0 million for costs to develop deepwater U.S. Gulf of Mexico fields including new fields acquired as part of the MP GOM and LLOG transactions, $25.4 million for work at Eagle Ford Shale. Included in this amount is approximately $379.7 million for approved expenditure for capital projects relating to non-operated interests.

Financing Arrangements and Long-Term Debt

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Financing Arrangements and Long-Term Debt

As of December 31, 2019, the Company has a $1.6 billion revolving credit facility (RCF). The RCF is a senior unsecured guaranteed facility which expires in November 2023. At December 31, 2019, the Company had no outstanding borrowings under the RCF and $3.7 million of outstanding letters of credit, which reduces the borrowing capacity of the RCF. At December 31, 2019, the interest rate in effect on borrowings under the facility would have been 3.21%. At December 31, 2019, the Company was in compliance with all covenants related to the RCF.

In May 2019, the Company entered into a $500 million term loan credit facility (the New Term Credit Facility). The New Term Credit Facility was a senior unsecured guaranteed facility with an original maturity date of December 2, 2019. The covenants within the New Term Credit Facility were substantially consistent with those in the Company’s revolving credit facility (see RCF above), and borrowings under the New Term Credit Facility bore interest at comparable rates to those incurred under the 2018 facility. In July 2019, the Company closed the previously announced Malaysia divestiture, repaid and terminated the New Term Credit Facility.

In November 2019, the Company sold $550 million of new notes that bear interest at a rate of 5.875% and mature on December 1, 2027. The Company incurred transaction costs of $7.4 million on the issuance of these new notes. The Company will pay interest semi-annually on June 1 and December 1 of each year, beginning June 1, 2020. The proceeds of the $550 million notes were used to repurchase and cancel $239.7 million of the Company’s 4.00% notes due 2022 and $281.6 million of the Company’s 4.45% notes due 2022 (originally issued as 3.70% notes due 2022, see table footnote below) (collectively the 2022 Notes) during November and December. The cost of the debt extinguishment of $32.1 million is included in Interest expense, net on the Consolidated Statement of Operations for the year ended December 31, 2019. The cash costs of $26.6 million are shown as a financing activity on the Consolidated Statement of Cash Flows for the year ended December 31, 2019.

໿



	December 31,
(Thousands of dollars)	2019			2018
Notes payable
4.00% notes, due June 2022	$	260,251		500,000
4.45% notes, due December 2022 ¹	318,417			600,000
6.875% notes, due August 2024	550,000			550,000
5.75% notes, due August 2025	550,000			550,000
5.875% notes, due December 2027	550,000			—
7.05% notes, due May 2029	250,000			250,000
5.875% notes, due December 2042 ¹	350,000			350,000
Total notes payable	2,828,668			2,800,000
Unamortized debt issuance cost and discount on notes payable	(25,287		)	(23,627	)
Total notes payable, net of unamortized discount	2,803,381			2,776,373
Capitalized lease obligation, due through March 2029 ¹	—			8,613
Total debt including current maturities	2,803,381			2,784,986
Senior Unsecured Revolving Credit Facility	—			325,000
Current maturities ²	—			(668	)
Total long-term debt	$	2,803,381		3,109,318

¹ Coupon rate may fluctuate 25 basis points if rating is periodically downgraded or upgraded by S&P and Moody’s.

² Capitalized lease obligation and current maturities relate to a finance lease in Brunei, which is classified as held for sale as of December 31, 2019 (see Note E).

The amount of long-term debt repayable over each of the next five years and thereafter are as follows: nil in 2020, nil in 2021, $578.7 million in 2022, nil in 2023, $550.0 million in 2024 and $1.70 billion thereafter.

Earnings per Share

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

Earnings per Share

Net income (loss) was used as the numerator in computing both basic and diluted income per Common share for each of the three years ended December 31, 2019. The following table reconciles the weighted-average shares outstanding used for these computations.



(Weighted-average shares)	2019	2018	2017
Basic method	163,992,427	172,974,491	172,524,061
Dilutive stock options ¹	820,001	1,234,274	—
Diluted method	164,812,428	174,208,765	172,524,061



	2019		2018		2017
Antidilutive stock options excluded from diluted shares	2,974,401		3,942,296		4,901,269
Weighted average price of these options		$45.26		$46.77		$45.74

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

^[1]

Dec. 31, 2017

Revenues and other income

Revenue from sales to customers

$ 2,817,111,000

$ 1,806,473,000

$ 1,300,464,000

^[1]

(Loss) gain on crude contracts

(856,000)

(41,975,000)

9,566,000

^[1]

Gain on sale of assets and other income

12,798,000

26,903,000

133,958,000

^[1]

Total revenues and other income

2,829,053,000

1,791,401,000

1,443,988,000

^[1]

605,180,000

353,832,000

299,420,000

^[1]

47,959,000

52,072,000

43,618,000

^[1]

Exploration expenses, including undeveloped lease amortization

176,315,000

75,043,000

^[1]

95,105,000

101,812,000

120,389,000

^[1]

232,736,000

205,192,000

207,391,000

^[1]

1,147,842,000

775,614,000

^[2]

751,878,000

^[1],[2]

40,506,000

27,119,000

^[2]

25,282,000

^[1],[2]

20,000,000

^[2]

^[1],[2]

Other expense (benefit)

38,117,000

(34,870,000)

22,329,000

^[1]

Operating income (loss) from continuing operations

2,383,760,000

1,575,814,000

1,470,307,000

^[1]

445,293,000

215,587,000

(26,319,000)

^[1]

Other income (loss)

Income (loss) from continuing operations before income taxes

(22,520,000)

7,774,000

(78,302,000)

^[1]

Interest expense, net

(219,275,000)

(180,359,000)

(178,263,000)

^[1]

Total other loss

(241,795,000)

(172,585,000)

(256,565,000)

^[1]

203,498,000

43,002,000

(282,884,000)

^[1]

Income (loss) from continuing operations

14,683,000

(126,136,000)

270,131,000

^[1]

188,815,000

169,138,000

(553,015,000)

^[1]

Income from discontinued operations, net of income taxes

1,064,487,000

250,348,000

^[2]

241,226,000

^[1],[2]

Net income (loss) including noncontrolling interest

1,253,302,000

419,486,000

^[2]

(311,789,000)

^[1],[2]

Less: Net income attributable to noncontrolling interest

103,570,000

8,392,000

^[1]

NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY

$ 1,149,732,000

$ 411,094,000

$ (311,789,000)

^[1]

INCOME (LOSS) PER COMMON SHARE – BASIC

Continuing operations (in USD per share)

$ 0.52

$ 0.92

$ (3.21)

^[1]

Discontinued operations (in USD per share)

6.49

1.46

1.40

^[1]

Net Income (in USD per share)

7.01

2.38

(1.81)

^[1]

INCOME (LOSS) PER COMMON SHARE – DILUTED

Continuing operations (in USD per share)

0.52

0.92

(3.21)

^[1]

Discontinued operations (in USD per share)

6.46

1.44

1.40

^[1]

Net income (loss) (in USD per share)

6.98

2.36

(1.81)

^[1]

Cash dividends per Common share (in USD per share)

$ 1.00

^[1]

Average Common shares outstanding (thousands)

Basic (in shares)

163,992,427

172,974,491

172,524,061

^[1]

Diluted (in shares)

164,812,428

174,208,765

172,524,061

^[1]

Previous Accounting Guidance

$ 58,900,000

[1]	¹ Reclassified to conform with current presentation (see Notes C and E). 2017 revenue is presented net of $58.9 million of transportation, gathering and processing costs as historically shown prior to the adoption of ASC 606 on January 1, 2018. See Notes to Consolidated Financial Statements, page 58.
[2]	Reclassified to conform with current presentation (see Note E)

Revenue from Contracts with Customers - Narrative (Details)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2019

USD ($)

Sep. 30, 2019

USD ($)

Jun. 30, 2019

USD ($)

Mar. 31, 2019

USD ($)

Dec. 31, 2018

USD ($)

Sep. 30, 2018

USD ($)

Jun. 30, 2018

USD ($)

Mar. 31, 2018

USD ($)

Dec. 31, 2019

USD ($)

segment

Dec. 31, 2018

USD ($)

Dec. 31, 2017

USD ($)

^[1]

Number of geographic segments | segment

Number of revenue streams | segment

Receivables from contracts with customers

$ 757,000

$ 750,300

$ 680,400

$ 629,400

$ 476,100

$ 475,500

$ 443,000

$ 411,900

$ 2,817,111

$ 1,806,473

^[1]

$ 1,300,464

186,800

$ 147,600

186,800

$ 147,600

Malaysia

Gain (loss) on disposition of business

$ 985,400

[1]

Commitments - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
Commitments - Narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2019
Commitments and Contingencies Disclosure [Line Items]
Future rental payments, next twelve months				$ 124,267
Future rental payments, due year two				74,978
Future rental payments, due year three				56,756
Future rental payments, due year four				54,986
Future rental payments, due year five				50,640
Commitments for capital expenditures				574,500
Commitments for capital projects relating to non-operated interests				379,700
Eagle Ford Shale
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures				25,400
Gulf of Mexico
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures				518,000
Processing Production Handling and Transportation Services
Commitments and Contingencies Disclosure [Line Items]
Future rental payments, next twelve months				128,700
Future rental payments, due year two				154,700
Future rental payments, due year three				160,800
Future rental payments, due year four				149,700
Future rental payments, due year five				$ 139,800
Processing and transportation charges	$ 117,700	$ 52,200	$ 53,800

Asset Retirement Obligations - Classification of Asset of Asset Retirement Obligations (Details) - USD ($)
$ in Thousands

Dec. 31, 2019

Dec. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

Current portion of liability at end of year

$ (39,315)

$ (47,598)

Noncurrent portion of liability at end of year

$ 825,794

$ 752,519

^[1]

[1]	Reclassified to conform with current presentation (see Note E)

Schedule II - Valuation Accounts and Reserves (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Allowance for doubtful accounts
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at January 1	$ 1.6	$ 1.6	$ 1.6
Charged (Credited) to Expense	0.0	0.0	0.0
Deductions	0.0	0.0	0.0
Other	0.0	0.0	0.0
Balance at January 1	1.6	1.6	1.6
Deferred tax asset valuation allowance
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at January 1	166.9	407.3	236.4
Charged (Credited) to Expense	10.9	3.3	18.6
Deductions	0.0	0.0	0.0
Other	(74.7)	(243.7)	152.3
Balance at January 1	$ 103.1	$ 166.9	$ 407.3

Property, Plant And Equipment - Net Changes in Capitalized Exploratory Well Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Beginning balance at January 1	$ 207,855	$ 155,103	$ 101,546
Additions pending the determination of proved reserves	83,712	59,487	53,557
Reclassifications to proved properties based on the determination of proved reserves	(61,096)	(2,214)	0
Capitalized exploration well costs charged to expense	(13,145)	(4,521)	0
Ending balance at December 31	$ 217,326	$ 207,855	$ 155,103

Incentive Plans

12 Months Ended

Dec. 31, 2019

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Incentive Plans

Murphy utilizes cash-based and/or share-based incentive awards to supplement normal salaries as compensation for executive management and certain employees. For share-based awards that qualify for equity accounting, costs are recognized as an expense in the Consolidated Statements of Operations using a grant date fair value-based measurement method over the periods that the awards vest. For share-based awards that are required to be accounted for under liability accounting rules, costs are recognized as expense using a fair value-based measurement method over the vesting period, but expense is adjusted as necessary through the date the award value is finally determined. Total expense for liability awards is ultimately adjusted to the final intrinsic value for the award.

In 2018, the Company’s shareholders approved replacement of the 2012 Long-Term Incentive Plan (2012 Long-Term Plan) with the 2018 Long-Term Incentive Plan (2018 Long-Term Plan). All awards on or after May 9, 2018 have been made under the 2018 Long-Term Plan.

The Company currently has outstanding incentive awards issued to certain employees under the 2017 Annual Incentive Plan, the 2012 Long-Term Plan and the 2018 Long-Term Plan. The 2017 Annual Incentive Plan authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees. Cash awards under the 2017 Annual Incentive Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.

The 2018 Long-Term Plan and the 2012 Long-term Plan authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units, performance units, performance shares, dividend equivalents and other stock-based incentives. The 2018 Long-Term Plan expires in 2028. A total of 6.75 million shares are issuable during the life of the 2018 Long-Term Plan, with annual grants limited to 1% of Common shares outstanding and total full value share awards (i.e. not options) not to exceed 50% of the total issuable amount; allowed shares not granted in an earlier year may be granted in future years. Based on awards made to date, there are 2.1 million shares available for grant under the 2018 Long-Term Plan at December 31, 2019. In 2018, the Company’s shareholders approved the 2018 Stock Plan for Non-Employee Directors (2018 NED Plan) that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.

The Company generally expects to issue treasury shares to satisfy future stock option exercises and vesting of restricted stock and restricted stock units.

Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:



(Thousands of dollars)	2019		2018	2017
Compensation charged against income (loss) before income tax benefit	$	50,170	34,467	40,365
Related income tax benefit recognized in income	7,389		4,383	5,017

As of December 31, 2019, there were $50.4 million in compensation costs to be expensed over approximately the next five years related to unvested share-based compensation arrangements granted by the Company. Employees receive net shares, after applicable withholding obligations, upon each stock option exercise and restricted stock award. Total income tax benefits realized from tax deductions related to stock option exercises under share-based payment arrangements were immaterial for the years ended December 31, 2019 and 2018. There were no income tax benefits realized in 2017 due to no stock option exercises during that year.

Equity-Settled Awards

STOCK OPTIONS – In 2018, the Company ceased the inclusion of stock options and stock appreciation rights as a part of the long-term incentive compensation mix.

Previously, the Committee fixed the option price of each option granted at no less than fair market value (FMV) on the date of the grant and fixed the option term at no more than seven years from such date. Each option granted to date under the 2012 Long-Term Plan has been nonqualified, with a term of seven years and an option price equal to FMV at date of grant. Under these plans, one-half of each grant is generally exercisable after two years and the remainder after three years. For stock options, the number of shares issued upon exercise is reduced for settlement of applicable statutory income tax withholdings owed by the grantee.

The fair value of each option award is estimated on the date of grant using the Black-Scholes pricing model based on the assumptions noted in the following table. Expected volatility is based on historical volatility of the Company’s stock and implied volatility on publicly traded at-the-money options on the Company’s stock. The Company estimates the expected term of the options granted based on historical option exercise patterns and considers certain groups of employees exhibiting different behavior. The risk-free interest rate for periods within the expected term of the option is based on the U.S. Treasury yield curve in effect at the time of grant.



	2019	2018	2017
Fair value per option grant	N/A	N/A	$7.96
Assumptions
Dividend yield	N/A	N/A	3.60%
Expected volatility	N/A	N/A	41.00%
Risk-free interest rate	N/A	N/A	1.97%
Expected life	N/A	N/A	5.30 years

Changes in stock options outstanding during the last three years are presented in the following table.



	Number of Shares		Average Exercise Price
Outstanding at December 31, 2016	5,757,435		$	48.46
Granted at FMV	603,000		28.51
Exercised	—		—
Forfeited	(1,459,166	)	49.34
Outstanding at December 31, 2017	4,901,269		45.74
Granted at FMV	—		—
Exercised	(72,000	)	17.57
Forfeited	(834,674	)	53.36
Outstanding at December 31, 2018	3,994,595		44.66
Granted at FMV	—		—
Exercised	(57,500	)	17.57
Forfeited	(1,016,685	)	48.29
Outstanding at December 31, 2019	2,920,410		43.93
Exercisable at December 31, 2016	3,830,535		$	53.80
Exercisable at December 31, 2017	3,197,269		54.22
Exercisable at December 31, 2018	3,182,345		49.10
Exercisable at December 31, 2019	2,694,410		43.51

Additional information about stock options outstanding at December 31, 2019 is shown below.



	Options Outstanding				Options Exercisable
Range of Exercise Prices per Option	No. of Options	Avg. Life Remaining in Years	Aggregate Intrinsic Value		No. of Options	Avg. Life Remaining in Years	Aggregate Intrinsic Value
$17.00 to $30.99	1,033,000	3.5	$	5,365,535	807,000	3.4	$	5,365,535
$31.00 to $50.99	730,000	2.1	—		730,000	2.1	—
$51.00 to $65.00	1,157,410	0.5	—		1,157,410	0.5	—
	2,920,410	2.0	$	5,365,535	2,694,410	1.8	$	5,365,535

The total intrinsic value of options exercised during 2019 was $0.5 million. There were no options exercised in 2017 as all awards either had no intrinsic value or were not vested. Intrinsic value is the excess of the market price of stock at date of exercise over the exercise price received by the Company upon exercise. Aggregate intrinsic value is nil when the exercise price of the stock option exceeds the market price of the Company’s common stock.

PERFORMANCE-BASED RESTRICTED STOCK UNITS – Performance-based restricted stock units (PSUs) to be settled in Common shares were granted in 2019 under the 2018 Long-Term Plan and in 2018 and 2017 under the 2012 Long-Term Plan. Each grant will vest if the Company achieves specific performance objectives at the end of the designated performance period. Additional shares may be awarded if performance objectives are exceeded. If performance goals are not met, PSUs will not vest, but recognized compensation cost associated with the stock award would not be reversed. For PSUs, the performance conditions are based on the Company’s total shareholder return over the performance period compared to an industry peer group of companies. During the performance period, PSUs are subject to transfer restrictions and are subject to forfeiture if a grantee terminates for reasons other than retirement, disability or death. Termination for these three reasons will lead to a pro rata award of amounts earned. No dividends are paid nor do voting rights exist on awards of PSUs prior to their settlement.

Changes in PSUs outstanding for each of the last three years are presented in the following table.



(Number of stock units)	2019		2018		2017
Outstanding at beginning of year	1,660,417		1,187,921		992,573
Granted	957,600		905,500		560,000
Vested and issued	(331,917	)	(311,866	)	(272,725	)
Forfeited	(156,367	)	(121,138	)	(91,927	)
Outstanding at end of year	2,129,733		1,660,417		1,187,921

The fair value of the equity-settled performance-based awards granted in each year was estimated on the date of grant using a Monte Carlo valuation model. Expected volatility was based on daily historical volatility of the Company’s stock price compared to a peer group average over a three-year period. The risk-free interest rate is based on the yield curve of three-year U.S. Treasury bonds and the stock beta was calculated using three years of historical averages of daily stock data for Murphy and the peer group. The assumptions used in the valuation of the performance awards granted in 2019, 2018 and 2017 are presented in the following table.



	2019	2018	2017
Fair value per share at grant date	$28.09	$22.99 - $30.56	$24.10 – $28.28
Assumptions
Expected volatility	46.00%	48.00%	47.00%
Risk-free interest rate	2.50%	2.30%	1.46%
Stock beta	1.037	1.103	1.058
Expected life	3.0 years	3.0 years	3.0 years

TIME-BASED RESTRICTED STOCK UNITS – Time-based restricted stock units (RSUs) have been granted to the Company’s Non-Employee Directors (NED) under the 2013 NED Plan and 2018 NED Plan and to certain employees under the 2012 Long-Term Plan and 2018 Long-Term Plan. These awards vest on the third anniversary of the date of grant. The fair value of these awards was estimated based on the market value of the Company’s stock on the date of grant, which were $21.68 to $28.16 per share in 2019, $25.69 to $28.43 per share in 2018, and $28.51 to $28.84 per share in 2017.

Changes in RSUs outstanding for each of the last three years are presented in the following table.



(Number of share units)	2019		2018		2017
Outstanding at beginning of year	1,538,854		1,035,980		923,282
Granted	409,692		823,803		419,720
Vested and issued	(275,738	)	(233,456	)	(217,633	)
Forfeited	(137,728	)	(87,473	)	(89,389	)
Outstanding at end of year	1,535,080		1,538,854		1,035,980

Cash-Settled Awards

The Company has granted stock-based incentive awards to be settled in cash to certain employees in the form of Stock Appreciation Rights (SARs), Performance-based restricted stock units (CPSUs), Time-based restricted stock units (CRSUs) and Phantom units.

SAR awards have terms similar to stock options. CPSU terms are similar to other performance-based restricted stock awards (PSUs). CRSUs generally settle on the third anniversary of the date of grant. Phantom units generally settle three to five years from date of grant. Each award granted is settled, net of applicable income tax withholdings, in cash rather than with Common shares. Total expense recorded in the Consolidated Statements of Operations for all cash-settled stock-based awards was $16.9 million in 2019, $6.5 million in 2018 and $12.9 million in 2017.

The Committee also administers the Company’s incentive compensation plans, which provide for annual or periodic cash awards to officers, directors and certain other employees. These cash awards are generally determinable based on the Company achieving specific financial and/or operational objectives. Compensation expense of $34.1 million, $30.0 million and $30.5 million was recorded in 2019, 2018 and 2017, respectively, for these plans.

Revenue from Contracts with Customers - Current Long-Term Contracts Outstanding (Details)	Dec. 31, 2019 MMcf / d Boe / d	Dec. 31, 2018 MMcf / d Boe / d
End Date, Q4, 2021 \| United States
Disaggregation of Revenue [Line Items]
Approximate Volumes \| Boe / d	17,000	17,000
End Date, Q4, 2021 \| Canada \| USD Index Pricing
Disaggregation of Revenue [Line Items]
Approximate Volumes	10
End Date, Q4, 2020 \| Canada \| Alberta AECO
Disaggregation of Revenue [Line Items]
Approximate Volumes	59	59
End Date, Q4, 2020 \| Canada \| USD Index Pricing
Disaggregation of Revenue [Line Items]
Approximate Volumes	60	60
End Date, Q4, 2024 \| Canada \| USD Index Pricing
Disaggregation of Revenue [Line Items]
Approximate Volumes	30	30
End Date, Q4, 2026 \| Canada \| USD Index Pricing
Disaggregation of Revenue [Line Items]
Approximate Volumes	38	38
End Date, Q3, 2019 \| United States
Disaggregation of Revenue [Line Items]
Approximate Volumes \| Boe / d		4,000
End Date, Q4, 2026 \| Canada \| USD Index Pricing
Disaggregation of Revenue [Line Items]
Approximate Volumes	11

Business Segments

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Business Segments

Murphy’s reportable segments are organized into geographic areas of operations. The Company’s exploration and production activity is subdivided into segments for the United States, Canada and all other countries. Each of these segments derives revenues primarily from the sale of crude oil, condensate, natural gas liquids and/or natural gas. The Company’s management evaluates segment performance based on income (loss) from operations, excluding interest income and interest expense.

The Company has several customers that purchase a significant portion of its oil and natural gas production. During 2019 sales to Chevron represented approximately 25% and Phillips 66 and affiliated companies accounted for 17% of the Company’s total sales revenue. In 2018 and 2017 sales to Phillips 66 and affiliated companies represented approximately 12% and 14%, respectively, of the Company’s total sales revenue. Due to the quantity of active oil and natural gas purchasers in the markets where it produces hydrocarbons, the Company does not foresee any difficulty with selling its hydrocarbon production at fair market prices.

The Company completed the sale of its Malaysian assets in 2019. The U.K. and Malaysian operations have been reported as Discontinued operations for all periods presented in these consolidated financial statements. For all years presented, assets and liabilities associated with U.K. refining and marketing operations were reported as held for sale in the Consolidated Balance Sheets. As of December 31, 2019, the assets and liabilities associated with Brunei as also reported as held for sale in the Consolidated Balance Sheet.

Information about business segments and geographic operations is reported in the following tables. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate and other activities, including interest income, other gains and losses (including foreign exchange gains/losses, and realized/unrealized gains/losses on crude oil contracts), interest expense and unallocated overhead, are shown in the tables to reconcile the business segments to consolidated totals. As used in the table on the following page, certain long-lived assets at December 31, exclude investments, noncurrent receivables, deferred tax assets, and other intangible assets.



	Exploration and Production
(Millions of dollars)	United States ¹			Canada		Other		Total E&P		Corporate and Other			Discontinued Operations	Consolidated Total
Year ended December 31, 2019
Segment income (loss) - including NCI ¹	$	518.4		(4.3	)	(53.5	)	460.6		$	(271.8	)	1,064.5	1,253.3
Revenues from external customers	2,367.0			447.0		11.6		2,825.6		3.5			—	2,829.1
Interest and other income (loss)	(13.4		)	(1.5	)	(0.9	)	(15.8	)	(6.7		)	—	(22.5	)
Interest expense, net of capitalization	—			(0.1	)	(0.4	)	(0.5	)	(218.8		)	—	(219.3	)
Income tax expense (benefit)	115.6			(2.9	)	(12.4	)	100.3		(85.6		)	—	14.7
Significant noncash charges (credits)
Depreciation, depletion and amortization	878.7			243.0		3.5		1,125.2		22.6			—	1,147.8
Accretion of asset retirement obligations	34.4			6.1		—		40.5		—			—	40.5
Amortization of undeveloped leases	23.1			1.3		3.6		28.0		—			—	28.0
Deferred and noncurrent income taxes	111.8			14.0		(13.4	)	112.4		(83.9		)	—	28.5
Additions to property, plant, equipment	2,193.3			284.1		69.8		2,547.2		13.6			—	2,560.8
Total assets at year-end	8,043.3			2,303.7		308.6		10,655.6		1,046.2			16.7	11,718.5
Year ended December 31, 2018
Segment income (loss) - including NCI ¹	$	242.9		51.1		(16.6	)	277.4		$	(108.2	)	250.3	419.5
Revenues from external customers	1,332.7			470.5		22.2		1,825.4		(34.0		)	—	1,791.4
Interest and other income (loss)	—			—		—		—		7.8			—	7.8
Interest expense, net of capitalization	—			—		0.2		0.2		(180.6		)	—	(180.4	)
Income tax expense (benefit)	68.1			14.5		(25.3	)	57.3		(183.4		)	—	(126.1	)
Significant noncash charges (credits)
Depreciation, depletion and amortization	519.5			232.4		3.5		755.4		20.2			—	775.6
Accretion of asset retirement obligations	19.5			7.6		—		27.1		—			—	27.1
Amortization of undeveloped leases	36.8			0.8		2.5		40.1		—			—	40.1
Deferred and noncurrent income taxes	68.1			16.5		(25.7	)	58.9		(242.1		)	—	(183.2	)
Additions to property, plant, equipment	1,343.5			373.8		15.9		1,733.2		22.7			138.6	1,894.5
Total assets at year-end	6,342.9			1,711.9		188.1		8,242.9		1,118.5			1,691.2	11,052.6
Year ended December 31, 2017
Segment income (loss)	$	(8.9	)	112.5		(37.5	)	66.1		$	(619.1	)	241.2	(311.8	)
Revenues from external customers	944.3			485.5		—		1,429.8		14.2			—	1,444.0
Interest and other income (loss)	—			—		—		—		(78.3		)	—	(78.3	)
Interest expense, net of capitalization	—			—		—		—		(178.3		)	—	(178.3	)
Income tax expense (benefit)	(0.8		)	44.4		(36.2	)	7.4		262.7			—	270.1
Significant noncash charges (credits)
Depreciation, depletion and amortization	546.1			185.4		3.8		735.3		16.6			—	751.9
Accretion of asset retirement obligations	17.4			7.9		—		25.3		—			—	25.3
Amortization of undeveloped leases	60.2			1.6		—		61.8		—			—	61.8
Deferred and noncurrent income taxes	2.5			55.3		(36.2	)	21.6		242.5			—	264.1
Additions to property, plant, equipment	534.8			267.6		37.6		840.0		14.8			16.0	870.8
Total assets at year-end	5,186.2			1,725.8		154.2		7,066.2		1,101.7			1,693.0	9,860.9

¹2019 and 2018 include results attributable to a noncontrolling interest in MP GOM.



Geographic Information	Certain Long-Lived Assets at December 31
(Millions of dollars)	United States		Canada	Other	Total
2019	$	8,003.9	1,761.2	204.6	9,969.7
2018	6,634.3		1,644.6	153.2	8,432.1
2017	5,050.5		1,635.9	141.3	6,827.7



Geographic Information	Revenues from External Customers for the Year
(Millions of dollars)	United States		Canada	Other	Total
2019	$	2,370.4	447.1	11.6	2,829.1
2018	1,300.3		468.9	22.2	1,791.4
2017	958.3		485.7	—	1,444.0

Significant Accounting Policies	12 Months Ended
Significant Accounting Policies	Dec. 31, 2019
Accounting Policies [Abstract]
Significant Accounting Policies	Significant Accounting Policies NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and natural gas company that conducts its business through various operating subsidiaries. The Company primarily produces oil and natural gas in the United States and Canada and conducts oil and natural gas exploration activities worldwide. The Company sold its Canadian heavy oil assets in early 2017 and Malaysian assets in 2019. See Notes E and G for more information regarding the sale of these assets. PRINCIPLES OF CONSOLIDATION – The consolidated financial statements include the accounts of Murphy Oil Corporation and all majority-owned subsidiaries. Undivided interests in oil and natural gas joint ventures are consolidated on a proportionate basis. Investments in affiliates in which the Company owns from 20% to 50% are accounted for by the equity method. Beginning in the fourth quarter of 2018, Murphy reports 100% of the sales volume, revenues, costs, assets and liabilities including the 20% noncontrolling interest (NCI), of MP GOM in accordance with accounting for noncontrolling interest as prescribed by ASC 810-10-45 (see Note D). Other investments are generally carried at cost. All significant intercompany accounts and transactions have been eliminated. REVENUE RECOGNITION – Revenues from sales of crude oil, natural gas liquids and natural gas are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer; the amount of revenue recognized reflects the consideration expected in exchange for those commodities. The Company measures revenue based on consideration specified in a contract and excludes taxes and other amounts collected on behalf of third parties. Revenues from the production of oil and natural gas properties in which Murphy shares in the undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period. Natural gas imbalances occur when the Company’s actual natural gas sales volumes differ from its proportional share of production from the well. The company follows the sales method of accounting for these natural gas imbalances. The Company records a liability for natural gas imbalances when it has sold more than its working interest of natural gas production and the estimated remaining reserves make it doubtful that partners can recoup their share of production from the field. At December 31, 2019 and 2018, the liabilities for natural gas balancing were immaterial. Gains and losses on asset disposals or retirements are included in net income/(loss) as a component of revenues. See Note B for further discussion on revenue recognition. CASH EQUIVALENTS – Short-term investments, which include government securities and other instruments with government securities as collateral, that are highly liquid and have a maturity of three months or less from the date of purchase are classified as cash equivalents. MARKETABLE SECURITIES – The Company classifies investments in marketable securities as available-for-sale or held-to-maturity. The Company does not have any investments classified as trading securities. Available-for-sale securities are carried at fair value with the unrealized gain or loss, net of tax, reported in other comprehensive loss. Held-to-maturity securities are recorded at amortized cost. Premiums and discounts are amortized or accreted into earnings over the life of the related available-for-sale or held-to-maturity security. Dividend and interest income is recognized when earned. Unrealized losses considered to be other than temporary are recognized in earnings. The cost of securities sold is based on the specific identification method. The fair value of investment securities is determined by available market prices. ACCOUNTS RECEIVABLE – At December 31, 2019 and 2018, the Company’s accounts receivable primarily consisted of amounts owed to the Company by customers for sales of crude oil and natural gas. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses on these receivables. The Company reviews this allowance for adequacy at least quarterly and bases its assessment on a combination of current information about its customers and historical write-off experience. Any trade accounts receivable balances written off are charged against the allowance for doubtful accounts. The Company has not experienced any significant credit-related losses in the past three years. INVENTORIES – Amounts included in the Consolidated Balance Sheets include unsold crude oil production and materials and supplies associated with oil and natural gas production operations. Unsold crude oil production is carried in inventory at the lower of cost (applied on a first-in, first-out basis and includes costs incurred to bring the inventory to its existing condition), or market. Materials and supplies inventories are valued at the lower of average cost or estimated market value and generally consist of tubulars and other drilling equipment. PROPERTY, PLANT AND EQUIPMENT – The Company uses the successful efforts method to account for exploration and development expenditures. Leasehold acquisition costs are capitalized. If proved reserves are found on undeveloped property, the leasehold cost is transferred to proved properties. Costs of undeveloped leases associated with unproved properties are expensed over the life of the leases. Exploratory well costs are capitalized pending determination about whether proved reserves have been found. In certain cases, a determination of whether a drilled exploratory well has found proved reserves cannot be made immediately. This is generally due to the need for major capital expenditure to produce and/or evacuate the hydrocarbon(s) found. The determination of whether to make such capital expenditure is usually dependent on whether further exploratory or appraisal wells find a sufficient quantity of additional reserves. The Company continues to capitalize exploratory well costs in Property, Plant and Equipment 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. The Company reevaluates its capitalized drilling costs at least annually to ascertain whether drilling costs continue to qualify for ongoing capitalization. Other exploratory costs, including geological and geophysical costs, are charged to expense as incurred. Development costs, including unsuccessful development wells, are capitalized. Interest is capitalized on significant development projects that are expected to take one year or more to complete. Oil and natural gas properties are evaluated by field for potential impairment. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets as applicable. An impairment is recognized when there are indications that the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to fair value. There were no impairments in 2019. As a result of management’s assessments during 2018, the Company recognized a pretax, noncash impairment charge of $20.0 million at select Midland properties. There were no impairments recorded during 2017. See also Note G for further discussion of impairment charges. The Company records a liability for asset retirement obligations (ARO) equal to the fair value of the estimated cost to retire an asset. The ARO liability is initially recorded in the period in which the obligation meets the definition of a liability, which is generally when a well is drilled or the asset is placed in service. The ARO liability is estimated by the Company’s engineers using existing regulatory requirements and anticipated future inflation rates. When the liability is initially recorded, the Company increases the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is increased over time to reflect the change in its present value, and the capitalized cost is depreciated over the useful life of the related long-lived asset. The Company reevaluates the adequacy of its recorded ARO liability at least annually. Actual costs of asset retirements such as dismantling oil and natural gas production facilities and site restoration are charged against the related liability. Any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability is recognized as a gain or loss in the Company’s earnings. Depreciation and depletion of producing oil and natural gas properties are recorded based on units of production. Unit rates are computed for unamortized development drilling and completion costs using proved developed reserves and acquisition costs are amortized over proved reserves. Proved reserves are estimated by the Company’s engineers and are subject to future revisions based on the availability of additional information. CAPITALIZED INTEREST– Interest associated with borrowings from third parties is capitalized on significant oil and natural gas development projects when the expected development period extends for one year or more. Interest capitalized is credited in the Consolidated Statements of Operations and is added to the cost of the underlying asset for the development project in Property, plant and equipment in the Consolidated Balance Sheets. Capitalized interest is amortized over the useful life of the asset in the same manner as other development costs. LEASES - At inception, contracts are assessed for the presence of a lease according to criteria laid out by ASC 842. If a lease is present, further criteria is assessed to determine if the lease should be classified as an operating or finance lease. Operating leases are presented on the Consolidated Balance Sheet as Operating lease assets with the corresponding lease liabilities presented in Operating lease liabilities and Non-current operating lease liabilities. Finance lease assets are presented on the Consolidated Balance Sheet within Assets held for sale with the corresponding liabilities presented in Current maturities of long-term debt and Long-term debt. Generally, lease liabilities are recognized at commencement and based on the present value of the future minimum lease payments to be made over the lease term. Lease assets are then recognized based on the value of the lease liabilities. Where implicit lease rates are not determinable, the minimum lease payments are discounted using the Company’s collateralized incremental borrowing rates. Operating leases are expensed according to their nature and recognized in Lease operating expenses, Selling and general expenses or capitalized in the Consolidated Financial Statements. Finance leases are depreciated with the relevant expenses recognized in Depreciation, depletion, and amortization and Interest expense, net on the Consolidated Statement of Operations. ENVIRONMENTAL LIABILITIES – A liability for environmental matters is established when it is probable that an environmental obligation exists and the cost can be reasonably estimated. If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used. Related expenditures are charged against the liability. Environmental remediation liabilities have not been discounted for the time value of future expected payments. Environmental expenditures that have future economic benefit are capitalized. INCOME TAXES – The Company accounts for income taxes using the asset and liability method. Under this method, income taxes are provided for amounts currently payable and for amounts deferred as tax assets and liabilities based on differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Deferred income taxes are measured using the enacted tax rates that are assumed will be in effect when the differences reverse. The Company routinely assesses the realizability of deferred tax assets based on available evidence including assumptions of future taxable income, tax planning strategies and other pertinent factors. A deferred tax asset valuation allowance is recorded when evidence indicates that it is more likely than not that all or a portion of these deferred tax assets will not be realized in a future period. On December 22, 2017 the Tax Cuts and Jobs Act (2017 Tax Act) was enacted which triggered the transitional tax on a deemed repatriation of all past foreign earnings (see Note J) and a provision for this impact has been recorded. Deferred tax liabilities are recorded for relevant withholding taxes when undistributed earnings of foreign subsidiaries are not considered indefinitely invested. Under present law, the Company would incur a 5% withholding tax on any earnings repatriated from Canada to the U.S. The accounting rules for income tax uncertainties permit recognition of income tax benefits only when they are more likely than not to be realized, and then only for the largest amount that is greater than 50% likely of being realized. The Company includes potential penalties and interest for uncertain income tax positions in income tax expense. FOREIGN CURRENCY – Local currency is the functional currency used for recording operations in Canada and former refining and marketing activities in the United Kingdom. The U.S. dollar is the functional currency used to record all other operations. Exchange gains or losses from transactions in a currency other than the functional currency are included in earnings as part of Interest and other income (loss). Gains or losses from translating foreign functional currencies into U.S. dollars are included in Accumulated Other Comprehensive Loss in Consolidated Statements of Stockholders’ Equity. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES – The fair value of a derivative instrument is recognized as an asset or liability in the Company’s Consolidated Balance Sheets. Upon entering into a derivative contract, the Company may designate the derivative as either a fair value hedge or a cash flow hedge or decide that the contract is not a hedge for accounting purposes, and thenceforth, recognize changes in the fair value of the contract in earnings. The Company documents the relationship between the derivative instrument designated as a hedge and the hedged items as well as its objective for risk management and strategy for the use of the hedging instrument to manage the risk. Derivative instruments designated as fair value or cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions. The Company assesses at inception and on an ongoing basis whether a derivative instrument accounted for as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting. The change in the fair value of a qualifying fair value hedge is recorded in earnings along with the gain or loss on the hedged item. The effective portion of the change in the fair value of a qualifying cash flow hedge is recorded in Accumulated other comprehensive loss in the Consolidated Balance Sheets until the hedged item is recognized currently in earnings. If a derivative instrument no longer qualifies as a cash flow hedge and the underlying forecasted transaction is no longer probable of occurring, hedge accounting is discontinued, and the gain or loss recorded in Accumulated other comprehensive loss is recognized immediately in earnings. FAIR VALUE MEASUREMENTS– The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. Fair value is determined using various techniques depending on the availability of observable inputs. Level 1 inputs include quoted prices in active markets for identical assets or liabilities. Level 2 inputs include observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants. See Note Q. STOCK-BASED COMPENSATION Equity-Settled Awards – The fair value of awarded stock options, restricted stock units and other stock-based compensation that are settled with Company shares is determined based on a combination of management assumptions and the market value of the Company’s common stock. The Company uses the Black-Scholes option pricing model for computing the fair value of equity-settled stock options. The primary assumptions made by management include the expected life of the stock option award and the expected volatility of Murphy’s common stock price. The Company uses both historical data and current information to support its assumptions. Stock option expense is recognized on a straight-line basis over the respective vesting period of two or three years. The Company uses a Monte Carlo valuation model to determine the fair value of performance-based restricted stock units that are equity settled and expense is recognized over the three-year vesting period. The fair value of time-lapse restricted stock units is determined based on the price of Company stock on the date of grant and expense is recognized over the vesting period. The Company estimates the number of stock options and performance-based restricted stock units that will not vest and adjusts its compensation expense accordingly. Differences between estimated and actual vested amounts are accounted for as an adjustment to expense when known. Cash-Settled Awards – The Company accounts for stock appreciation rights (SAR), cash-settled restricted stock units (CRSU) and phantom stock units as liability awards. Expense associated with these awards are recognized over the vesting period based on the latest available estimate of the fair value of the awards, which is generally determined using a Black-Scholes method for SAR, a Monte Carlo method for performance-based CRSU, and the period-end price of the Company’s common stock for time-based CRSU and phantom units. When SAR are exercised and when CRSU and phantom units settle, the Company adjusts previously recorded expense to the final amounts paid out in cash for these awards. See Note K. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS – The Company recognizes the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of its defined benefit and other postretirement benefit plans in the Consolidated Balance Sheets. Changes in the funded status which have not yet been recognized in the Consolidated Statement of Operations are recorded net of tax in Accumulated other comprehensive loss. The remaining amounts in Accumulated other comprehensive loss include net actuarial losses and prior service (cost) credit. See Note L. NET INCOME (LOSS) PER COMMON SHARE – Basic income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period. Diluted income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period plus the effects of all potentially dilutive common shares. Dilutive securities are not included in the computation of diluted income (loss) per share when a net loss occurs as the inclusion would have the effect of reducing the diluted loss per share. USE OF ESTIMATES – In preparing the financial statements of the Company in conformity with U.S. generally accepted accounting principles (GAAP), management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.

Other Financial Information - Narrative (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other Financial Information [Abstract]
Net gains (losses) from foreign currency transactions		$ (6.0)	$ 16.1	$ (82.7)
Increase (Decrease) in Asset Retirement Obligations	$ 37.3

Revenue from Contracts with Customers

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Revenue from Contracts with Customers

Nature of Goods and Services

The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and natural gas) in select basins around the globe. The Company’s revenue from sales of oil and natural gas production activities are primarily subdivided into two key geographic segments: the U.S and Canada. Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil and condensate, natural gas liquids, and natural gas.

For operated oil and natural gas production where the non-operated working interest owner does not take-in-kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production. The exception to this is the reporting of the noncontrolling interest in MP GOM as prescribed by ASC 810-10-45.

U.S.- In the United States, the Company primarily produces oil and natural gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico. Revenue is generally recognized when oil and natural gas are transferred to the customer at the delivery point. Revenue recognized is largely index based with price adjustments for floating market differentials.

Canada- In Canada, contracts associated with the Onshore business, are primarily long-term floating commodity index priced, except for certain natural gas physical forward sales fixed-price contracts. For the Offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load based on the volumes on the bill of lading and point of custody transfer.

In 2019, the Company made an immaterial reclassification to correct its financial statements to report transportation, gathering, and processing costs as a separate line item (previously reported net in revenue) in the Consolidated Statements of Operations and revised the 2018 period to reflect this presentation. There was no resultant change in net income attributable to Murphy. The Company did not revise 2017 as it was presented in accordance with ASC 605.

Disaggregation of Revenue

The Company reviews performance based on two key geographical segments and between onshore and offshore sources of Revenue within these geographies.



		Years Ended December 31,
(Thousands of dollars)		2019			2018		2017
Net crude oil and condensate revenue
United States	Onshore	$	750,278		786,537		644,024
	Offshore	1,477,816			417,527		208,984
Canada	Onshore	116,174			111,836		51,013
	Offshore	159,254			176,291		147,230
Other		11,642			6,079		—
Total crude oil and condensate revenue		2,515,164			1,498,270		1,051,251

Net natural gas liquids revenue
United States	Onshore	30,615			61,810		43,804
	Offshore	26,968			11,832		6,894
Canada	Onshore	12,001			14,670		5,450
Total natural gas liquids revenue		69,584			88,312		56,148

Net natural gas revenue
United States	Onshore	27,668			36,070		27,460
	Offshore	46,259			17,559		10,480
Canada	Onshore	158,436			166,262		155,125
Total natural gas revenue		232,363			219,891		193,065
Total revenue from contracts with customers ¹		2,817,111			1,806,473		1,300,464

Gain (loss) on crude contracts		(856		)	(41,975	)	9,566
Gain on sale of assets and other income²		12,798			26,903		133,958
Total revenue and other income		$	2,829,053		1,791,401		1,443,988

¹ 2019 and2018 include revenue attributable to noncontrolling interest in MP GOM, effective November 30, 2018.

² Gain on sale of Malaysia operations of $985.4 million in 2019 is reported in discontinued operations. See Note E.

Contract Balances and Asset Recognition

As of December 31, 2019, and 2018, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $186.8 million and $147.6 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on historical collections and ability of customers to pay, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.

The Company has not entered into any upstream oil and natural gas sale contracts that have financing components as of December 31, 2019.

The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer.

Performance Obligations

The Company recognizes oil and natural gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer. Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is

considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.

For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods.

The Company has entered into several long-term, fixed-price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the company’s long-term strategy.



Current Long-Term Contracts Outstanding at December 31, 2019
Location	Commodity	End Date	Description	Approximate Volumes
U.S.	NGL	Q4 2020	Dedicated acreage delivery in GOM	As produced
U.S.	Oil	Q4 2021	Fixed quantity delivery in Eagle Ford	17,000 BOED
U.S.	Natural Gas and NGL	Q2 2026	Deliveries from dedicated acreage in Eagle Ford	As produced
Canada	Natural Gas	Q4 2020	Contracts to sell natural gas at Alberta AECO fixed prices	59 MMCFD
Canada	Natural Gas	Q4 2020	Contracts to sell natural gas at USD Index pricing	60 MMCFD
Canada	Natural Gas	Q4 2021	Contracts to sell natural gas at USD Index pricing	10 MMCFD
Canada	Natural Gas	Q4 2024	Contracts to sell natural gas at USD Index pricing	30 MMCFD
Canada	Natural Gas	Q4 2026	Contracts to sell natural gas at USD Index pricing	38 MMCFD
Canada	Natural Gas	Q4 2026	Contracts to sell natural gas at USD Index pricing	11 MMCFD

Revenue from Contracts with Customers - Disaggregation of Revenue (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

(Loss) gain on crude contracts

$ 757,000

$ 750,300

$ 680,400

$ 629,400

$ 476,100

$ 475,500

$ 443,000

$ 411,900

$ 2,817,111

$ 1,806,473

^[1]

$ 1,300,464

^[1]

(856)

(41,975)

^[1]

9,566

^[1]

Gain on sale of assets and other income

12,798

26,903

^[1]

133,958

^[1]

Total revenues and other income

2,829,053

1,791,401

^[1]

1,443,988

^[1]

Net crude oil and condensate revenue

Net natural gas liquids revenue

2,515,164

1,498,270

1,051,251

69,584

88,312

56,148

Net natural gas revenue

United States | Net crude oil and condensate revenue

232,363

219,891

193,065

United States | Net natural gas liquids revenue

750,278

786,537

644,024

United States | Net natural gas revenue

30,615

61,810

43,804

United States Offshore | Net crude oil and condensate revenue

27,668

36,070

27,460

United States Offshore | Net natural gas liquids revenue

1,477,816

417,527

208,984

United States Offshore | Net natural gas revenue

26,968

11,832

6,894

Canada | Net crude oil and condensate revenue

46,259

17,559

10,480

Canada | Net natural gas liquids revenue

116,174

111,836

51,013

Canada | Net natural gas revenue

12,001

14,670

5,450

Canada Offshore | Net crude oil and condensate revenue

158,436

166,262

155,125

Other | Net crude oil and condensate revenue

159,254

176,291

147,230

Derivative Instruments and Hedging Activities Disclosure [Abstract]

$ 11,642

$ 6,079

$ 0

[1]

Employee and Retiree Benefit Plans - Amounts Included in Accumulated Other Comprehensive Income Expected to be Amortized into Net Periodic Benefit Expense (Details) $ in Thousands	Dec. 31, 2019 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ (17,096)
Prior service cost	(734)
Amounts included in accumulated other comprehensive loss expected to be amortized into net periodic benefit expense	(17,830)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	0
Prior service cost	0
Amounts included in accumulated other comprehensive loss expected to be amortized into net periodic benefit expense	$ 0

Financial Instruments and Risk Management (Tables)

12 Months Ended

Dec. 31, 2019

Fair Value of Derivative Instruments Not Designated as Hedging Instruments

At December 31, 2019 and 2018, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

December 31, 2019

December 31, 2018

(Thousands of dollars)

Asset (Liability) Derivatives

Type of Derivative Contract

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Commodity

Accounts payable

(33,364

)

Accounts receivable

3,837

Recognized Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments



		Gain (Loss)
(Thousands of dollars)		Year Ended December 31,
Type of Derivative Contract	Statement of Operations Locations	2019			2018		2017
Commodity	Gain (loss) on crude contracts	$	(856	)	(41,975	)	9,566

Supplemental Oil and Gas Information - Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property acquisition costs
Unproved	$ 547.0	$ 3.0	$ 63.4
Proved	733.1	794.3	7.7
Total acquisition costs	1,280.1	797.3	71.1
Cost Incurred, Refunded Exploration Costs			79.2
Exploration costs	118.6	126.0
Development costs	1,282.4	1,390.0	819.0
Total costs incurred	2,681.1	2,313.3	969.3
Charged to expense
Dry hole expense		20.6	(4.2)
Geophysical and other costs	54.3	47.4	65.2
Total charged to expense	54.3	68.0	61.0
Property additions	2,626.8	2,245.3	908.3
United States
Property acquisition costs
Unproved	533.8	2.8	50.4
Proved	733.1	794.3	7.7
Total acquisition costs	1,266.9	797.1	58.1
Cost Incurred, Refunded Exploration Costs			13.7
Exploration costs	44.8	88.1
Development costs	979.0	853.7	508.4
Total costs incurred	2,290.7	1,738.9	580.2
Charged to expense
Dry hole expense		16.0	(1.9)
Geophysical and other costs	21.6	13.4	9.7
Total charged to expense	21.6	29.4	7.8
Property additions	2,269.1	1,709.5	572.4
Canada
Property acquisition costs
Unproved	0.2	0.0	0.0
Proved	0.0	0.0	0.0
Total acquisition costs	0.2	0.0	0.0
Cost Incurred, Refunded Exploration Costs			0.6
Exploration costs	6.4	0.6
Development costs	281.8	373.8	273.8
Total costs incurred	288.4	374.4	274.4
Charged to expense
Dry hole expense		0.0	0.0
Geophysical and other costs	0.5	0.6	0.5
Total charged to expense	0.5	0.6	0.5
Property additions	287.9	373.8	273.9
Malaysia
Property acquisition costs
Unproved	0.0	0.0	0.0
Proved	0.0	0.0	0.0
Total acquisition costs	0.0	0.0	0.0
Cost Incurred, Refunded Exploration Costs			(8.9)
Exploration costs	0.0	2.2
Development costs	0.0	145.9	35.7
Total costs incurred	0.0	148.1	26.8
Charged to expense
Dry hole expense		0.1	0.7
Geophysical and other costs	0.0	2.1	1.7
Total charged to expense	0.0	2.2	2.4
Property additions	0.0	145.9	24.4
Other
Property acquisition costs
Unproved	13.0	0.2	13.0
Proved	0.0	0.0	0.0
Total acquisition costs	13.0	0.2	13.0
Cost Incurred, Refunded Exploration Costs			73.8
Exploration costs	67.4	35.1
Development costs	21.6	16.6	1.1
Total costs incurred	102.0	51.9	87.9
Charged to expense
Dry hole expense		4.5	(3.0)
Geophysical and other costs	32.2	31.3	53.3
Total charged to expense	32.2	35.8	50.3
Property additions	69.8	16.1	37.6
Asset retirement obligations
Property acquisition costs
Exploration costs	0.0	0.0	0.0
Development costs	79.6	373.5	52.3
Total costs incurred	79.6	373.5	52.3
Asset retirement obligations \| United States
Property acquisition costs
Exploration costs	0.0	0.0	0.0
Development costs	75.8	366.0	37.6
Total costs incurred	75.8	366.0	37.6
Asset retirement obligations \| Canada
Property acquisition costs
Exploration costs	0.0	0.0	0.0
Development costs	3.8	0.0	6.3
Total costs incurred	3.8	0.0	6.3
Asset retirement obligations \| Malaysia
Property acquisition costs
Exploration costs	0.0	0.0	0.0
Development costs	0.0	7.3	8.4
Total costs incurred	0.0	7.3	8.4
Asset retirement obligations \| Other
Property acquisition costs
Exploration costs	0.0	0.0	0.0
Development costs	0.0	0.2	0.0
Total costs incurred	$ 0.0	$ 0.2	$ 0.0

Common Stock Issued and Outstanding

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Common Stock Issued and Outstanding

Activity in the number of shares of Common Stock issued and outstanding for the three years ended December 31, 2019 is shown below.



(Number of shares outstanding)	2019		2018	2017
Beginning of year	173,058,829		172,572,873	172,202,177
Stock options exercised ¹	12,345		21,200	—
Restricted stock awards ¹	561,729		464,756	368,132
Employee stock purchase and thrift plans	—		—	2,564
Treasury shares purchased	(20,697,542	)	—	—
End of year	152,935,361		173,058,829	172,572,873

¹Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note K due to withholdings for statutory income taxes owed upon issuance of shares.

Earnings per Share - Weighted-Average Shares Outstanding for Computation of Basic and Diluted Income per Common Share (Details) - USD ($)

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Earnings Per Share [Abstract]

Basic method

163,992,427

172,974,491

^[1]

172,524,061

^[1]

Dilutive stock options

820,001

1,234,274

Diluted method

164,812,428

174,208,765

^[1]

172,524,061

^[1]

Unvested stock awards

$ 0

[1]

Supplemental Oil and Gas Information - Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Net changes in prices and production costs	$ (2,993.9)	$ 2,972.6	$ 2,428.4
Net changes in development costs	(675.7)	(1,891.1)	(724.4)
Sales and transfers of oil and natural gas produced, net of production costs	(2,163.8)	(1,978.6)	(1,576.0)
Net change due to extensions and discoveries	1,221.9	1,930.3	807.9
Net change due to purchases and sales of proved reserves	(628.1)	3,152.4	85.9
Development costs incurred	1,282.4	1,017.3	802.7
Accretion of discount	1,002.0	469.5	270.9
Revisions of previous quantity estimates	(71.2)	(347.8)	(109.5)
Net change in income taxes	574.1	(967.6)	(643.0)
Net increase (decrease)	(2,452.3)	4,357.0	1,342.9
Standardized measure	$ 5,827.6	$ 8,279.9	$ 3,922.9	$ 2,580.0

New Accounting Principles and Recent Accounting Pronouncements - Narrative (Details) - USD ($)
$ in Thousands

12 Months Ended

Jan. 01, 2018

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Jan. 01, 2019

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Operating lease assets

$ 598,293

$ 0

^[1]

$ 618,100

Operating lease liabilities

92,286

^[1]

155,500

Operating And Finance Lease Liabilities, Noncurrent

$ 468,400

Reclassification of certain tax effects from accumulated other comprehensive loss

(30,237)

$ 0

Accumulated Defined Benefit Plans Adjustment Attributable to Parent | Accounting Standards Update 2018-02

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Reclassification of certain tax effects from accumulated other comprehensive loss

$ 28,400

Deferred Loss on Interest Rate Derivative Hedges | Accounting Standards Update 2018-02

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Reclassification of certain tax effects from accumulated other comprehensive loss

1,800

Retained Earnings

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Sale and leaseback gain recognized upon adoption of ASC 842, net of tax impact

114,712

Reclassification of certain tax effects from accumulated other comprehensive loss

$ 0

$ 30,237

$ 0

Retained Earnings | Accounting Standards Update 2016-02

New Accounting Pronouncements or Change in Accounting Principle [Line Items]

Cumulative effect of change on equity or net assets

$ 160,000

[1]	Reclassified to conform with current presentation (see Note E)

Contingencies	12 Months Ended
Contingencies	Dec. 31, 2019
Environmental Remediation Obligations [Abstract]
Contingencies	Contingencies The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax legislation changes, including tax rate changes, and retroactive tax claims; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and natural gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences or may be taken in response to actions of other governments. It is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company. ENVIRONMENTAL MATTERS – Murphy and other companies in the oil and natural gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment. Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result. The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup, and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period. There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity. LEGAL MATTERS – Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

Employee and Retiree Benefit Plans - Weighted-Average Assumptions used in Measurement of Benefit Obligations and Net Periodic Benefit Expense (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligations, Expected return on plan assets	5.51%
Weighted average expected return on plan asset	5.51%
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligations, Discount rate	3.85%	4.07%
Benefit Obligations, Expected return on plan assets	5.05%	5.37%
Benefit Obligation, Rate of compensation increase	3.28%	3.28%
Net Periodic Benefit Expense, Discount rate	3.35%	3.54%
Weighted average expected return on plan asset	5.05%	5.37%
Net Periodic Benefit Expense, Rate of compensation increase	3.52%	3.52%
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligations, Discount rate	3.42%	3.73%
Benefit Obligations, Expected return on plan assets	0.00%	0.00%
Benefit Obligation, Rate of compensation increase	0.00%	0.00%
Net Periodic Benefit Expense, Discount rate	4.42%	4.32%
Weighted average expected return on plan asset	0.00%	0.00%
Net Periodic Benefit Expense, Rate of compensation increase	0.00%	0.00%

Supplemental Oil and Gas Information - Summary of Proved Reserves Based on Average Prices (Details) MMBbls in Millions, ft³ in Billions	12 Months Ended
	Dec. 31, 2019 MMBbls ft³	Dec. 31, 2018 MMBbls ft³	Dec. 31, 2017 MMBbls ft³	Dec. 31, 2016 MMBbls ft³
Proved developed and undeveloped oil reserves:
Proved developed reserves	472.3	430.2	346.7	343.5
Proved undeveloped reserves	352.7	413.8	351.5	341.1
Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance	844.0	698.2	684.5
Revisions of previous estimates	28.4	(21.8)	(5.6)
Improved recovery		0.9	2.0
Extensions and discoveries	73.3	122.6	71.2
Purchases of properties	76.2	106.9	5.9
Sales of properties	(121.5)
Production	(75.4)	(62.8)	(59.8)
Proved developed and undeveloped reserves, Ending Balance	825.0	844.0	698.2
Net crude oil and condensate revenue \| Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance	432.5	328.1	329.0
Revisions of previous estimates	(31.0)	(15.3)	(6.0)
Improved recovery		0.8	2.0
Extensions and discoveries	58.2	58.9	31.6
Purchases of properties	56.3	93.6	4.7
Sales of properties	(45.8)
Production	(46.3)	(33.6)	(33.2)
Proved developed and undeveloped reserves, Ending Balance	423.9	432.5	328.1
Proved developed reserves	230.9	249.3	185.5	184.9
Proved undeveloped reserves	193.0	183.2	142.6	144.1
Net natural gas liquids revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance	54.2	48.9	42.5
Revisions of previous estimates	(5.0)	(6.2)	1.3
Extensions and discoveries	6.8	12.0	7.8
Purchases of properties	5.2	3.0	0.5
Sales of properties	(0.6)
Production	(4.5)	(3.5)	(3.2)
Proved developed and undeveloped reserves, Ending Balance	56.1	54.2	48.9
Proved developed reserves	28.1	27.3	24.6	22.2
Proved undeveloped reserves	28.0	26.9	24.3	20.3
Net natural gas revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance \| ft³	2,143.6	1,927.1	1,878.0
Revisions of previous estimates \| ft³	386.5	(1.8)	(5.4)
Improved recovery \| ft³		0.6
Extensions and discoveries \| ft³	49.8	310.3	190.6
Purchases of properties \| ft³	88.3	61.7	4.0
Sales of properties	(450,700.0)
Production \| ft³	(147.8)	(154.3)	(140.1)
Proved developed and undeveloped reserves, Ending Balance \| ft³	2,069.7	2,143.6	1,927.1
Proved developed reserves \| ft³	1,279.8	921.6	819.3	818.1
Proved undeveloped reserves \| ft³	789.9	1,222.0	1,107.8	1,059.9
MP Gulf of Mexico LLC
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Ending Balance	24.6
Proved developed reserves	19.6
Proved undeveloped reserves	5.0
MP Gulf of Mexico LLC \| Net crude oil and condensate revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Ending Balance	22.1
Proved developed reserves	17.7
Proved undeveloped reserves	4.4
MP Gulf of Mexico LLC \| Net natural gas liquids revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Ending Balance	0.9
Proved developed reserves	0.7
Proved undeveloped reserves	0.2
MP Gulf of Mexico LLC \| Net natural gas revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Ending Balance \| ft³	9.5
Proved developed reserves \| ft³	7.1
Proved undeveloped reserves \| ft³	2.4
United States
Proved developed and undeveloped oil reserves:
Proved developed reserves	273.4	247.0	170.9	157.8
Proved undeveloped reserves	226.7	178.7	134.0	129.6
United States \| Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance	425.6	304.9	287.4
Revisions of previous estimates	(17.9)	(14.0)	(5.4)
Improved recovery		0.0	0.0
Extensions and discoveries	62.2	60.1	39.6
Purchases of properties	76.2	98.7	5.9
Sales of properties	(0.1)
Production	(45.9)	(24.0)	(22.5)
Proved developed and undeveloped reserves, Ending Balance	500.1	425.6	304.9
United States \| Net crude oil and condensate revenue \| Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance	326.5	224.7	214.4
Revisions of previous estimates	(17.1)	(15.0)	(4.7)
Improved recovery		0.0	0.0
Extensions and discoveries	49.2	42.9	27.2
Purchases of properties	56.3	92.3	4.7
Sales of properties	(0.1)
Production	(37.0)	(18.4)	(16.9)
Proved developed and undeveloped reserves, Ending Balance	377.8	326.5	224.7
Proved developed reserves	205.0	189.0	126.3	113.9
Proved undeveloped reserves	172.8	137.5	98.4	100.5
United States \| Net natural gas liquids revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance	47.6	43.0	36.4
Revisions of previous estimates	(2.5)	(5.3)	2.0
Extensions and discoveries	6.4	9.7	7.0
Purchases of properties	5.2	3.0	0.5
Sales of properties	0.0
Production	(3.9)	(2.8)	(2.9)
Proved developed and undeveloped reserves, Ending Balance	52.8	47.6	43.0
Proved developed reserves	26.2	24.9	23.3	20.8
Proved undeveloped reserves	26.6	22.7	19.7	15.6
United States \| Net natural gas revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance \| ft³	309.0	223.3	219.4
Revisions of previous estimates \| ft³	10.3	37.6	(16.0)
Improved recovery \| ft³		0.0
Extensions and discoveries \| ft³	39.5	44.7	32.2
Purchases of properties \| ft³	88.3	20.3	4.0
Sales of properties	(100.0)
Production \| ft³	(30.2)	(16.9)	(16.3)
Proved developed and undeveloped reserves, Ending Balance \| ft³	416.8	309.0	223.3
Proved developed reserves \| ft³	253.1	198.3	127.7	138.7
Proved undeveloped reserves \| ft³	163.7	110.7	95.6	80.7
Canada
Proved developed and undeveloped oil reserves:
Proved developed reserves	198.1	124.2	114.1	103.3
Proved undeveloped reserves	126.0	164.5	145.1	137.7
Canada \| Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance	288.6	259.2	241.0
Revisions of previous estimates	46.1	(18.1)	4.9
Improved recovery		0.0	0.0
Extensions and discoveries	11.1	61.8	31.3
Purchases of properties	0.0	6.9	0.0
Sales of properties	0.0
Production	(21.7)	(21.1)	(18.1)
Proved developed and undeveloped reserves, Ending Balance	324.1	288.6	259.2
Canada \| Net crude oil and condensate revenue \| Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance	55.0	51.5	48.9
Revisions of previous estimates	(14.0)	(8.0)	2.3
Improved recovery		0.0	0.0
Extensions and discoveries	9.0	16.0	4.4
Purchases of properties	0.0	0.0	0.0
Sales of properties	0.0
Production	(4.7)	(4.5)	(4.1)
Proved developed and undeveloped reserves, Ending Balance	45.3	55.0	51.5
Proved developed reserves	25.1	23.3	21.9	19.2
Proved undeveloped reserves	20.2	31.7	29.6	29.7
Canada \| Net natural gas liquids revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance	5.9	5.6	5.6
Revisions of previous estimates	(2.5)	(1.6)	(0.6)
Extensions and discoveries	0.4	2.3	0.8
Purchases of properties	0.0	0.0	0.0
Sales of properties	0.0
Production	(0.5)	(0.4)	(0.2)
Proved developed and undeveloped reserves, Ending Balance	3.3	5.9	5.6
Proved developed reserves	1.9	1.7	1.0	0.9
Proved undeveloped reserves	1.4	4.2	4.6	4.7
Canada \| Net natural gas revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance \| ft³	1,366.4	1,212.4	1,118.9
Revisions of previous estimates \| ft³	375.3	(51.2)	19.4
Improved recovery \| ft³		0.0
Extensions and discoveries \| ft³	10.3	261.0	156.7
Purchases of properties \| ft³	0.0	41.4	0.0
Sales of properties	0.0
Production \| ft³	(99.1)	(97.2)	(82.6)
Proved developed and undeveloped reserves, Ending Balance \| ft³	1,652.9	1,366.4	1,212.4
Proved developed reserves \| ft³	1,026.7	595.0	547.0	498.9
Proved undeveloped reserves \| ft³	626.2	771.4	665.5	620.0
Malaysia & Other
Proved developed and undeveloped oil reserves:
Proved developed reserves	0.8	59.1	61.7	82.4
Proved undeveloped reserves	0.0	70.7	72.4	73.8
Malaysia & Other \| Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance	129.7	134.1	156.2
Revisions of previous estimates	0.3	10.4	(5.2)
Improved recovery		0.9	2.0
Extensions and discoveries	0.0	0.8	0.3
Purchases of properties	0.0	1.3	0.0
Sales of properties	(121.4)
Production	(7.8)	(17.7)	(19.2)
Proved developed and undeveloped reserves, Ending Balance	0.8	129.7	134.1
Malaysia & Other \| Net crude oil and condensate revenue \| Crude Oil
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance	51.0	51.9	65.7
Revisions of previous estimates	0.1	7.7	(3.6)
Improved recovery		0.8	2.0
Extensions and discoveries	0.0	0.0	0.0
Purchases of properties	0.0	1.3	0.0
Sales of properties	(45.7)
Production	(4.6)	(10.7)	(12.2)
Proved developed and undeveloped reserves, Ending Balance	0.8	51.0	51.9
Proved developed reserves	0.8	37.0	37.3	51.8
Proved undeveloped reserves	0.0	14.0	14.6	13.9
Malaysia & Other \| Net natural gas liquids revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance	0.7	0.3	0.5
Revisions of previous estimates	0.0	0.7	(0.1)
Extensions and discoveries	0.0	0.0	0.0
Purchases of properties	0.0	0.0	0.0
Sales of properties	(0.6)
Production	(0.1)	(0.3)	(0.1)
Proved developed and undeveloped reserves, Ending Balance	0.0	0.7	0.3
Proved developed reserves	0.0	0.7	0.3	0.5
Proved undeveloped reserves	0.0	0.0	0.0	0.0
Malaysia & Other \| Net natural gas revenue
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance \| ft³	468.2	491.4	539.7
Revisions of previous estimates \| ft³	0.9	11.8	(8.8)
Improved recovery \| ft³		0.6
Extensions and discoveries \| ft³	0.0	4.6	1.7
Purchases of properties \| ft³	0.0	0.0	0.0
Sales of properties	(450,600.0)
Production \| ft³	(18.5)	(40.2)	(41.2)
Proved developed and undeveloped reserves, Ending Balance \| ft³	0.0	468.2	491.4
Proved developed reserves \| ft³	0.0	128.3	144.6	180.5
Proved undeveloped reserves \| ft³	0.0	339.9	346.7	359.2

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Operating Activities

Net income (loss) including noncontrolling interest

$ 1,253,302,000

$ 419,486,000

^[1],[2]

$ (311,789,000)

^[1],[2]

Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities:

(Income) loss from discontinued operations

(1,064,487,000)

(250,348,000)

^[1],[2]

(241,226,000)

^[1],[2]

Previously suspended exploration costs (credits)

1,147,842,000

775,614,000

^[1],[2]

751,878,000

^[1],[2]

12,840,000

20,508,000

^[2]

(4,861,000)

^[2]

Amortization of undeveloped leases

27,973,000

40,177,000

^[2]

61,775,000

^[2]

40,506,000

27,119,000

^[1],[2]

25,282,000

^[1],[2]

20,000,000

^[1],[2]

Pretax (gain) loss from sale of assets

28,530,000

(177,627,000)

^[2]

270,072,000

^[2]

(227,000)

(54,000)

^[2]

(127,434,000)

^[2]

Mark to market loss (gain) on contingent consideration

8,672,000

(4,810,000)

^[2]

Mark to market loss (gain) on crude contracts

33,364,000

(33,954,000)

^[2]

(13,748,000)

^[2]

Long-term non-cash compensation

76,958,000

72,151,000

^[2]

44,119,000

^[2]

Net (increase) decrease in noncash operating working capital

(16,887,000)

(16,103,000)

^[2]

78,846,000

^[2]

Other operating activities, net

(59,281,000)

(142,764,000)

^[2]

80,437,000

^[2]

Net cash provided by continuing operations activities

1,489,105,000

749,395,000

^[2]

613,351,000

^[2]

Investing Activities

Acquisition of oil and natural gas properties

(1,212,315,000)

(794,623,000)

^[2]

Property additions and dry hole costs

(1,344,271,000)

(1,011,292,000)

^[2]

(910,030,000)

^[2]

Proceeds from sales of property, plant and equipment

20,382,000

1,175,000

^[2]

69,506,000

^[2]

Purchase of investment securities

^[2]

(212,661,000)

^[2]

Proceeds from maturity of investment securities

^[2]

320,828,000

^[2]

Net cash required by investing activities

(2,536,204,000)

(1,804,740,000)

^[2]

(732,357,000)

^[2]

Financing Activities

Borrowings on revolving credit facility and term loan

1,725,000,000

325,000,000

^[2]

Repayment of revolving credit facility and term loan

(2,050,000,000)

^[2]

Debt issuance, net of cost

542,394,000

^[2]

541,597,000

^[2]

Early retirement of debt

(521,332,000)

^[2]

(550,000,000)

^[2]

Loss on early extinguishment of debt

(26,626,000)

^[2]

Repurchase of common stock

(499,924,000)

^[2]

Capital lease obligation payments

(688,000)

(318,000)

^[2]

Withholding tax on stock-based incentive awards

(6,991,000)

(8,076,000)

^[2]

(7,116,000)

^[2]

Distributions to noncontrolling interest

(128,158,000)

^[2]

Cash dividends paid

(163,669,000)

(173,044,000)

^[2]

(172,565,000)

^[2]

Net cash (required) provided by financing activities

(1,129,994,000)

143,562,000

^[2]

(188,084,000)

^[2]

Cash Flows from Discontinued Operations

Operating activities

^[3]

73,783,000

406,857,000

^[2]

527,228,000

^[2]

Investing activities

^[3]

2,022,034,000

(91,398,000)

^[2]

(99,637,000)

^[2]

Financing activities

^[3]

(4,914,000)

(9,432,000)

^[2]

(17,133,000)

^[2]

Net cash provided by discontinued operations

^[3]

2,090,903,000

306,027,000

^[2]

410,458,000

^[2]

Cash transferred from discontinued operations to continuing operations

2,120,397,000

612,543,000

^[2]

325,446,000

^[2]

Effect of exchange rate changes on cash and cash equivalents

3,533,000

28,730,000

^[2]

1,327,000

^[2]

Net increase (decrease) in cash and cash equivalents

(53,163,000)

(270,510,000)

^[2]

19,683,000

^[2]

Cash and cash equivalents at beginning of period

^[2]

359,923,000

630,433,000

610,750,000

Cash and cash equivalents at end of period

$ 306,760,000

$ 359,923,000

^[2]

$ 630,433,000

^[2]

[1]	¹ Reclassified to conform with current presentation (see Notes C and E). 2017 revenue is presented net of $58.9 million of transportation, gathering and processing costs as historically shown prior to the adoption of ASC 606 on January 1, 2018. See Notes to Consolidated Financial Statements, page 58.
[2]	Reclassified to conform with current presentation (see Note E)
[3]	Net cash provided by discontinued operations are not part of the cash flow reconciliation.

Supplemental Quarterly Infomation (Details) - USD ($)
$ / shares in Units, $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2019

Dec. 31, 2018

^[1]

Dec. 31, 2017

^[1]

Quarterly Financial Information Disclosure [Abstract]

Revenue from contracts with customers

$ 757,000

$ 750,300

$ 680,400

$ 629,400

$ 476,100

$ 475,500

$ 443,000

$ 411,900

$ 2,817,111

$ 1,806,473

$ 1,300,464

Income (loss) from continuing operations before income taxes

(115,300)

177,100

107,900

33,700

12,700

74,000

(22,600)

(21,100)

203,498

43,002

(282,884)

Income (loss) from continuing operations

(91,300)

158,300

98,800

22,900

47,600

56,100

(25,200)

90,600

188,815

169,138

(553,015)

Net income (loss) including noncontrolling interest

(54,400)

1,111,700

123,200

72,800

111,800

93,900

45,500

168,300

1,253,302

419,486

^[2]

(311,789)

^[2]

Net income (loss) attributable to Murphy

$ (71,700)

$ 1,089,000

$ 92,300

$ 40,200

$ 103,400

$ 93,900

$ 45,500

$ 168,300

$ 1,149,732

$ 411,094

$ (311,789)

Income (loss) from continuing operations per Common share

Basic (in USD per share)

$ (0.71)

$ 0.85

$ 0.40

$ (0.06)

$ 0.23

$ 0.32

$ (0.14)

$ 0.52

$ 0.92

$ (3.21)

Diluted (in USD per share)

(0.70)

0.84

0.40

(0.06)

0.22

0.32

(0.15)

0.52

0.92

(3.21)

Net income (loss) per Common share

Basic (in USD per share)

(0.71)

6.79

0.55

0.23

0.60

0.54

0.27

0.97

7.01

2.38

(1.81)

Diluted (in USD per share)

(0.47)

6.76

0.54

0.23

0.59

0.54

0.25

0.96

6.98

2.36

(1.81)

Cash dividend per Common share (in USD per share)

$ 0.25

$ 1.00

[1]	¹ Reclassified to conform with current presentation (see Notes C and E). 2017 revenue is presented net of $58.9 million of transportation, gathering and processing costs as historically shown prior to the adoption of ASC 606 on January 1, 2018. See Notes to Consolidated Financial Statements, page 58.
[2]	Reclassified to conform with current presentation (see Note E)

Financing Arrangements and Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Schedule of Long-term Debt

໿



	December 31,
(Thousands of dollars)	2019			2018
Notes payable
4.00% notes, due June 2022	$	260,251		500,000
4.45% notes, due December 2022 ¹	318,417			600,000
6.875% notes, due August 2024	550,000			550,000
5.75% notes, due August 2025	550,000			550,000
5.875% notes, due December 2027	550,000			—
7.05% notes, due May 2029	250,000			250,000
5.875% notes, due December 2042 ¹	350,000			350,000
Total notes payable	2,828,668			2,800,000
Unamortized debt issuance cost and discount on notes payable	(25,287		)	(23,627	)
Total notes payable, net of unamortized discount	2,803,381			2,776,373
Capitalized lease obligation, due through March 2029 ¹	—			8,613
Total debt including current maturities	2,803,381			2,784,986
Senior Unsecured Revolving Credit Facility	—			325,000
Current maturities ²	—			(668	)
Total long-term debt	$	2,803,381		3,109,318

¹ Coupon rate may fluctuate 25 basis points if rating is periodically downgraded or upgraded by S&P and Moody’s.

² Capitalized lease obligation and current maturities relate to a finance lease in Brunei, which is classified as held for sale as of December 31, 2019 (see Note E).

Accumulated Other Comprehensive Loss - Components of Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]

$ 5,197,642

^[1]

$ 4,620,191

19,336

(163,676)

16,290

16,132

35,626

(147,544)

$ 165,969

Foreign Currency Translation Gains (Losses)

5,804,611

5,197,642

^[1]

4,620,191

AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]

(419,852)

(274,830)

66,600

(145,022)

66,600

(145,022)

Retirement and Postretirement Benefit Plan Adjustments

(353,252)

(419,852)

(274,830)

AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]

(182,036)

(178,987)

(47,264)

(16,839)

11,285

13,790

(35,979)

(3,049)

Deferred Loss on Interest Rate Derivative Hedges

(218,015)

(182,036)

(178,987)

AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]

(7,899)

(8,426)

(1,815)

5,005

2,342

5,005

527

AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]

(2,894)

(7,899)

(8,426)

Total

(609,787)

(462,243)

Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent

(574,161)

(609,787)

$ (462,243)

AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]

Reclassifications before taxes, included in net periodic benefit expense

6,335

2,963

Reclassifications, income tax expense

1,330

622

Accumulated Defined Benefit Plans Adjustment Attributable to Parent

AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]

Reclassifications before taxes, included in net periodic benefit expense

14,380

17,313

Reclassifications, income tax expense

$ 3,095

$ 3,523

[1]	Reclassified to conform with current presentation (see Note E)

Supplemental Quarterly Information (Unaudited)

12 Months Ended

Dec. 31, 2019

Quarterly Financial Information Disclosure [Abstract]

Supplemental Quaterly Information



(Millions of dollars except per share amounts)	First Quarter			Second Quarter		Third Quarter	Fourth Quarter		Year
Year ended December 31, 2019
Revenue from contracts with customers	$	629.4		680.4		750.3	757.0		2,817.1
Income (loss) from continuing operations before income taxes	33.7			107.9		177.1	(115.3	)	203.5
Income (loss) from continuing operations	22.9			98.8		158.3	(91.3	)	188.8
Net income (loss) including noncontrolling interest	72.8			123.2		1,111.7	(54.4	)	1,253.3
Net income (loss) attributable to Murphy	40.2			92.3		1,089.0	(71.7	)	1,149.7
Income (loss) from continuing operations per Common share
Basic	(0.06		)	0.40		0.85	(0.71	)	0.52
Diluted	(0.06		)	0.40		0.84	(0.70	)	0.52
Net income (loss) per Common share
Basic	0.23			0.55		6.79	(0.71	)	7.01
Diluted	0.23			0.54		6.76	(0.47	)	6.98
Cash dividend per Common share	0.25			0.25		0.25	0.25		1.00
Year ended December 31, 2018
Revenue from contracts with customers	$	411.9		443.0		475.5	476.1		1,806.5
Income (loss) from continuing operations before income taxes	(21.1		)	(22.6	)	74.0	12.7		43.0
Income (loss) from continuing operations	90.6			(25.2	)	56.1	47.6		169.1
Net income including noncontrolling interest	168.3			45.5		93.9	111.8		419.5
Net income attributable to Murphy	168.3			45.5		93.9	103.4		411.1
Income (loss) from continuing operations per Common share
Basic	0.52			(0.14	)	0.32	0.23		0.92
Diluted	0.52			(0.15	)	0.32	0.22		0.92
Net income (loss) per Common share
Basic	0.97			0.27		0.54	0.60		2.38
Diluted	0.96			0.25		0.54	0.59		2.36
Cash dividend per Common share	0.25			0.25		0.25	0.25		1.00

Includes noncontrolling interest in MP GOM.

Financial Instruments and Risk Management - Recognized Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Not Designated as Hedging Instrument \| Commodity derivative contracts \| Gain (loss) on crude contracts
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ (856)	$ (41,975)	$ 9,566

Incentive Plans - Additional Information about Stock Options Outstanding (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options Outstanding, No. of Options	2,920,410
Options Outstanding, Avg. Life Remaining in Years	2 years
Options Outstanding, Aggregate Intrinsic Value	$ 5,365,535
Options Exercisable, No. of Options	(2,694,410)
Options Exercisable, Avg. Life Remaining in Years	1 year 9 months 18 days
Options Exercisable, Aggregate Intrinsic Value	$ 5,365,535
Range of Exercise Prices per Option, $17.00 to $30.00
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices per option, lower limit		$ 17
Range of exercise prices per option, upper limit		30
Options Outstanding, No. of Options	1,033,000
Options Outstanding, Avg. Life Remaining in Years	3 years 6 months
Options Outstanding, Aggregate Intrinsic Value	$ 5,365,535
Options Exercisable, No. of Options	(807,000)
Options Exercisable, Avg. Life Remaining in Years	3 years 4 months 24 days
Options Exercisable, Aggregate Intrinsic Value	$ 5,365,535
Range of Exercise Prices per Option, $31.00 to $50.00
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices per option, lower limit		31
Range of exercise prices per option, upper limit		50
Options Outstanding, No. of Options	730,000
Options Outstanding, Avg. Life Remaining in Years	2 years 1 month 6 days
Options Outstanding, Aggregate Intrinsic Value	$ 0
Options Exercisable, No. of Options	(730,000)
Options Exercisable, Avg. Life Remaining in Years	2 years 1 month 6 days
Options Exercisable, Aggregate Intrinsic Value	$ 0
Range of Exercise Prices per Option, $51.00 to $65.00
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices per option, lower limit		51
Range of exercise prices per option, upper limit		$ 65
Options Outstanding, No. of Options	1,157,410
Options Outstanding, Avg. Life Remaining in Years	6 months
Options Outstanding, Aggregate Intrinsic Value	$ 0
Options Exercisable, No. of Options	(1,157,410)
Options Exercisable, Avg. Life Remaining in Years	15 days
Options Exercisable, Aggregate Intrinsic Value	$ 0

Leases Summary of Lease Related Expenses (Details) - USD ($)
$ in Thousands

9 Months Ended

12 Months Ended

Sep. 30, 2019

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

^[1]

Interest on lease liabilities

Amortization of asset

$ 420

202

Sublease income

1,419

Net lease expense

400,764

Variable lease expenses primarily related to additional volumes processed at gas processing plant

$ 28,700

605,180

$ 353,832

^[1]

$ 299,420

232,736

205,192

^[1]

$ 207,391

Asset Retirement Obligation, Current

9,969,743

8,432,133

^[2]

39,315

$ 47,598

Property, plant and equipment

133,837

Asset retirement obligations

102,700

Asset Retirement Obligation, Current

3,024

3,000

249,787

Selling and general expense

56,300

12,325

4,300

Other operating expense

Schedule of Components of Income Tax Expense (Benefit)

$ 2,588

Other expense (benefit)

$ 2,600

[1]	¹ Reclassified to conform with current presentation (see Notes C and E). 2017 revenue is presented net of $58.9 million of transportation, gathering and processing costs as historically shown prior to the adoption of ASC 606 on January 1, 2018. See Notes to Consolidated Financial Statements, page 58.
[2]	Reclassified to conform with current presentation (see Note E)

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

The components of income (loss) from continuing operations before income taxes for each of the three years presented and income tax expense (benefit) attributable thereto were as follows.



(Thousands of dollars)	2019			2018		2017
Income (loss) from continuing operations before income taxes
United States	$	282,199		14,907		(299,349	)
Foreign	(78,701		)	28,095		16,465
Total	$	203,498		43,002		(282,884	)
Income tax expense (benefit)
U.S. Federal – Current	$	—		(9,765	)	—
– Deferred	30,598			(131,200	)	156,065
Total U.S. Federal	30,598			(140,965	)	156,065
State	5,139			3,299		4,230
Foreign – Current	(17,823		)	61,257		59
– Deferred	(3,231		)	(49,727	)	109,777
Total Foreign	(21,054		)	11,530		109,836
Total	$	14,683		(126,136	)	270,131

Effective Income Tax Rates

The following table reconciles income taxes based on the U.S. statutory tax rate to the Company’s income tax expense.



(Thousands of dollars)	2019			2018		2017
Income tax expense (benefit) based on the U.S. statutory tax rate	$	42,735		9,031		(98,868	)
Revaluation of deferred tax (U.S. tax reform)	—			—		118,004
Alberta tax rate reduction and tax impact of deemed repatriation of foreign invested earnings (U.S. tax reform)	(17,019		)	(135,700	)	156,000
Deferred tax effect on Canadian earnings no longer indefinitely invested	—			—		65,000
Foreign income (loss) subject to foreign tax rates different than the U.S.statutory rate	(1,122		)	5,822		2,032
State income taxes, net of federal benefit	4,060			2,607		2,438
U.S. tax benefit on certain foreign upstream investments	(14,975		)	(14,702	)	(32,926	)
Increase in deferred tax asset valuation allowance related to other foreign exploration expenditures	10,927			3,283		18,601
Tax effect on income attributable to noncontrolling interest	(21,750		)	(1,753	)	—
Other, net	11,827			5,276		39,850
Total	$	14,683		(126,136	)	270,131

Analysis of Deferred Tax Assets and Deferred Tax Liabilities Showing Tax Effects of Significant Temporary Differences

An analysis of the Company’s deferred tax assets and deferred tax liabilities at December 31, 2019 and 2018 showing the tax effects of significant temporary differences follows.



(Thousands of dollars)	2019			2018
Deferred tax assets
Property and leasehold costs	$	233,351		231,389
Liabilities for dismantlements	78,361			88,075
Postretirement and other employee benefits	125,250			113,826
Alternative minimum tax	9,765			9,765
U. S. net operating loss	495,252			496,629
Other deferred tax assets	66,795			19,974
Total gross deferred tax assets	1,008,774			959,658
Less valuation allowance	(103,113		)	(166,991	)
Net deferred tax assets	905,661			792,667
Deferred tax liabilities
Deferred tax on undistributed foreign earnings	(5,000		)	(5,000	)
Accumulated depreciation, depletion and amortization	(938,614		)	(710,384	)
Investment in partnership	(14,250		)	(32,178	)
Other deferred tax liabilities	(25,708		)	(28,802	)
Total gross deferred tax liabilities	(983,572		)	(776,364	)
Net deferred tax (liabilities) assets	$	(77,911	)	16,303

Reconciliation of Beginning and Ending Amount of Consolidated Liability for Unrecognized Income Tax Benefits

A reconciliation of the beginning and ending amount of the consolidated liability for unrecognized income tax benefits during the three years presented is shown in the following table.



(Thousands of dollars)	2019			2018		2017
Balance at January 1	$	2,903		3,437		7,417
Additions for tax positions related to current year	456			454		769
Settlements due to lapse of time	(821		)	(988	)	(4,834	)
Foreign currency translation effect	—			—		85
Balance at December 31	$	2,538		2,903		3,437

Income Taxes - Analysis of Deferred Tax Assets and Deferred Tax Liabilities Showing Tax Effects of Significant Temporary Differences (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Deferred tax assets
Property and leasehold costs	$ 233,351	$ 231,389
Liabilities for dismantlements	78,361	88,075
Postretirement and other employee benefits	125,250	113,826
Alternative minimum tax	9,765	9,765	$ 29,700
U. S. net operating loss	495,252	496,629
Other deferred tax assets	66,795	19,974
Total gross deferred tax assets	1,008,774	959,658
Less valuation allowance	(103,113)	(166,991)
Net deferred tax assets	905,661	792,667
Deferred tax liabilities
Deferred tax on undistributed foreign earnings	(5,000)	(5,000)	$ (65,000)
Accumulated depreciation, depletion and amortization	(938,614)	(710,384)
Deferred Tax Liabilities, Investments	(14,250)	(32,178)
Other deferred tax liabilities	(25,708)	(28,802)
Total gross deferred tax liabilities	(983,572)	(776,364)
Net deferred tax (liabilities) assets	$ (77,911)
Net deferred tax (liabilities) assets		$ 16,303

Employee and Retiree Benefit Plans - Amount Related to Foreign Benefit Plans (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at December 31		$ 547,484	$ 487,094
Foreign Plans
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at December 31		197,965	170,551
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	$ 883,269	777,645	881,932
Fair value of plan assets at December 31	547,484	487,094	563,825
Net plan liabilities recognized	(335,785)	(290,551)
Net periodic benefit expense (benefit)	25,150	28,840	24,102
Pension Benefits \| Foreign Plans
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31		209,923	173,860
Fair value of plan assets at December 31		197,965	170,551
Net plan liabilities recognized		(11,957)	3,309
Net periodic benefit expense (benefit)		(933)	3,983
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	108,401	94,779	106,276
Fair value of plan assets at December 31	0	0	0
Net plan liabilities recognized	(108,401)	(94,779)
Net periodic benefit expense (benefit)	$ 5,230	5,354	4,971
Other Postretirement Benefits \| Foreign Plans
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31		387	812
Fair value of plan assets at December 31		0	0
Net plan liabilities recognized		387	812
Net periodic benefit expense (benefit)		$ 147	$ 146

Discontinued Operations and Assets Held for Sale - Major Categories of Assets and Liabilities Reflected as Held for Sale (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Current liabilities

Total current liabilities associated with assets held for sale

$ 13,298

$ 286,458

^[1]

Non-current liabilities

Total non-current liabilities associated with assets held for sale

392,720

^[1]

Discontinued Operations, Held-for-sale or Disposed of by Sale

Current assets

Cash

25,185

44,669

Accounts receivable

4,834

103,158

Inventories

406

7,887

Prepaid expenses and other

1,882

18,151

Property, Plant, and Equipment, net

82,116

Deferred income taxes and other assets

9,441

Total current assets associated with assets held for sale

123,864

173,865

Non-current assets

Property, Plant, and Equipment, net

1,325,431

Deferred income taxes and other assets

219,577

Total non-current assets associated with assets held for sale

1,545,008

Current liabilities

Accounts payable

3,702

203,236

Other accrued liabilities

55,273

Current maturities of long-term debt (finance lease)

705

9,915

Taxes payable

1,411

18,034

Asset retirement obligation

240

Long-term debt (finance lease)

7,240

Total current liabilities associated with assets held for sale

13,298

286,458

Non-current liabilities

Long-term debt

117,816

Asset retirement obligation

274,904

Total non-current liabilities associated with assets held for sale

$ 392,720

Malaysia

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Gain (loss) on disposition of business

$ 985,400

[1]	Reclassified to conform with current presentation (see Note E)

Employee and Retiree Benefit Plans - Benefit Payments Expected to be Paid in Future Years (Details) $ in Thousands	Dec. 31, 2019 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2020	$ 42,399
2021	43,500
2022	44,824
2023	44,850
2024	45,557
2025-2030	233,751
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2020	5,233
2021	5,360
2022	5,428
2023	5,421
2024	5,505
2025-2030	$ 27,847

Acquisitions (Tables)

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

Preliminary Puchase Price Allocation

The following table contains the purchase price allocations at fair value:



(Thousands of dollars)	PAI (Final)			LLOG (Preliminary)
Cash consideration paid	$	780,678		$	1,238,353
Fair value of net assets contributed	154,468			—
Contingent consideration	52,540			89,444
NCI in acquired assets	246,922			—
Total purchase consideration	$	1,234,608		$	1,327,797
(Thousands of dollars)
Fair value of Property, plant and equipment	1,617,371			1,358,372
Other assets	5,628			6,697
Less: Asset retirement obligations	(388,391		)	(37,272		)
Total net assets	$	1,234,608		$	1,327,797

Pro Forma Financial Information

The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have occurred had the transaction taken place on January 1, 2018; furthermore, the financial information is not intended to be a projection of future results.



	Years Ended December 31,
(Thousands of dollars, except per share amounts)	2019		2018
Revenues	$	3,061,575	3,290,104
Net Income Attributable to Murphy	1,209,380		758,639

Net Income Attributable to Murphy per Common Share
Basic	$	7.37	4.39
Diluted	7.34		4.35

Business Segments (Tables)

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Segment Information



	Exploration and Production
(Millions of dollars)	United States ¹			Canada		Other		Total E&P		Corporate and Other			Discontinued Operations	Consolidated Total
Year ended December 31, 2019
Segment income (loss) - including NCI ¹	$	518.4		(4.3	)	(53.5	)	460.6		$	(271.8	)	1,064.5	1,253.3
Revenues from external customers	2,367.0			447.0		11.6		2,825.6		3.5			—	2,829.1
Interest and other income (loss)	(13.4		)	(1.5	)	(0.9	)	(15.8	)	(6.7		)	—	(22.5	)
Interest expense, net of capitalization	—			(0.1	)	(0.4	)	(0.5	)	(218.8		)	—	(219.3	)
Income tax expense (benefit)	115.6			(2.9	)	(12.4	)	100.3		(85.6		)	—	14.7
Significant noncash charges (credits)
Depreciation, depletion and amortization	878.7			243.0		3.5		1,125.2		22.6			—	1,147.8
Accretion of asset retirement obligations	34.4			6.1		—		40.5		—			—	40.5
Amortization of undeveloped leases	23.1			1.3		3.6		28.0		—			—	28.0
Deferred and noncurrent income taxes	111.8			14.0		(13.4	)	112.4		(83.9		)	—	28.5
Additions to property, plant, equipment	2,193.3			284.1		69.8		2,547.2		13.6			—	2,560.8
Total assets at year-end	8,043.3			2,303.7		308.6		10,655.6		1,046.2			16.7	11,718.5
Year ended December 31, 2018
Segment income (loss) - including NCI ¹	$	242.9		51.1		(16.6	)	277.4		$	(108.2	)	250.3	419.5
Revenues from external customers	1,332.7			470.5		22.2		1,825.4		(34.0		)	—	1,791.4
Interest and other income (loss)	—			—		—		—		7.8			—	7.8
Interest expense, net of capitalization	—			—		0.2		0.2		(180.6		)	—	(180.4	)
Income tax expense (benefit)	68.1			14.5		(25.3	)	57.3		(183.4		)	—	(126.1	)
Significant noncash charges (credits)
Depreciation, depletion and amortization	519.5			232.4		3.5		755.4		20.2			—	775.6
Accretion of asset retirement obligations	19.5			7.6		—		27.1		—			—	27.1
Amortization of undeveloped leases	36.8			0.8		2.5		40.1		—			—	40.1
Deferred and noncurrent income taxes	68.1			16.5		(25.7	)	58.9		(242.1		)	—	(183.2	)
Additions to property, plant, equipment	1,343.5			373.8		15.9		1,733.2		22.7			138.6	1,894.5
Total assets at year-end	6,342.9			1,711.9		188.1		8,242.9		1,118.5			1,691.2	11,052.6
Year ended December 31, 2017
Segment income (loss)	$	(8.9	)	112.5		(37.5	)	66.1		$	(619.1	)	241.2	(311.8	)
Revenues from external customers	944.3			485.5		—		1,429.8		14.2			—	1,444.0
Interest and other income (loss)	—			—		—		—		(78.3		)	—	(78.3	)
Interest expense, net of capitalization	—			—		—		—		(178.3		)	—	(178.3	)
Income tax expense (benefit)	(0.8		)	44.4		(36.2	)	7.4		262.7			—	270.1
Significant noncash charges (credits)
Depreciation, depletion and amortization	546.1			185.4		3.8		735.3		16.6			—	751.9
Accretion of asset retirement obligations	17.4			7.9		—		25.3		—			—	25.3
Amortization of undeveloped leases	60.2			1.6		—		61.8		—			—	61.8
Deferred and noncurrent income taxes	2.5			55.3		(36.2	)	21.6		242.5			—	264.1
Additions to property, plant, equipment	534.8			267.6		37.6		840.0		14.8			16.0	870.8
Total assets at year-end	5,186.2			1,725.8		154.2		7,066.2		1,101.7			1,693.0	9,860.9

¹2019 and 2018 include results attributable to a noncontrolling interest in MP GOM.



Geographic Information	Certain Long-Lived Assets at December 31
(Millions of dollars)	United States		Canada	Other	Total
2019	$	8,003.9	1,761.2	204.6	9,969.7
2018	6,634.3		1,644.6	153.2	8,432.1
2017	5,050.5		1,635.9	141.3	6,827.7



Geographic Information	Revenues from External Customers for the Year
(Millions of dollars)	United States		Canada	Other	Total
2019	$	2,370.4	447.1	11.6	2,829.1
2018	1,300.3		468.9	22.2	1,791.4
2017	958.3		485.7	—	1,444.0

Acquisitions - Narrative (Details)
$ in Thousands

1 Months Ended

3 Months Ended

7 Months Ended

9 Months Ended

12 Months Ended

13 Months Ended

Jun. 30, 2019

USD ($)

Dec. 31, 2018

USD ($)

MMBoe

Dec. 31, 2019

USD ($)

Sep. 30, 2019

USD ($)

Jun. 30, 2019

USD ($)

Mar. 31, 2019

USD ($)

Dec. 31, 2018

USD ($)

MMBoe

Sep. 30, 2018

USD ($)

Jun. 30, 2018

USD ($)

Mar. 31, 2018

USD ($)

Dec. 31, 2019

USD ($)

Sep. 30, 2019

USD ($)

Dec. 31, 2019

USD ($)

Dec. 31, 2018

USD ($)

MMBoe

Dec. 31, 2017

USD ($)

^[1]

Dec. 31, 2019

USD ($)

May 31, 2019

MMBoe

Revenue from sales to customers

$ 757,000

$ 750,300

$ 680,400

$ 629,400

$ 476,100

$ 475,500

$ 443,000

$ 411,900

$ 2,817,111

$ 1,806,473

^[1]

$ 1,300,464

Income (loss) from continuing operations before income taxes

(115,300)

$ 177,100

$ 107,900

$ 33,700

$ 12,700

$ 74,000

$ (22,600)

$ (21,100)

203,498

$ 43,002

^[1]

$ (282,884)

Acquisition-related costs

6,200

PAI (Final)

Percentage of interest in subsidiary transferred

$ 780,700

$ 780,678

20.00%

PAI (Final) | Sales Thresholds 2019 to 2025

LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C. [Member]

$ 150,000

150,000

$ 150,000

150,000

$ 150,000

150,000

Revenue from sales to customers

$ 1,238,400

1,238,353

$ 278,700

Income (loss) from continuing operations before income taxes

$ 60,100

LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C. [Member] | Sales Thresholds 2019 to 2025

LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C. [Member] | Net crude oil and condensate revenue

200,000

$ 50,000

MP Gulf of Mexico LLC

Parent ownership interest

80.00%

PAI (Final) | MP Gulf of Mexico LLC

Noncontrolling ownership interest

20.00%

[1]

Assets and Liabilities Measured at Fair Value - Narratives (Details)

12 Months Ended

Dec. 31, 2019

USD ($)

OffsettingPosition

Dec. 31, 2018

USD ($)

^[1],[2]

Dec. 31, 2017

USD ($)

^[1],[2]

Expected life

3 years

Number of offsetting positions | OffsettingPosition

Impairment of assets | $

$ 0

$ 20,000,000

$ 0

Contingent consideration

Expected life

6 years

Fair value, expected volatility rate

30.00%

Risk-free interest rate

1.66%

[1]	¹ Reclassified to conform with current presentation (see Notes C and E). 2017 revenue is presented net of $58.9 million of transportation, gathering and processing costs as historically shown prior to the adoption of ASC 606 on January 1, 2018. See Notes to Consolidated Financial Statements, page 58.
[2]	Reclassified to conform with current presentation (see Note E)

New Accounting Principles and Recent Accounting Pronouncements	12 Months Ended
	Dec. 31, 2019
Accounting Changes and Error Corrections [Abstract]
New Accounting Principles and Recent Accounting Pronouncements	New Accounting Principles and Recent Accounting Pronouncements Accounting Principles Adopted Leases. In February 2016, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) 2016-02 (Topic 842) to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous Generally Accepted Accounting Principles (GAAP) and this ASU is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. The company adopted the standard in the first quarter of 2019 utilizing the modified retrospective transition method through a cumulative-effect adjustment at the beginning of the first quarter of 2019. The Company has elected the package of practical expedients, which allows the Company not to reassess (1) whether any expired or existing contracts as of the adoption date are or contain a lease, (2) lease classification for any expired or existing leases as of the adoption date and (3) initial direct costs for any existing leases as of the adoption date. The Company did not elect to apply the hindsight practical expedient when determining lease term and assessing impairment of right-of-use assets. The adoption of ASU 2016-02 resulted in the initial recognition of right-of-use assets of $618.1 million, current lease liabilities for operating leases of approximately $155.5 million, non-current lease liabilities of $468.4 million and a cumulative-effect adjustment to credit retained earnings of $114.7 million on its Consolidated Balance Sheets, with no material impact to its Consolidated Statements of Operations. See Note V for further information regarding the impact of the adoption of ASU 2016-02 on the Company’s financial statements. Compensation – Stock Compensation. In June 2018, the FASB issued an ASU 2018-07 which supersedes existing guidance for equity-based payments to nonemployees and expands the scope of guidance for stock compensation to include all share-based payment arrangements related to the acquisition of goods and services from both nonemployees and employees. As a result, the same guidance that provides for employee share-based payments, including most of its requirements related to classification and measurement, applies to nonemployee share-based payment arrangements. The Company adopted this guidance during the first quarter of 2019 and it did not have material impact on its consolidated financial statements. In May 2017, the FASB issued ASU 2017-9 which amends the scope of modification accounting for share-based payment arrangements and provides guidance on the type of changes to the terms and conditions of share-based payment awards to which an entity would be required to apply modification accounting. The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period. The Company adopted this accounting standard in the first quarter of 2018 and it did not have a material impact on its consolidated financial statements. Compensation-Retirement Benefits-Defined Benefit Plans-General. In March 2017, the FASB issued ASU 2017-7 requiring that the service cost component of pension and postretirement benefit costs be presented in the same line item as other current employee compensation costs and other components of those benefit costs be presented separately from the service cost component outside a subtotal of income from operations, if presented. The update also requires that only the service cost component of pension and postretirement benefit cost is eligible for capitalization. The update is effective for annual and interim periods beginning after December 15, 2017. The Company elected to apply the practical expedient, which allows us to reclassify amounts disclosed previously in the retirement benefits note as the basis for applying retrospective presentation for comparative periods. The Company adopted the standard in the first quarter of 2018 and it did not have a material impact on its consolidated financial statements. Revenue from Contracts with Customers. In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-9, which established a comprehensive model of accounting for revenue arising from contracts with customers that superseded most revenue recognition requirements and industry-specific guidance. Under the new standard, the Company recognizes revenue when it transfers control of the commodity to customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for the commodity. Additional disclosures are required to describe the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers. The Company adopted the new standard in the first quarter of 2018 using the modified retrospective method. The Company performed a review of contracts in each of its revenue streams and implemented accounting policies and internal controls to address the requirements of the ASU. Prior to January 1, 2018, the Company followed the sales method of revenue recognition under Accounting Standards Codification (ASC) Topic 605 - Revenue Recognition, and recorded revenue when deliveries occurred, and legal ownership of the commodity transferred to the customer. There was no adjustment to the opening balance of stockholders’ equity as at January 1, 2018, resulting from the application of the new ASU promulgated in ASC Topic 606 using the modified retrospective method. The 2017 information has not been adjusted and continues to be reported under ASC Topic 605 – Revenue Recognition. See also Note C for further discussion of Revenue Recognition. Statement of Cash Flows. In August 2016, the FASB issued ASU 2016-15 to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The amendment provides guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instrument with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees. The amendments in this ASU were effective for annual and interim periods beginning after December 15, 2017. The Company adopted this guidance in the first quarter of 2018 and it did not have a material impact on its consolidated financial statements. Statement of Operations – Reporting Comprehensive Income. In February 2018, the FASB issued ASU 2018-2, which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. The Company elected to early adopt this accounting standard during the first quarter of 2018 and recorded discrete adjustments from accumulated other comprehensive income to retained earnings of $28.4 million related to retirement and postretirement obligations and $1.8 million related to the deferred loss on interest rate derivative hedges. The adoption of this ASU will have no future impact. SEC Disclosures Update and Simplification. In August 2018, the U.S. Securities and Exchange Commission (SEC) adopted the final rule under SEC Release No. 33-10532 Disclosure Update and Simplification, to eliminate or modify certain disclosure rules that are redundant, outdated, or duplicative of U.S. GAAP or other regulatory requirements. Among other changes, the amendments eliminated the annual requirement to disclose the high and low trading prices of our common stock and the ratio of earnings to fixed charges. In addition, the amendments provide that disclosure requirements related to the analysis of shareholders’ equity are expanded for interim financial statements. An analysis of the changes in each caption of shareholders’ equity presented in the balance sheet must be provided in a note or separate statement, as well as the amount of dividends per share for each class of shares. This rule was effective on November 5, 2018; and the expanded interim disclosure requirements for changes in shareholders’ equity was effective for the Company for our quarterly reporting beginning March 31, 2019. Recent Accounting Pronouncements Financial Instruments – Credit Losses. In June 2016, the FASB issued ASU 2016-13 which replaces the impairment model for most financial assets, including trade receivables, from the incurred loss methodology to a forward-looking expected loss model that will result in earlier recognition of credit losses. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. The Company adopted this accounting standard in the first quarter of 2020 and it did not have a material impact on its consolidated financial statements. Fair Value Measurement. In August 2018, the FASB issued ASU 2018-13 which modifies disclosure requirements related to fair value measurement. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Implementation on a prospective or retrospective basis varies by specific disclosure requirement. Early adoption is permitted. The standard also allows for early adoption of any removed or modified disclosures upon issuance of this ASU while delaying adoption of the additional disclosures until their effective date. The Company adopted this accounting standard in the first quarter of 2020 and it did not have a material impact on its consolidated financial statements. Income Taxes. In December 2019, the FASB issued ASU 2019-12, which removes certain exceptions for investments, intraperiod allocations and interim calculations, and adds guidance to reduce complexity in accounting for income taxes. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. Implementation on a prospective or retrospective basis varies by specific topics within the ASU. Early adoption is permitted. The Company is currently assessing the potential impact of this ASU to its consolidated financial statements. Compensation-Retirement Benefits-Defined Benefit Plans-General. In August 2018, the FASB issued ASU 2018-14 which modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. For public companies, the amendments in this ASU are effective for fiscal years beginning after December 15, 2020, with early adoption permitted, and is to be applied on a retrospective basis to all periods presented. The Company is currently assessing the potential impact of this ASU to its consolidated financial statements.

Discontinued Operations and Assets Held for Sale (Tables)

12 Months Ended

Dec. 31, 2019

Discontinued Operations and Disposal Groups [Abstract]

Major Categories of Assets and Liabilities Reflected as Held for Sale



(Thousands of dollars)	2019		2018
Current assets
Cash	$	25,185	44,669
Accounts receivable	4,834		103,158
Inventories	406		7,887
Prepaid expenses and other	1,882		18,151
Property, Plant, and Equipment, net	82,116		—
Deferred income taxes and other assets	9,441		—
Total current assets associated with assets held for sale	123,864		173,865
Non-current assets
Property, Plant, and Equipment, net	—		1,325,431
Deferred income taxes and other assets	—		219,577
Total non-current assets associated with assets held for sale	—		1,545,008
Current liabilities
Accounts payable	3,702		203,236
Other accrued liabilities	—		55,273
Current maturities of long-term debt (finance lease)	705		9,915
Taxes payable	1,411		18,034
Asset retirement obligation	240		—
Long-term debt (finance lease)	7,240		—
Total current liabilities associated with assets held for sale	13,298		286,458
Non-current liabilities
Long-term debt	—		117,816
Asset retirement obligation	—		274,904
Total non-current liabilities associated with assets held for sale	$	—	392,720

Results of Operations Associated with Discontinued Operations

The results of operations associated with discontinued operations are presented in the following table.



(Thousands of dollars)	2019		2018	2017
Revenues ¹	$	1,364,943	854,251	781,995
Costs and expenses
Lease operating expense	127,138		202,062	168,903
Depreciation, depletion and amortization	33,697		196,287	205,841
Other costs and expenses (benefits)	81,538		70,088	53,409
Total income from discontinued operations before taxes	1,122,570		385,814	353,842
Income tax expense	58,083		135,466	112,616
Income from discontinued operations	$	1,064,487	250,348	241,226

¹ 2019 includes a $985.4 million gain on sale of the Malaysia operations.

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($)
$ in Thousands

Dec. 31, 2019

Dec. 31, 2018

$ 19,303,389

$ 16,502,620

Exploration and Production

9,969,743

8,432,133

^[1]

19,096,323

16,309,149

9,875,727

8,329,514

Corporate and other

207,066

193,471

94,016

102,619

Mineral Rights

508,526

512,025

Administrative Assets and Support Equipment

121,163

144,912

$ 24,698

$ 27,915

[1]	Reclassified to conform with current presentation (see Note E)

Acquisitions - Pro Forma Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Pro Forma Financial Information
Revenues	$ 3,061,575
Net Income Attributable to Murphy	$ 1,209,380
Net Income Attributable to Murphy per Common Share
Basic (in USD per share)	$ 7.37
Diluted (in USD per share)	$ 7.34
PAI (Final)
Pro Forma Financial Information
Revenues		$ 3,290,104
Net Income Attributable to Murphy		$ 758,639
Net Income Attributable to Murphy per Common Share
Basic (in USD per share)		$ 4.39
Diluted (in USD per share)		$ 4.35

Leases Schedule of Maturity of Lease Liabilities (Details) $ in Thousands	Dec. 31, 2019 USD ($)
Leases, Operating [Abstract]
2020	$ 124,267
2021	74,978
2022	56,756
2023	54,986
2024	50,640
Remaining	493,833
Total future minimum lease payments	855,460
Less imputed interest	241,850
Present value of lease liabilities	613,610
Finance Lease, Cost [Abstract]
2020	1,069
2021	1,069
2022	1,069
2023	1,069
2024	1,069
Remaining	4,541
Total future minimum lease payments	9,886
Less imputed interest	1,941
Present value of lease liabilities	7,945
2020	125,336
2021	76,047
2022	57,825
2023	56,055
2024	51,709
Remaining	498,374
Total future minimum lease payments	865,346
Less imputed interest	243,791
Present value of lease liabilities	621,555
Minimum lease payments for leases signed but not yet commenced	$ 278,700
Lease duration of leases signed but not yet commenced	20 years

Leases (Notes)

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Leases

Nature of Leases

The Company has entered into various operating leases such as a natural gas processing plant, floating production storage and off-take vessels, buildings, marine vessels, vehicles, drilling rigs, pipelines and other oil and gas field equipment. Remaining lease terms range from 1 year to 20 years, some of which may include options to extend leases for multi-year periods and others which include options to terminate the leases within 1 month. Options to extend lease terms are at the Company’s discretion. Early lease terminations are a combination of both at Company discretion and mutual agreement between the Company and lessor. Purchase options also exist for certain leases.

Related Expenses

Expenses related to finance and operating leases included in the Consolidated Financial Statements are as follows:



(Thousands of dollars)	Financial Statement Category	Year Ended December 31, 2019
Operating lease ^1,2	Lease operating expenses	$	249,787
Operating lease ²	Selling and general expense	12,325
Operating lease ²	Other operating expense	2,588
Operating lease ²	Property, plant and equipment	133,837
Operating lease ²	Asset retirement obligations	3,024
Finance lease
Amortization of asset	Depreciation, depletion and amortization	420
Interest on lease liabilities	Interest expense, net	202
Sublease income	Other income	(1,419		)
Net lease expense		$	400,764

¹ For the year ended December 31, 2019, includes variable lease expenses of $28.7 million, primarily related to additional volumes processed at a natural gas processing plant.

Maturity of Lease Liabilities໿



(Thousands of dollars)	Operating Leases ¹			Finance Leases		Total
2020	$	124,267		1,069		125,336
2021	74,978			1,069		76,047
2022	56,756			1,069		57,825
2023	54,986			1,069		56,055
2024	50,640			1,069		51,709
Remaining	493,833			4,541		498,374
Total future minimum lease payments	855,460			9,886		865,346
Less imputed interest	(241,850		)	(1,941	)	(243,791	)
Present value of lease liabilities²	$	613,610		7,945		621,555

Lease Term and Discount Rate



	December 31, 2019
Weighted average remaining lease term:
Operating leases	10 years
Finance leases	9 years
Weighted average discount rate:
Operating leases	4.7	%
Finance leases	4.7	%

Other Information໿



(Thousands of dollars)	Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	193,968
Operating cash flows from finance leases	408
Financing cash flows from finance leases	688
Right-of-use assets obtained in exchange for lease liabilities:
Operating leases	$	125,026

Assets and Liabilities Measured at Fair Value - Carrying Value of Assets and Liabilities Recorded at Fair Value on Recurring Basis (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	$ 0	$ 3,837
Liabilities	197,186	61,575
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	0
Liabilities	17,035	13,845
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	3,837
Liabilities	33,364	0
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	0
Liabilities	146,787	47,730
Nonqualified employee savings plans
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nonqualified employee savings plans	17,035	13,845
Nonqualified employee savings plans \| Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nonqualified employee savings plans	17,035	13,845
Nonqualified employee savings plans \| Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nonqualified employee savings plans	0	0
Nonqualified employee savings plans \| Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Nonqualified employee savings plans	0	0
Commodity derivative contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	3,837
Commodity derivative contracts	33,364
Commodity derivative contracts \| Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	0
Commodity derivative contracts	0
Commodity derivative contracts \| Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	3,837
Commodity derivative contracts	33,364
Commodity derivative contracts \| Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	0
Commodity derivative contracts	0
Contingent consideration
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Contingent consideration	146,787	47,730
Contingent consideration \| Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Contingent consideration	0	0
Contingent consideration \| Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Contingent consideration	0	0
Contingent consideration \| Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Contingent consideration	$ 146,787	$ 47,730

Acquisitions

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Acquisitions

PAI Transaction:

In December 2018, the Company announced the completion of a transaction with Petrobras Americas Inc. (PAI) which was effective October 1, 2018. Through this transaction, Murphy acquired all of PAI’s producing Gulf of Mexico assets along with certain blocks that hold deep exploration rights. This transaction added approximately 97 MMBOE (including noncontrolling interest, NCI) of proven reserves at December 31, 2018.

Under the terms of the transaction, Murphy paid cash consideration of $780.7 million, after adjustments provided for in the sale and purchase agreement, and transferred a 20% interest in MP Gulf of Mexico, LLC (MP GOM), a subsidiary of Murphy, to PAI. Murphy also has an obligation to pay additional contingent consideration up to $150 million if certain sales thresholds are exceeded beginning in 2019 through 2025 (see Note Q for the contingent consideration liability balance as of December 31, 2019 and 2018 for the remainder of the covered periods). The revenue threshold was not exceeded in 2019 and no contingent consideration is payable related to the 2019 period. Both companies contributed all of their then-currently producing Gulf of Mexico assets into MP GOM. MP GOM is owned 80% by Murphy and 20% by PAI, with Murphy overseeing the operations.

LLOG Transaction:

Under the terms of the transaction, Murphy paid cash consideration of $1,238.4 million and has an obligation to pay additional contingent consideration of up to $200 million in the event that certain revenue thresholds are exceeded between 2019 and 2022, and $50 million following first oil from certain development projects (see Note Q for the contingent consideration liability balance as of December 31, 2019 and 2018 for the remainder of the covered periods). The revenue threshold was not exceeded in 2019 and no contingent consideration is payable related to the 2019 period.

The following table contains the purchase price allocations at fair value:



(Thousands of dollars)	PAI (Final)			LLOG (Preliminary)
Cash consideration paid	$	780,678		$	1,238,353
Fair value of net assets contributed	154,468			—
Contingent consideration	52,540			89,444
NCI in acquired assets	246,922			—
Total purchase consideration	$	1,234,608		$	1,327,797
(Thousands of dollars)
Fair value of Property, plant and equipment	1,617,371			1,358,372
Other assets	5,628			6,697
Less: Asset retirement obligations	(388,391		)	(37,272		)
Total net assets	$	1,234,608		$	1,327,797

The fair value measurements of crude oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert expected future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) proved and probable reserves; (ii) production rates and related development timing; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average discount rate. These inputs require significant judgments and estimates by management at the time of the valuation, are sensitive, and may be subject to change.

Certain data necessary to complete the LLOG purchase price allocation is not yet available, and includes, but is not limited to, analysis of the underlying tax basis of the assets acquired and liabilities assumed as well as the final purchase price adjustments to be settled in 2020. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities may be revised as appropriate.

Results of Operations

Murphy’s Consolidated Statement of Operations for the year ended December 31, 2019, included additional revenues of $278.7 million and pre-tax income of $60.1 million attributable to the acquired LLOG assets.

Pro Forma Financial Information

The following pro forma condensed combined financial information was derived from historical financial statements of Murphy, PAI and LLOG and gives effect to the transaction as if it had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including depletion of LLOG fair-valued proved crude oil and natural gas properties. The pro forma condensed combined financial information was also adjusted to exclude acquisition-related costs of $6.2 million incurred by Murphy. The pro forma results of operations do not include any cost savings or other synergies that we expect to realize from the transaction or any estimated costs that have been or will be incurred by us to integrate the PAI or LLOG assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have occurred had the transaction taken place on January 1, 2018; furthermore, the financial information is not intended to be a projection of future results.



	Years Ended December 31,
(Thousands of dollars, except per share amounts)	2019		2018
Revenues	$	3,061,575	3,290,104
Net Income Attributable to Murphy	1,209,380		758,639

Net Income Attributable to Murphy per Common Share
Basic	$	7.37	4.39
Diluted	7.34		4.35

Incentive Plans (Tables)

12 Months Ended

Dec. 31, 2019

Share-Based Plans, Amounts Recognized

Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:



(Thousands of dollars)	2019		2018	2017
Compensation charged against income (loss) before income tax benefit	$	50,170	34,467	40,365
Related income tax benefit recognized in income	7,389		4,383	5,017

Fair Value of Option Award Estimated on Date of Grant using Black-Scholes Pricing Model



	2019	2018	2017
Fair value per option grant	N/A	N/A	$7.96
Assumptions
Dividend yield	N/A	N/A	3.60%
Expected volatility	N/A	N/A	41.00%
Risk-free interest rate	N/A	N/A	1.97%
Expected life	N/A	N/A	5.30 years

Changes in Stock Options Outstanding

Changes in stock options outstanding during the last three years are presented in the following table.



	Number of Shares		Average Exercise Price
Outstanding at December 31, 2016	5,757,435		$	48.46
Granted at FMV	603,000		28.51
Exercised	—		—
Forfeited	(1,459,166	)	49.34
Outstanding at December 31, 2017	4,901,269		45.74
Granted at FMV	—		—
Exercised	(72,000	)	17.57
Forfeited	(834,674	)	53.36
Outstanding at December 31, 2018	3,994,595		44.66
Granted at FMV	—		—
Exercised	(57,500	)	17.57
Forfeited	(1,016,685	)	48.29
Outstanding at December 31, 2019	2,920,410		43.93
Exercisable at December 31, 2016	3,830,535		$	53.80
Exercisable at December 31, 2017	3,197,269		54.22
Exercisable at December 31, 2018	3,182,345		49.10
Exercisable at December 31, 2019	2,694,410		43.51

Additional Information about Stock Options Outstanding

Additional information about stock options outstanding at December 31, 2019 is shown below.



	Options Outstanding				Options Exercisable
Range of Exercise Prices per Option	No. of Options	Avg. Life Remaining in Years	Aggregate Intrinsic Value		No. of Options	Avg. Life Remaining in Years	Aggregate Intrinsic Value
$17.00 to $30.99	1,033,000	3.5	$	5,365,535	807,000	3.4	$	5,365,535
$31.00 to $50.99	730,000	2.1	—		730,000	2.1	—
$51.00 to $65.00	1,157,410	0.5	—		1,157,410	0.5	—
	2,920,410	2.0	$	5,365,535	2,694,410	1.8	$	5,365,535

Changes in Performance-Based RSU Outstanding

Changes in PSUs outstanding for each of the last three years are presented in the following table.



(Number of stock units)	2019		2018		2017
Outstanding at beginning of year	1,660,417		1,187,921		992,573
Granted	957,600		905,500		560,000
Vested and issued	(331,917	)	(311,866	)	(272,725	)
Forfeited	(156,367	)	(121,138	)	(91,927	)
Outstanding at end of year	2,129,733		1,660,417		1,187,921

Assumptions used in Valuation of Performance Awards Granted

The assumptions used in the valuation of the performance awards granted in 2019, 2018 and 2017 are presented in the following table.



	2019	2018	2017
Fair value per share at grant date	$28.09	$22.99 - $30.56	$24.10 – $28.28
Assumptions
Expected volatility	46.00%	48.00%	47.00%
Risk-free interest rate	2.50%	2.30%	1.46%
Stock beta	1.037	1.103	1.058
Expected life	3.0 years	3.0 years	3.0 years

Changes in Time-Lapse Restricted Stock and Restricted Stock Units Outstanding

Changes in RSUs outstanding for each of the last three years are presented in the following table.



(Number of share units)	2019		2018		2017
Outstanding at beginning of year	1,538,854		1,035,980		923,282
Granted	409,692		823,803		419,720
Vested and issued	(275,738	)	(233,456	)	(217,633	)
Forfeited	(137,728	)	(87,473	)	(89,389	)
Outstanding at end of year	1,535,080		1,538,854		1,035,980

Employee and Retiree Benefit Plans - Amounts Included in Accumulated Other Comprehensive Income Not Recognized in Net Periodic Benefit Expense (Details) $ in Thousands	Dec. 31, 2019 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial gain (loss)	$ (269,391)
Prior service cost	(4,090)
Amounts included in accumulated other comprehensive loss which have not been recognized in net periodic benefit expense	(273,481)
Other Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net actuarial gain (loss)	3,307
Prior service cost	0
Amounts included in accumulated other comprehensive loss which have not been recognized in net periodic benefit expense	$ 3,307

Asset Retirement Obligations - Schedule of Reconciliation of Beginning and Ending Aggregate Carrying Amount of Asset Retirement Obligations (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Liabilities assumed from acquisitions

$ 800,117

$ 447,270

Accretion expense

40,506

27,119

^[1],[2]

$ 25,282

^[1],[2]

Liabilities incurred

14,759

6,572

64,810

359,643

Revisions of previous estimates

(34,371)

(20,012)

Liabilities settled

(25,544)

(11,510)

Liabilities associated with assets held for sale

(240)

Changes due to translation of foreign currencies

5,072

(8,965)