View Filing Data

2,570,603,000

2,225,129,000

^[1]

1,811,238,000

Costs and Expenses

555,894,000

468,323,000

^[1]

559,360,000

Exploration expenses, including undeveloped lease amortization

52,072,000

43,618,000

^[1]

43,826,000

103,977,000

122,834,000

^[1]

101,861,000

216,024,000

203,573,000

^[1]

246,277,000

971,901,000

957,719,000

^[1]

1,054,081,000

20,000,000

95,088,000

11,332,000

15,000,000

^[1]

39,100,000

44,559,000

42,590,000

^[1]

46,742,000

Other (income) expense

(34,873,000)

30,706,000

^[1]

13,806,000

Operating income (loss) from continuing operations

1,940,886,000

1,884,363,000

^[1]

2,200,141,000

629,717,000

340,766,000

^[1]

(388,903,000)

Other income (loss)

Interest and other income (loss)

(15,775,000)

(87,181,000)

^[1]

43,958,000

Interest expense, net

(181,604,000)

(181,783,000)

^[1]

(148,170,000)

Total other loss

(197,379,000)

(268,964,000)

^[1]

(104,212,000)

Income (loss) from continuing operations before income taxes

432,338,000

71,802,000

^[1]

(493,115,000)

Income (loss) from continuing operations

9,330,000

382,738,000

^[1]

(219,172,000)

423,008,000

(310,936,000)

^[1]

(273,943,000)

Loss from discontinued operations, net of income taxes

(3,522,000)

(853,000)

^[1]

(2,027,000)

Net income (loss) including noncontrolling interest

419,486,000

(311,789,000)

^[1]

(275,970,000)

Less: Net income attributable to noncontrolling interest

8,392,000

NET INCOME (LOSS) ATTRIBUTABLE TO MURPHY

$ 411,094,000

$ (311,789,000)

^[1]

$ (275,970,000)

INCOME (LOSS) PER COMMON SHARE - BASIC

Continuing operations

$ 2.39

$ (1.81)

^[1]

$ (1.59)

Discontinued operations

(0.01)

Net income (loss)

2.38

(1.81)

^[1]

(1.60)

INCOME (LOSS) PER COMMON SHARE - DILUTED

Continuing operations

2.37

(1.81)

^[1]

(1.59)

Discontinued operations

(0.01)

Net income (loss)

2.36

(1.81)

^[1]

(1.60)

Cash dividends per Common share

$ 1.00

^[1]

$ 1.20

Average Common shares outstanding

Basic

172,974,491

172,524,061

^[1]

172,173,012

Diluted

174,208,765

172,524,061

^[1]

172,173,012

[1]	Reclassified to conform to current presentation (see Note B).

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract]

Net income (loss) including noncontrolling interest

$ 419,486

$ (311,789)

^[1]

$ (275,970)

^[1]

Other comprehensive income (loss), net of tax

Net gain (loss) from foreign currency translation

(145,022)

171,725

66,449

Retirement and postretirement benefit plans

29,110

(7,682)

7,955

Deferred loss on interest rate hedges reclassified to interest expense

2,342

1,926

Reclassification of certain tax effects to retained earnings

(30,237)

Other comprehensive income (loss)

(3,737)

(147,544)

165,969

76,330

COMPREHENSIVE INCOME (LOSS)

$ 271,942

$ (145,820)

$ (199,640)

[1]	Reclassified to conform to current presentation (see Note B).

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Operating Activities

Net income (loss) including noncontrolling interest

$ 419,486,000

$ (311,789,000)

^[1]

$ (275,970,000)

^[1]

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

Loss from discontinued operations

3,522,000

853,000

^[1]

2,027,000

^[1]

971,901,000

957,719,000

^[1]

1,054,081,000

^[1]

Amortization of deferred major repair costs

20,000,000

95,088,000

^[1]

3,794,000

Dry hole costs (credits)

20,624,000

(4,163,000)

15,047,000

40,177,000

61,776,000

43,417,000

Deferred income tax expense (benefit)

44,559,000

42,590,000

^[1]

46,742,000

^[1]

(183,680,000)

260,420,000

(387,843,000)

Pretax gains from disposition of assets

(54,000)

(127,434,000)

(1,663,000)

Net (increase) decrease in noncash operating working capital

(169,808,000)

136,414,000

(38,689,000)

Other operating activities, net

52,669,000

111,689,000

44,764,000

Net cash provided by continuing operations activities

1,219,396,000

1,128,075,000

600,795,000

Investing Activities

Acquisition of oil properties

(794,623,000)

Property additions and dry hole costs

(1,102,805,000)

(1,009,667,000)

(926,948,000)

Proceeds from sales of property, plant and equipment

1,383,000

69,506,000

1,155,144,000

Purchase of investment securities

^[2]

(212,661,000)

(695,879,000)

Proceeds from maturity of investment securities

^[2]

320,828,000

761,000,000

Other investing activities, net

(7,230,000)

Net cash provided (required) by investing activities

(1,896,045,000)

(831,994,000)

286,087,000

Financing Activities

Borrowings of debt

325,000,000

541,597,000

541,444,000

Repayments of debt

(550,000,000)

(600,000,000)

Capital lease obligation payments

(9,750,000)

(17,133,000)

(10,447,000)

Issue cost of debt facility

(6,366,000)

(14,085,000)

Cash dividends paid

(173,044,000)

(172,565,000)

(206,635,000)

Other financing activities, net

(8,076,000)

(7,116,000)

(1,158,000)

Net cash required by financing activities

127,764,000

(205,217,000)

(290,881,000)

Effect of exchange rate changes on cash and cash equivalents

(28,730,000)

1,327,000

(6,387,000)

Net increase (decrease) in cash and cash equivalents

(577,615,000)

92,191,000

589,614,000

Cash and cash equivalents at beginning of period

964,988,000

872,797,000

283,183,000

Cash and cash equivalents at end of period

$ 387,373,000

$ 964,988,000

$ 872,797,000

[1]	Reclassified to conform to current presentation (see Note B).
[2]	Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical)	12 Months Ended
CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical)	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
CONSOLIDATED STATEMENTS OF CASH FLOWS [Abstract]
Maturity of Canadian government securities	90 days	90 days	90 days

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

Cumulative Preferred Stock [Member]

Common Stock [Member]

Capital In Excess Of Par Value [Member]

Retained Earnings [Member]

Accumulated Other Comprehensive Loss [Member]

Treasury Stock [Member]

Parent [Member]

Noncontrolling Interest [Member]

Total

Balance at beginning of year at Dec. 31, 2015

$ 195,056

$ 910,074

$ 6,212,201

$ (704,542)

$ (1,306,061)

Exercise of stock options, inlcuding income tax benefits

(12,017)

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

66,449

$ 66,449

Net income (loss) for the year attributable to Murphy

(275,970)

^[1]

Restricted stock transactions and other

(10,078)

Cash dividends

(206,635)

Retirement and postretirement benefit plans, net of income taxes

7,955

Sale of stock under employee stock purchase plans

509

Stock-based compensation

29,119

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

(299)

1,926

Awarded restricted stock

8,992

Balance at end of year at Dec. 31, 2016

195,056

916,799

5,729,596

(628,212)

(1,296,560)

$ 4,916,679

4,916,679

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

171,725

Net income (loss) for the year attributable to Murphy

(311,789)

^[1]

Restricted stock transactions and other

(26,553)

Cash dividends

(172,565)

Retirement and postretirement benefit plans, net of income taxes

(7,682)

Sale of stock under employee stock purchase plans

146

Stock-based compensation

27,496

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

(77)

1,926

Awarded restricted stock

20,885

Balance at end of year at Dec. 31, 2017

195,056

917,665

5,245,242

(462,243)

(1,275,529)

4,620,191

Exercise of stock options, inlcuding income tax benefits

(362)

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

(145,022)

Acquisition

$ 359,951

Net income (loss) for the year attributable to Murphy

411,094

8,392

411,094

Distributions to noncontrolling Interest Owners

Reclassification of certain tax effects from accumulated other comprehensive loss

30,237

(30,237)

Restricted stock transactions and other

(3,737)

(33,920)

Cash dividends

(173,044)

Retirement and postretirement benefit plans, net of income taxes

29,110

Stock-based compensation

27,920

Fair value increase in common controlled assets

68,339

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

2,342

Awarded restricted stock

26,367

Balance at end of year at Dec. 31, 2018

$ 195,077

$ 979,642

$ 5,513,529

$ (609,787)

$ (1,249,162)

$ 4,829,299

$ 368,343

$ 5,197,642

[1]	Reclassified to conform to current presentation (see Note B).

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY [Abstract]
Cumulative Preferred Stock, par value (per share)	$ 100	$ 100	$ 100
Cumulative Preferred Stock, authorized shares	400,000	400,000	400,000
Cumulative Preferred Stock, shares issued	0	0	0
Common Stock, par value (per share)	$ 1.00	$ 1.00	$ 1.00
Common Stock, authorized shares	450,000,000	450,000,000	450,000,000
Common Stock, shares issued	195,076,924	195,055,724	195,055,724
Treasury stock, shares	22,018,095	22,482,851	22,853,547

Significant Accounting Policies	12 Months Ended
Significant Accounting Policies	Dec. 31, 2018
Significant Accounting Policies [Abstract]
Significant Accounting Policies	These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 55-59 of the Form 10-K report. Note A – Significant Accounting Policies NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries. The Company primarily produces oil and natural gas in the United States, Canada and Malaysia and conducts oil and natural gas exploration activities worldwide. The Company sold its interest in a Canadian synthetic oil operation in 2016 and its Canadian heavy oil assets in early 2017. 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 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 the new Gulf of Mexico transaction (MP GOM) with Petrobras Americas Inc (PAI), 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. Beginning in 2017, certain reclassifications in presentation have been made to the Consolidated Statements of Operations. The Company now presents a separate “Operating income (loss) from continuing operations” subtotal on the Consolidated Statements of Operations. Additionally, “Interest and other income (loss),” which includes foreign exchange gains and losses, has been reclassified from a component of total revenues and is now presented below Operating income (loss) from continuing operations. “Interest expense” and “Capitalized interest” have also been combined into the “Interest expense, net” line item and are now presented below “Operating income (loss) from continuing operations.” Previously reported periods have been reclassified to conform to the current period presentation. These reclassifications did not impact previously reported Income (loss) from continuing operations before income taxes, Loss from continuing operations, or Net Loss. 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. Revenue is presented as the Company’s share net of certain costs associated with generation of Revenue. Examples of costs that reduce revenue include transportation, gathering, compression, and processing fees in U.S. and Canada, as well as certain required payments associated with production sharing contracts (PSCs) and export taxes in Malaysia. Natural gas imbalances occur when the Company’s actual 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 gas imbalances when it has sold more than its working interest of gas production and the estimated remaining reserves make it doubtful that partners can recoup their share of production from the field. At December 31, 2018 and 2017, 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. Note A – Significant Accounting Policies (Contd.) 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, 2018 and 2017, 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 gas production operations. Unsold crude oil production is carried in inventory at the lower of cost, generally applied on a first-in, first-out (FIFO) basis, or market, and includes costs incurred to bring the inventory to its existing condition. Materials and supplies inventories are valued at the lower of average cost or estimated 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 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 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. 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. In 2016, charges of $95.1 million at its Terra Nova field offshore Canada and its Western Canada onshore heavy oil producing properties were reported. 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 gas production facilities and site restoration are charged against the related liability. Note A – Significant Accounting Policies (Contd.) 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 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. Additionally, certain natural gas processing facilities and related equipment in Malaysia are being depreciated on a straight-line basis over their estimated useful life ranging from 20 to 25 years. Capitalized Interest – Interest associated with borrowings from third parties is capitalized on significant oil and 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. 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 bases 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. Prior to 2017, the Company did not provide U.S. deferred taxes for undistributed earnings of certain foreign subsidiaries when these earnings were considered indefinitely invested. 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. Also, 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. 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 Note A – Significant Accounting Policies (Contd.) 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.

New Accounting Principles and Recent Accounting Pronouncements	12 Months Ended
	Dec. 31, 2018
New Accounting Principles and Recent Accounting Pronouncements [Abstract]
New Accounting Principles and Recent Accounting Pronouncements	Note B – New Accounting Principles and Recent Accounting Pronouncements Accounting Principles Adopted Revenue from Contracts with Customers. In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, 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 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 comparative 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. Compensation – Retirement Benefits. In March 2017, the FASB issued ASU 2017-07 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. Compensation – Stock Compensation. In May 2017, the FASB issued ASU 2017-09 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. Statement of Operations – Reporting Comprehensive Income. In February 2018, the FASB issued ASU 2018-02, 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. Note B – New Accounting Principles and Recent Accounting Pronouncements (Contd). Accounting Principles Adopted (Contd). 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 will be effective for the Company for our quarterly reporting beginning March 31, 2019. Recent Accounting Pronouncements Leases. In February 2016, the FASB established Topic 842 (the new standard) by issuing ASU 2016-02 to increase transparency and comparability among companies. The new standard requires lease benefits and corresponding lease liabilities to be recorded on the balance sheet and requires disclosing key information about leasing arrangements. The main difference between previous Generally Accepted Accounting Principles (GAAP) and the requirements of the new standard, is the recognition of right-of-use (ROU) assets and lease liabilities for certain leases. Entities will now be required to recognize operating leases alongside finance leases (formerly referred to as capital leases), with the distinction affecting the classification of expense recognition. The new standard also calls for disclosures regarding leasing arrangements and costs, to provide a more comprehensive insight into an entity’s leasing activities. The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods. Early adoption is permitted for all entities. The Company adopted this guidance in the first quarter of 2019 effective as of January 1, 2019. A modified retrospective transition approach is required upon adoption, with the new standard being applied to all leases at the date of initial application. We expect to take certain practical expedients that allow our initial date of application to coincide with the effective date, such that the new standard is applied prospectively on January 1, 2019 (relief option). Therefore, financial information and disclosures related to prior periods will neither be updated nor recast and will not reflect the new requirements. Further, the new standard also provides other practical expedients that an entity may elect, at its option, to facilitate a more efficient transition. We expect to elect the main ‘package of practical expedients,’ allowing entities not to reassess lease conclusions made under previous GAAP (primarily related to lease identification and classification). We currently expect to elect the short-term lease recognition exemption for all leases that qualify. We expect the new standard will have a material effect on our financial statements. Reviews indicate the impact will be generated primarily from ROU assets and lease liabilities related to an operating lease of a gas processing plant and floating, platform, storage, and off-take vessels. As required by the standard, previously deferred gains related to a sale-leaseback transaction will be transferred to equity upon transition, lowering liabilities but increasing retained earnings by approximately $160 million (see Note G). For all asset classes, preliminary estimates suggest operating leases could add approximately $800 million, representing the present value of remaining minimum lease payments. These estimates are provisional. Additional changes may arise due to the finalization of policies and elections made to the volume of leases recognized and revisions made to anticipated lease terms. We do not expect the standard to have an impact on our underlying liquidity or our debt-covenant compliance under our existing agreements. Note B – New Accounting Principles and Recent Accounting Pronouncements (Contd.) Recent Accounting Pronouncements (Contd.) Compensation – Stock Compensation. In June 2018, the FASB issued 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 ASU is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods. Early adoption is permitted. The Company adopted this guidance for the first quarter of 2019 and it is not expected to 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 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 that 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.

Revenue from Contracts with Customers

12 Months Ended

Dec. 31, 2018

Revenue from Contracts with Customers [Abstract]

Revenue from Contracts with Customers

Note C – 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 gas) in select basins around the globe. The Company’s revenue from sales of oil and gas production activities are primarily subdivided into three key geographic segments: the U.S., Canada, and Malaysia. 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 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 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 gas are transferred to the customer at the delivery point and is net of transportation costs. Revenue recognized is largely index based with price adjustments for floating market differentials.

Canada- Primarily all long-term contracts in Canada, except for certain natural gas physical forward sales fixed-price contracts, are floating commodity index priced. For the Onshore business in Canada, the recorded revenue is net of transportation and any gain or loss on spot purchases made to meet committed volumes on sales contracts for the month. 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.

Malaysia- In Malaysia, the Company has interests in seven separate PSCs. The Company serves as the operator of all these areas except for the unitized Gumusut-Kakap field. Crude oil contracts in Malaysia share similar features of largely fixed cargo quantities and variable index-based pricing, and revenue is typically recognized as the same time of vessel load. Malaysia also has three long term Gas Sales Agreements (GSA) with terms until the end of the field life, economic life, or PSC term.

Note C – Revenue from Contracts with Customers (Contd.)

Disaggregation of Revenue

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

For the years ended December 31, 2018, 2017, and 2016 the Company recognized $2.6 billion, $2.1 billion, and 1.9 billion, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas.


		For the Year Ended
		December 31,
(Thousands of dollars)		2018	2017	2016
Net crude oil and condensate revenue
United States – Onshore	$	778,198	644,023	508,045
– Offshore 1		403,523	208,984	172,022
Canada – Onshore		105,651	51,013	92,605
– Offshore		170,895	147,230	138,425
Malaysia – Sarawak		282,370	241,774	209,751
– Block K		406,653	378,401	403,912
Other		6,079	–	–
Total crude oil and condensate revenue		2,153,369	1,671,425	1,524,760

Net natural gas liquids revenue
United States – Onshore		53,335	43,804	28,316
– Offshore 1		10,269	6,894	5,781
Canada – Onshore		14,657	5,450	1,351
Malaysia – Sarawak		19,798	19,733	10,001
Total natural gas liquids revenue		98,059	75,881	45,449

Net natural gas revenue
United States – Onshore		28,335	27,460	24,281
– Offshore 1		14,525	10,480	10,839
Canada – Onshore		147,613	155,125	129,968
Malaysia – Sarawak		144,222	137,479	126,975
– Block K		504	698	619
Total natural gas revenue		335,199	331,242	292,682
Total revenue from contracts with customers		2,586,627	2,078,548	1,862,891

Gain (loss) on crude contracts		(41,975)	9,566	(63,412)
Other operating income		25,897	9,581	10,096
Gain on sale of assets		54	127,434	1,663
Total revenue	$	2,570,603	2,225,129	1,811,238

1 2018 includes revenue attributable to noncontrolling interest in MP GOM, effective November 30, 2018.

Contract Balances and Asset Recognition

As of December 31, 2018, and December 31, 2017, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet, were $263.0 million and $203.4 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.

Note C – Revenue from Contracts with Customers (Contd.)

The Company has not entered into any upstream oil and gas sale contracts that have financing components as of December 31, 2018.

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 gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer and considers each unit of measure, of the specified commodity, to represent a distinct performance obligation. The pricing for the Company’s sales contracts is typically market or index-based based. The Company has elected the direct allocation exception and therefore the variable consideration is allocated to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied performance obligations for delivery of a commodity in subsequent periods.

The Company has applied the exemption to not report any unsatisfied performance obligation related to contracts with terms of less than one year.

As at December 31, 2018, the Company had the following sales contracts in place with terms greater than one year:


Current Long-Term Contracts Outstanding at December 31, 2018
Location	Commodity	End Date	Description	Approximate Volumes
U.S.	Oil	Q3 2019	Fixed quantity delivery in Eagle Ford	4,000 BOED
U.S.	Oil	Q4 2021	Fixed quantity delivery in Eagle Ford	17,000 BOED
U.S.	Gas and NGL	Q2 2026	Deliveries from dedicated acreage in Eagle Ford	As produced
Canada	Gas	Q4 2020	Contracts to sell natural gas at Alberta AECO fixed prices	59 MMCFD
Canada	Gas	Q4 2020	Contracts to sell natural gas at USD Index pricing	60 MMCFD
Canada	Gas	Q4 2024	Contracts to sell natural gas at USD Index pricing	30 MMCFD
Canada	Gas	Q4 2026	Contracts to sell natural gas at USD Index pricing	38 MMCFD

Acquisition

12 Months Ended

Dec. 31, 2018

Acquisition [Abstract]

Acquisition

Note D – Acquisition

In December 2018, the Company announced the completion of a transaction with Petrobras Americas Inc. (PAI) which became effective October 1, 2018. Through this transaction, Murphy acquired all PAI’s producing Gulf of Mexico assets along with certain blocks that hold deep exploration rights. This transaction added production of approximately 50,000 BOED (including noncontrolling interest, NCI) along with approximately 97 MMBOE (including NCI) of proven reserves at December 31, 2018. See Supplemental Oil and Gas Information (Unaudited), below for discussion of proved reserves acquired.

Under the terms of the transaction, Murphy paid cash consideration of $794.6 million and transferred a 20% interest in MP Gulf of Mexico, LLC (MP GOM), a subsidiary of Murphy, to PAI. Murphy could also owe additional contingent consideration up to $150 million if certain sales thresholds are exceeded beginning in 2019 through 2025. Both companies contributed all of their current producing Gulf of Mexico assets into MP GOM. Following closing of the transaction, MP GOM is owned 80% by Murphy and 20% by PAI, with Murphy overseeing the operations.

The following tables contain the preliminary purchase price allocation at fair value:


(Thousands of dollars)
Cash consideration paid to PAI	$	794,623
Fair value of net assets contributed		166,797
Fair value of contingent consideration		52,540
Noncontrolling interest in acquired assets		253,490
Total purchase consideration	$	1,267,450


(Thousands of dollars)
Fair value of Property, Plant, and Equipment	$	1,617,052
Other assets		10,041
Less: Asset retirement obligations		(359,643)
Total net assets	$	1,267,450

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, probable, and possible 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 required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change.

Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, analysis of the underlying tax basis of the PAI assets acquired and liabilities assumed and the final purchase price adjustments to be settled in 2019. 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

The results of operations attributable to the acquired PAI assets are included in our Consolidated Statement of Operations beginning on December 1, 2018. Murphy generated additional revenues of $56.7 million and pre-tax income of $36.5 million related to the acquired assets from the period December 1, 2018 to December 31, 2018.

Note D – Acquisition (Contd.)

Pro Forma Financial Information

The following pro forma condensed combined financial information was derived from historical financial statements of Murphy and PAI and gives effect to the transaction as if it had occurred on January 1, 2017. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including depletion of PAI 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 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, 2017; 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)		2018	2017
Revenues	$	2,825,169	2,816,458
Net Income Attributable to Murphy		603,231	(224,860)

Net Income Attributable to Murphy per Common Share
Basic	$	3.49	(1.30)
Diluted		3.46	(1.30)

Discontinued Operations and Assets Held for Sale

12 Months Ended

Dec. 31, 2018

Discontinued Operations and Assets Held for Sale [Abstract]

Discontinued Operations and Assets Held for Sale

Note E – Discontinued Operations and Assets Held for Sale

The Company has accounted for its former U.K. and U.S. refining and marketing operations as discontinued operations for all periods presented.

The following table presents the carrying value of the major categories of assets and liabilities of U.K. discontinued refining and marketing operations reflected as held for sale on the Company’s Consolidated Balance Sheets at December 31, 2018 and 2017.



(Thousands of dollars)	2018		2017
Current assets
Cash	$	17,219	16,631
Accounts receivable		3,728	6,298
Total current assets held for sale	$	20,947	22,929
Current liabilities
Accounts payable	$	106	837
Refinery decommissioning cost		2,658	2,693
Total current liabilities associated with assets held for sale	$	2,764	3,530

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



(Thousands of dollars)	2018		2017	2016
Revenues	$	6	854	1,464
Loss from operations before income taxes	$	(3,522)	(853)	(2,027)
Loss on sale before income taxes		–	–	–
Total loss from discontinued operations before taxes		(3,522)	(853)	(2,027)
Income tax expense		–	–	–
Loss from discontinued operations	$	(3,522)	(853)	(2,027)

Inventories

12 Months Ended

Dec. 31, 2018

Inventories [Abstract]

Inventories

Note F – Inventories

Inventories consisted of the following at December 31, 2018 and 2017.



	December 31,
	2018		2017
(Thousands of dollars)
Unsold crude oil	$	25,205	20,153
Materials and supplies		62,706	84,974
	$	87,911	105,127

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2018

Property, Plant And Equipment [Abstract]

Property, Plant and Equipment

Note G – Property, Plant and Equipment



	December 31, 2018				December 31, 2017
(Thousands of dollars)	Cost		Net		Cost	Net
Exploration and production1	$	22,629,844	9,654,945	2	20,329,930	8,120,293	2
Corporate and other		193,471	102,619		170,842	99,738
	$	22,823,315	9,757,564		20,500,772	8,220,031
1 Includes unproved mineral rights as follows:	$	512,025	144,912		600,423	198,349

2. Includes $32,071 in 2018 and $38,670 in 2017 related to administrative assets and support equipment.

Divestments

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

In 2016, a Canadian subsidiary of the Company completed the sale of its five percent, non-operated working interest in Syncrude Canada Ltd. (Syncrude) asset to Suncor Energy Inc. (Suncor). The Company received net cash proceeds of $739.1 million and recorded an after-tax gain of $71.7 million associated with the Syncrude divestiture.

In 2016, a Canadian subsidiary of the Company completed a divestiture of natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia. Total cash consideration received upon closing was $414.1 million. A gain on sale of approximately $187.0 million was

deferred and is being recognized over approximately the next 17 years in the Canadian operating segment. The Company amortized approximately $7.6 million and $7.1 million of the deferred gain during 2018 and 2017, respectively. The remaining deferred gain of $160.2 million was included as a component of Deferred credits and other liabilities in the Company’s Consolidated Balance Sheet as of December 31, 2018.

Acquisition

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 excludes exploration blocks from Murphy. However, PAI’s blocks that hold deep exploration rights were part of the transaction. Murphy paid net cash consideration of $794.6 million at closing, 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 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 costs in the St. Malo Field if certain enhanced oil recovery projects are undertaken.

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

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, 2018, $102.0 million of the carried interest had been paid. The carry is to be paid over a period through 2020.

Impairments

During 2018, underperforming wells led to impairments in certain of the Company’s US Onshore properties. In 2018 the Company recorded a pretax noncash impairment charge of $20 million to reduce the carrying values to their estimated fair values at select Midland properties. During 2016, declines in future oil and gas prices led to impairments in certain of the Company’s producing properties. During 2016, the Company recorded pretax noncash impairment charges of $95.1 million to reduce the carrying values to their estimated fair values for the Terra Nova field offshore Canada and the Western Canada onshore heavy oil producing properties.

The following table reflects the recognized impairments for the three years ended December 31, 2018.


	December 31,
(Thousands of dollars)		2018	2017	2016
US Onshore (Midland)	$	20,000	–	–
Canada		–	–	95,088
Malaysia		–	–	–
	$	20,000	–	95,088

Other

In 2006, the Kakap field in Block K was unitized with the Gumusut field in an adjacent block under a Unitization and Unit Operating Agreement (UUOA) between the owners. The Gumusut-Kakap Unit is operated by another company. In the fourth quarter 2016, the owners completed the first redetermination process for a revision to the blocks’ tract participation interest, and the operator of the unitized field sought the approval of Petronas to effect the change in 2017. In 2016, the Company recorded an estimated redetermination expense of $39.1 million ($24.1 million after taxes) related to an expected revision in the Company’s working interest covering the period from inception through year-end 2016 at Kakap. In February 2017, the Company received Petronas official approval to the redetermination change that reduced the Company’s working interest in oil operations to 6.67% effective at April 1, 2017. Working interest redeterminations are required at different points within the life of the unitized field. Following a partial payment, the remaining redetermination liability of $17.3 million was included as a component of Other current liabilities in the Company’s Consolidated Balance Sheet as of December 30, 2018.

In 2017, following a further Unitization Framework Agreement (UFA) between the governments of Brunei and Malaysia, the Company has a 6.35% interest in the Kakap field in Block K Malaysia. The UFA unitized the Gumusut/Kakap (GK) and Geronggong/Jagus East fields effective November 23, 2017. In the fourth quarter 2017, the Company recorded an estimated redetermination expense of $15.0 million ($9.3 million after tax) related to Company’s revised working interest, which was included as a component of Other current liabilities in the Company’s Consolidated Balance Sheet as of December 31, 2018.

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

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, 2018, 2017 and 2016, the Company had total capitalized drilling costs pending the determination of proved reserves of $229.1 million, $175.6 million and $148.5 million, respectively. The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 2018.



(Thousands of dollars)	2018		2017	2016
Beginning balance at January 1	$	175,640	148,500	130,514
Additions pending the determination of proved reserves		60,179	51,488	17,986
Reclassifications to proved properties based on the determination of proved reserves		(2,214)	(15,988)	–
Capitalized exploration well costs charged to expense		(4,521)	(8,360)	–
Ending balance at December 31	$	229,084	175,640	148,500

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 has now been reached. This well was originally drilled in 2012. The capitalized well costs charged to expense in 2017 included the Marakas-01 well in Block SK314A, offshore Malaysia in which development of the well could not be justified due to noncommercial hydrocarbon quantities found.

The 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.



	2018				2017				2016
(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	$	61,096	1	1	$	41,480	3	2	$	20,481	1	1
One to two years		40,523	3	2		5,812	1	1		63,527	5	5
Two to three years		–	–	–		43,200	2	2		–	–	–
Three years or more		127,465	6	3		85,148	7	1		64,492	6	–
	$	229,084	10	6	$	175,640	13	6	$	148,500	12	6

Of the $167.9 million of exploratory well costs capitalized more than one year at December 31, 2018, $55.8 million is in Brunei, $63.5 million is in Vietnam, $27.4 million in the U.S., and $21.2 million is in Malaysia. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

Financing Arrangements and Long-Term Debt

12 Months Ended

Dec. 31, 2018

Financing Arrangements and Long-Term Debt [Abstract]

Financing Arrangements and Long-Term Debt

Note H – Financing Arrangements and Long-Term Debt

As of December 31, 2018, the Company has a $1.6 billion revolving credit facility (2018 facility). The 2018 facility is a senior unsecured guaranteed facility which expires in November 2023 and it replaced the $1.1 billion senior unsecured guaranteed credit facility (2016 facility). At December 31, 2018, the Company had outstanding borrowings of $325.0 million under the 2018 facility and $24.7 million of outstanding letters of credit, which reduce the borrowing capacity of the 2018 facility. Borrowings under the 2018 facility bear interest at rates, based, at the Company’s option, on the “Alternate Base Rate” of interest in effect plus the “ABR Spread” or the “Adjusted LIBOR Rate,” which is a periodic fixed rate based on LIBOR with a term equivalent to the interest period for such borrowing, plus the “Eurodollar Spread.” The “Alternate Base Rate” of interest is the highest of (i) the Wall Street Journal prime rate, (ii) the New York Federal Reserve Bank Rate plus 0.50%, and (iii) one-month LIBOR plus 1.00%. The “Eurodollar Spread” ranges from 1.075% to 2.10% per annum based upon the Corporation’s senior unsecured long-term debt securities credit ratings (the “Credit Ratings”). A facility fee accrues and is payable quarterly in arrears at a rate ranging from 0.175% to 0.40% per annum (based upon the Company’s Credit Ratings) on the aggregate commitments under the 2016 facility. At December 31, 2018, the interest rate in effect on borrowings under the facility was 3.831%. At December 31, 2018, the Company was in compliance with all covenants related to the 2018 facility.

In August 2017, the Company sold $550 million of new notes that bear interest at the rate of 5.75% and mature on August 15, 2025. The Company incurred transaction costs of $8.4 million on the issuance of these new notes. The Company pays interest semi-annually on February 15 and August 15 of each year. The initial interest payment was paid on February 15, 2018. The proceeds of the $550 million notes were used to redeem the Company’s 3.50% notes in September 2017. The 3.50% notes had an original maturity of December 2017.

The Company and its partners are parties to a 25-year lease of production equipment at the Kakap field offshore Malaysia. The lease has been accounted for as a capital lease (finance lease under ASC 842), and payments under the agreement are to be made over a 15-year period through March 2029. Current maturities of long-term debt and long-term debt on the Consolidated Balance Sheet included $10.6 million and $125.8 million, respectively, associated with this lease at December 31, 2018.



	December 31,
(Thousands of dollars)	2018		2017
Notes payable
4.00% notes, due June 2022	$	500,000	500,000
4.45% notes, due December 20221		600,000	600,000
6.875% notes, due August 2024		550,000	550,000
5.75% notes, due August 2025		550,000	550,000
7.05% notes, due May 2029		250,000	250,000
5.875% notes, due December 20421		350,000	350,000
Total notes payable		2,800,000	2,800,000
Unamortized debt issuance cost and discount on notes payable		(23,627)	(27,433)
Total notes payable, net of unamortized discount		2,776,373	2,772,567
Capitalized lease obligation, due through March 2029		136,344	143,855
Total debt including current maturities		2,912,717	2,916,422
Senior Unsecured Revolving Credit Facility		325,000	-
Current maturities		(10,583)	(9,902)
Total long-term debt	$	3,227,134	2,906,520

1 Due to a series of ratings changes by credit agencies, the paying interest rates on the notes due December 2022 and December 2042 decreased from 4.7% to 4.45% and 6.125% to 5.875%, respectively, in 2017 and remained through 2018.

The amount of debt repayable over each of the next five years and thereafter are as follows: ‘$10.6 million in 2019, $11.2 million in 2020, $11.7 million in 2021, $1.1 billion in 2022, $337.9 million in 2023 and $1.76 billion thereafter.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

Note I – Asset Retirement Obligations

The asset retirement obligations liabilities (ARO) recognized by the Company at December 31, 2018 and 2017 are related to the estimated costs to dismantle and abandon its producing oil and gas properties and related equipment.

A reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligation for 2018 and 2017 is shown in the following table.



(Thousands of dollars)	2018		2017
Balance at beginning of year	$	722,139	781,057
Accretion expense		44,559	42,590
Liabilities incurred		13,886	52,331
Liabilities assumed from PAI		359,643	–
Revisions of previous estimates		(24,959)	(47,612)
Liabilities settled		(23,398)	(29,111)
Liabilities assumed by purchaser of oil and gas assets		–	(87,456)
Changes due to translation of foreign currencies		(8,966)	10,340
Balance at end of year		1,082,904	722,139
Current portion of liability at end of year1		(55,481)	(12,840)
Noncurrent portion of liability at end of year	$	1,027,423	709,299

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.

In 2017, revisions of previous estimates primarily reflected the impact of lower rig service rates in the U.S.

Liabilities assumed from PAI in 2018 primarily represent obligations assumed as part of the MP GOM acquisition

(see Note D).

Income Taxes

12 Months Ended

Dec. 31, 2018

Income Taxes [Abstract]

Income Taxes

Note J – 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)	2018		2017	2016
Income (loss) from continuing operations before income taxes
United States	$	14,907	(299,349)	(595,196)
Foreign		417,431	371,151	102,081
Total	$	432,338	71,802	(493,115)
Income tax expense (benefit)
Federal – Current	$	(9,765)	–	-
– Deferred		(131,200)	156,065	(197,450)
Total Federal		(140,965)	156,065	(197,450)
State		3,299	4,230	13,984
Foreign – Current		202,775	122,318	146,861
– Deferred		(55,779)	100,125	(182,567)
Total Foreign		146,996	222,443	(35,706)
Total	$	9,330	382,738	(219,172)

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


(Thousands of dollars)	2018		2017	2016
Income tax expense (benefit) based on the U.S. statutory tax rate	$	90,791	25,131	(172,590)
Revaluation of deferred tax (US tax reform)		–	118,004	–
Tax impact of deemed repatriation of foreign invested earnings (U.S. tax reform)		(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		72,007	12,658	8,582
State income taxes, net of federal benefit		2,607	2,438	9,090
U.S. tax benefit on certain foreign upstream investments		(14,702)	(32,926)	(21,336)
Tax effects on sale of Canadian assets		–	–	(89,473)
Tax effects on sale of Malaysian assets		–	–	2,080
Increase in deferred tax asset valuation allowance related to other foreign exploration expenditures		3,283	18,601	25,734
Other, net		(8,956)	17,832	18,741
Total	$	9,330	382,738	(219,172)

Note J – Income Taxes (Contd.)

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 related to the Section 965(n) election. This guidance 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 late 2019, and the balance to be refunded or available to offset future U.S. income tax obligations over the next four years.

An analysis of the Company’s deferred tax assets and deferred tax liabilities at December 31, 2018 and 2017 showing the tax effects of significant temporary differences follows.



(Thousands of dollars)	2018		2017
Deferred tax assets
Property and leasehold costs	$	491,660	488,584
Liabilities for dismantlements		88,075	98,444
Postretirement and other employee benefits		113,826	134,444
Alternative minimum tax		9,765	29,710
Foreign tax credit carryforwards		–	228,159
U. S. net operating loss		496,629	272,930
Other deferred tax assets		19,974	13,892
Total gross deferred tax assets		1,219,929	1,266,163
Less valuation allowance		(213,815)	(476,256)
Net deferred tax assets		1,006,114	789,907
Deferred tax liabilities
Deferred tax on undistributed foreign earnings		(5,000)	(65,000)
Accumulated depreciation, depletion and amortization		(742,562)	(669,638)
Other deferred tax liabilities		(28,802)	(2,824)
Total gross deferred tax liabilities		(776,364)	(737,462)
Net deferred tax assets	$	229,750	52,445

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 unexpected to be realized. The valuation allowance decreased $262 million in 2018 primarily due to a decrease in foreign tax credit carryforwards. 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 $2.36 billion at year-end 2018 with a corresponding deferred tax asset of $496.6 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.

Note J – Income Taxes (Contd.)

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 reflected on the Company’s December 31, 2017 balance sheet as earnings not permanently reinvested, with an accompanying $65.0 million liability. 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, 2018, $1.2 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 examination. 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)	2018		2017	2016
Balance at January 1	$	3,437	7,417	6,631
Additions for tax positions related to current year		454	769	756
Settlements due to lapse of time		(988)	(4,834)	–
Foreign currency translation effect		–	85	30
Balance at December 31	$	2,903	3,437	7,417

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, 2018, 2017 and 2016 for interest and penalties of $0.2 million, $0.1 million and $0.3 million, respectively, associated with uncertain tax positions. Income tax expense for the years ended December 31, 2018, 2017 and 2016 included net benefits for interest and penalties of $0.1 million, $0.2 million and $0.1 million, respectively, associated with uncertain tax positions.

During the next twelve months, the Company currently expects to add between $0.2 million and $1.0 million to the liability for uncertain taxes for 2019 events. 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 2019.

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, 2018, the earliest years remaining open for audit and/or settlement in the Company’s major taxing jurisdictions are as follows: United States – 2015; Canada – 2013; Malaysia – 2012; and United Kingdom – 2017.

Incentive Plans

12 Months Ended

Dec. 31, 2018

Incentive Plans [Abstract]

Incentive Plans

Note K – 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.

At the Company’s annual stockholders’ meeting held on May 9, 2018, 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). The 2018 Long-Term Plan authorizes the Committee to make grants of the Company’s Common Stock to employees in the same form as the 2012 Long-Term Plan. The new plan can be found in the Company’s Definitive Proxy statement (Definitive 14A) dated March 23, 2018. All awards on or after May 9, 2018 will be 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 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 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 authorize 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; allowed shares not granted in an earlier year may be granted in future years. Based on awards made to date, 3.4 million shares are available for grant under the 2018 Long-Term Plan at December 31, 2018. 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)	2018		2017	2016
Compensation charged against income (loss) before income tax benefit	$	34,467	40,365	46,300
Related income tax benefit recognized in income		4,383	5,017	15,244

As of December 31, 2018, there were $46.5 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 statutory withholding taxes, 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 year ended December 31, 2018. There were no income tax benefits realized in either 2017 or 2016 due to no stock option exercises during those years.

Equity-Settled Awards

STOCK OPTIONS – The Committee fixes the option price of each option granted at no less than fair market value (FMV) on the date of the grant and fixes 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.

Note K – Incentive Plans (Contd.)

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. In 2018, in light of a shift in the peer group compensation practices, the Company ceased the inclusion of stock options and stock appreciation rights as a part of the long-term incentive compensation mix.



	2018	2017	2016

Fair value per option grant	N/A	$7.96	$5.03
Assumptions
Dividend yield	N/A	3.60%	4.00%
Expected volatility	N/A	41.00%	45.00%
Risk-free interest rate	N/A	1.97%	1.32%
Expected life	N/A	5.30 yrs.	5.20 yrs.

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, 2015	5,443,288	$	52.93
Granted at FMV	862,000		17.57
Exercised	–		-
Forfeited	(547,853)		44.23
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
Exercisable at December 31, 2015	3,542,352	$	52.26
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

Additional information about stock options outstanding at December 31, 2018 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 $30.00	1,131,500	4.5	$	3,719,263	319,250	4	$	1,859,631
$31.00 to $50.00	817,350	2.9		–	817,350	2.9		–
$51.00 to $65.00	2,045,745	1.0		–	2,045,745	1.0		–
	3,994,595	2.4	$	3,719,263	3,182,345	1.8	$	1,859,631

Note K – Incentive Plans (Contd.)

The total intrinsic value of options exercised during 2018 was $1 million. There were no options exercised in both 2017 and 2016 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 each of the last three years 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 past awards, the performance conditions were 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 or 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)	2018	2017	2016
Outstanding at beginning of year	1,187,921	992,573	1,103,986
Granted	905,500	560,000	394,000
Vested and issued	(311,866)	(272,725)	(361,096)
Forfeited	(121,138)	(91,927)	(144,317)
Outstanding at end of year	1,660,417	1,187,921	992,573

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 2018, 2017 and 2016 are presented in the following table.



	2018	2017	2016

Fair value per share at grant date	$22.99 - $30.56	$24.10 – $28.28	$12.21 – $16.34
Assumptions
Expected volatility	48.00%	47.00%	33.00%
Risk-free interest rate	2.30%	1.46%	0.93%
Stock beta	1.103	1.058	0.863
Expected life	3.0 yrs.	3.0 yrs.	3.0 yrs.

Note K – Incentive Plans (Contd.)

TIME-BASED RESTRICTED STOCK UNITS – Time-based restricted stock units (RSUs) have been granted to the Company’s Non-Employee Directors under the 2013 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 $25.69 to $28.43 per share in 2018, $28.51 per share in 2017, and $17.57 per share in 2016.

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



(Number of share units)	2018	2017	2016

Outstanding at beginning of year	1,035,980	923,282	477,244
Granted	823,803	419,720	503,555
Vested and issued	(233,456)	(217,633)	(32,092)
Forfeited	(87,473)	(89,389)	(25,425)
Outstanding at end of year	1,538,854	1,035,980	923,282

EMPLOYEE STOCK PURCHASE PLAN (ESPP) – The Company had an ESPP under which the Company’s Common stock could have been purchased by eligible U.S. and Canadian employees. The plan ceased to operate in 2017. Each quarter, an eligible employee could have elected to withhold up to 10% of his or her salary to purchase shares of the Company’s stock at the end of the quarter at a price equal to 90% of the fair value of the stock as of the first day of the quarter. Employee stock purchases under the ESPP were 2,564 shares at an average price of $26.85 per share in 2017 and 8,962 shares at an average price of $23.41 per share in 2016. 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, and such expenses were immaterial for all periods presented. The fair value per share issued under the ESPP was approximately $5.34 and $2.94 for the years ended December 31, 2017 and 2016, respectively.

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 (SAR), Performance-based restricted stock units (CPSU), Time-based restricted stock units (CRSU) 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 $6.5 million in 2018, $12.9 million in 2017 and $17.2 million in 2016.

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 $30 million, $30.5 million and $25.8 million was recorded in 2018, 2017 and 2016, respectively, for these plans.

Employee and Retiree Benefit Plans

12 Months Ended

Dec. 31, 2018

Employee and Retiree Benefit Plans [Abstract]

Employee and Retiree Benefit Plans

Note L – 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.

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, 2018 and 2017 and a statement of the funded status as of December 31, 2018 and 2017.



	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)	2018		2017	2018	2017
Change in benefit obligation
Obligation at January 1	$	881,932	815,593	106,276	106,679
Service cost		8,994	8,279	1,965	1,601
Interest cost		26,168	27,047	3,427	3,444
Participant contributions		–	–	2,104	2,075
Actuarial loss (gain)		(57,378)	60,855	(13,778)	(3,077)
Medicare Part D subsidy		–	–	325	318
Exchange rate changes		(12,742)	18,751	(67)	46
Benefits paid		(41,132)	(39,910)	(5,473)	(4,810)
Prior Service Cost		737	–	–	–
Other		(28,934)	(8,683)	–	–
Obligation at December 31		777,645	881,932	94,779	106,276
Change in plan assets
Fair value of plan assets at January 1		563,825	519,357	–	–
Actual return on plan assets		(18,951)	50,079	–	–
Employer contributions		24,357	24,918	3,044	2,417
Participant contributions		–	–	2,104	2,075
Medicare Part D subsidy		–	–	325	318
Exchange rate changes		(12,071)	18,064	–	–
Benefits paid		(41,132)	(39,910)	(5,473)	(4,810)
Other		(28,934)	(8,683)	–	–
Fair value of plan assets at December 31		487,094	563,825	–	–
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets		11,039	5,905	–	–
Other accrued liabilities		(9,175)	(8,856)	(5,101)	(5,392)
Deferred credits and other liabilities		(292,415)	(315,156)	(89,678)	(100,884)
Funded status and net plan liability recognized at December 31	$	(290,551)	(318,107)	(94,779)	(106,276)

Note L – Employee and Retiree Benefit Plans (Contd.)

At December 31, 2018, 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 loss	$	(239,030)	13,969
Prior service (cost) credit		(5,568)	–
	$	(244,598)	13,969

Amounts included in AOCL at December 31, 2018 that are expected to be amortized into net periodic benefit expense during 2019 are shown in the following table.



(Thousands of dollars)	Pension Benefits		Other Postretirement Benefits
Net actuarial loss	$	(14,117)	(391)
Prior service (cost) credit		(956)	–
	$	(15,073)	(391)

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)	2018		2017	2018	2017	2018	2017
Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets	$	457,446	691,923	447,793	640,230	316,543	540,161
Unfunded nonqualified and directors' plans where accumulated benefit obligation exceeds fair value of plan assets		158,228	172,364	150,586	163,319	–	–
Unfunded other postretirement plans		94,808	106,276	94,808	106,276	–	–

The table that follows provides the components of net periodic benefit expense for each of the three years ended December 31, 2018.


	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)		2018	2017	2016	2018	2017	2016
Service cost	$	8,994	8,279	8,136	1,965	1,601	1,864
Interest cost		26,168	27,047	25,185	3,427	3,444	3,800
Expected return on plan assets		(29,236)	(28,941)	(28,154)	–	–	–
Amortization of prior service cost (credit)		1,021	1,026	1,204	(38)	(74)	(75)
Amortization of transitional (asset) liability		–	–	–	–	–	–
Recognized actuarial loss		21,893	16,691	16,165	–	–	5
		28,840	24,102	22,536	5,354	4,971	5,594
Termination benefits expense		–	–	–	–	–	–
Curtailment expense		–	–	822	–	–	(19)
Net periodic benefit expense	$	28,840	24,102	23,358	5,354	4,971	5,575

Note L – Employee and Retiree Benefit Plans (Contd.)

Termination and curtailment expenses in 2016 were primarily related to plan amendments made upon early retirement of certain employees during 2016.

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



	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)	2018		2017	2018	2017
Benefit obligation at December 31	$	173,860	222,483	812	791
Fair value of plan assets at December 31		170,551	212,535	–	–
Net plan liabilities recognized		3,309	9,948	812	791
Net periodic benefit expense (benefit)		3,983	194	146	133

The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2018 and 2017 and net periodic benefit expense for 2018 and 2017.



	Benefit Obligations				Net Periodic Benefit Expense
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
	December 31		December 31		Year		Year
	2018	2017	2018	2017	2018	2017	2018	2017
Discount rate	4.07%	3.42%	3.73%	3.73%	3.54%	3.66%	4.32%	4.33%
Expected return on plan assets	5.37%	5.64%	–	–	5.37%	5.64%	–	–
Rate of compensation increase	3.28%	3.52%	–	–	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
2018	$	37,266	5,754
2019		37,565	5,839
2020		38,606	5,994
2021		39,660	6,130
2022		39,908	6,171
2023-2027		207,633	32,109

For purposes of measuring postretirement benefit obligations at December 31, 2018, the future annual rates of increase in the cost of health care were assumed to be 6.5% for 2018 decreasing each year to an ultimate rate of 4.5% in 2038 and thereafter.

Note L – Employee and Retiree Benefit Plans (Contd.)

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, 2018	$	1,049	(813)
Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2018		12,656	(10,350)

During 2018, the Company made contributions of $23.7 million to its domestic defined benefit pension plans, $0.8 million to its foreign defined benefit pension plans and $3.0 million to its domestic postretirement benefits plan. During 2019, Company currently expects to make contributions of $26.7 million to its domestic defined benefit pension plans, $0.6 million to its foreign defined benefit pension plans and $5.1 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. The parameters for asset allocation call for the following minimum and maximum percentages: equity securities of between 40% and 70%; fixed income securities of between 30% and 60%; long/short equity of between 0% and 15%; and cash and equivalents of between 0% and 15%. The Committee is authorized to direct investments within these parameters. Equity investments may include common, preferred and convertible preferred stocks, emerging markets stocks and similar funds, and long/short equity funds. Long/short equity is a strategy invested in a portfolio of long stocks hedged with short sales of stocks and/or stock index options, with the combination of investment intended to produce equity-like returns with lower volatility over the long term. 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 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.

Note L – Employee and Retiree Benefit Plans (Contd.)

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 a fiduciary investment manager to manage the assets of the plan within the parameters of the Statement of Investment Principles (Statement). The objective of investments is to earn a reasonable return within the allocation strategy permitted in the Statement while limiting the risk for the funded position of the plan. The Statement specifies a strategy with an allocation goal of 60% Delegated growth fund (DGF) equities and 40% Delegated liability fund (DLF). Also, the allocation goal includes interest rate hedge ratio and inflation rate hedge ratio of 100%. Hewitt Risk Management Services Limited (Manager) has discretion to vary the level of interest rate and inflation hedge ratios from the strategic levels. 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 schemes on an exposure basis in the relevant tenures and instruments (long/short, real/nominal). The DLF holds cash as collateral for the leveraged positions. Small working cash balances are permitted 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 normal allocation for 2019 includes total equity securities of 42% with a range of 37% to 47% of total assets. Fixed income securities have a normal allocation of 56% with a range of 51% to 61%. Cash will normally have an allocation of 2% with a range of 0% to 10%. The Policy calls for diversification norms within the investment portfolios of both equity securities and fixed income securities.

The weighted average asset allocation for the Company’s funded pension benefit plans at December 31, 2018 and 2017 are presented in the following table.



	December 31,
	2018		2017
Equity securities	56.0	%	60.3	%
Fixed income securities	42.2		37.2
Cash equivalents	1.8		2.5
	100.0	%	100.0	%

The Company’s weighted average expected return on plan assets was 5.42% in 2018 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 5.42% expected return was based on an expected average future equity securities return of 6.97% and a fixed income securities return of 3.44% 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 7.71%.

Note L – Employee and Retiree Benefit Plans (Contd.)

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

Note L – Employee and Retiree Benefit Plans (Contd.)

At December 31, 2017, 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, 2017		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	$	67,343	67,343	–	–
U.S. small/midcap		24,544	24,544	–	–
Hedged funds and other alternative strategies		50,522	–	12,572	37,950
International commingled trust fund		83,960	–	83,960	–
Emerging market commingled equity fund		20,774	–	20,774	–
Fixed income securities:
U.S. fixed income		79,890	–	79,890	–
International commingled trust fund		13,122	–	13,122	–
Emerging market mutual fund		5,266	–	5,266	–
Cash and equivalents		5,871	5,871	–	–
Total Domestic Plans		351,292	97,758	215,584	37,950
Foreign Plans
Equity securities funds		78,666	–	78,666	–
Fixed income securities funds		103,314	–	103,314	–
Diversified pooled fund		23,665	–	23,665	–
Cash and equivalents		6,888	–	6,888	–
Total Foreign Plans		212,533	–	212,533	–
Total	$	563,825	97,758	428,117	37,950

The definition of levels within the fair value hierarchy in the tables above is included in Note Q.

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.

Note L – Employee and Retiree Benefit Plans (Contd.)

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, 2016		$	34,114
Actual return on plan assets:
Relating to assets held at the reporting date			3,836
Relating to assets sold during the period			–
Purchases, sales and settlements			–
Total at December 31, 2017			37,950
Actual return on plan assets:
Relating to assets held at the reporting date			(2,921)
Relating to assets sold during the period			–
Purchases, sales and settlements			–
Total at December 31, 2018		$	35,029

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 $5.2 million in 2018, $7.8 million in 2017 and $7.4 million in 2016.

Financial Instruments and Risk Management

12 Months Ended

Dec. 31, 2018

Financial Instruments and Risk Management [Abstract]

Financial Instruments and Risk Management

Note M – 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 until the anticipated transactions occur.

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, 2018, the Company had no open WTI crude oil swap financial contracts. At December 31, 2017, the Company had 21,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2018 at an average price of $54.88.

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, 2018 and 2017.

Note M – Financial Instruments and Risk Management (Contd.)

At December 31, 2018 and 2017, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.



	December 31, 2018			December 31, 2017
(Thousands of dollars)	Asset (Liability) Derivatives			Asset (Liability) Derivatives
Type of Derivative Contract	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value
Commodity	Accounts receivable	$	3,837	Accounts payable	$	(39,093)

For the years ended December 31, 2018, 2017 and 2016, 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	2018		2017	2016
Commodity	(Loss) gain on crude contracts	$	(41,975)	9,566	(63,412)
Foreign exchange	Interest and other income (loss)		–	–	26,714
		$	(41,975)	9,566	(36,698)

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 each of the three years ended December 31, 2018, $3.0 million of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statements of Operations. The remaining loss (net of tax) deferred on these matured contracts at December 31, 2018 was $7.9 million, which is recorded, net of income taxes of $2.1 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheets. The Company expects to charge approximately $3.0 million of this deferred loss to Interest expense in the Consolidated Statements of Operations during 2019.

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.

Earnings per Share

12 Months Ended

Dec. 31, 2018

Earnings per Share [Abstract]

Earnings per Share

Note N – 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, 2018. The following table reconciles the weighted-average shares outstanding used for these computations.



(Weighted-average shares)	2018	2017	2016
Basic method	172,974,491	172,524,061	172,173,012
Dilutive stock options 1	1,234,274	–	–
Diluted method	174,208,765	172,524,061	172,173,012

1 Due to a net loss recognized by the Company for the years ended December 31, 2017 and 2016, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive.

The following table reflects certain options to purchase shares of common stock that were outstanding during the three years ended December 31, 2018, but were not included in the computation of dilutive earnings per share because the incremental shares from the assumed conversion were antidilutive.



	2018	2017	2016
Antidilutive stock options excluded from diluted shares	3,942,296	4,901,269	5,757,435
Weighted average price of these options	$46.77	$45.74	$48.46

Other Financial Information

12 Months Ended

Dec. 31, 2018

Other Financial Information [Abstract]

Other Financial Information

Note O – 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 $(7.8) million in 2018, $(75.4) million in 2017 and $59.7 million in 2016.

Noncash operating working capital (increased) decreased during each of the three years ended December 31, 2018 as shown in the following table.



(Thousands of dollars)	2018		2017	2016
Accounts receivable	$	(89,070)	114,401	119,671
Inventories		12,216	26,883	(5,171)
Prepaid expenses		(17,341)	29,570	149,946
Deferred income tax assets		–	–	-
Accounts payable and accrued liabilities		(51,769)	(51,439)	(328,078)
Current income tax liabilities		(23,844)	16,999	24,943
Net (increase) decrease in noncash operating working capital	$	(169,808)	136,414	(38,689)
Supplementary disclosures (including discontinued operations):
Cash income taxes paid, net of refunds	$	129,296	68,076	6,707
Interest paid, net of amounts capitalized of $5,258 in 2018, $4,488 in 2017 and $4,322 in 2016		167,750	147,975	127,798

Noncash investing activities, related to continuing operations:
Asset retirement costs capitalized	$	353,436	8,509	13,690
Decrease (increase) in capital expenditure accrual		(42,467)	99,199	158,885

Note O – Other Financial Information (Contd.)

DEEPWATER RIG CONTRACT EXIT COSTS – At year-end 2015, the Company had two deepwater drilling rigs in the Gulf of Mexico under contract that were scheduled to expire in February and November 2016. In the face of low commodity prices, a significant reduction in the Company’s overall 2016 capital spending program and lack of interest by working interest partners and others to participate in drilling opportunities in 2016, the Company idled and stacked both rigs during the fourth quarter of 2015. The Company reported a pretax charge to Other expense in 2015 totaling $282.0 million that included both the costs incurred in 2015 when the rigs were idle and stacked together with the remaining day rate commitments due under the contracts in 2016. The contract originally scheduled to expire in November 2016 was terminated by the Company. The Company paid approximately $266.7 million related to these contracts in 2016 and reported a pretax benefit to Other expense in 2017 and 2016 of $6.1 million and $4.3 million, respectively, for the final settlement of the contracts at less than the recorded costs. These amounts are included in Other expense in the Consolidated Statements of Operations.

Accumulated Other Comprehensive Loss

12 Months Ended

Dec. 31, 2018

Accumulated Other Comprehensive Loss [Abstract]

Accumulated Other Comprehensive Loss

Note P – Accumulated Other Comprehensive Loss

The components of Accumulated other comprehensive loss on the Consolidated Balance Sheets at December 31, 2018 and December 31, 2017 and the changes during 2017 and 2016 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, 2016	$	(446,555)	(171,305)		(10,352)		(628,212)
2017 components of other comprehensive income (loss):
Before reclassifications to income		171,725	(17,269)		–		154,456
Reclassifications to income		–	9,587	1	1,926	2	11,513
Net other comprehensive income		171,725	(7,682)		1,926		165,969
Balance at December 31, 2017		(274,830)	(178,987)		(8,426)		(462,243)
2018 components of other comprehensive income (loss):
Before reclassifications to income		(145,022)	(16,839)		(1,815)		(163,676)
Reclassifications to income		–	13,790	1	2,342	2	16,132
Net other comprehensive income (loss)		(145,022)	(3,049)		527		(147,544)
Balance at December 31, 2018	$	(419,852)	(182,036)		(7,899)		(609,787)

Reclassifications before taxes of $17,313 and $14,821 are included in the computation of net periodic benefit expense in 2018 and 2017, respectively. See Note L for additional information. Related income taxes of $3,523 and $5,234 are included in income tax expense in 2018 and 2017, respectively.

Reclassifications before taxes of $2,963 are included in Interest expense in both 2018 and 2017. Related income taxes of $622 and $1,037 are included in income tax expense in 2018 and 2017. See Note M for additional information.

Assets and Liabilities Measured at Fair Value

12 Months Ended

Dec. 31, 2018

Assets and Liabilities Measured at Fair Value [Abstract]

Assets and Liabilities Measured at Fair Value

Note Q – 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.

Note Q – Assets and Liabilities Measured at Fair Value (Contd.)

The fair value measurements for these assets and liabilities at December 31, 2018 and 2017 are presented in the following table.

December 31, 2018

December 31, 2017

(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

13,845

–

13,845

16,158

–

16,158

Contingent consideration

–

47,730

–

Commodity derivative contracts

–

39,093

–

39,093

13,845

–

47,730

61,575

16,158

39,093

–

55,251

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 Company’s contingent consideration liability (as further described in Note D) is measured at fair value on a recurring basis and is categorized as Level 3 in the fair value hierarchy. The contingent consideration is valued using a Monte Carlo simulation model, which used the following assumptions as of December 31, 2018: (i) the remaining expected life of 7 years, (ii) West Texas Intermediate forward strip pricing with historical volatility of 30.0%, and (iii) a risk-free interest rate of 2.752%. 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 fair value of West Texas Intermediate (WTI) crude oil contracts in 2018 and 2017 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 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, 2018 and 2017.

The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 2018 and 2017. 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,
	2018			2017
(Thousands of dollars)	Carrying Amount		Fair Value	Carrying Amount	Fair Value
Financial assets (liabilities):
Current and long-term debt	$	(3,237,717)	(3,003,388)	(2,916,422)	(2,993,003)

Note Q – Assets and Liabilities Measured at Fair Value (Contd.)

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.

As a result of significantly lower commodity prices during 2016, the Company recognized $95.1 million, respectively, in pretax noncash impairment charges related primarily to producing properties.

The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, costs and a discount rate believed to be consistent with those used by principal market participants in the applicable region.

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




	Year Ended December 31,
						Total
					Net Book	Pretax
					Value	(Noncash)
	Fair Value				Prior to	Impairment
(Thousands of dollars)		Level 1	Level 2	Level 3	Impairment	Expense
2018
Assets:
Impaired proved properties
United States Midland	$	–	–	37,690	57,690	20,000
2016
Assets:
Impaired proved properties
Western Canada	$	–	–	71,967	167,055	95,088

Commitments	12 Months Ended
Commitments	Dec. 31, 2018
Commitments [Abstract]
Commitments	Note R – Commitments The Company leases production and other facilities under operating leases. The most significant operating leases are associated with floating, production, storage and offloading facilities at the Kikeh oil field, the West Patricia field and the Gulf of Mexico Cascade Chinook facility. During each of the next five years, expected future net rental payments under all operating leases are approximately $188.6 million in 2019, $88.9 million in 2020, $61.9 million in 2021, $27.6 million in 2022 and $15.6 million in 2023. Rental expense for noncancelable operating leases, including contingent payments when applicable, was $75.3 million in 2018, $72.6 million in 2017, and $77.5 million in 2016. A lease of production equipment at the Kakap field offshore Sabah, Malaysia has been accounted for as a capital lease and is included in long-term debt discussed in Note H. The Company has entered into contracts to hire various drilling rigs and associated equipment for periods beyond December 31, 2018. These rigs will primarily be utilized for drilling operations in onshore U.S., Canada, and the Gulf of Mexico. Future commitments under these contracts, all of which expire by 2020, total $57.9 million. Gulf of Mexico rig contracts are short term in nature and can be terminated within 30 days without cost. A portion of these costs are expected to be borne by other working interest owners as partners of the Company when the wells are drilled. These drilling costs are generally expected to be accounted for as capital expenditures as incurred during the contract periods. Note R – Commitments (Contd.) 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 2024, while the Western Canada processing contracts call for minimum monthly payments through 2045. Future required minimum monthly payments for the next five years are $116.8 million in 2019, $128.0 million in 2020, $145.3 million in 2021, $136.2 million in 2022 and $123.7 million in 2023. 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 $52.2 million in 2018, $53.8 million in 2017, and $50.3 million in 2016. Commitments for capital expenditures were approximately $383.1 million at December 31, 2018, including $165.2 million for costs to develop deepwater U.S. Gulf of Mexico fields including new fields acquired as part of the MP GOM transaction, $103.0 million for field development and future work commitments in Malaysia, $60.0 million for development at Kaybob Duvernay in Canada, $31.4 million for work at Eagle Ford Shale, $14.7 million for exploration cost in Mexico, and $8.8 million for future work commitments in Vietnam.

Contingencies	12 Months Ended
Contingencies	Dec. 31, 2018
Contingencies [Abstract]
Contingencies	Note S – 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 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 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. Note S – Contingencies (Contd.) In 2015, the Company’s subsidiary in Canada identified a leak or leaks at an infield condensate transfer pipeline at the Seal field in a remote area of Alberta. The pipeline was immediately shut down and the Company’s emergency response plan was activated. In cooperation with local governmental regulators, and with the assistance of qualified consultants, an investigation and remediation plan is progressing as planned and the Company’s insurers were notified. Based on the assessments done to date, the Company recorded $43.9 million in Other expense during 2015 and a further $3.8 million in 2018 associated with the estimated costs of remediating the site. The Company has spent $44.7 million from inception to December 31, 2018. Further refinements in the estimated total cost to remediate the site may occur in future periods. The Company retained the responsibility for this remediation upon sale of the Seal field in 2017. As of December 31, 2018, the Company has a remaining accrued liability of $3.0 million associated with this event. In 2018, the Company received $25.0 million in respect to an insurance claim regarding this matter and the outcome of further insurance claims by the Company is pending. 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.

Common Stock Issued and Outstanding

12 Months Ended

Dec. 31, 2018

Stockholders' Equity and Common Stock Issued and Outstanding [Abstract]

Common Stock Issued and Outstanding

Note T – Common Stock Issued and Outstanding

Activity in the number of shares of Common Stock issued and outstanding for the three years ended December 31, 2018 is shown below.



(Number of shares outstanding)	2018	2017	2016
Beginning of year	172,572,873	172,202,177	172,034,711
Stock options exercised 1	21,200	–	–
Restricted stock awards 1	464,756	368,132	158,504
Employee stock purchase and thrift plans	–	2,564	8,962
Treasury shares purchased	–	–	–
End of year	173,058,829	172,572,873	172,202,177

1 Shares 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.

Business Segments

12 Months Ended

Dec. 31, 2018

Business Segments [Abstract]

Business Segments

Note U – 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, Malaysia 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 2018, 2017, and 2016, sales to Phillips 66 and affiliated companies represented approximately 12%, 14% and 17%, 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 U.K. downstream assets during 2015. 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. These operations have been reported as Discontinued operations for all periods presented in these consolidated financial statements.

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.


Segment Information	Exploration and Production
(Millions of dollars)	United States		Canada1	Malaysia	Other	Total E&P
Year ended December 31, 2018
Segment income (loss)	$	242.9	51.1	269.5	(16.6)	546.9
Revenues from external customers		1,289.6	438.6	854.2	22.2	2,604.6	2
Interest income		–	–	–	–	–
Interest expense, net of capitalization		–	–	–	0.2	0.2
Income tax expense (benefit)		68.1	14.5	143.3	(25.3)	200.6
Significant noncash charges (credits)
Depreciation, depletion and amortization		519.5	232.4	198.6	3.5	954.0
Accretion of asset retirement obligations		19.5	7.7	17.4	–	44.6
Amortization of undeveloped leases		36.8	0.8	–	2.5	40.1
Impairment of assets		20.0	–	–	–	20.0
Deferred and noncurrent income taxes		68.1	16.5	(0.5)	(25.7)	58.4
Additions to property, plant, equipment		1,343.5	373.8	138.6	15.9	1,871.8
Total assets at year-end		6,342.9	1,711.9	1,670.2	188.1	9,913.1
Year ended December 31, 2017
Segment income (loss)	$	(8.9)	112.5	224.2	(37.5)	290.3
Revenues from external customers		944.3	485.5	781.1	–	2,210.9
Interest income		–	–	–	–	–
Interest expense, net of capitalization		–	–	–	–	–
Income tax expense (benefit)		(0.8)	44.4	126.4	(36.2)	133.8
Significant noncash charges (credits)
Depreciation, depletion and amortization		546.1	185.4	204.6	3.8	939.9
Accretion of asset retirement obligations		17.4	7.9	17.3	–	42.6
Amortization of undeveloped leases		60.2	1.6	–	–	61.8
Deferred and noncurrent income taxes		2.5	55.3	(3.7)	(36.2)	17.9
Additions to property, plant, equipment		534.8	267.6	16.0	37.6	856.0
Total assets at year-end		5,186.2	1,725.8	1,670.1	154.2	8,736.3
Year ended December 31, 2016
Segment loss	$	(164.2)	(35.9)	171.1	(54.7)	(83.7)
Revenues from external customers		749.1	365.3	753.4	0.2	1,868.0
Interest income		–	–	–	–	–
Interest expense, net of capitalization		–	–	–	–	–
Income tax expense (benefit)		(65.7)	(134.3)	85.9	(18.8)	(132.9)
Significant noncash charges (credits)
Depreciation, depletion and amortization		600.5	203.2	227.7	5.9	1,037.3
Accretion of asset retirement obligations		17.1	13.3	16.3	–	46.7
Amortization of undeveloped leases		38.4	4.5	–	0.5	43.4
Impairment of assets		–	95.1	–	–	95.1
Deferred and noncurrent income taxes		(108.4)	(175.8)	(8.5)	(18.3)	(311.0)
Additions to property, plant, equipment		269.8	361.3	101.4	(1.3)	731.2
Total assets at year-end		5,419.0	1,559.5	2,024.7	115.7	9,118.9

1 Includes Synthetic crude operations in 2016. This business was sold in June 2016.

2 Includes a pretax gain of $129.0 million on sale of Seal area heavy oil field sold in January 2017.



Geographic Information	Certain Long-Lived Assets at December 31
(Millions of dollars)	United States		Canada	Malaysia	United Kingdom	Other	Total
2018	$	6,634.3	1,644.6	1,325.4	–	153.3	9,757.6
2017		5,050.5	1,635.9	1,392.3	–	141.3	8,220.0
2016		5,121.6	1,451.4	1,637.0	–	106.2	8,316.2



Segment Information — Continued
(Millions of dollars)	Corporate and Other		Discontinued Operations	Consolidated Total
Year ended December 31, 2018
Segment income (loss)	$	(123.9)	(3.5)	419.5
Revenues from external customers		(34.0)	–	2,570.6
Interest income		8.0	–	8.0
Interest expense, net of capitalization		181.4	–	181.6
Income tax expense (benefit)		(191.3)	–	9.3
Significant noncash charges (credits)
Depreciation, depletion and amortization		17.9	–	971.9
Accretion of asset retirement obligations		–	–	44.6
Amortization of undeveloped leases		–	–	40.1
Deferred and noncurrent income taxes		(242.1)	–	(183.7)
Additions to property, plant, equipment		22.7	–	1,894.5
Total assets at year-end		1,118.5	20.9	11,052.5
Year ended December 31, 2017
Segment income (loss)	$	(607.5)	(0.9)	(311.8)
Revenues from external customers		4.6	–	2,225.1
Interest income		7.4	–	7.4
Interest expense, net of capitalization		181.8	–	181.8
Income tax expense (benefit)		245.6	–	382.7
Significant noncash charges (credits)
Depreciation, depletion and amortization		17.8	–	957.7
Accretion of asset retirement obligations		–	–	42.6
Amortization of undeveloped leases		–	–	61.8
Deferred and noncurrent income taxes		242.5	–	260.4
Additions to property, plant, equipment		14.8	–	870.8
Total assets at year-end		1,101.7	22.9	9,860.9

Year ended December 31, 2016
Segment loss	$	(149.1)	(2.0)	(276.0)
Revenues from external customers		6.6	–	1,811.2
Interest income		2.9	–	2.9
Interest expense, net of capitalization		148.2	–	148.2
Income tax expense (benefit)		(64.1)	–	(219.2)
Significant noncash charges (credits)
Depreciation, depletion and amortization		16.8	–	1,054.1
Accretion of asset retirement obligations		–	–	46.7
Amortization of undeveloped leases		–	–	43.4
Impairment of assets		–	–	95.1
Deferred and noncurrent income taxes		(76.8)	–	(387.8)
Additions to property, plant, equipment		21.9	–	753.1
Total assets at year-end		1,149.9	27.1	10,295.9



Geographic Information	Revenues from External Customers for the Year
(Millions of dollars)	United States		Canada	Malaysia	Other	Total
2018	$	1,297.5	438.5	854.3	(19.7)	2,570.6
2017		958.3	485.7	781.1	–	2,225.1
2016		692.3	365.3	753.4	0.2	1,811.2

Supplemental Oil and Gas Information

12 Months Ended

Dec. 31, 2018

Supplemental Oil and Gas Information [Abstract]

Supplemental Oil and Gas Information

The following unaudited schedules are presented in accordance with required disclosures about Oil and 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 PROVED CRUDE OIL RESERVES

SCHEDULE 2 – SUMMARY OF PROVED NATURAL GAS LIQUIDS RESERVES

SCHEDULE 3 – 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 gas on the first calendar day of each month during the year. 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). The average prices used for 2017 were $51.34 per barrel for NYMEX crude oil (WTI), and $2.98 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.

Prior to its disposition in 2016, Murphy included synthetic crude oil from its five percent interest in the Syncrude project in Alberta, Canada in its proved crude oil reserves. All synthetic oil volumes reported as proved reserves in Schedule 1 are the final synthetic crude oil product.

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 and synthetic reserves, 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.

All proved reserves in Malaysia are associated with production sharing contracts for Blocks SK 309/311, K and H. Malaysia reserves include oil and gas to be received for both cost recovery and profit provisions under the contract. At December 31, 2018, liquids and natural gas proved reserves associated with the production sharing contracts in Malaysia totaled 51.7 million barrels and 468.2 billion cubic feet (BCF), respectively. At December 31, 2018, approximately 26.1 BCF of natural gas proved reserves in Malaysia relate to fields in Block K for which the Company expects to receive sale proceeds of approximately $0.24 per thousand cubic feet. Sales price for other natural gas produced in Malaysia is based on market-driven prices.

SCHEDULE 6 – STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND 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, a decrease from the previous rate of 35%.

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 6 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, 2018.

Schedule 1 – Summary of Proved Crude Oil Reserves Based on Average Prices for 2015 – 2018



	Crude & Synthetic Oil	Crude Oil				Synthetic Oil 1
(Millions of barrels)	Total	Total	United States	Canada	Malaysia	Canada
Proved developed and undeveloped crude oil / synthetic oil reserves:
December 31, 2015	456.2	341.4	238.9	27.9	74.6	114.8
Revisions of previous estimates	(5.8)	(5.8)	(10.9)	2.5	2.6	–
Extensions and discoveries	11.0	11.0	8.6	–	2.4	–
Purchases of properties	26.3	26.3	–	26.3	–	–
Sales of properties	(121.0)	(7.8)	(4.5)	(3.3)	–	(113.2)
Production	(37.7)	(36.1)	(17.7)	(4.5)	(13.9)	(1.6)
December 31, 2016	329.0	329.0	214.4	48.9	65.7	(0.0)
Revisions of previous estimates	(6.0)	(6.0)	(4.7)	2.3	(3.6)	–
Improved recovery	2.0	2.0	–	–	2.0	–
Extensions and discoveries	31.6	31.6	27.2	4.4	–	–
Purchases of properties	4.7	4.7	4.7	–	–	–
Production	(33.2)	(33.2)	(16.9)	(4.1)	(12.2)	–
December 31, 2017	328.1	328.1	224.7	51.5	51.9	–
Revisions of previous estimates	(15.3)	(15.3)	(15.0)	(8.0)	7.7	–
Improved recovery	0.8	0.8	–	–	0.8	–
Extensions and discoveries	58.9	58.9	42.9	16.0	–	–
Purchases of properties	93.6	93.6	92.3	–	1.3	–
Production	(33.6)	(33.6)	(18.4)	(4.5)	(10.7)	–
December 31, 2018 2	432.5	432.5	326.5	55.0	51.0	–
Proved developed crude oil/ synthetic oil reserves:
December 31, 2015	326.6	211.8	125.9	23.8	62.1	114.8
December 31, 2016	184.9	184.9	113.9	19.2	51.8	–
December 31, 2017	185.5	185.5	126.3	21.9	37.3	–
December 31, 2018 3	249.3	249.3	189.0	23.3	37.0	–
Proved undeveloped crude oil reserves:
December 31, 2015	129.6	129.6	113.0	4.1	12.5	–
December 31, 2016	144.1	144.1	100.5	29.7	13.9	–
December 31, 2017	142.6	142.6	98.4	29.6	14.6	–
December 31, 2018 4	183.2	183.2	137.5	31.7	14.0	–

1 All synthetic oil operations were sold in June 2016.

2 Includes total proved reserves of 25.5 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.

3 Includes proved developed reserves of 19.1 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.

4 Includes proved undeveloped reserves of 6.4 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.

Schedule 1 – Summary of Proved Crude Oil and Synthetic Oil Reserves Based on Average Prices

for 2015 – 2018 – Continued

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 removing locations in lower performing areas of the 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 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 Western 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.

2016 Comments for Proved Crude Oil and Synthetic Oil Reserves Changes

Revisions of previous estimates – The 2016 negative crude oil revision in the U.S. was primarily attributable to impacts of lower price on Eagle Ford Shale volumes and reduced performance in a particular location, partially offset by improved Eagle Ford Shale costs and drilling results in the Gulf of Mexico. The positive Canadian oil reserves revisions in 2016 resulted from improved Kaybob Duvernay performance and an increase at Terra Nova due to development drilling. The positive revisions for crude oil reserves in Malaysia was attributable to improved performance and lower government entitlement under the terms of the respective production sharing contracts due to lower oil prices, which collectively more than offset a negative revision at Kikeh following updated decline curve analysis.

2016 Comments for Proved Crude Oil and Synthetic Oil Reserves Changes (Contd.)

Extensions and discoveries – In 2016, proved oil reserves were added in the U.S. for drilling activities in the Eagle Ford Shale, and deeper oil-water contacts realized at a field in Malaysia.

Purchases of properties – In 2016, the Company’s Canadian subsidiary acquired working interests in the Kaybob Duvernay and liquids rich Placid Montney areas. The crude oil reserves are all associated with the Kaybob Duvernay area.

Sales of properties – In the U.S., proved oil reserves were reduced following the sale of certain non-core Eagle Ford Shale acreage. In Canada, the Company sold its interests in both a heavy oil field and a synthetic oil project.

Schedule 2 – Summary of Proved Natural Gas Liquids (NGL) Reserves Based on Average Prices

for 2015 – 2018




(Millions of barrels)	Total	United States	Canada	Malaysia
Proved developed and undeveloped NGL reserves:
December 31, 2015	36.4	35.4	0.4	0.6
Revisions of previous estimates	1.6	1.2	0.2	0.2
Extensions and discoveries	2.9	2.8	0.1	–
Purchase of properties	5.1	–	5.1	–
Production	(3.5)	(3.0)	(0.2)	(0.3)
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	–
Purchases 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 1	54.2	47.6	5.9	0.7
Proved developed NGL reserves:
December 31, 2015	21.6	20.7	0.3	0.6
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 2	27.3	24.9	1.7	0.7
Proved undeveloped NGL reserves:
December 31, 2015	14.8	14.7	0.1	–
December 31, 2016	20.3	15.6	4.7	–
December 31, 2017	24.3	19.7	4.6	–
December 31, 2018 3	26.9	22.7	4.2	–

1 Includes total proved reserves of 1.1 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

2 Includes proved developed reserves of 0.8 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

3 Includes proved undeveloped reserves of 0.3 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

Schedule 2 – Summary of Proved Natural Gas Liquids (NGL) Reserves Based on Average Prices

for 2015 – 2018 – Continued

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 removing locations in lower performing areas of the Kaybob Duvernay. The positive revisions for NGL reserves in Malaysia were principally attributable to improved performance for 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 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.

2016 Comments for Proved Natural Gas Liquids Reserves Changes

Revisions of previous estimates – The positive 2016 NGL proved reserves revision was primarily in the Eagle Ford Shale area based on an updated ratio of oil to gas production.

Extensions and discoveries – Proved NGL reserves were added primarily from drilling activities in the Eagle Ford Shale area.

Purchase of properties – In Canada, proved NGL reserves were added following the acquisition of acreage in both the Kabob Duvernay and liquids rich Placid Montney areas.

Schedule 3 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2015 – 2018



(Billions of cubic feet)	Total	United States	Canada	Malaysia
Proved developed and undeveloped natural gas reserves:
December 31, 2015	1,688.8	232.4	909.6	546.8
Revisions of previous estimates	43.3	0.1	45.3	(2.1)
Improved recovery	164.2	6.4	120.2	37.6
Extensions and discoveries	122.3	–	122.3	–
Sales of properties	(2.2)	(0.1)	(2.1)	–
Production	(138.4)	(19.4)	(76.4)	(42.6)
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 1	2,143.6	309.0	1,366.4	468.2
Proved developed natural gas reserves:
December 31, 2015	783.5	148.3	453.5	181.7
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 2	921.6	198.3	595.0	128.3
Proved undeveloped natural gas reserves:
December 31, 2015	905.3	84.1	456.1	365.1
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 3	1,222.0	110.7	771.4	339.9

1 Includes total proved reserves of 10.8 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

2 Includes proved developed reserves of 8.2 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

3 Includes proved undeveloped reserves of 2.6 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

Schedule 3 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2015 – 2018 – Continued

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 removing locations in lower performing areas of the Kaybob Duvernay asset 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 gas prices.

Improved recovery – The 2018 Malaysia natural gas proved reserve addition was due to favorable impacts from 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 Western 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 Western 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 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 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 Western 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 Western 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.

2016 Comments for Proved Natural Gas Reserves Changes

Revisions of previous estimates – The 2016 positive natural gas revisions in Canada were attributable to updated well type curves and field development techniques in both the Montney and Duvernay areas of Western Canada. The negative revision for natural gas reserves in Malaysia was primarily attributable to the removal of Sarawak area proved reserves resulting from the government’s decision to delay certain field development plans.

Extensions and discoveries – In 2016, 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 area. In Malaysia, proved natural gas reserves were added in Block H as the Permai field was added to the field development plan.

Purchase of properties – In Canada, proved natural gas reserves were added following the acquisition of acreage in both the Kaybob Duvernay and liquids rich Placid Montney areas.

2016 Comments for Proved Natural Gas Reserves Changes (Contd.)

Sales of properties – Proved natural gas reserves were reduced following the sale of certain non-core Eagle Ford Shale acreage in the U.S. and the associated gas related to the sale of a heavy oil field in Canada.

Schedule 4 – Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities



(Millions of dollars)	United States		Canada		Malaysia	Other	Total
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
Year ended December 31, 2016
Property acquisition costs
Unproved	$	18.6	–		–	–	18.6
Proved		–	206.7		–	–	206.7
Total acquisition costs		18.6	206.7	–	–	–	225.3
Exploration costs 1		18.5	3.6		6.0	42.0	70.1
Development costs 1		239.7	165.1		102.9	0.3	508.0
Total costs incurred		276.8	375.4		108.9	42.3	803.4
Charged to expense
Dry hole expense		0.4	–		4.5	10.2	15.1
Geophysical and other costs		5.7	3.6		0.7	33.4	43.4
Total charged to expense		6.1	3.6		5.2	43.6	58.5
Property additions	$	270.7	371.8		103.7	(1.3)	744.9

1 Includes noncash asset retirement costs as follows:



2018
Exploration costs	$	–	–	–	–	–
Development costs		366.0	–	7.3	0.2	373.5
	$	366.0	–	7.3	0.20	373.5
2017
Exploration costs	$	–	–	–	–	–
Development costs		37.6	6.3	8.4	–	52.3
	$	37.6	6.3	8.4	–	52.3
2016
Exploration costs	$	–	–	–	–	–
Development costs		0.9	10.5	2.3	–	13.7
	$	0.9	10.5	2.3	–	13.7

Schedule 5 – Results of Operations for Oil and Gas Producing Activities 1




	United
(Millions of dollars)	States		Canada	Malaysia	Other	Total
Year ended December 31, 2018
Revenues
Crude oil and natural gas liquids sales	$	1,245.3	291.2	708.8	6.1	2,251.4
Natural gas sales		42.9	147.6	144.7	–	335.2
Total oil and gas revenues		1,288.2	438.8	853.5	6.1	2,586.6
Other operating revenues		1.4	(0.2)	0.7	16.1	18.0
Total revenues		1,289.6	438.6	854.2	22.2	2,604.6
Costs and expenses
Lease operating expenses		230.5	122.6	202.1	0.7	555.9
Severance and ad valorem taxes		50.9	1.2	–	–	52.1
Exploration costs charged to expense		29.4	0.6	2.2	31.6	63.8
Undeveloped lease amortization		36.8	0.8	–	2.5	40.1
Depreciation, depletion and amortization		519.5	232.4	198.6	3.5	954.0
Accretion of asset retirement obligations		19.5	7.7	17.4	–	44.6
Impairment of assets		20.0	–	–	–	20.0
Redetermination expense		–	–	11.3	–	11.3
Selling and general expenses		49.0	26.8	10.8	23.5	110.1
Other expenses (benefits)		23.0	(19.1)	(1.0)	2.3	5.2
Total costs and expenses		978.6	373.0	441.4	64.1	1,857.1
Results of operations before taxes		311.0	65.6	412.8	(41.9)	747.5
Income tax expense (benefit)		68.1	14.5	143.3	(25.3)	200.6
Results of operations	$	242.9	51.1	269.5	(16.6)	546.9
Year ended December 31, 2017
Revenues
Crude oil and natural gas liquids sales	$	903.7	203.7	639.9	–	1,747.3
Natural gas sales		37.9	155.1	138.2	–	331.2
Total oil and gas revenues		941.6	358.8	778.1	–	2,078.5
Other operating revenues		2.7	126.7	3.0	–	132.4
Total revenues		944.3	485.5	781.1	–	2,210.9
Costs and expenses
Lease operating expenses		198.5	101.1	168.8	–	468.4
Severance and ad valorem taxes		42.2	1.5	–	–	43.7
Exploration costs charged to expense		7.8	0.5	2.4	50.3	61.0
Undeveloped lease amortization		60.2	1.6	–	–	61.8
Depreciation, depletion and amortization		546.1	185.4	204.6	3.8	939.9
Accretion of asset retirement obligations		17.4	7.9	17.3	–	42.6
Redetermination expense		–	–	15.0	–	15.0
Selling and general expenses		61.8	28.3	14.0	19.6	123.7
Other expenses		20.0	2.3	8.4	–	30.7
Total costs and expenses		954.0	328.6	430.5	73.7	1,786.8
Results of operations before taxes		(9.7)	156.9	350.6	(73.7)	424.1
Income tax expense (benefit)		(0.8)	44.4	126.4	(36.2)	133.8
Results of operations	$	(8.9)	112.5	224.2	(37.5)	290.3

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

Schedule 5 – Results of Operations for Oil and Gas Producing Activities 1 – Continued



			Canada
	United		Conven-
(Millions of dollars)	States		tional	Synthetic	Malaysia	Other	Total
Year ended December 31, 2016
Revenues
Crude oil and natural gas liquids sales	$	714.1	171.7	60.7	623.7	–	1,570.2
Natural gas sales		35.1	130.0	–	127.6	–	292.7
Total oil and gas revenues		749.2	301.7	60.7	751.3	–	1,862.9
Other operating revenues		(0.1)	(0.7)	3.6	2.1	0.2	5.1
Total revenues		749.1	301.0	64.3	753.4	0.2	1,868.0
Costs and expenses
Lease operating expenses		218.6	102.6	69.8	168.4	–	559.4
Severance and ad valorem taxes		37.0	4.3	2.5	–	–	43.8
Exploration costs charged to expense		6.1	3.6	–	5.2	43.6	58.5
Undeveloped lease amortization		38.4	4.5	–	–	0.5	43.4
Depreciation, depletion and amortization		600.5	186.7	16.5	227.7	5.9	1,037.3
Accretion of asset retirement obligations		17.1	10.9	2.4	16.3	–	46.7
Impairment of assets		–	95.1	–	–	–	95.1
Redetermination expense		–	–	–	39.1	–	39.1
Selling and general expenses		54.0	28.2	0.5	15.4	33.6	131.7
Other expenses		7.3	7.9	–	24.3	(9.9)	29.6
Total costs and expenses		979.0	443.8	91.7	496.4	73.7	2,084.6
Results of operations before taxes		(229.9)	(142.8)	(27.4)	257.0	(73.5)	(216.6)
Income tax expense (benefit)		(65.7)	(58.9)	(75.4)	85.9	(18.8)	(132.9)
Results of operations	$	(164.2)	(83.9)	48.0	171.1	(54.7)	(83.7)

1 Results exclude corporate overhead, interest and discontinued operations.

Schedule 6 – Standardized Measure of Discounted Future Net Cash Flows Relating to

Proved Oil and Gas Reserves 1



(Millions of dollars)	United States		Canada	Malaysia	Total
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
December 31, 2016
Future cash inflows	$	9,477.9	3,752.7	4,318.7	17,549.3
Future development costs		(1,691.1)	(1,143.6)	(763.8)	(3,598.5)
Future production costs		(3,981.6)	(2,329.7)	(2,661.2)	(8,972.5)
Future income taxes		(118.9)	(81.3)	(73.3)	(273.5)
Future net cash flows		3,686.3	198.1	820.4	4,704.8
10% annual discount for estimated timing of cash flows		(1,799.5)	(95.0)	(230.3)	(2,124.8)
Standardized measure of discounted future net cash flows	$	1,886.8	103.1	590.1	2,580.0

1 2018 includes noncontrolling interest in MP GOM.

Schedule 6 – Standardized Measure of Discounted Future Net Cash Flows Relating to

Proved Oil and Gas Reserves – Continued 1

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



(Millions of dollars)		2018	2017	2016
Net changes in prices and production costs	$	2,972.6	2,428.4	(1,476.1)
Net changes in development costs		(1,891.1)	(724.4)	544.9
Sales and transfers of oil and gas produced, net of production costs		(1,978.6)	(1,576.0)	(1,196.3)
Net change due to extensions and discoveries		1,930.3	807.9	280.5
Net change due to purchases and sales of proved reserves		3,152.4	85.9	(583.4)
Development costs incurred		1,017.3	802.7	479.6
Accretion of discount		469.5	270.9	428.1
Revisions of previous quantity estimates		(347.8)	(109.5)	(49.2)
Net change in income taxes		(967.6)	(643.0)	292.8
Net increase (decrease)		4,357.0	1,342.9	(1,279.1)
Standardized measure at January 1		3,922.9	2,580.0	3,859.1
Standardized measure at December 31	$	8,279.9	3,922.9	2,580.0

1 2018 includes noncontrolling interest in MP GOM.

Schedule 7 – Capitalized Costs Relating to Oil and Gas Producing Activities



(Millions of dollars)	United States		Canada	Malaysia	Other	Total
December 31, 2018
Unproved oil and gas properties	$	394.2	250.0	21.2	176.9	842.3
Proved oil and gas properties		11,678.3	3,693.0	6,263.5	–	21,634.8
Gross capitalized costs		12,072.5	3,943.0	6,284.7	176.9	22,477.1
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties		(129.3)	(213.5)	–	(25.4)	(368.2)
Proved oil and gas properties		(5,433.7)	(2,088.8)	(4,963.5)	–	(12,486.0)
Net capitalized costs	$	6,509.5	1,640.7	1,321.2	151.5	9,622.9
December 31, 2017
Unproved oil and gas properties	$	360.9	286.8	20.5	162.1	830.3
Proved oil and gas properties		9,606.4	3,603.4	6,139.7	–	19,349.5
Gross capitalized costs		9,967.3	3,890.2	6,160.2	162.1	20,179.8
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties		(149.5)	(230.7)	–	(21.8)	(402.0)
Proved oil and gas properties		(4,893.8)	(2,027.9)	(4,774.5)	–	(11,696.2)
Net capitalized costs	$	4,924.0	1,631.6	1,385.7	140.3	8,081.6

Note:Unproved oil and 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.

Supplemental Quarterly Information

12 Months Ended

Dec. 31, 2018

Supplemental Quarterly Information [Abstract]

Supplemental Quaterly Information



(Millions of dollars except per share amounts)	First Quarter		Second Quarter	Third Quarter	Fourth Quarter	Year
Year ended December 31, 2018 1
Revenue from contracts with customers	$	606.9	655.2	659.8	664.7	2,586.6
Income (loss) from continuing operations before income taxes		97.0	82.3	146.8	106.2	432.3
Income (loss) from continuing operations		168.7	45.9	95.8	112.6	423.0
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		0.98	0.26	0.55	0.60	2.39
Diluted		0.97	0.26	0.55	0.59	2.37
Net income (loss) per Common share
Basic		0.97	0.26	0.54	0.60	2.38
Diluted		0.96	0.26	0.54	0.59	2.36
Cash dividend per Common share		0.25	0.25	0.25	0.25	1.00
Year ended December 31, 2017
Revenue from contracts with customers	$	509.0	477.6	511.2	580.5	2,078.5
Loss from continuing operations before income taxes		154.9	(21.9)	(63.6)	2.4	71.8
Income (loss) from continuing operations		57.5	(17.3)	(66.3)	(284.8)	(310.9)
Net income (loss) attributable to Murphy		58.5	(17.6)	(65.9)	(286.8)	(311.8)
Income from continuing operations per Common share
Basic		0.33	(0.10)	(0.38)	(1.65)	(1.81)
Diluted		0.33	(0.10)	(0.38)	(1.65)	(1.81)
Net income (loss) per Common share
Basic		0.34	(0.10)	(0.38)	(1.66)	(1.81)
Diluted		0.34	(0.10)	(0.38)	(1.66)	(1.81)
Cash dividend per Common share		0.25	0.25	0.25	0.25	1.00

1 2018 includes noncontrolling interest in MP GOM.

Schedule II - Valuation Accounts and Reserves

12 Months Ended

Dec. 31, 2018

Schedule II - Valuation Accounts and Reserves [Abstract]

Schedule II - Valuation Accounts and Reserves



(Millions of dollars)	Balance at January 1		Charged to Expense	Deductions	Other 1	Balance at December 31
2018
Deducted from asset accounts:
Allowance for doubtful accounts	$	1.6	–	–	–	1.6
Deferred tax asset valuation allowance		476.3	3.3	–	(265.9)	213.7
2017
Deducted from asset accounts:
Allowance for doubtful accounts	$	1.6	–	–	–	1.6
Deferred tax asset valuation allowance		305.4	18.6	–	152.3	476.3
2016
Deducted from asset accounts:
Allowance for doubtful accounts	$	1.6	–	–	–	1.6
Deferred tax asset valuation allowance		294.4	25.7	–	(14.7)	305.4

1Amounts in 2017 and 2016 for deferred tax asset valuations are primarily associated with an increase in foreign tax credit carryforwards. The amount in 2018 for deferred tax asset valuation allowance is primarily associated with utilization of foreign tax credit carryforwards.

Significant Accounting Policies (Policies)	12 Months Ended
Significant Accounting Policies (Policies)	Dec. 31, 2018
Significant Accounting Policies [Abstract]
Nature of Business	NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries. The Company primarily produces oil and natural gas in the United States, Canada and Malaysia and conducts oil and natural gas exploration activities worldwide. The Company sold its interest in a Canadian synthetic oil operation in 2016 and its Canadian heavy oil assets in early 2017. 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 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 the new Gulf of Mexico transaction (MP GOM) with Petrobras Americas Inc (PAI), 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. Beginning in 2017, certain reclassifications in presentation have been made to the Consolidated Statements of Operations. The Company now presents a separate “Operating income (loss) from continuing operations” subtotal on the Consolidated Statements of Operations. Additionally, “Interest and other income (loss),” which includes foreign exchange gains and losses, has been reclassified from a component of total revenues and is now presented below Operating income (loss) from continuing operations. “Interest expense” and “Capitalized interest” have also been combined into the “Interest expense, net” line item and are now presented below “Operating income (loss) from continuing operations.” Previously reported periods have been reclassified to conform to the current period presentation. These reclassifications did not impact previously reported Income (loss) from continuing operations before income taxes, Loss from continuing operations, or Net Loss.
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. Revenue is presented as the Company’s share net of certain costs associated with generation of Revenue. Examples of costs that reduce revenue include transportation, gathering, compression, and processing fees in U.S. and Canada, as well as certain required payments associated with production sharing contracts (PSCs) and export taxes in Malaysia. Natural gas imbalances occur when the Company’s actual 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 gas imbalances when it has sold more than its working interest of gas production and the estimated remaining reserves make it doubtful that partners can recoup their share of production from the field. At December 31, 2018 and 2017, 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, 2018 and 2017, 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 gas production operations. Unsold crude oil production is carried in inventory at the lower of cost, generally applied on a first-in, first-out (FIFO) basis, or market, and includes costs incurred to bring the inventory to its existing condition. Materials and supplies inventories are valued at the lower of average cost or estimated 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 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 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. 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. In 2016, charges of $95.1 million at its Terra Nova field offshore Canada and its Western Canada onshore heavy oil producing properties were reported. 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 gas production facilities and site restoration are charged against the related liability. Note A – Significant Accounting Policies (Contd.) 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 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. Additionally, certain natural gas processing facilities and related equipment in Malaysia are being depreciated on a straight-line basis over their estimated useful life ranging from 20 to 25 years.
Capitalized Interest	Capitalized Interest – Interest associated with borrowings from third parties is capitalized on significant oil and 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.
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 bases 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. Prior to 2017, the Company did not provide U.S. deferred taxes for undistributed earnings of certain foreign subsidiaries when these earnings were considered indefinitely invested. 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. Also, 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. 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 Note A – Significant Accounting Policies (Contd.) 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

Revenue from Contracts with Customers (Tables)

12 Months Ended

Dec. 31, 2018

Revenue from Contracts with Customers [Abstract]

Disaggregation of Revenue

		For the Year Ended
		December 31,
(Thousands of dollars)		2018	2017	2016
Net crude oil and condensate revenue
United States – Onshore	$	778,198	644,023	508,045
– Offshore 1		403,523	208,984	172,022
Canada – Onshore		105,651	51,013	92,605
– Offshore		170,895	147,230	138,425
Malaysia – Sarawak		282,370	241,774	209,751
– Block K		406,653	378,401	403,912
Other		6,079	–	–
Total crude oil and condensate revenue		2,153,369	1,671,425	1,524,760

Net natural gas liquids revenue
United States – Onshore		53,335	43,804	28,316
– Offshore 1		10,269	6,894	5,781
Canada – Onshore		14,657	5,450	1,351
Malaysia – Sarawak		19,798	19,733	10,001
Total natural gas liquids revenue		98,059	75,881	45,449

Net natural gas revenue
United States – Onshore		28,335	27,460	24,281
– Offshore 1		14,525	10,480	10,839
Canada – Onshore		147,613	155,125	129,968
Malaysia – Sarawak		144,222	137,479	126,975
– Block K		504	698	619
Total natural gas revenue		335,199	331,242	292,682
Total revenue from contracts with customers		2,586,627	2,078,548	1,862,891

Gain (loss) on crude contracts		(41,975)	9,566	(63,412)
Other operating income		25,897	9,581	10,096
Gain on sale of assets		54	127,434	1,663
Total revenue	$	2,570,603	2,225,129	1,811,238

1 2018 includes revenue attributable to noncontrolling interest in MP GOM, effective November 30, 2018.

Current Long-Term Contracts Outstanding


Current Long-Term Contracts Outstanding at December 31, 2018
Location	Commodity	End Date	Description	Approximate Volumes
U.S.	Oil	Q3 2019	Fixed quantity delivery in Eagle Ford	4,000 BOED
U.S.	Oil	Q4 2021	Fixed quantity delivery in Eagle Ford	17,000 BOED
U.S.	Gas and NGL	Q2 2026	Deliveries from dedicated acreage in Eagle Ford	As produced
Canada	Gas	Q4 2020	Contracts to sell natural gas at Alberta AECO fixed prices	59 MMCFD
Canada	Gas	Q4 2020	Contracts to sell natural gas at USD Index pricing	60 MMCFD
Canada	Gas	Q4 2024	Contracts to sell natural gas at USD Index pricing	30 MMCFD
Canada	Gas	Q4 2026	Contracts to sell natural gas at USD Index pricing	38 MMCFD

Acquisition (Tables)

12 Months Ended

Dec. 31, 2018

Acquisition [Abstract]

Preliminary Puchase Price Allocation

(Thousands of dollars)
Cash consideration paid to PAI	$	794,623
Fair value of net assets contributed		166,797
Fair value of contingent consideration		52,540
Noncontrolling interest in acquired assets		253,490
Total purchase consideration	$	1,267,450


(Thousands of dollars)
Fair value of Property, Plant, and Equipment	$	1,617,052
Other assets		10,041
Less: Asset retirement obligations		(359,643)
Total net assets	$	1,267,450

Pro Forma Financial Information



	Years Ended December 31,
(Thousands of dollars, except per share amounts)		2018	2017
Revenues	$	2,825,169	2,816,458
Net Income Attributable to Murphy		603,231	(224,860)

Net Income Attributable to Murphy per Common Share
Basic	$	3.49	(1.30)
Diluted		3.46	(1.30)

Discontinued Operations and Assets Held for Sale (Tables)

12 Months Ended

Dec. 31, 2018

Discontinued Operations and Assets Held for Sale [Abstract]

Major Categories of Assets and Liabilities Reflected as Held for Sale



(Thousands of dollars)	2018		2017
Current assets
Cash	$	17,219	16,631
Accounts receivable		3,728	6,298
Total current assets held for sale	$	20,947	22,929
Current liabilities
Accounts payable	$	106	837
Refinery decommissioning cost		2,658	2,693
Total current liabilities associated with assets held for sale	$	2,764	3,530

Results of Operations Associated with Discontinued Operations



(Thousands of dollars)	2018		2017	2016
Revenues	$	6	854	1,464
Loss from operations before income taxes	$	(3,522)	(853)	(2,027)
Loss on sale before income taxes		–	–	–
Total loss from discontinued operations before taxes		(3,522)	(853)	(2,027)
Income tax expense		–	–	–
Loss from discontinued operations	$	(3,522)	(853)	(2,027)

Inventories (Tables)

12 Months Ended

Dec. 31, 2018

Inventories [Abstract]

Schedule of Inventory



	December 31,
	2018		2017
(Thousands of dollars)
Unsold crude oil	$	25,205	20,153
Materials and supplies		62,706	84,974
	$	87,911	105,127

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2018

Property, Plant And Equipment [Abstract]

Schedule of Property, Plant and Equipment



	December 31, 2018				December 31, 2017
(Thousands of dollars)	Cost		Net		Cost	Net
Exploration and production1	$	22,629,844	9,654,945	2	20,329,930	8,120,293	2
Corporate and other		193,471	102,619		170,842	99,738
	$	22,823,315	9,757,564		20,500,772	8,220,031
1 Includes unproved mineral rights as follows:	$	512,025	144,912		600,423	198,349

2. Includes $32,071 in 2018 and $38,670 in 2017 related to administrative assets and support equipment.

Schedule of Recognized Impairments


	December 31,
(Thousands of dollars)		2018	2017	2016
US Onshore (Midland)	$	20,000	–	–
Canada		–	–	95,088
Malaysia		–	–	–
	$	20,000	–	95,088

Net Changes in Capitalized Exploratory Well Costs



(Thousands of dollars)	2018		2017	2016
Beginning balance at January 1	$	175,640	148,500	130,514
Additions pending the determination of proved reserves		60,179	51,488	17,986
Reclassifications to proved properties based on the determination of proved reserves		(2,214)	(15,988)	–
Capitalized exploration well costs charged to expense		(4,521)	(8,360)	–
Ending balance at December 31	$	229,084	175,640	148,500

Aging of Capitalized Exploratory Well Costs



	2018				2017				2016
(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	$	61,096	1	1	$	41,480	3	2	$	20,481	1	1
One to two years		40,523	3	2		5,812	1	1		63,527	5	5
Two to three years		–	–	–		43,200	2	2		–	–	–
Three years or more		127,465	6	3		85,148	7	1		64,492	6	–
	$	229,084	10	6	$	175,640	13	6	$	148,500	12	6

Financing Arrangements and Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2018

Financing Arrangements and Long-Term Debt [Abstract]

Schedule of Long-term Debt


	December 31,
(Thousands of dollars)	2018		2017
Notes payable
4.00% notes, due June 2022	$	500,000	500,000
4.45% notes, due December 20221		600,000	600,000
6.875% notes, due August 2024		550,000	550,000
5.75% notes, due August 2025		550,000	550,000
7.05% notes, due May 2029		250,000	250,000
5.875% notes, due December 20421		350,000	350,000
Total notes payable		2,800,000	2,800,000
Unamortized debt issuance cost and discount on notes payable		(23,627)	(27,433)
Total notes payable, net of unamortized discount		2,776,373	2,772,567
Capitalized lease obligation, due through March 2029		136,344	143,855
Total debt including current maturities		2,912,717	2,916,422
Senior Unsecured Revolving Credit Facility		325,000	-
Current maturities		(10,583)	(9,902)
Total long-term debt	$	3,227,134	2,906,520

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligations [Abstract]

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



(Thousands of dollars)	2018		2017
Balance at beginning of year	$	722,139	781,057
Accretion expense		44,559	42,590
Liabilities incurred		13,886	52,331
Liabilities assumed from PAI		359,643	–
Revisions of previous estimates		(24,959)	(47,612)
Liabilities settled		(23,398)	(29,111)
Liabilities assumed by purchaser of oil and gas assets		–	(87,456)
Changes due to translation of foreign currencies		(8,966)	10,340
Balance at end of year		1,082,904	722,139
Current portion of liability at end of year1		(55,481)	(12,840)
Noncurrent portion of liability at end of year	$	1,027,423	709,299

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

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Income Taxes [Abstract]

Components of Income (Loss) from Continuing Operations Before Income Taxes and Income Tax Expense



(Thousands of dollars)	2018		2017	2016
Income (loss) from continuing operations before income taxes
United States	$	14,907	(299,349)	(595,196)
Foreign		417,431	371,151	102,081
Total	$	432,338	71,802	(493,115)
Income tax expense (benefit)
Federal – Current	$	(9,765)	–	-
– Deferred		(131,200)	156,065	(197,450)
Total Federal		(140,965)	156,065	(197,450)
State		3,299	4,230	13,984
Foreign – Current		202,775	122,318	146,861
– Deferred		(55,779)	100,125	(182,567)
Total Foreign		146,996	222,443	(35,706)
Total	$	9,330	382,738	(219,172)

Effective Income Tax Rates


(Thousands of dollars)	2018		2017	2016
Income tax expense (benefit) based on the U.S. statutory tax rate	$	90,791	25,131	(172,590)
Revaluation of deferred tax (US tax reform)		–	118,004	–
Tax impact of deemed repatriation of foreign invested earnings (U.S. tax reform)		(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		72,007	12,658	8,582
State income taxes, net of federal benefit		2,607	2,438	9,090
U.S. tax benefit on certain foreign upstream investments		(14,702)	(32,926)	(21,336)
Tax effects on sale of Canadian assets		–	–	(89,473)
Tax effects on sale of Malaysian assets		–	–	2,080
Increase in deferred tax asset valuation allowance related to other foreign exploration expenditures		3,283	18,601	25,734
Other, net		(8,956)	17,832	18,741
Total	$	9,330	382,738	(219,172)

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



(Thousands of dollars)	2018		2017
Deferred tax assets
Property and leasehold costs	$	491,660	488,584
Liabilities for dismantlements		88,075	98,444
Postretirement and other employee benefits		113,826	134,444
Alternative minimum tax		9,765	29,710
Foreign tax credit carryforwards		–	228,159
U. S. net operating loss		496,629	272,930
Other deferred tax assets		19,974	13,892
Total gross deferred tax assets		1,219,929	1,266,163
Less valuation allowance		(213,815)	(476,256)
Net deferred tax assets		1,006,114	789,907
Deferred tax liabilities
Deferred tax on undistributed foreign earnings		(5,000)	(65,000)
Accumulated depreciation, depletion and amortization		(742,562)	(669,638)
Other deferred tax liabilities		(28,802)	(2,824)
Total gross deferred tax liabilities		(776,364)	(737,462)
Net deferred tax assets	$	229,750	52,445

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



(Thousands of dollars)	2018		2017	2016
Balance at January 1	$	3,437	7,417	6,631
Additions for tax positions related to current year		454	769	756
Settlements due to lapse of time		(988)	(4,834)	–
Foreign currency translation effect		–	85	30
Balance at December 31	$	2,903	3,437	7,417

Incentive Plans (Tables)

12 Months Ended

Dec. 31, 2018

Incentive Plans [Abstract]

Share-Based Plans, Amounts Recognized



(Thousands of dollars)	2018		2017	2016
Compensation charged against income (loss) before income tax benefit	$	34,467	40,365	46,300
Related income tax benefit recognized in income		4,383	5,017	15,244

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



	2018	2017	2016

Fair value per option grant	N/A	$7.96	$5.03
Assumptions
Dividend yield	N/A	3.60%	4.00%
Expected volatility	N/A	41.00%	45.00%
Risk-free interest rate	N/A	1.97%	1.32%
Expected life	N/A	5.30 yrs.	5.20 yrs.

Changes in Stock Options Outstanding



	Number of Shares	Average Exercise Price

Outstanding at December 31, 2015	5,443,288	$	52.93
Granted at FMV	862,000		17.57
Exercised	–		-
Forfeited	(547,853)		44.23
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
Exercisable at December 31, 2015	3,542,352	$	52.26
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

Additional Information about Stock Options Outstanding



	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 $30.00	1,131,500	4.5	$	3,719,263	319,250	4	$	1,859,631
$31.00 to $50.00	817,350	2.9		–	817,350	2.9		–
$51.00 to $65.00	2,045,745	1.0		–	2,045,745	1.0		–
	3,994,595	2.4	$	3,719,263	3,182,345	1.8	$	1,859,631

Changes in Performance-Based RSU Outstanding



(Number of stock units)	2018	2017	2016
Outstanding at beginning of year	1,187,921	992,573	1,103,986
Granted	905,500	560,000	394,000
Vested and issued	(311,866)	(272,725)	(361,096)
Forfeited	(121,138)	(91,927)	(144,317)
Outstanding at end of year	1,660,417	1,187,921	992,573

Assumptions used in Valuation of Performance Awards Granted



	2018	2017	2016

Fair value per share at grant date	$22.99 - $30.56	$24.10 – $28.28	$12.21 – $16.34
Assumptions
Expected volatility	48.00%	47.00%	33.00%
Risk-free interest rate	2.30%	1.46%	0.93%
Stock beta	1.103	1.058	0.863
Expected life	3.0 yrs.	3.0 yrs.	3.0 yrs.

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



(Number of share units)	2018	2017	2016

Outstanding at beginning of year	1,035,980	923,282	477,244
Granted	823,803	419,720	503,555
Vested and issued	(233,456)	(217,633)	(32,092)
Forfeited	(87,473)	(89,389)	(25,425)
Outstanding at end of year	1,538,854	1,035,980	923,282

Employee and Retiree Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2018

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)	2018		2017	2018	2017
Change in benefit obligation
Obligation at January 1	$	881,932	815,593	106,276	106,679
Service cost		8,994	8,279	1,965	1,601
Interest cost		26,168	27,047	3,427	3,444
Participant contributions		–	–	2,104	2,075
Actuarial loss (gain)		(57,378)	60,855	(13,778)	(3,077)
Medicare Part D subsidy		–	–	325	318
Exchange rate changes		(12,742)	18,751	(67)	46
Benefits paid		(41,132)	(39,910)	(5,473)	(4,810)
Prior Service Cost		737	–	–	–
Other		(28,934)	(8,683)	–	–
Obligation at December 31		777,645	881,932	94,779	106,276
Change in plan assets
Fair value of plan assets at January 1		563,825	519,357	–	–
Actual return on plan assets		(18,951)	50,079	–	–
Employer contributions		24,357	24,918	3,044	2,417
Participant contributions		–	–	2,104	2,075
Medicare Part D subsidy		–	–	325	318
Exchange rate changes		(12,071)	18,064	–	–
Benefits paid		(41,132)	(39,910)	(5,473)	(4,810)
Other		(28,934)	(8,683)	–	–
Fair value of plan assets at December 31		487,094	563,825	–	–
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets		11,039	5,905	–	–
Other accrued liabilities		(9,175)	(8,856)	(5,101)	(5,392)
Deferred credits and other liabilities		(292,415)	(315,156)	(89,678)	(100,884)
Funded status and net plan liability recognized at December 31	$	(290,551)	(318,107)	(94,779)	(106,276)

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



(Thousands of dollars)	Pension Benefits		Other Postretirement Benefits
Net actuarial loss	$	(239,030)	13,969
Prior service (cost) credit		(5,568)	–
	$	(244,598)	13,969

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



(Thousands of dollars)	Pension Benefits		Other Postretirement Benefits
Net actuarial loss	$	(14,117)	(391)
Prior service (cost) credit		(956)	–
	$	(15,073)	(391)

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



	Projected Benefit Obligations			Accumulated Benefit Obligations		Fair Value of Plan Assets
(Thousands of dollars)	2018		2017	2018	2017	2018	2017
Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets	$	457,446	691,923	447,793	640,230	316,543	540,161
Unfunded nonqualified and directors' plans where accumulated benefit obligation exceeds fair value of plan assets		158,228	172,364	150,586	163,319	–	–
Unfunded other postretirement plans		94,808	106,276	94,808	106,276	–	–

Components of Net Periodic Benefit Expense


	Pension Benefits				Other Postretirement Benefits
(Thousands of dollars)		2018	2017	2016	2018	2017	2016
Service cost	$	8,994	8,279	8,136	1,965	1,601	1,864
Interest cost		26,168	27,047	25,185	3,427	3,444	3,800
Expected return on plan assets		(29,236)	(28,941)	(28,154)	–	–	–
Amortization of prior service cost (credit)		1,021	1,026	1,204	(38)	(74)	(75)
Amortization of transitional (asset) liability		–	–	–	–	–	–
Recognized actuarial loss		21,893	16,691	16,165	–	–	5
		28,840	24,102	22,536	5,354	4,971	5,594
Termination benefits expense		–	–	–	–	–	–
Curtailment expense		–	–	822	–	–	(19)
Net periodic benefit expense	$	28,840	24,102	23,358	5,354	4,971	5,575

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



	Benefit Obligations				Net Periodic Benefit Expense
	Pension Benefits		Other Postretirement Benefits		Pension Benefits		Other Postretirement Benefits
	December 31		December 31		Year		Year
	2018	2017	2018	2017	2018	2017	2018	2017
Discount rate	4.07%	3.42%	3.73%	3.73%	3.54%	3.66%	4.32%	4.33%
Expected return on plan assets	5.37%	5.64%	–	–	5.37%	5.64%	–	–
Rate of compensation increase	3.28%	3.52%	–	–	3.52%	3.52%	–	–

Benefit Payments Expected to be Paid in Future Years



(Thousands of dollars)	Pension Benefits		Other Postretirement Benefits
2018	$	37,266	5,754
2019		37,565	5,839
2020		38,606	5,994
2021		39,660	6,130
2022		39,908	6,171
2023-2027		207,633	32,109

One Percent Change in Assumed Health Care Cost Trend Rates



(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, 2018	$	1,049	(813)
Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2018		12,656	(10,350)

Weighted Average Asset Allocation for Funded Pension Benefit Plans



	December 31,
	2018		2017
Equity securities	56.0	%	60.3	%
Fixed income securities	42.2		37.2
Cash equivalents	1.8		2.5
	100.0	%	100.0	%

Fair Value Measurements of Retirement Plan Assets

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

Note L – Employee and Retiree Benefit Plans (Contd.)

At December 31, 2017, 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, 2017		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	$	67,343	67,343	–	–
U.S. small/midcap		24,544	24,544	–	–
Hedged funds and other alternative strategies		50,522	–	12,572	37,950
International commingled trust fund		83,960	–	83,960	–
Emerging market commingled equity fund		20,774	–	20,774	–
Fixed income securities:
U.S. fixed income		79,890	–	79,890	–
International commingled trust fund		13,122	–	13,122	–
Emerging market mutual fund		5,266	–	5,266	–
Cash and equivalents		5,871	5,871	–	–
Total Domestic Plans		351,292	97,758	215,584	37,950
Foreign Plans
Equity securities funds		78,666	–	78,666	–
Fixed income securities funds		103,314	–	103,314	–
Diversified pooled fund		23,665	–	23,665	–
Cash and equivalents		6,888	–	6,888	–
Total Foreign Plans		212,533	–	212,533	–
Total	$	563,825	97,758	428,117	37,950

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



(Thousands of dollars)	Hedged Funds and Other Alternative Strategies
Total at December 31, 2016		$	34,114
Actual return on plan assets:
Relating to assets held at the reporting date			3,836
Relating to assets sold during the period			–
Purchases, sales and settlements			–
Total at December 31, 2017			37,950
Actual return on plan assets:
Relating to assets held at the reporting date			(2,921)
Relating to assets sold during the period			–
Purchases, sales and settlements			–
Total at December 31, 2018		$	35,029

Foreign Plans [Member]

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)	2018		2017	2018	2017
Benefit obligation at December 31	$	173,860	222,483	812	791
Fair value of plan assets at December 31		170,551	212,535	–	–
Net plan liabilities recognized		3,309	9,948	812	791
Net periodic benefit expense (benefit)		3,983	194	146	133

Financial Instruments and Risk Management (Tables)

12 Months Ended

Dec. 31, 2018

Financial Instruments and Risk Management [Abstract]

Fair Value of Derivative Instruments Not Designated as Hedging Instruments



	December 31, 2018			December 31, 2017
(Thousands of dollars)	Asset (Liability) Derivatives			Asset (Liability) Derivatives
Type of Derivative Contract	Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value
Commodity	Accounts receivable	$	3,837	Accounts payable	$	(39,093)

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	2018		2017	2016
Commodity	(Loss) gain on crude contracts	$	(41,975)	9,566	(63,412)
Foreign exchange	Interest and other income (loss)		–	–	26,714
		$	(41,975)	9,566	(36,698)

Earnings per Share (Tables)

12 Months Ended

Dec. 31, 2018

Earnings per Share [Abstract]

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



(Weighted-average shares)	2018	2017	2016
Basic method	172,974,491	172,524,061	172,173,012
Dilutive stock options 1	1,234,274	–	–
Diluted method	174,208,765	172,524,061	172,173,012

Anti Dilutive Securities Not Included in Computation of Diluted EPS



	2018	2017	2016
Antidilutive stock options excluded from diluted shares	3,942,296	4,901,269	5,757,435
Weighted average price of these options	$46.77	$45.74	$48.46

Other Financial Information (Tables)

12 Months Ended

Dec. 31, 2018

Other Financial Information [Abstract]

Noncash Operating Working Capital (Increase) Decrease



(Thousands of dollars)	2018		2017	2016
Accounts receivable	$	(89,070)	114,401	119,671
Inventories		12,216	26,883	(5,171)
Prepaid expenses		(17,341)	29,570	149,946
Deferred income tax assets		–	–	-
Accounts payable and accrued liabilities		(51,769)	(51,439)	(328,078)
Current income tax liabilities		(23,844)	16,999	24,943
Net (increase) decrease in noncash operating working capital	$	(169,808)	136,414	(38,689)
Supplementary disclosures (including discontinued operations):
Cash income taxes paid, net of refunds	$	129,296	68,076	6,707
Interest paid, net of amounts capitalized of $5,258 in 2018, $4,488 in 2017 and $4,322 in 2016		167,750	147,975	127,798

Noncash investing activities, related to continuing operations:
Asset retirement costs capitalized	$	353,436	8,509	13,690
Decrease (increase) in capital expenditure accrual		(42,467)	99,199	158,885

Accumulated Other Comprehensive Loss (Tables)

12 Months Ended

Dec. 31, 2018

Accumulated Other Comprehensive Loss [Abstract]

Components of 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, 2016	$	(446,555)	(171,305)		(10,352)		(628,212)
2017 components of other comprehensive income (loss):
Before reclassifications to income		171,725	(17,269)		–		154,456
Reclassifications to income		–	9,587	1	1,926	2	11,513
Net other comprehensive income		171,725	(7,682)		1,926		165,969
Balance at December 31, 2017		(274,830)	(178,987)		(8,426)		(462,243)
2018 components of other comprehensive income (loss):
Before reclassifications to income		(145,022)	(16,839)		(1,815)		(163,676)
Reclassifications to income		–	13,790	1	2,342	2	16,132
Net other comprehensive income (loss)		(145,022)	(3,049)		527		(147,544)
Balance at December 31, 2018	$	(419,852)	(182,036)		(7,899)		(609,787)

Assets and Liabilities Measured at Fair Value (Tables)

12 Months Ended

Dec. 31, 2018

Assets and Liabilities Measured at Fair Value [Abstract]

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

December 31, 2018

December 31, 2017

(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

13,845

–

13,845

16,158

–

16,158

Contingent consideration

–

47,730

–

Commodity derivative contracts

–

39,093

–

39,093

13,845

–

47,730

61,575

16,158

39,093

–

55,251

Carrying Amounts and Estimated Fair Values of Financial Instruments


	December 31,
	2018			2017
(Thousands of dollars)	Carrying Amount		Fair Value	Carrying Amount	Fair Value
Financial assets (liabilities):
Current and long-term debt	$	(3,237,717)	(3,003,388)	(2,916,422)	(2,993,003)

Nonrecurring Fair Value Measurements




	Year Ended December 31,
						Total
					Net Book	Pretax
					Value	(Noncash)
	Fair Value				Prior to	Impairment
(Thousands of dollars)		Level 1	Level 2	Level 3	Impairment	Expense
2018
Assets:
Impaired proved properties
United States Midland	$	–	–	37,690	57,690	20,000
2016
Assets:
Impaired proved properties
Western Canada	$	–	–	71,967	167,055	95,088

Common Stock Issued and Outstanding (Tables)

12 Months Ended

Dec. 31, 2018

Stockholders' Equity and Common Stock Issued and Outstanding [Abstract]

Activity in Number of Shares of Common Stock Issued and Outstanding



(Number of shares outstanding)	2018	2017	2016
Beginning of year	172,572,873	172,202,177	172,034,711
Stock options exercised 1	21,200	–	–
Restricted stock awards 1	464,756	368,132	158,504
Employee stock purchase and thrift plans	–	2,564	8,962
Treasury shares purchased	–	–	–
End of year	173,058,829	172,572,873	172,202,177

1 Shares 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.

Business Segments (Tables)

12 Months Ended

Dec. 31, 2018

Business Segments [Abstract]

Segment Information


Segment Information	Exploration and Production
(Millions of dollars)	United States		Canada1	Malaysia	Other	Total E&P
Year ended December 31, 2018
Segment income (loss)	$	242.9	51.1	269.5	(16.6)	546.9
Revenues from external customers		1,289.6	438.6	854.2	22.2	2,604.6	2
Interest income		–	–	–	–	–
Interest expense, net of capitalization		–	–	–	0.2	0.2
Income tax expense (benefit)		68.1	14.5	143.3	(25.3)	200.6
Significant noncash charges (credits)
Depreciation, depletion and amortization		519.5	232.4	198.6	3.5	954.0
Accretion of asset retirement obligations		19.5	7.7	17.4	–	44.6
Amortization of undeveloped leases		36.8	0.8	–	2.5	40.1
Impairment of assets		20.0	–	–	–	20.0
Deferred and noncurrent income taxes		68.1	16.5	(0.5)	(25.7)	58.4
Additions to property, plant, equipment		1,343.5	373.8	138.6	15.9	1,871.8
Total assets at year-end		6,342.9	1,711.9	1,670.2	188.1	9,913.1
Year ended December 31, 2017
Segment income (loss)	$	(8.9)	112.5	224.2	(37.5)	290.3
Revenues from external customers		944.3	485.5	781.1	–	2,210.9
Interest income		–	–	–	–	–
Interest expense, net of capitalization		–	–	–	–	–
Income tax expense (benefit)		(0.8)	44.4	126.4	(36.2)	133.8
Significant noncash charges (credits)
Depreciation, depletion and amortization		546.1	185.4	204.6	3.8	939.9
Accretion of asset retirement obligations		17.4	7.9	17.3	–	42.6
Amortization of undeveloped leases		60.2	1.6	–	–	61.8
Deferred and noncurrent income taxes		2.5	55.3	(3.7)	(36.2)	17.9
Additions to property, plant, equipment		534.8	267.6	16.0	37.6	856.0
Total assets at year-end		5,186.2	1,725.8	1,670.1	154.2	8,736.3
Year ended December 31, 2016
Segment loss	$	(164.2)	(35.9)	171.1	(54.7)	(83.7)
Revenues from external customers		749.1	365.3	753.4	0.2	1,868.0
Interest income		–	–	–	–	–
Interest expense, net of capitalization		–	–	–	–	–
Income tax expense (benefit)		(65.7)	(134.3)	85.9	(18.8)	(132.9)
Significant noncash charges (credits)
Depreciation, depletion and amortization		600.5	203.2	227.7	5.9	1,037.3
Accretion of asset retirement obligations		17.1	13.3	16.3	–	46.7
Amortization of undeveloped leases		38.4	4.5	–	0.5	43.4
Impairment of assets		–	95.1	–	–	95.1
Deferred and noncurrent income taxes		(108.4)	(175.8)	(8.5)	(18.3)	(311.0)
Additions to property, plant, equipment		269.8	361.3	101.4	(1.3)	731.2
Total assets at year-end		5,419.0	1,559.5	2,024.7	115.7	9,118.9

1 Includes Synthetic crude operations in 2016. This business was sold in June 2016.

2 Includes a pretax gain of $129.0 million on sale of Seal area heavy oil field sold in January 2017.



Geographic Information	Certain Long-Lived Assets at December 31
(Millions of dollars)	United States		Canada	Malaysia	United Kingdom	Other	Total
2018	$	6,634.3	1,644.6	1,325.4	–	153.3	9,757.6
2017		5,050.5	1,635.9	1,392.3	–	141.3	8,220.0
2016		5,121.6	1,451.4	1,637.0	–	106.2	8,316.2



Segment Information — Continued
(Millions of dollars)	Corporate and Other		Discontinued Operations	Consolidated Total
Year ended December 31, 2018
Segment income (loss)	$	(123.9)	(3.5)	419.5
Revenues from external customers		(34.0)	–	2,570.6
Interest income		8.0	–	8.0
Interest expense, net of capitalization		181.4	–	181.6
Income tax expense (benefit)		(191.3)	–	9.3
Significant noncash charges (credits)
Depreciation, depletion and amortization		17.9	–	971.9
Accretion of asset retirement obligations		–	–	44.6
Amortization of undeveloped leases		–	–	40.1
Deferred and noncurrent income taxes		(242.1)	–	(183.7)
Additions to property, plant, equipment		22.7	–	1,894.5
Total assets at year-end		1,118.5	20.9	11,052.5
Year ended December 31, 2017
Segment income (loss)	$	(607.5)	(0.9)	(311.8)
Revenues from external customers		4.6	–	2,225.1
Interest income		7.4	–	7.4
Interest expense, net of capitalization		181.8	–	181.8
Income tax expense (benefit)		245.6	–	382.7
Significant noncash charges (credits)
Depreciation, depletion and amortization		17.8	–	957.7
Accretion of asset retirement obligations		–	–	42.6
Amortization of undeveloped leases		–	–	61.8
Deferred and noncurrent income taxes		242.5	–	260.4
Additions to property, plant, equipment		14.8	–	870.8
Total assets at year-end		1,101.7	22.9	9,860.9

Year ended December 31, 2016
Segment loss	$	(149.1)	(2.0)	(276.0)
Revenues from external customers		6.6	–	1,811.2
Interest income		2.9	–	2.9
Interest expense, net of capitalization		148.2	–	148.2
Income tax expense (benefit)		(64.1)	–	(219.2)
Significant noncash charges (credits)
Depreciation, depletion and amortization		16.8	–	1,054.1
Accretion of asset retirement obligations		–	–	46.7
Amortization of undeveloped leases		–	–	43.4
Impairment of assets		–	–	95.1
Deferred and noncurrent income taxes		(76.8)	–	(387.8)
Additions to property, plant, equipment		21.9	–	753.1
Total assets at year-end		1,149.9	27.1	10,295.9



Geographic Information	Revenues from External Customers for the Year
(Millions of dollars)	United States		Canada	Malaysia	Other	Total
2018	$	1,297.5	438.5	854.3	(19.7)	2,570.6
2017		958.3	485.7	781.1	–	2,225.1
2016		692.3	365.3	753.4	0.2	1,811.2

Supplemental Oil and Gas Information (Tables)

12 Months Ended

Dec. 31, 2018

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



(Millions of dollars)	United States		Canada		Malaysia	Other	Total
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
Year ended December 31, 2016
Property acquisition costs
Unproved	$	18.6	–		–	–	18.6
Proved		–	206.7		–	–	206.7
Total acquisition costs		18.6	206.7	–	–	–	225.3
Exploration costs 1		18.5	3.6		6.0	42.0	70.1
Development costs 1		239.7	165.1		102.9	0.3	508.0
Total costs incurred		276.8	375.4		108.9	42.3	803.4
Charged to expense
Dry hole expense		0.4	–		4.5	10.2	15.1
Geophysical and other costs		5.7	3.6		0.7	33.4	43.4
Total charged to expense		6.1	3.6		5.2	43.6	58.5
Property additions	$	270.7	371.8		103.7	(1.3)	744.9

1 Includes noncash asset retirement costs as follows:



2018
Exploration costs	$	–	–	–	–	–
Development costs		366.0	–	7.3	0.2	373.5
	$	366.0	–	7.3	0.20	373.5
2017
Exploration costs	$	–	–	–	–	–
Development costs		37.6	6.3	8.4	–	52.3
	$	37.6	6.3	8.4	–	52.3
2016
Exploration costs	$	–	–	–	–	–
Development costs		0.9	10.5	2.3	–	13.7
	$	0.9	10.5	2.3	–	13.7

Results of Operations for Oil andGas Producing Activities




	United
(Millions of dollars)	States		Canada	Malaysia	Other	Total
Year ended December 31, 2018
Revenues
Crude oil and natural gas liquids sales	$	1,245.3	291.2	708.8	6.1	2,251.4
Natural gas sales		42.9	147.6	144.7	–	335.2
Total oil and gas revenues		1,288.2	438.8	853.5	6.1	2,586.6
Other operating revenues		1.4	(0.2)	0.7	16.1	18.0
Total revenues		1,289.6	438.6	854.2	22.2	2,604.6
Costs and expenses
Lease operating expenses		230.5	122.6	202.1	0.7	555.9
Severance and ad valorem taxes		50.9	1.2	–	–	52.1
Exploration costs charged to expense		29.4	0.6	2.2	31.6	63.8
Undeveloped lease amortization		36.8	0.8	–	2.5	40.1
Depreciation, depletion and amortization		519.5	232.4	198.6	3.5	954.0
Accretion of asset retirement obligations		19.5	7.7	17.4	–	44.6
Impairment of assets		20.0	–	–	–	20.0
Redetermination expense		–	–	11.3	–	11.3
Selling and general expenses		49.0	26.8	10.8	23.5	110.1
Other expenses (benefits)		23.0	(19.1)	(1.0)	2.3	5.2
Total costs and expenses		978.6	373.0	441.4	64.1	1,857.1
Results of operations before taxes		311.0	65.6	412.8	(41.9)	747.5
Income tax expense (benefit)		68.1	14.5	143.3	(25.3)	200.6
Results of operations	$	242.9	51.1	269.5	(16.6)	546.9
Year ended December 31, 2017
Revenues
Crude oil and natural gas liquids sales	$	903.7	203.7	639.9	–	1,747.3
Natural gas sales		37.9	155.1	138.2	–	331.2
Total oil and gas revenues		941.6	358.8	778.1	–	2,078.5
Other operating revenues		2.7	126.7	3.0	–	132.4
Total revenues		944.3	485.5	781.1	–	2,210.9
Costs and expenses
Lease operating expenses		198.5	101.1	168.8	–	468.4
Severance and ad valorem taxes		42.2	1.5	–	–	43.7
Exploration costs charged to expense		7.8	0.5	2.4	50.3	61.0
Undeveloped lease amortization		60.2	1.6	–	–	61.8
Depreciation, depletion and amortization		546.1	185.4	204.6	3.8	939.9
Accretion of asset retirement obligations		17.4	7.9	17.3	–	42.6
Redetermination expense		–	–	15.0	–	15.0
Selling and general expenses		61.8	28.3	14.0	19.6	123.7
Other expenses		20.0	2.3	8.4	–	30.7
Total costs and expenses		954.0	328.6	430.5	73.7	1,786.8
Results of operations before taxes		(9.7)	156.9	350.6	(73.7)	424.1
Income tax expense (benefit)		(0.8)	44.4	126.4	(36.2)	133.8
Results of operations	$	(8.9)	112.5	224.2	(37.5)	290.3

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

Schedule 5 – Results of Operations for Oil and Gas Producing Activities 1 – Continued



			Canada
	United		Conven-
(Millions of dollars)	States		tional	Synthetic	Malaysia	Other	Total
Year ended December 31, 2016
Revenues
Crude oil and natural gas liquids sales	$	714.1	171.7	60.7	623.7	–	1,570.2
Natural gas sales		35.1	130.0	–	127.6	–	292.7
Total oil and gas revenues		749.2	301.7	60.7	751.3	–	1,862.9
Other operating revenues		(0.1)	(0.7)	3.6	2.1	0.2	5.1
Total revenues		749.1	301.0	64.3	753.4	0.2	1,868.0
Costs and expenses
Lease operating expenses		218.6	102.6	69.8	168.4	–	559.4
Severance and ad valorem taxes		37.0	4.3	2.5	–	–	43.8
Exploration costs charged to expense		6.1	3.6	–	5.2	43.6	58.5
Undeveloped lease amortization		38.4	4.5	–	–	0.5	43.4
Depreciation, depletion and amortization		600.5	186.7	16.5	227.7	5.9	1,037.3
Accretion of asset retirement obligations		17.1	10.9	2.4	16.3	–	46.7
Impairment of assets		–	95.1	–	–	–	95.1
Redetermination expense		–	–	–	39.1	–	39.1
Selling and general expenses		54.0	28.2	0.5	15.4	33.6	131.7
Other expenses		7.3	7.9	–	24.3	(9.9)	29.6
Total costs and expenses		979.0	443.8	91.7	496.4	73.7	2,084.6
Results of operations before taxes		(229.9)	(142.8)	(27.4)	257.0	(73.5)	(216.6)
Income tax expense (benefit)		(65.7)	(58.9)	(75.4)	85.9	(18.8)	(132.9)
Results of operations	$	(164.2)	(83.9)	48.0	171.1	(54.7)	(83.7)

1 Results 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	Total
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
December 31, 2016
Future cash inflows	$	9,477.9	3,752.7	4,318.7	17,549.3
Future development costs		(1,691.1)	(1,143.6)	(763.8)	(3,598.5)
Future production costs		(3,981.6)	(2,329.7)	(2,661.2)	(8,972.5)
Future income taxes		(118.9)	(81.3)	(73.3)	(273.5)
Future net cash flows		3,686.3	198.1	820.4	4,704.8
10% annual discount for estimated timing of cash flows		(1,799.5)	(95.0)	(230.3)	(2,124.8)
Standardized measure of discounted future net cash flows	$	1,886.8	103.1	590.1	2,580.0

1 2018 includes noncontrolling interest in MP GOM.

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



(Millions of dollars)		2018	2017	2016
Net changes in prices and production costs	$	2,972.6	2,428.4	(1,476.1)
Net changes in development costs		(1,891.1)	(724.4)	544.9
Sales and transfers of oil and gas produced, net of production costs		(1,978.6)	(1,576.0)	(1,196.3)
Net change due to extensions and discoveries		1,930.3	807.9	280.5
Net change due to purchases and sales of proved reserves		3,152.4	85.9	(583.4)
Development costs incurred		1,017.3	802.7	479.6
Accretion of discount		469.5	270.9	428.1
Revisions of previous quantity estimates		(347.8)	(109.5)	(49.2)
Net change in income taxes		(967.6)	(643.0)	292.8
Net increase (decrease)		4,357.0	1,342.9	(1,279.1)
Standardized measure at January 1		3,922.9	2,580.0	3,859.1
Standardized measure at December 31	$	8,279.9	3,922.9	2,580.0

Capitalized Costs Relating to Oil and Gas Producing Activities



(Millions of dollars)	United States		Canada	Malaysia	Other	Total
December 31, 2018
Unproved oil and gas properties	$	394.2	250.0	21.2	176.9	842.3
Proved oil and gas properties		11,678.3	3,693.0	6,263.5	–	21,634.8
Gross capitalized costs		12,072.5	3,943.0	6,284.7	176.9	22,477.1
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties		(129.3)	(213.5)	–	(25.4)	(368.2)
Proved oil and gas properties		(5,433.7)	(2,088.8)	(4,963.5)	–	(12,486.0)
Net capitalized costs	$	6,509.5	1,640.7	1,321.2	151.5	9,622.9
December 31, 2017
Unproved oil and gas properties	$	360.9	286.8	20.5	162.1	830.3
Proved oil and gas properties		9,606.4	3,603.4	6,139.7	–	19,349.5
Gross capitalized costs		9,967.3	3,890.2	6,160.2	162.1	20,179.8
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties		(149.5)	(230.7)	–	(21.8)	(402.0)
Proved oil and gas properties		(4,893.8)	(2,027.9)	(4,774.5)	–	(11,696.2)
Net capitalized costs	$	4,924.0	1,631.6	1,385.7	140.3	8,081.6

Crude Oil And Condensate [Member]

Summary of Proved Reserves Based on Average Prices


	Crude & Synthetic Oil	Crude Oil				Synthetic Oil 1
(Millions of barrels)	Total	Total	United States	Canada	Malaysia	Canada
Proved developed and undeveloped crude oil / synthetic oil reserves:
December 31, 2015	456.2	341.4	238.9	27.9	74.6	114.8
Revisions of previous estimates	(5.8)	(5.8)	(10.9)	2.5	2.6	–
Extensions and discoveries	11.0	11.0	8.6	–	2.4	–
Purchases of properties	26.3	26.3	–	26.3	–	–
Sales of properties	(121.0)	(7.8)	(4.5)	(3.3)	–	(113.2)
Production	(37.7)	(36.1)	(17.7)	(4.5)	(13.9)	(1.6)
December 31, 2016	329.0	329.0	214.4	48.9	65.7	(0.0)
Revisions of previous estimates	(6.0)	(6.0)	(4.7)	2.3	(3.6)	–
Improved recovery	2.0	2.0	–	–	2.0	–
Extensions and discoveries	31.6	31.6	27.2	4.4	–	–
Purchases of properties	4.7	4.7	4.7	–	–	–
Production	(33.2)	(33.2)	(16.9)	(4.1)	(12.2)	–
December 31, 2017	328.1	328.1	224.7	51.5	51.9	–
Revisions of previous estimates	(15.3)	(15.3)	(15.0)	(8.0)	7.7	–
Improved recovery	0.8	0.8	–	–	0.8	–
Extensions and discoveries	58.9	58.9	42.9	16.0	–	–
Purchases of properties	93.6	93.6	92.3	–	1.3	–
Production	(33.6)	(33.6)	(18.4)	(4.5)	(10.7)	–
December 31, 2018 2	432.5	432.5	326.5	55.0	51.0	–
Proved developed crude oil/ synthetic oil reserves:
December 31, 2015	326.6	211.8	125.9	23.8	62.1	114.8
December 31, 2016	184.9	184.9	113.9	19.2	51.8	–
December 31, 2017	185.5	185.5	126.3	21.9	37.3	–
December 31, 2018 3	249.3	249.3	189.0	23.3	37.0	–
Proved undeveloped crude oil reserves:
December 31, 2015	129.6	129.6	113.0	4.1	12.5	–
December 31, 2016	144.1	144.1	100.5	29.7	13.9	–
December 31, 2017	142.6	142.6	98.4	29.6	14.6	–
December 31, 2018 4	183.2	183.2	137.5	31.7	14.0	–

1 All synthetic oil operations were sold in June 2016.

2 Includes total proved reserves of 25.5 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.

3 Includes proved developed reserves of 19.1 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.

4 Includes proved undeveloped reserves of 6.4 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.

Summary of Proved Reserves Based on Average Prices



(Millions of barrels)	Total	United States	Canada	Malaysia
Proved developed and undeveloped NGL reserves:
December 31, 2015	36.4	35.4	0.4	0.6
Revisions of previous estimates	1.6	1.2	0.2	0.2
Extensions and discoveries	2.9	2.8	0.1	–
Purchase of properties	5.1	–	5.1	–
Production	(3.5)	(3.0)	(0.2)	(0.3)
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	–
Purchases 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 1	54.2	47.6	5.9	0.7
Proved developed NGL reserves:
December 31, 2015	21.6	20.7	0.3	0.6
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 2	27.3	24.9	1.7	0.7
Proved undeveloped NGL reserves:
December 31, 2015	14.8	14.7	0.1	–
December 31, 2016	20.3	15.6	4.7	–
December 31, 2017	24.3	19.7	4.6	–
December 31, 2018 3	26.9	22.7	4.2	–

1 Includes total proved reserves of 1.1 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

2 Includes proved developed reserves of 0.8 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

3 Includes proved undeveloped reserves of 0.3 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.

Summary of Proved Reserves Based on Average Prices


(Billions of cubic feet)	Total	United States	Canada	Malaysia
Proved developed and undeveloped natural gas reserves:
December 31, 2015	1,688.8	232.4	909.6	546.8
Revisions of previous estimates	43.3	0.1	45.3	(2.1)
Improved recovery	164.2	6.4	120.2	37.6
Extensions and discoveries	122.3	–	122.3	–
Sales of properties	(2.2)	(0.1)	(2.1)	–
Production	(138.4)	(19.4)	(76.4)	(42.6)
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 1	2,143.6	309.0	1,366.4	468.2
Proved developed natural gas reserves:
December 31, 2015	783.5	148.3	453.5	181.7
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 2	921.6	198.3	595.0	128.3
Proved undeveloped natural gas reserves:
December 31, 2015	905.3	84.1	456.1	365.1
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 3	1,222.0	110.7	771.4	339.9

1 Includes total proved reserves of 10.8 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

2 Includes proved developed reserves of 8.2 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

3 Includes proved undeveloped reserves of 2.6 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.

Supplemental Quarterly Information (Tables)

12 Months Ended

Dec. 31, 2018

Supplemental Quarterly Information [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, 2018 1
Revenue from contracts with customers	$	606.9	655.2	659.8	664.7	2,586.6
Income (loss) from continuing operations before income taxes		97.0	82.3	146.8	106.2	432.3
Income (loss) from continuing operations		168.7	45.9	95.8	112.6	423.0
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		0.98	0.26	0.55	0.60	2.39
Diluted		0.97	0.26	0.55	0.59	2.37
Net income (loss) per Common share
Basic		0.97	0.26	0.54	0.60	2.38
Diluted		0.96	0.26	0.54	0.59	2.36
Cash dividend per Common share		0.25	0.25	0.25	0.25	1.00
Year ended December 31, 2017
Revenue from contracts with customers	$	509.0	477.6	511.2	580.5	2,078.5
Loss from continuing operations before income taxes		154.9	(21.9)	(63.6)	2.4	71.8
Income (loss) from continuing operations		57.5	(17.3)	(66.3)	(284.8)	(310.9)
Net income (loss) attributable to Murphy		58.5	(17.6)	(65.9)	(286.8)	(311.8)
Income from continuing operations per Common share
Basic		0.33	(0.10)	(0.38)	(1.65)	(1.81)
Diluted		0.33	(0.10)	(0.38)	(1.65)	(1.81)
Net income (loss) per Common share
Basic		0.34	(0.10)	(0.38)	(1.66)	(1.81)
Diluted		0.34	(0.10)	(0.38)	(1.66)	(1.81)
Cash dividend per Common share		0.25	0.25	0.25	0.25	1.00

1 2018 includes noncontrolling interest in MP GOM.

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

3 Months Ended

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

^[1]

Withholding tax on amounts repatriated

$ 20,000,000

$ 0

$ 95,088,000

5.00%

Petrobas America Inc [Member]

Percentage of acquired entity reported

100.00%

Percentage of acquired entity noncontrolling interest reported

20.00%

Stock Options [Member]

Stock-based compensation, fair value assumption model

Black-Scholes option pricing model

Performance Based Restricted Stock [Member]

Stock-based compensation, fair value assumption model

Monte Carlo valuation model

Stock-based compensation, vesting period

3 years

Minimum [Member]

Equity method investment, ownership percentage

20.00%

Minimum [Member] | Stock Options [Member]

Stock-based compensation, vesting period

2 years

Maximum [Member]

Equity method investment, ownership percentage

50.00%

Maximum [Member] | Stock Options [Member]

Stock-based compensation, vesting period

3 years

Malaysia [Member] | Minimum [Member]

Depreciable lives, straight-line method

20 years

Malaysia [Member] | Maximum [Member]

Depreciable lives, straight-line method

25 years

[1]	Reclassified to conform to current presentation (see Note B).

New Accounting Principles and Recent Accounting Pronouncements (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of certain tax effects from accumulated other comprehensive loss		$ (30,237)
Accounting Standards Update 2016-02 [Member] \| Liabilities [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New accounting pronouncement, expected effect		(160,000)
Accounting Standards Update 2016-02 [Member] \| Assets [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New accounting pronouncement, expected effect		800,000
Retirement and Postretirement Benefit Plan Adjustments [Member] \| Accounting Standards Update 2018-02 [Member]
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 [Member] \| Accounting Standards Update 2018-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of certain tax effects from accumulated other comprehensive loss	$ 1,800
Retained Earnings [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of certain tax effects from accumulated other comprehensive loss		30,237
Retained Earnings [Member] \| Accounting Standards Update 2016-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New accounting pronouncement, expected effect		$ 160,000

Revenue from Contracts with Customers (Narrative) (Details)	12 Months Ended	36 Months Ended
	Dec. 31, 2018 USD ($) contract segment agreement item	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Disaggregation of Revenue [Line Items]
Number of geographic segments \| segment	3
Number of revenue streams \| item	3
Number of production sharing contracts \| contract	7
Receivables from contracts with customers	$ 263,000,000	$ 263,000,000	$ 203,400,000
Impairment losses on receivables or contract assets		$ 0
Malaysia [Member]
Disaggregation of Revenue [Line Items]
Number of gas sale agreements \| agreement	3

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

3 Months Ended

12 Months Ended

Dec. 31, 2018

^[1]

Sep. 30, 2018

^[1]

Jun. 30, 2018

^[1]

Mar. 31, 2018

^[1]

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

(Loss) gain on crude contracts

$ 664,700

$ 659,800

$ 655,200

$ 606,900

$ 580,500

$ 511,200

$ 477,600

$ 509,000

$ 2,586,627

$ 2,078,548

^[2]

$ 1,862,891

^[2]

(41,975)

9,566

^[2]

(63,412)

^[2]

Other operating income

25,897

9,581

10,096

Gain on sale of assets

127,434

1,663

Crude Oil And Condensate [Member]

2,570,603

2,225,129

^[2]

1,811,238

^[2]

2,153,369

1,671,425

1,524,760

98,059

75,881

45,449

United States Onshore [Member] | Crude Oil And Condensate [Member]

335,199

331,242

292,682

United States Onshore [Member] | Natural Gas Liquids [Member]

778,198

644,023

508,045

United States Onshore [Member] | Natural Gas [Member]

53,335

43,804

28,316

United States Offshore [Member] | Crude Oil And Condensate [Member]

28,335

27,460

24,281

United States Offshore [Member] | Natural Gas Liquids [Member]

^[3]

403,523

208,984

172,022

United States Offshore [Member] | Natural Gas [Member]

^[3]

10,269

6,894

5,781

Canada Onshore [Member] | Crude Oil And Condensate [Member]

^[3]

14,525

10,480

10,839

Canada Onshore [Member] | Natural Gas Liquids [Member]

105,651

51,013

92,605

Canada Onshore [Member] | Natural Gas [Member]

14,657

5,450

1,351

Canada Offshore [Member] | Crude Oil And Condensate [Member]

147,613

155,125

129,968

Malaysia - Sarawak [Member] | Crude Oil And Condensate [Member]

170,895

147,230

138,425

Malaysia - Sarawak [Member] | Natural Gas Liquids [Member]

282,370

241,774

209,751

Malaysia - Sarawak [Member] | Natural Gas [Member]

19,798

19,733

10,001

Malaysia - Block K [Member] | Crude Oil And Condensate [Member]

144,222

137,479

126,975

Malaysia - Block K [Member] | Natural Gas [Member]

406,653

378,401

403,912

Other Locations [Member] | Crude Oil And Condensate [Member]

504

$ 698

$ 619

$ 6,079

[1]	2018 includes noncontrolling interest in MP GOM.
[2]	Reclassified to conform to current presentation (see Note B).
[3]	2018 includes revenue attributable to noncontrolling interest in MP GOM, effective November 30, 2018.

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

Acquisition (Narrative) (Details)
$ in Thousands

1 Months Ended

3 Months Ended

12 Months Ended

Dec. 31, 2018

USD ($)

Boe / d

MMBoe

Dec. 31, 2018

USD ($)

MMBoe

Sep. 30, 2018

USD ($)

^[1]

Jun. 30, 2018

USD ($)

^[1]

Mar. 31, 2018

USD ($)

^[1]

Dec. 31, 2017

USD ($)

Sep. 30, 2017

USD ($)

Jun. 30, 2017

USD ($)

Mar. 31, 2017

USD ($)

Dec. 31, 2018

USD ($)

MMBoe

Dec. 31, 2017

USD ($)

^[2]

Dec. 31, 2016

USD ($)

^[2]

Revenue from sales to customers

$ 664,700

^[1]

$ 659,800

$ 655,200

$ 606,900

$ 580,500

$ 511,200

$ 477,600

$ 509,000

$ 2,586,627

$ 2,078,548

$ 1,862,891

Income (loss) from continuing operations before income taxes

$ 106,200

^[1]

$ 146,800

$ 82,300

$ 97,000

$ 2,400

$ (63,600)

$ (21,900)

$ 154,900

$ 432,338

$ 71,802

$ (493,115)

Petrobas America Inc [Member]

Production capacity | Boe / d

50,000

Proved reserves | MMBoe

Acquisition, cash paid

$ 794,623

Percentage of interest in subsidiary transferred

20.00%

Revenue from sales to customers

$ 56,700

Income (loss) from continuing operations before income taxes

36,500

Acquisition-related costs

$ 6,200

Petrobas America Inc [Member] | Sales Thresholds 2019 to 2025 [Member]

Contingent consideration, maximum

$ 150,000

MP Gulf Of Mexico LLC [Member]

Parent ownership interest

80.00%

Petrobas America Inc [Member] | MP Gulf Of Mexico LLC [Member]

Noncontrolling ownership interest

20.00%

[1]	2018 includes noncontrolling interest in MP GOM.
[2]	Reclassified to conform to current presentation (see Note B).

Acquisition (Preliminary Purchase Price Allocation) (Details) $ in Thousands	1 Months Ended
	Dec. 31, 2018 USD ($)
Business Acquisition [Line Items]
Fair value of Property, Plant and Equipment	$ 1,617,052
Other assets	10,041
Less: Asset retirement obligations	(359,643)
Total net assets	1,267,450
Petrobas America Inc [Member]
Business Acquisition [Line Items]
Cash consideration paid to PAI	794,623
Fair value of net assets contributed	166,797
Fair value of contingent consideration	52,540
Noncontrolling interest in acquired assets	253,490
Total purchase consideration	$ 1,267,450

Acquisition (Pro Forma Financial Information) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Acquisition [Abstract]
Revenues	$ 2,825,169	$ 2,816,458
Net Income Attributable to Murphy	$ 603,231	$ (224,860)
Net Income Attributable to Murphy per Common Share, Basic	$ 3.49	$ (1.30)
Net Income Attributable to Murphy per Common Share, Diluted	$ 3.46	$ (1.30)

Discontinued Operations and Assets Held for Sale (Major Categories of Assets and Liabilities Reflected as Held for Sale) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts receivable	$ 331,859	$ 243,472
Total current assets held for sale	20,947	22,929
Accounts payable	596,071	595,916
Total current liabilities associated with assets held for sale	2,764	3,530
UK Refining And Marketing Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash	17,219	16,631
Accounts receivable	3,728	6,298
Total current assets held for sale	20,947	22,929
Accounts payable	106	837
Refinery decommissioning cost	2,658	2,693
Total current liabilities associated with assets held for sale	$ 2,764	$ 3,530

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Discontinued Operations and Assets Held for Sale [Abstract]

Loss from operations before income taxes

$ 6

$ 854

$ 1,464

(3,522)

(853)

(2,027)

Total loss from discontinued operations before taxes

(3,522)

(853)

(2,027)

Income (loss) from discontinued operations

$ (3,522)

$ (853)

^[1]

$ (2,027)

^[1]

[1]	Reclassified to conform to current presentation (see Note B).

- 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 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

Inventories (Schedule of Inventory) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Inventories [Abstract]
Unsold crude oil	$ 25,205	$ 20,153
Materials and supplies	62,706	84,974
Inventory, Net, Total	$ 87,911	$ 105,127

Property, Plant and Equipment (Narrative) (Details) - USD ($)

1 Months Ended

3 Months Ended

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Apr. 01, 2017

Dec. 31, 2015

Total capitalized exploratory well costs

$ 229,084,000

$ 175,640,000

$ 229,084,000

$ 175,640,000

$ 148,500,000

$ 130,514,000

Exploratory well costs capitalized more than one year

$ 167,900,000

167,900,000

Proceeds from sales of property, plant and equipment

1,383,000

69,506,000

1,155,144,000

Asset retirement obligation settled

23,398,000

29,111,000

Costs Incurred Acquisition Of Oil And Gas Properties

54,000

127,434,000

1,663,000

797,300,000

71,100,000

225,300,000

Cost of acquired assets

797,300,000

71,100,000

225,300,000

20,000,000

95,088,000

^[1]

MP Gulf Of Mexico LLC [Member]

$ 11,332,000

15,000,000

^[1]

39,100,000

^[1]

Parent ownership interest

80.00%

MP Gulf Of Mexico LLC [Member] | Petrobas America Inc [Member]

Noncontrolling ownership interest

20.00%

Athabasca Oil Corporation [Member]

Cost of acquired assets, cash paid

206,700,000

Athabasca Oil Corporation [Member] | Canadian Subsidiary [Member]

Costs Incurred Acquisition Of Oil And Gas Properties

375,000,000

Cost of acquired assets

375,000,000

Petrobas America Inc [Member]

Petrobas America Inc [Member] | Sales Thresholds 2019 to 2025 [Member]

Acquisition, cash paid

$ 794,623,000

Contingent consideration, maximum

150,000,000

$ 150,000,000

Petrobas America Inc [Member] | Enhanced Oil Recovery Projects [Member]

Contingent consideration, maximum

50,000,000

Western Canada [Member]

Proceeds from sales of property, plant and equipment

48,800,000

Asset retirement obligation settled

85,900,000

Eagle Ford Shale [Member]

129,000,000

Proceeds from sales of property, plant and equipment

19,600,000

Syncrude [Member]

Proceeds from sales of property, plant and equipment

739,100,000

Syncrude [Member] | Canadian Subsidiary [Member]

$ 71,700,000

Percentage of interest in oil and gas property sold during period

5.00%

Montney Natural Gas Fields [Member]

Proceeds from sales of property, plant and equipment

$ 414,100,000

Deferred gain on sale of property

7,600,000

7,100,000

160,200,000

$ 160,200,000

187,000,000

Deferred gain, period of recognition

17 years

Brunei [Member]

Exploratory well costs capitalized more than one year

55,800,000

$ 55,800,000

Vietnam [Member]

Exploratory well costs capitalized more than one year

63,500,000

Costs Incurred Acquisition Of Oil And Gas Properties

797,100,000

58,100,000

18,600,000

Cost of acquired assets

797,100,000

$ 58,100,000

18,600,000

Exploratory well costs capitalized more than one year

21,200,000

Kaybob Duvernay Lands, Alberta [Member] | Athabasca Oil Corporation [Member]

Cost of acquired assets, carried interest

$ 168,000,000

Carried interest paid

102,000,000

Kaybob Duvernay Lands, Alberta [Member] | Athabasca Oil Corporation [Member] | Canadian Subsidiary [Member]

Interest in assets acquired

70.00%

Placid Montney Lands, Alberta [Member] | Athabasca Oil Corporation [Member] | Canadian Subsidiary [Member]

Interest in assets acquired

30.00%

Kakap Field Block K Malaysia [Member]

Working interest

6.35%

6.67%

Redetermination expense, net of tax

$ 15,000,000

$ 39,100,000

$ 9,300,000

$ 24,100,000

Redetermination liability

$ 17,300,000

[1]	Reclassified to conform to current presentation (see Note B).

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

Dec. 31, 2018

Dec. 31, 2017

$ 22,823,315

$ 20,500,772

Exploration and Production [Member]

9,757,564

8,220,031

^[1]

22,629,844

20,329,930

Corporate and Other [Member]

^[1],[2]

9,654,945

8,120,293

193,471

170,842

102,619

99,738

Mineral Rights [Member]

512,025

600,423

Administrative Assets and Support Equipment [Member]

144,912

198,349

$ 32,071

$ 38,670

[1]	Includes mineral rights as follows: $600,423 198,349 595,138 188,689
[2]	Includes $38,670 in 2017 and $48,053 in 2016 related to administrative assets and support equipment.

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

United States Onshore [Member]

Impairment Expense

$ 20,000,000

$ 0

$ 95,088,000

^[1]

Impairment Expense

$ 20,000,000

Canada [Member]

Asset Retirement Obligations [Abstract]

Impairment Expense

$ 95,088,000

[1]	Reclassified to conform to current presentation (see Note B).

Property, Plant And Equipment (Net Changes in Capitalized Exploratory Well Costs) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Property, Plant And Equipment [Abstract]
Beginning balance at January 1	$ 175,640	$ 148,500	$ 130,514
Additions pending the determination of proved reserves	60,179	51,488	17,986
Reclassifications to proved properties based on the determination of proved reserves	(2,214)	(15,988)
Capitalized exploratory well costs charged to expense	(4,521)	(8,360)
Ending balance at December 31	$ 229,084	$ 175,640	$ 148,500

Property, Plant And Equipment (Aging of Capitalized Exploratory Well Costs) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018 USD ($) item	Dec. 31, 2017 USD ($) item	Dec. 31, 2016 USD ($) item	Dec. 31, 2015 USD ($)
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount \| $	$ 229,084	$ 175,640	$ 148,500	$ 130,514
No. of Wells	10	13	12
No. of Projects	6	6	6
Zero to One Year [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount \| $	$ 61,096	$ 41,480	$ 20,481
No. of Wells	1	3	1
No. of Projects	1	2	1
One to Two Years [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount \| $	$ 40,523	$ 5,812	$ 63,527
No. of Wells	3	1	5
No. of Projects	2	1	5
Two to Three Years [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount \| $		$ 43,200
No. of Wells		2
No. of Projects		2
Three Years or More [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount \| $	$ 127,465	$ 85,148	$ 64,492
No. of Wells	6	7	6
No. of Projects	3	1

Financing Arrangements and Long-Term Debt (Narrative) (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Aug. 31, 2017
Line of Credit Facility [Line Items]
Amount outstanding		$ 325,000
Repayments of debt			$ 550,000	$ 600,000
Capital lease duration		25 years
Capital lease payment duration		15 years
Capital lease expiration date		Mar. 01, 2029
Capital lease obligations, current		$ 10,600
Capital lease obligations, noncurrent		125,800
Future maturities of long term debt in 2019		10,600
Future maturities of long term debt in 2020		11,200
Future maturities of long term debt in 2021		11,700
Future maturities of long term debt in 2022		1,100,000
Future maturities of long term debt in 2023		337,900
Thereafter		$ 1,760,000
5.75% Notes, Due August 15, 2025 [Member]
Line of Credit Facility [Line Items]
Interest rate					5.75%
Face amount of notes					$ 550,000
Maturity date		Aug. 15, 2025
Transaction costs					$ 8,400
3.50% notes, due December 2017 [Member]
Line of Credit Facility [Line Items]
Interest rate	3.50%
Repayments of debt	$ 550,000
Letter of Credit [Member]
Line of Credit Facility [Line Items]
Amount outstanding		$ 24,700
2018 Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Credit facility maximum borrowing capacity		$ 1,600,000
Credit facility, expiration date		Nov. 01, 2023
Amount outstanding		$ 325,000
2018 Revolving Credit Facility [Member] \| New York Federal Reserve Bank Rate [Member]
Line of Credit Facility [Line Items]
Spread above variable interest rate		0.50%
2018 Revolving Credit Facility [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Spread above variable interest rate		1.00%
2018 Revolving Credit Facility [Member] \| Minimum [Member]
Line of Credit Facility [Line Items]
Facility fee arrears accrual rate		0.175%
2018 Revolving Credit Facility [Member] \| Minimum [Member] \| Eurodollar [Member]
Line of Credit Facility [Line Items]
Spread above variable interest rate		1.075%
2018 Revolving Credit Facility [Member] \| Maximum [Member]
Line of Credit Facility [Line Items]
Facility fee arrears accrual rate		0.40%
2018 Revolving Credit Facility [Member] \| Maximum [Member] \| Eurodollar [Member]
Line of Credit Facility [Line Items]
Spread above variable interest rate		2.10%
Previous 2016 Senior Unsecured Credity Facility [Member]
Line of Credit Facility [Line Items]
Credit facility maximum borrowing capacity			$ 1,100,000
Interest rate		3.831%

Financing Arrangements and Long-Term Debt (Schedule of Long Term Debt) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Notes payable	$ 2,800,000	$ 2,800,000
Unamortized discount on notes payable	(23,627)	(27,433)
Total notes payable, net of unamortized discount	2,776,373	2,772,567
Capitalized lease obligation, due through June 2029	136,344	143,855
Total debt including current maturities	2,912,717	2,916,422
Senior Unsecured Revolving Credit Facility	325,000
Current maturities	(10,583)	(9,902)
Total long-term debt	$ 3,227,134	2,906,520
Capital lease expiration date	Mar. 01, 2029
4.00% notes, due June 2022 [Member]
Debt Instrument [Line Items]
Notes payable	$ 500,000	500,000
Interest rate	4.00%
Debt Instrument, Maturity Month And Year	June 2022
4.45% notes, due December 2022 [Member]
Debt Instrument [Line Items]
Notes payable	$ 600,000	$ 600,000
Interest rate	4.45%	4.70%
Debt Instrument, Maturity Month And Year	December 2022
6.875% notes, due August 15, 2024 [Member]
Debt Instrument [Line Items]
Notes payable	$ 550,000	$ 550,000
Interest rate	6.875%
Debt Instrument, Maturity Month And Year	August 2024
5.75% notes, due August 2025 [Member]
Debt Instrument [Line Items]
Notes payable	$ 550,000	550,000
Interest rate	5.75%
Debt Instrument, Maturity Month And Year	August 2025
7.05% notes, due May 2029 [Member]
Debt Instrument [Line Items]
Notes payable	$ 250,000	250,000
Interest rate	7.05%
Debt Instrument, Maturity Month And Year	May 2029
5.875% notes, due December 2042 [Member]
Debt Instrument [Line Items]
Notes payable	$ 350,000	$ 350,000
Interest rate	5.875%	6.125%
Debt Instrument, Maturity Month And Year	December 2042

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, 2018

Dec. 31, 2017

Dec. 31, 2016

Balance at beginning of year

$ 722,139

$ 781,057

Accretion expense

44,559

42,590

^[1]

$ 46,742

^[1]

Liabilities incurred

13,886

52,331

Liabilities assumed from PAI

359,643

Liabilities assumed by purchaser of oil and gas assets

(24,959)

(47,612)

Liabilities settled

(23,398)

(29,111)

(87,456)

Changes due to translation of foreign currencies

(8,966)

10,340

Balance at end of year

$ 1,082,904

$ 722,139

$ 781,057

[1]	Reclassified to conform to current presentation (see Note B).

Asset Retirement Obligations (Classification of Asset of Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligations [Abstract]
Balance at end of year	$ 1,082,904	$ 722,139	$ 781,057
Current portion of liability at end of year	(55,481)	(12,840)
Noncurrent portion of liability at end of year	$ 1,027,423	$ 709,299

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, 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
Transition tax on deemed repatriation	10,100
Alternative minimum tax	9,765	29,710
Alternative minimum tax expected to be refunded next fiscal year	19,600
Operating loss carryforwards	2,360,000
Deferred tax asset. operating loss carryforward	496,629	272,930
Decrease in income tax expense, foreign tax credits	16,000
Increase (decrease) in deferred tax asset valuation allowance	$ 262,000
Withholding tax on amounts repatriated	5.00%
Deferred tax expense, undistributed foreign earnings	$ 60,000
Earnings repatriated	1,200,000
Earnings expected to be repatriated in next fiscal year	100,000	1,300,000
Deferred tax liability, undistributed foreign earnings	5,000	65,000
Undistributed foreign earnings	1,200,000
Other recorded liabilities for interest and penalties	200	100	$ 300
Income tax expense (benefit) related to interest and penalties	$ (100)	$ (200)	$ (100)
United States [Member]
Income Tax Disclosure [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions	2015
Canada [Member]
Income Tax Disclosure [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions	2013
Malaysia [Member]
Income Tax Disclosure [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions	2012
United Kingdom [Member]
Income Tax Disclosure [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions	2017
Minimum [Member]
Income Tax Disclosure [Line Items]
Expected liability to be added for uncertain taxes during next twelve months	$ 200
Minimum [Member] \| United States [Member]
Income Tax Disclosure [Line Items]
Operating loss carryforward, expiration date	Dec. 31, 2036
Maximum [Member]
Income Tax Disclosure [Line Items]
Expected liability to be added for uncertain taxes during next twelve months	$ 1,000
Maximum [Member] \| United States [Member]
Income Tax Disclosure [Line Items]
Operating loss carryforward, expiration date	Dec. 31, 2037

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, 2018

^[1]

Sep. 30, 2018

^[1]

Jun. 30, 2018

^[1]

Mar. 31, 2018

^[1]

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Income (loss) from continuing operations before income taxes

United States

$ 14,907

$ (299,349)

$ (595,196)

Foreign

417,431

371,151

102,081

Income (loss) from continuing operations before income taxes

$ 106,200

$ 146,800

$ 82,300

$ 97,000

$ 2,400

$ (63,600)

$ (21,900)

$ 154,900

432,338

71,802

^[2]

(493,115)

^[2]

Income tax expense (benefit)

Federal - Current

(9,765)

Federal - Deferred

(131,200)

156,065

(197,450)

Total Federal income tax expense (benefit)

(140,965)

156,065

(197,450)

State

3,299

4,230

13,984

Foreign - Current

202,775

122,318

146,861

Foreign - Deferred

(55,779)

100,125

(182,567)

Total Foreign income tax expense (benefit)

146,996

222,443

(35,706)

Total income tax expense (benefit)

$ 9,330

$ 382,738

^[2]

$ (219,172)

^[2]

[1]	2018 includes noncontrolling interest in MP GOM.
[2]	Reclassified to conform to current presentation (see Note B).

Income Taxes (Effective Income Tax Rates) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Line Items]
Income tax expense (benefit) based on the U.S. statutory tax rate	$ 90,791	$ 25,131	$ (172,590)
Revaluation of deferred tax (U.S. tax reform)		118,004
Tax impact of deemed repatriation of foreign ivnested earnings (U.S. tax reform)	(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	72,007	12,658	8,582
State income taxes, net of federal benefit	2,607	2,438	9,090
U.S. tax benefit on certain foreign upstream investments	(14,702)	(32,926)	(21,336)
Increase in deferred tax asset valuation allowance related to other foreign exploration expenditures	3,283	18,601	25,734
Other, net	$ (8,956)	$ 17,832	18,741
Canada [Member]
Income Tax Disclosure [Line Items]
Tax effects on sale of assets			(89,473)
Malaysia [Member]
Income Tax Disclosure [Line Items]
Tax effects on sale of assets			$ 2,080

Income Taxes (Analysis of Deferred Tax Assets and Deferred Tax Liabilities Showing Tax Effects of Significant Temporary Differences) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Deferred tax assets
Property and leasehold costs	$ 491,660	$ 488,584
Liabilities for dismantlements	88,075	98,444
Postretirement and other employee benefits	113,826	134,444
Alternative minimum tax	9,765	29,710
Foreign tax credit carryforwards		228,159
U.S. net operating loss	496,629	272,930
Other deferred tax assets	19,974	13,892
Total gross deferred tax assets	1,219,929	1,266,163
Less valuation allowance	(213,815)	(476,256)
Net deferred tax assets	1,006,114	789,907
Deferred tax liabilities
Deferred tax on undistributed foreign earnings	(5,000)	(65,000)
Accumulated depreciation, depletion and amortization	(742,562)	(669,638)
Other deferred tax liabilities	(28,802)	(2,824)
Total gross deferred tax liabilities	(776,364)	(737,462)
Net deferred tax assets	$ 229,750	$ 52,445

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes [Abstract]
Balance at January 1	$ 3,437	$ 7,417	$ 6,631
Additions for tax positions related to current year	454	769	756
Settlements due to lapse of time	(988)	(4,834)
Foreign currency translation effect		85	30
Balance at December 31	$ 2,903	$ 3,437	$ 7,417

Incentive Plans (Narrative) (Details) - USD ($)

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Vesting scheme

Under these plans, one-half of each grant is generally exercisable after two years and the remainder after three years.

Option term

7 years

Stock options exercised

21,200

^[1]

Unvested share-based compensation arrangements, compensation costs to be expensed

$ 46,500,000

Unvested share-based compensation arrangements, number of years compensation costs to be expensed

5 years

Incentive compensation plan expense

$ 30,000,000

$ 30,500,000

$ 25,800,000

4,383,000

5,017,000

15,244,000

Cash settled awards

6,500,000

12,900,000

17,200,000

Total intrinsic value of options exercised

$ 1,000,000

$ 0

Share-based Compensation Award, Tranche One [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Vesting period

2 years

Share-based Compensation Award, Tranche Two [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Vesting period

3 years

2012 Long-Term Plan [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Long term plan expiration year

2028

Maximum number of shares available for issuance

6,750,000

Maximum number of shares available for issuance, annual rate

1.00%

Option term

7 years

Number of shares available

3,400,000

Employee Stock Purchase Plan [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Salary that can be withheld by eligible employee for stock purchase

10.00%

Stock purchase price, percentage of the fair value of the stock

90.00%

Employess stock purchases, price per share

$ 26.85

$ 23.41

Employee stock purchases, shares

2,564

8,962

Discount percentage

10.00%

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

Fair value per share issued under ESPP

$ 5.34

$ 2.94

Annual Incentive Plan [Member] | Share-based Compensation Award, Tranche One [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Vesting percentage

50.00%

Employee Stock Options [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Stock options exercised

$ 0

Time Lapse Restricted Stock [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Fair value per share at grant date

$ 28.51

$ 17.57

Time Lapse Restricted Stock [Member] | Minimum [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Fair value per share at grant date

$ 25.69

Time Lapse Restricted Stock [Member] | Maximum [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Fair value per share at grant date

$ 28.43

[1]	Shares 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.

Incentive Plans (Share-Based Plans, Amounts Recognized) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Incentive Plans [Abstract]
Compensation charged against income (loss) before tax benefit	$ 34,467	$ 40,365	$ 46,300
Related income tax benefit recognized in income	$ 4,383	$ 5,017	$ 15,244

Incentive Plans (Fair Value of Option Award Estimated on Date of Grant using Black-Scholes Pricing Model) (Details) - Stock Options [Member] - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
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%
Expected life	5 years 3 months 18 days	5 years 2 months 12 days
Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value per option grant		$ 5.03
Assumptions
Dividend yield		4.00%
Expected volatility		45.00%
Risk-free interest rate		1.32%

Incentive Plans (Changes in Stock Options Outstanding) (Details) - $ / shares

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Number of Shares

Exercised

(21,200)

^[1]

Outstanding at end of year

3,994,595

Exercisable at end of year

3,182,345

Stock Options [Member]

Number of Shares

Outstanding at beginning of year

4,901,269

5,757,435

5,443,288

Granted at FMV

603,000

862,000

Exercised

(72,000)

Forfeited

(834,674)

(1,459,166)

(547,853)

Outstanding at end of year

3,994,595

4,901,269

5,757,435

Exercisable at end of year

3,182,345

3,197,269

3,830,535

3,542,352

Average Exercise Price

Outstanding at beginning of year

$ 45.74

$ 48.46

$ 52.93

Granted at FMV

28.51

17.57

Exercised

17.57

Forfeited

53.36

49.34

44.23

Outstanding at end of year

44.66

45.74

48.46

Exercisable at end of year

$ 49.10

$ 54.22

$ 53.80

$ 52.26

[1]	Shares 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.

Incentive Plans (Additional Information about Stock Options Outstanding) (Details)	12 Months Ended
	Dec. 31, 2018 USD ($) $ / shares shares
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options Outstanding, No. of Options	3,994,595
Options Outstanding, Avg. Life Remaining in Years	2 years 4 months 24 days
Options Outstanding, Aggregate Intrinsic Value \| $	$ 3,719,263
Options Exercisable, No. of Options	3,182,345
Options Exercisable, Avg. Life Remaining in Years	1 year 9 months 18 days
Options Exercisable, Aggregate Intrinsic Value \| $	$ 1,859,631
Range of Exercise Prices per Option, $17.00 to $30.00 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices per option, lower limit \| $ / shares	$ 17.00
Range of exercise prices per option, upper limit \| $ / shares	$ 30.00
Options Outstanding, No. of Options	1,131,500
Options Outstanding, Avg. Life Remaining in Years	4 years 6 months
Options Outstanding, Aggregate Intrinsic Value \| $	$ 3,719,263
Options Exercisable, No. of Options	319,250
Options Exercisable, Avg. Life Remaining in Years	4 years
Options Exercisable, Aggregate Intrinsic Value \| $	$ 1,859,631
Range of Exercise Prices per Option, $31.00 to $50.00 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices per option, lower limit \| $ / shares	$ 31.00
Range of exercise prices per option, upper limit \| $ / shares	$ 50.00
Options Outstanding, No. of Options	817,350
Options Outstanding, Avg. Life Remaining in Years	2 years 10 months 24 days
Options Exercisable, No. of Options	817,350
Options Exercisable, Avg. Life Remaining in Years	2 years 10 months 24 days
Range of Exercise Prices per Option, $51.00 to $65.00 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices per option, lower limit \| $ / shares	$ 51.00
Range of exercise prices per option, upper limit \| $ / shares	$ 65.00
Options Outstanding, No. of Options	2,045,745
Options Outstanding, Avg. Life Remaining in Years	1 year
Options Exercisable, No. of Options	2,045,745
Options Exercisable, Avg. Life Remaining in Years	1 year

Incentive Plans (Changes in Performance-Based RSU Outstanding) (Details) - Equity-Settled Restricted Stock Units [Member] - shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at beginning of year	1,187,921	992,573	1,103,986
Granted	905,500	560,000	394,000
Vested and issued	(311,866)	(272,725)	(361,096)
Forfeited	(121,138)	(91,927)	(144,317)
Outstanding at end of year	1,660,417	1,187,921	992,573

Incentive Plans (Assumptions used in Valuation Performance Awards Granted) (Details) - Performance Based Restricted Stock [Member]	12 Months Ended
	Dec. 31, 2018 item $ / shares	Dec. 31, 2017 item $ / shares	Dec. 31, 2016 item $ / shares
Assumptions
Expected volatility	48.00%	47.00%	33.00%
Risk-free interest rate	2.30%	1.46%	0.93%
Stock beta \| item	1.103	1.058	0.863
Expected life	3 years	3 years	3 years
Minimum [Member]
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 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value per share at grant date	$ 30.56	$ 28.28	$ 16.34

Incentive Plans (Changes in Time-Lapse Restricted Stock and Restricted Stock Units Outstanding) (Details) - Restricted Stock and Restricted Stock Units [Member] - shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding at beginning of year	1,035,980	923,282	477,244
Granted	823,803	419,720	503,555
Vested and issued	(233,456)	(217,633)	(32,092)
Forfeited	(87,473)	(89,389)	(25,425)
Outstanding at end of year	1,538,854	1,035,980	923,282

Employee and Retiree Benefit Plans (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended			120 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	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%			6.50%
Ultimate rate of health care cost in 2028 and thereafter	4.50%			4.50%
Plan asset, maximum investment in any one issuer	10.00%			10.00%
Equity securities minimum market capitalization	$ 100,000			$ 100,000
Fixed income portfolio, maximum average maturity years	11 years
Weighted average expected return on plan asset	5.42%
Basis used to determine expected return on plan asset, average expected investment expenses	0.60%
Perentage return on plan assets				7.71%
Defined benefit plan, percentage of employer's matching contribution	6.00%
Thrift plan expense	$ 5,200	$ 7,800	$ 7,400
Investment 2 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Domestic plan, investment notice period	90 days
Investment 3 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Domestic plan, investment lock up period	2 years
Domestic plan, investment notice period	95 days
Defined Benefit Plan, Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted average expected return on plan asset	6.97%
Defined Benefit Plan, Equity Securities [Member] \| Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	40.00%			40.00%
Defined Benefit Plan, Equity Securities [Member] \| Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	70.00%			70.00%
Defined Benefit Plan, Fixed Income Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted average expected return on plan asset	3.44%
Defined Benefit Plan, Fixed Income Securities [Member] \| Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	30.00%			30.00%
Defined Benefit Plan, Fixed Income Securities [Member] \| Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	60.00%			60.00%
Defined Benefit Plan, Long/Short Equity [Member] \| Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	0.00%			0.00%
Defined Benefit Plan, Long/Short Equity [Member] \| Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	15.00%			15.00%
Defined Benefit Plan, Cash And Equivalents [Member] \| Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	0.00%			0.00%
Defined Benefit Plan, Cash And Equivalents [Member] \| Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	15.00%			15.00%
Defined Benefit Plan, Equity Securities, Emerging Market Commingled Equity Fund [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Domestic plan, investment notice period	10 days
Canada [Member] \| Defined Benefit Plan, Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	42.00%			42.00%
Canada [Member] \| Defined Benefit Plan, Equity Securities [Member] \| Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	37.00%			37.00%
Canada [Member] \| Defined Benefit Plan, Equity Securities [Member] \| Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	47.00%			47.00%
Canada [Member] \| Defined Benefit Plan, Fixed Income Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	56.00%			56.00%
Canada [Member] \| Defined Benefit Plan, Fixed Income Securities [Member] \| Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	51.00%			51.00%
Canada [Member] \| Defined Benefit Plan, Fixed Income Securities [Member] \| Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	61.00%			61.00%
Canada [Member] \| Defined Benefit Plan, Cash [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	2.00%			2.00%
Canada [Member] \| Defined Benefit Plan, Cash [Member] \| Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	0.00%			0.00%
Canada [Member] \| Defined Benefit Plan, Cash [Member] \| Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	10.00%			10.00%
United Kingdom [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target interest and inflation rate hedge ratio	100.00%
United Kingdom [Member] \| Defined Benefit Plan, Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	60.00%			60.00%
United Kingdom [Member] \| Defined Benefit Plan, Fixed Income Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	40.00%			40.00%
Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	$ 24,357	$ 24,918
Weighted average expected return on plan asset	5.37%	5.64%
Pension Benefits [Member] \| United States [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	$ 23,700
Expected benefit plan contributions to be made during next year	26,700			$ 26,700
Pension Benefits [Member] \| Foreign Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	800
Expected benefit plan contributions to be made during next year	600			600
Other Postretirement Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	3,044	$ 2,417
Other Postretirement Benefits [Member] \| United States [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	3,000
Expected benefit plan contributions to be made during next year	$ 5,100			$ 5,100

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, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017
Change in plan assets
Total beginning balance	$ 563,825
Total ending balance	487,094	$ 563,825
Pension Benefits [Member]
Change in benefit obligation
Obligation at January 1	777,645	881,932	$ 815,593	$ 777,645	$ 881,932
Service cost	8,994	8,279	8,136
Interest cost	26,168	27,047	25,185
Participant contributions
Actuarial loss (gain)	(57,378)	60,855
Medicare Part D subsidy
Exchange rate changes	(12,742)	18,751
Benefits paid	(41,132)	(39,910)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), before Tax	737
Other	(28,934)	(8,683)
Obligation at December 31	777,645	881,932	815,593
Change in plan assets
Total beginning balance	563,825	519,357
Actual return on plan assets	(18,951)	50,079
Employer contributions	24,357	24,918
Participant contributions
Medicare Part D subsidy
Exchange rate changes	12,071	(18,064)
Benefits paid	(41,132)	(39,910)
Other				(28,934)	(8,683)
Total ending balance	487,094	563,825	519,357
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets				11,039	5,905
Other accrued liabilities				(9,175)	(8,856)
Deferred credits and other liabilities				(292,415)	(315,156)
Funded status and net plan liability recognized at December 31				(290,551)	(318,107)
Other Postretirement Benefits [Member]
Change in benefit obligation
Obligation at January 1	94,779	106,276	106,679	94,779	106,276
Service cost	1,965	1,601	1,864
Interest cost	3,427	3,444	3,800
Participant contributions	2,104	2,075
Actuarial loss (gain)	(13,778)	(3,077)
Medicare Part D subsidy	325	318
Exchange rate changes	(67)	46
Benefits paid	(5,473)	(4,810)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), before Tax
Other
Obligation at December 31	94,779	106,276	106,679
Change in plan assets
Total beginning balance
Actual return on plan assets
Employer contributions	3,044	2,417
Participant contributions	2,104	2,075
Medicare Part D subsidy	325	318
Exchange rate changes
Benefits paid	(5,473)	(4,810)
Other
Total ending balance
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets
Other accrued liabilities				(5,101)	(5,392)
Deferred credits and other liabilities				(89,678)	(100,884)
Funded status and net plan liability recognized at December 31				$ (94,779)	$ (106,276)

Employee and Retiree Benefit Plans (Amounts Included in Accumulated Other Comprehensive Income Not Recognized in Net Periodic Benefit Expense) (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ (239,030)
Prior service (cost) credit	(5,568)
Amounts included in accumulated other comprehensive loss which have not been recognized in net periodic benefit expense	(244,598)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	13,969
Amounts included in accumulated other comprehensive loss which have not been recognized in net periodic benefit expense	$ 13,969

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, 2018 USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ (14,117)
Prior service (cost) credit	(956)
Amounts included in accumulated other comprehensive loss expected to be amortized into net periodic benefit expense	(15,073)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	(391)
Amounts included in accumulated other comprehensive loss expected to be amortized into net periodic benefit expense	$ (391)

Employee and Retiree Benefit Plans (Projected Benefit Obligations, Accumulated Benefit Obligations and Fair Value of Plan Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Funded Plan [Member] \| Qualified Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations	$ 457,446	$ 691,923
Accumulated Benefit Obligations	447,793	640,230
Fair Value of Plan Assets	316,543	540,161
Unfunded Plan [Member] \| Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations	94,808	106,276
Accumulated Benefit Obligations	94,808	106,276
Unfunded Plan [Member] \| Nonqualified Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations	158,228	172,364
Accumulated Benefit Obligations	$ 150,586	$ 163,319

Employee and Retiree Benefit Plans (Components of Net Periodic Benefit Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 8,994	$ 8,279	$ 8,136
Interest cost	26,168	27,047	25,185
Expected return on plan assets	(29,236)	(28,941)	(28,154)
Amortization of prior service cost (credit)	1,021	1,026	1,204
Recognized actuarial loss	21,893	16,691	16,165
Gross periodic benefit expense	28,840	24,102	22,536
Curtailment expense			822
Net periodic benefit expense	28,840	24,102	23,358
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	1,965	1,601	1,864
Interest cost	3,427	3,444	3,800
Amortization of prior service cost (credit)	(38)	(74)	(75)
Recognized actuarial loss			5
Gross periodic benefit expense	5,354	4,971	5,594
Curtailment expense			(19)
Net periodic benefit expense	$ 5,354	$ 4,971	$ 5,575

Employee and Retiree Benefit Plans (Amount Related to Foreign Benefit Plans) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at December 31	$ 487,094	$ 563,825
Foreign Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at December 31	170,551	212,533
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	777,645	881,932	$ 815,593
Fair value of plan assets at December 31	487,094	563,825	519,357
Net plan liabilities recognized	(290,551)	(318,107)
Net periodic benefit expense (benefit)	28,840	24,102	23,358
Pension Benefits [Member] \| Foreign Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	173,860	222,483
Fair value of plan assets at December 31	170,551	212,535
Net plan liabilities recognized	3,309	9,948
Net periodic benefit expense (benefit)	3,983	194
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	94,779	106,276	106,679
Fair value of plan assets at December 31
Net plan liabilities recognized	(94,779)	(106,276)
Net periodic benefit expense (benefit)	5,354	4,971	$ 5,575
Other Postretirement Benefits [Member] \| Foreign Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	812	791
Net plan liabilities recognized	812	791
Net periodic benefit expense (benefit)	$ 146	$ 133

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	5.42%
Net Periodic Benefit Expense, Expected return on plan assets	5.42%
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligations, Discount rate	4.07%	3.42%
Benefit Obligations, Expected return on plan assets	5.37%	5.64%
Benefit Obligation, Rate of compensation increase	3.28%	3.52%
Net Periodic Benefit Expense, Discount rate	3.54%	3.66%
Net Periodic Benefit Expense, Expected return on plan assets	5.37%	5.64%
Net Periodic Benefit Expense, Rate of compensation increase	3.52%	3.52%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligations, Discount rate	3.73%	3.73%
Net Periodic Benefit Expense, Discount rate	4.32%	4.33%

Employee and Retiree Benefit Plans (Benefit Payments Expected to be Paid in Future Years) (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2018	$ 37,266
2019	37,565
2020	38,606
2021	39,660
2022	39,908
2023-2027	207,633
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2018	5,754
2019	5,839
2020	5,994
2021	6,130
2022	6,171
2023-2027	$ 32,109

Employee and Retiree Benefit Plans (One Percent Change in Assumed Health Care Cost Trend Rates) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018 USD ($)
Employee and Retiree Benefit Plans [Abstract]
1% Increase, Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 2018	$ 1,049
1% Increase, Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2018	12,656
1% Decrease, Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 2018	(813)
1% Decrease, Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2018	$ (10,350)

Employee and Retiree Benefit Plans (Weighted Average Asset Allocation for Funded Pension Benefit Plans) (Details)	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	100.00%	100.00%
Defined Benefit Plan, Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	56.00%	60.30%
Defined Benefit Plan, Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	42.20%	37.20%
Defined Benefit Plan, Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	1.80%	2.50%

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, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Total beginning balance	$ 563,825
Total ending balance	487,094	$ 563,825
Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total beginning balance	37,950
Total ending balance	35,055	37,950
Defined Benefit Plan, Hedged Funds And Other Alternative Strategies [Member] \| Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total beginning balance	37,950	34,114
Relating to assets held at the reporting date	(2,921)	3,836
Relating to assets sold during the period
Purchases, sales and settlements
Total ending balance	$ 35,029	$ 37,950

Financial Instruments and Risk Management (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018 USD ($) contract $ / bbl	Dec. 31, 2017 USD ($) bbl / d contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of foreign currency derivatives \| contract	0	0
Amount of loss reclassified to interest expense	$ 2,963	$ 2,963
Amount of loss expected to be reclassified to interest expense in the next 12 months	3,000
Loss deferred for fair value of interest rate derivative contracts, net of tax	7,900
Income taxes on deferred loss on fair value of interest rate derivative contracts	$ 2,100
Commodity Derivative Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Daily production commitment (barrels per day) \| bbl / d		21,000
Average price \| $ / bbl	54.88

Financial Instruments and Risk Management (Fair Value of Derivative Instruments Not Designated as Hedging Instruments) (Details) - Nondesignated [Member] - Commodity Derivative Contracts [Member] - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Accounts Receivable [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	$ 3,837
Accounts Payable [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives		$ (39,093)

Financial Instruments and Risk Management (Recognized Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments) (Details) - Nondesignated [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ (41,975)	$ 9,566	$ (36,698)
Commodity Derivative Contracts [Member] \| Gain (Loss) on Crude Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ (41,975)	$ 9,566	(63,412)
Foreign Exchange Derivative Contracts [Member] \| Interest And Other Income (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)			$ 26,714

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Earnings per Share [Abstract]

Basic method

172,974,491

172,524,061

^[1]

172,173,012

^[1]

Dilutive stock options

1,234,274

^[2]

Diluted method

174,208,765

172,524,061

^[1]

172,173,012

^[1]

[1]	Reclassified to conform to current presentation (see Note B).
[2]	Due to a net loss recognized by the Company for the years ended December 31, 2017 and 2016, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive.

Earnings per Share (Anti Dilutive Securities Not Included in Computation of Diluted EPS) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings per Share [Abstract]
Antidilutive stock options excluded from diluted shares (in shares)	3,942,296	4,901,269	5,757,435
Weighted average price of these options (per share)	$ 46.77	$ 45.74	$ 48.46

Other Financial Information (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($) item
Other Financial Information [Line Items]
Net gains (losses) from foreign currency transactions	$ (7.8)	$ (75.4)	$ 59.7
Deepwater rig contract exit costs				$ 282.0
Payment of contract exit costs			266.7
Write down of accrued contract exit costs		$ 6.1	$ 4.3
Gulf Of Mexico [Member]
Other Financial Information [Line Items]
Number of deepwater drilling rigs \| item				2

Other Financial Information (Noncash Opearting Working Capital (Increase) Decrease) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Other Financial Information [Abstract]
(Increase) decrease in accounts receivable	$ (89,070)	$ 114,401	$ 119,671
Decrease in inventories	12,216	26,883	(5,171)
(Increase) decrease in prepaid expenses	(17,341)	29,570	149,946
Increase (decrease) in accounts payable and accrued liabilities	(51,769)	(51,439)	(328,078)
Current income tax liabilities	(23,844)	16,999	24,943
Net (increase) decrease in noncash operating working capital	(169,808)	136,414	(38,689)
Cash income taxes paid, net of refunds	129,296	68,076	6,707
Interest paid, net of amounts capitalized of $3,719 in 2018 and $3,338 in 2017	167,750	147,975	127,798
Asset retirement costs capitalized	353,436	8,509	13,690
(Increase) decrease in capital expenditure accrual	(42,467)	99,199	158,885
Interest paid, amounts capitalized	$ 5,258	$ 4,488	$ 4,322

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Accumulated Other Comprehensive Income (Loss) [Line Items]

$ (462,243)

$ (628,212)

(163,676)

154,456

16,132

11,513

(147,544)

165,969

$ 76,330

Reclassifications before taxes, included in net periodic benefit expense

(609,787)

(462,243)

(628,212)

14,821

17,313

Reclassifications, income tax expense

5,234

3,523

Reclassifications income tax, included in interest expense

622

1,037

Foreign Currency Translation Gains (Losses) [Member]

Accumulated Other Comprehensive Income (Loss) [Line Items]

(274,830)

(446,555)

(145,022)

171,725

(145,022)

171,725

Retirement and Postretirement Benefit Plan Adjustments [Member]

(419,852)

(274,830)

(446,555)

Accumulated Other Comprehensive Income (Loss) [Line Items]

(178,987)

(171,305)

(16,839)

(17,269)

^[1]

13,790

9,587

(3,049)

(7,682)

Deferred Loss On Interest Rate Derivative Hedges [Member]

(182,036)

(178,987)

(171,305)

Accumulated Other Comprehensive Income (Loss) [Line Items]

(8,426)

(10,352)

(1,815)

^[2]

2,342

1,926

527

1,926

$ (7,899)

$ (8,426)

$ (10,352)

[1]	Reclassifications before taxes of $17,313 and $14,821 are included in the computation of net periodic benefit expense in 2018 and 2017, respectively. See Note L for additional information. Related income taxes of $3,523 and $5,234 are included in income tax expense in 2018 and 2017, respectively.
[2]	Reclassifications before taxes of $2,963 are included in Interest expense in both 2018 and 2017. Related income taxes of $622 and $1,037 are included in income tax expense in 2018 and 2017. See Note M for additional information.

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

^[1]

Contingent Consideration Liability [Member]

$ 20,000,000

$ 0

$ 95,088,000

Fair value assumptions, expected term

7 years

Fair value assumptions, expected volatility rate

30.00%

Fair value assumptions

2.752%

[1]	Reclassified to conform to current presentation (see Note B).

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 [Member] - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Commodity derivative contracts	$ 3,837
Assets, Total	3,837
Liabilities, Nonqualified employee savings plans	13,845	$ 16,158
Liabilities, Commodity derivative contracts		39,093
Business Combination, Contingent Consideration, Liability	47,730
Liabilities, Total	61,575	55,251
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, Nonqualified employee savings plans	13,845	16,158
Liabilities, Total	13,845	16,158
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Commodity derivative contracts	3,837
Assets, Total	3,837
Liabilities, Commodity derivative contracts		39,093
Liabilities, Total		$ 39,093
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Business Combination, Contingent Consideration, Liability	47,730
Liabilities, Total	$ 47,730

Assets and Liabilities Measured at Fair Value (Carrying Amounts and Estimated Fair Values of Financial Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Financial assets (liabilities), Carrying value
Current and long-term debt	$ (3,237,717)	$ (2,916,422)
Financial assets (liabilities), Fair value
Current and long-term debt	$ (3,003,388)	$ (2,993,003)

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Assets and Liabilities Measured at Fair Value [Abstract]

Total Pretax (Noncash) Impairment Expense

$ 20,000,000

$ 0

$ 95,088,000

^[1]

[1]	Reclassified to conform to current presentation (see Note B).

Commitments (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
Commitments (Narrative) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Commitments and Contingencies Disclosure [Line Items]
Operating lease rental payments due in 2019	$ 188,600
Operating lease rental payments due in 2020	88,900
Operating lease rental payments due in 2021	61,900
Operating lease rental payments due in 2022	27,600
Operating lease rental payments due in 2023	15,600
Rental expenses for non-cancellable lease, including contingent payments	75,300	$ 72,600	$ 77,500
Commitments for capital expenditures	383,100
Malaysia [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	103,000
Kaybob Duvernay Lands, Alberta [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	60,000
Eagle Ford Shale [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	31,400
Mexico [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	14,700
Gulf Of Mexico [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	$ 165,200
Rig contract cancellation period	30 days
Vietnam [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	$ 8,800
Drilling Rigs And Associated Equipment [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	57,900
Processing Production Handling and Transportation Services [Member]
Commitments and Contingencies Disclosure [Line Items]
Operating lease rental payments due in 2019	116,800
Operating lease rental payments due in 2020	128,000
Operating lease rental payments due in 2021	145,300
Operating lease rental payments due in 2022	136,200
Operating lease rental payments due in 2023	123,700
Processing and transportation charges	$ 52,200	$ 53,800	$ 50,300

Contingencies (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
Contingencies (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2015
Contingencies Disclosure [Line Items]
Remediation accrual	$ 3.0
Proceeds from insurance settlement	25.0
Canada [Member]
Contingencies Disclosure [Line Items]
Remediation costs	3.8	$ 43.9
Payments for environmental liabilities	$ 44.7

Common Stock Issued and Outstanding (Activity in the Number of Common Stock Issued and Outstanding) (Details) - shares

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Stockholders' Equity and Common Stock Issued and Outstanding [Abstract]

Beginning of year

172,572,873

172,202,177

172,034,711

Stock options exercised

21,200

^[1]

Restricted stock awards

^[1]

464,756

368,132

158,504

Employee stock purchase and thrift plans

2,564

8,962

Treasury shares purchased

End of year

173,058,829

172,572,873

172,202,177

[1]	Shares 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.

Business Segments (Narrative) (Details)	12 Months Ended
Business Segments (Narrative) (Details)	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Sales Revenue [Member] \| Phillips 66 and Affiliated Companies [Member]
Segment Reporting Information [Line Items]
Concentration risk	12.00%	14.00%	17.00%

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

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

^[1]

Jun. 30, 2018

^[1]

Mar. 31, 2018

^[1]

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Revenues From External Customers And Long Lived Assets [Line Items]

Net income (loss) including noncontrolling interest

$ 111,800,000

^[1]

$ 93,900,000

$ 45,500,000

$ 168,300,000

$ 419,486,000

$ (311,789,000)

^[2]

$ (275,970,000)

^[2]

2,570,603,000

2,225,129,000

^[2]

1,811,238,000

^[2]

181,604,000

181,783,000

^[2]

148,170,000

^[2]

9,330,000

382,738,000

^[2]

(219,172,000)

^[2]

971,901,000

957,719,000

^[2]

1,054,081,000

^[2]

44,559,000

42,590,000

^[2]

46,742,000

^[2]

40,177,000

61,776,000

43,417,000

20,000,000

95,088,000

^[2]

11,052,587,000

9,860,942,000

Revenues From External Customers And Long Lived Assets [Line Items]

Revenues From External Customers And Long Lived Assets [Line Items]

1,297,500,000

958,300,000

692,300,000

Canada [Member]

438,500,000

485,700,000

365,300,000

95,088,000

Revenues From External Customers And Long Lived Assets [Line Items]

Revenues From External Customers And Long Lived Assets [Line Items]

854,300,000

781,100,000

753,400,000

Other [Member]

Discontinued Operations [Member]

(19,700,000)

200,000

Revenues From External Customers And Long Lived Assets [Line Items]

Net income (loss) including noncontrolling interest

(3,500,000)

(900,000)

(2,000,000)

Operating Segments [Member]

20,900,000

22,900,000

27,100,000

Revenues From External Customers And Long Lived Assets [Line Items]

Net income (loss) including noncontrolling interest

419,500,000

(311,800,000)

(276,000,000)

2,570,600,000

2,225,100,000

1,811,200,000

8,000,000

7,400,000

2,900,000

181,600,000

181,800,000

148,200,000

9,300,000

382,700,000

(219,200,000)

971,900,000

957,700,000

1,054,100,000

44,600,000

42,600,000

46,700,000

40,100,000

61,800,000

43,400,000

95,100,000

(183,700,000)

260,400,000

(387,800,000)

1,894,500,000

870,800,000

753,100,000

Exploration And Production Segment [Member]

11,052,500,000

9,860,900,000

10,295,900,000

Revenues From External Customers And Long Lived Assets [Line Items]

Net income (loss) including noncontrolling interest

546,900,000

290,300,000

(83,700,000)

2,604,600,000

^[3]

2,210,900,000

1,868,000,000

200,000

200,600,000

133,800,000

(132,900,000)

954,000,000

939,900,000

1,037,300,000

44,600,000

42,600,000

46,700,000

40,100,000

61,800,000

43,400,000

20,000,000

95,100,000

58,400,000

17,900,000

(311,000,000)

1,871,800,000

856,000,000

731,200,000

Exploration And Production Segment [Member] | United States [Member]

9,913,100,000

8,736,300,000

9,118,900,000

Revenues From External Customers And Long Lived Assets [Line Items]

Net income (loss) including noncontrolling interest

242,900,000

(8,900,000)

(164,200,000)

1,289,600,000

^[3]

944,300,000

749,100,000

68,100,000

(800,000)

(65,700,000)

519,500,000

546,100,000

600,500,000

19,500,000

17,400,000

17,100,000

36,800,000

60,200,000

38,400,000

20,000,000

68,100,000

2,500,000

(108,400,000)

1,343,500,000

534,800,000

269,800,000

Exploration And Production Segment [Member] | Canada [Member]

6,342,900,000

5,186,200,000

5,419,000,000

Revenues From External Customers And Long Lived Assets [Line Items]

Net income (loss) including noncontrolling interest

^[4]

51,100,000

112,500,000

(35,900,000)

^[4]

438,600,000

^[3]

485,500,000

365,300,000

^[4]

^[4]

^[4]

14,500,000

44,400,000

(134,300,000)

^[4]

232,400,000

185,400,000

203,200,000

^[4]

7,700,000

7,900,000

13,300,000

^[4]

800,000

1,600,000

4,500,000

^[4]

95,100,000

^[4]

16,500,000

55,300,000

(175,800,000)

^[4]

373,800,000

267,600,000

361,300,000

Exploration And Production Segment [Member] | Malaysia [Member]

^[4]

1,711,900,000

1,725,800,000

1,559,500,000

Revenues From External Customers And Long Lived Assets [Line Items]

Net income (loss) including noncontrolling interest

269,500,000

224,200,000

171,100,000

854,200,000

^[3]

781,100,000

753,400,000

143,300,000

126,400,000

85,900,000

198,600,000

204,600,000

227,700,000

17,400,000

17,300,000

16,300,000

(500,000)

(3,700,000)

(8,500,000)

138,600,000

16,000,000

101,400,000

Exploration And Production Segment [Member] | Other [Member]

1,670,200,000

1,670,100,000

2,024,700,000

Revenues From External Customers And Long Lived Assets [Line Items]

Net income (loss) including noncontrolling interest

(16,600,000)

(37,500,000)

(54,700,000)

22,200,000

^[3]

200,000

200,000

(25,300,000)

(36,200,000)

(18,800,000)

3,500,000

3,800,000

5,900,000

2,500,000

500,000

(25,700,000)

(36,200,000)

(18,300,000)

15,900,000

37,600,000

(1,300,000)

Corporate and Other [Member]

188,100,000

154,200,000

115,700,000

Revenues From External Customers And Long Lived Assets [Line Items]

Net income (loss) including noncontrolling interest

(123,900,000)

(607,500,000)

(149,100,000)

(34,000,000)

4,600,000

6,600,000

8,000,000

7,400,000

2,900,000

181,400,000

181,800,000

148,200,000

(191,300,000)

245,600,000

(64,100,000)

17,900,000

17,800,000

16,800,000

(242,100,000)

242,500,000

(76,800,000)

22,700,000

14,800,000

21,900,000

$ 1,118,500,000

$ 1,101,700,000

$ 1,149,900,000

[1]	2018 includes noncontrolling interest in MP GOM.
[2]	Reclassified to conform to current presentation (see Note B).
[3]	Includes a pretax gain of $129.0 million on sale of Seal area heavy oil field sold in January 2017.
[4]	Includes Synthetic crude operations in 2016. This business was sold in June 2016.

Business Segments (Geographic Information on Certain Long-Lived Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	$ 9,757.6	$ 8,220.0	$ 8,316.2
United States [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	6,634.3	5,050.5	5,121.6
Canada [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	1,644.6	1,635.9	1,451.4
Malaysia [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	1,325.4	1,392.3	1,637.0
Other [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	$ 153.3	$ 141.3	$ 106.2

Supplemental Oil and Gas Information (Narrative) (Details)
MMBbls in Millions

12 Months Ended

Dec. 31, 2018

$ / bbl

$ / Mcf

MMcf

Dec. 31, 2017

$ / bbl

$ / Mcf

ft³

MMBbls

Dec. 31, 2018

bbl

Dec. 31, 2018

ft³

Dec. 31, 2018

MMBbls

Dec. 31, 2018

$ / Mcf

Dec. 31, 2018

Dec. 31, 2016

ft³

MMBbls

Dec. 31, 2015

ft³

MMBbls

Future net cash flows annual discount factor, percentage

328.1

432.5

^[1]

329.0

456.2

10.00%

U.S. statutory rate

21.00%

35.00%

Equity Method Investee [Member]

Reserves attributable to investees accounted for my the equity method | bbl

Crude Oil And Condensate [Member]

Reserve estimates, average market price | $ / bbl

65.56

51.34

Proved undeveloped reserve development window

5 years

Proved undeveloped reserve development window

48.9

54.2

^[2]

42.5

36.4

5 years

Reserve estimates, average market price | $ / Mcf

3.10

2.98

Proved reserves | ft³

1,927,100,000,000

2,143,600,000,000

^[3]

1,878,000,000,000

1,688,800,000,000

Proved undeveloped reserve development window

5 years

Alberta, Canada [Member]

Malaysia [Member] | Crude Oil And Condensate [Member]

Working interest

5.00%

Malaysia [Member] | Natural Gas Liquids [Member]

51.7

Malaysia [Member] | Natural Gas [Member]

0.3

0.7

^[2]

0.5

0.6

Malaysia [Member] | Natural Gas [Member] | Held-for-sale [Member]

468,200

491,400,000,000

468,200,000,000

^[3]

539,700,000,000

546,800,000,000

Expected sales proceeds | $ / Mcf

Proved reserves | ft³

26,100

0.24

Canada [Member] | Natural Gas Liquids [Member]

Canada [Member] | Natural Gas [Member]

5.6

5.9

^[2]

5.6

0.4

Canada [Member] | Synthetic Oil [Member]

Proved reserves | ft³

1,212,400,000,000

1,366,400,000,000

^[3]

1,118,900,000,000

909,600,000,000

^[4]

0.0

114.8

[1]	Includes total proved reserves of 25.5 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.
[2]	Includes total proved reserves of 1.1 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.
[3]	Includes total proved reserves of 10.8 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.
[4]	All synthetic oil operations were sold in June 2016.

Supplemental Oil and Gas Information (Summary of Proved Reserves Based on Average Prices) (Details)
bbl in Millions, MMBbls in Millions, ft³ in Billions

12 Months Ended

Dec. 31, 2018

MMcf

bbl

ft³

MMBbls

Dec. 31, 2018

bbl

ft³

MMBbls

Dec. 31, 2018

bbl

ft³

MMBbls

Dec. 31, 2018

bbl

ft³

MMBbls

Dec. 31, 2017

ft³

MMBbls

Dec. 31, 2016

ft³

MMBbls

Dec. 31, 2015

ft³

MMBbls

Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance

328.1

329.0

456.2

(15.3)

(6.0)

(5.8)

Improved recovery

0.8

2.0

58.9

31.6

11.0

93.6

4.7

26.3

(121.0)

Proved developed and undeveloped reserves, Ending Balance

(33.6)

(33.2)

(37.7)

432.5

^[1]

328.1

329.0

249.3

^[2]

249.3

^[2]

249.3

^[2]

249.3

^[2]

185.5

184.9

326.6

183.2

^[3]

183.2

^[3]

183.2

^[3]

183.2

^[3]

142.6

144.1

129.6

Crude Oil [Member]

Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance

328.1

329.0

341.4

(15.3)

(6.0)

(5.8)

Improved recovery

0.8

2.0

58.9

31.6

11.0

93.6

4.7

26.3

(7.8)

Proved developed and undeveloped reserves, Ending Balance

(33.6)

(33.2)

(36.1)

432.5

^[1]

328.1

329.0

249.3

^[2]

249.3

^[2]

249.3

^[2]

249.3

^[2]

185.5

184.9

211.8

183.2

^[3]

183.2

^[3]

183.2

^[3]

183.2

^[3]

142.6

144.1

129.6

Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance

48.9

42.5

36.4

(6.2)

1.3

1.6

12.0

7.8

2.9

3.0

0.5

5.1

Proved developed and undeveloped reserves, Ending Balance

(3.5)

(3.2)

(3.5)

54.2

^[4]

48.9

42.5

27.3

^[5]

27.3

^[5]

27.3

^[5]

27.3

^[5]

24.6

22.2

21.6

26.9

^[6]

26.9

^[6]

26.9

^[6]

26.9

^[6]

24.3

20.3

14.8

Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance | ft³

1,927.1

1,878.0

1,688.8

(1.8)

(5.4)

43.3

0.6

164.2

Purchases of properties | ft³

310.3

190.6

122.3

61.7

4.0

Sales of properties | ft³

(2.2)

Proved developed and undeveloped reserves, Ending Balance | ft³

(154.3)

(140.1)

(138.4)

2,143.6

^[7]

1,927.1

1,878.0

921.6

^[8]

921.6

^[8]

921.6

^[8]

921.6

^[8]

819.3

818.1

783.5

MP Gulf Of Mexico LLC [Member] | Crude Oil And Condensate [Member]

1,222.0

^[9]

1,222.0

^[9]

1,222.0

^[9]

1,222.0

^[9]

1,107.8

1,059.9

905.3

Proved developed and undeveloped reserves, Ending Balance | bbl

25.5

Proved developed reserves | bbl

19.1

Proved undeveloped reserves | bbl

6.4

MP Gulf Of Mexico LLC [Member] | Natural Gas Liquids [Member]

Proved developed and undeveloped reserves, Ending Balance | bbl

1.1

Proved developed reserves | bbl

0.8

Proved undeveloped reserves | bbl

0.3

MP Gulf Of Mexico LLC [Member] | Natural Gas [Member]

Proved developed and undeveloped reserves, Ending Balance | ft³

10.8

8.2

United States [Member] | Crude Oil [Member]

2.6

Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance

224.7

214.4

238.9

(15.0)

(4.7)

(10.9)

42.9

27.2

8.6

92.3

4.7

(4.5)

Proved developed and undeveloped reserves, Ending Balance

(18.4)

(16.9)

(17.7)

326.5

^[1]

224.7

214.4

189.0

^[2]

189.0

^[2]

189.0

^[2]

189.0

^[2]

126.3

113.9

125.9

United States [Member] | Natural Gas Liquids [Member]

137.5

^[3]

137.5

^[3]

137.5

^[3]

137.5

^[3]

98.4

100.5

113.0

Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance

43.0

36.4

35.4

(5.3)

2.0

1.2

9.7

7.0

2.8

3.0

0.5

Proved developed and undeveloped reserves, Ending Balance

(2.8)

(2.9)

(3.0)

47.6

^[4]

43.0

36.4

24.9

^[5]

24.9

^[5]

24.9

^[5]

24.9

^[5]

23.3

20.8

20.7

United States [Member] | Natural Gas [Member]

22.7

^[6]

22.7

^[6]

22.7

^[6]

22.7

^[6]

19.7

15.6

14.7

Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance | ft³

223.3

219.4

232.4

37.6

(16.0)

0.1

6.4

Purchases of properties | ft³

44.7

32.2

20.3

4.0

Sales of properties | ft³

(0.1)

Proved developed and undeveloped reserves, Ending Balance | ft³

(16.9)

(16.3)

(19.4)

309.0

^[7]

223.3

219.4

198.3

^[8]

198.3

^[8]

198.3

^[8]

198.3

^[8]

127.7

138.7

148.3

Canada [Member] | Crude Oil [Member]

110.7

^[9]

110.7

^[9]

110.7

^[9]

110.7

^[9]

95.6

80.7

84.1

Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance

51.5

48.9

27.9

(8.0)

2.3

2.5

16.0

4.4

26.3

(3.3)

Proved developed and undeveloped reserves, Ending Balance

(4.5)

(4.1)

(4.5)

55.0

^[1]

51.5

48.9

23.3

^[2]

23.3

^[2]

23.3

^[2]

23.3

^[2]

21.9

19.2

23.8

Canada [Member] | Synthetic Oil [Member]

31.7

^[3]

31.7

^[3]

31.7

^[3]

31.7

^[3]

29.6

29.7

4.1

Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance

^[10]

0.0

114.8

^[10]

(113.2)

Proved developed and undeveloped reserves, Ending Balance

^[10]

(1.6)

^[10]

0.0

Canada [Member] | Natural Gas Liquids [Member]

^[10]

114.8

Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance

5.6

0.4

(1.6)

(0.6)

0.2

2.3

0.8

0.1

5.1

Proved developed and undeveloped reserves, Ending Balance

(0.4)

(0.2)

5.9

^[4]

5.6

1.7

^[5]

1.7

^[5]

1.7

^[5]

1.7

^[5]

1.0

0.9

0.3

Canada [Member] | Natural Gas [Member]

4.2

^[6]

4.2

^[6]

4.2

^[6]

4.2

^[6]

4.6

4.7

0.1

Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance | ft³

1,212.4

1,118.9

909.6

(51.2)

19.4

45.3

120.2

Purchases of properties | ft³

261.0

156.7

122.3

41.4

Sales of properties | ft³

(2.1)

Proved developed and undeveloped reserves, Ending Balance | ft³

(97.2)

(82.6)

(76.4)

1,366.4

^[7]

1,212.4

1,118.9

595.0

^[8]

595.0

^[8]

595.0

^[8]

595.0

^[8]

547.0

498.9

453.5

Malaysia [Member] | Crude Oil [Member]

771.4

^[9]

771.4

^[9]

771.4

^[9]

771.4

^[9]

665.5

620.0

456.1

Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance

51.9

65.7

74.6

7.7

(3.6)

2.6

Improved recovery

0.8

2.0

2.4

1.3

Proved developed and undeveloped reserves, Ending Balance

(10.7)

(12.2)

(13.9)

51.0

^[1]

51.9

65.7

37.0

^[2]

37.0

^[2]

37.0

^[2]

37.0

^[2]

37.3

51.8

62.1

Malaysia [Member] | Crude Oil And Condensate [Member]

14.0

^[3]

14.0

^[3]

14.0

^[3]

14.0

^[3]

14.6

13.9

12.5

Proved developed and undeveloped reserves, Ending Balance

51.7

Malaysia [Member] | Natural Gas Liquids [Member]

Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance

0.3

0.5

0.6

0.7

(0.1)

0.2

Proved developed and undeveloped reserves, Ending Balance

(0.3)

(0.1)

(0.3)

0.7

^[4]

0.3

0.5

Malaysia [Member] | Natural Gas [Member]

0.7

^[5]

0.7

^[5]

0.7

^[5]

0.7

^[5]

0.3

0.5

0.6

Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance | ft³

491.4

539.7

546.8

11.8

(8.8)

(2.1)

0.6

37.6

4.6

1.7

Proved developed and undeveloped reserves, Ending Balance

(40.2)

(41.2)

(42.6)

468,200

468.2

^[7]

491.4

539.7

128.3

^[8]

128.3

^[8]

128.3

^[8]

128.3

^[8]

144.6

180.5

181.7

339.9

^[9]

339.9

^[9]

339.9

^[9]

339.9

^[9]

346.7

359.2

365.1

[1]	Includes total proved reserves of 25.5 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.
[2]	Includes proved developed reserves of 19.1 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.
[3]	Includes proved undeveloped reserves of 6.4 MMBO for Total and United States attributable to the noncontrolling interest in MP GOM.
[4]	Includes total proved reserves of 1.1 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.
[5]	Includes proved developed reserves of 0.8 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.
[6]	Includes proved undeveloped reserves of 0.3 MMBBL for Total and United States attributable to the noncontrolling interest in MP GOM.
[7]	Includes total proved reserves of 10.8 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.
[8]	Includes proved developed reserves of 8.2 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.
[9]	Includes proved undeveloped reserves of 2.6 BCF for Total and United States attributable to the noncontrolling interest in MP GOM.
[10]	All synthetic oil operations were sold in June 2016.

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Property acquisition costs
Unproved	$ 3.0	$ 63.4	$ 18.6
Proved	794.3	7.7	206.7
Total acquisition costs	797.3	71.1	225.3
Exploration costs	126.0	79.2	70.1
Development costs	1,390.0	819.0	508.0
Total costs incurred	2,313.3	969.3	803.4
Charged to expense
Dry hole expense	20.6	(4.2)	15.1
Geophysical and other costs	47.4	65.2	43.4
Total charged to expense	68.0	61.0	58.5
Property additions	2,245.3	908.3	744.9
United States [Member]
Property acquisition costs
Unproved	2.8	50.4	18.6
Proved	794.3	7.7
Total acquisition costs	797.1	58.1	18.6
Exploration costs	88.1	13.7	18.5
Development costs	853.7	508.4	239.7
Total costs incurred	1,738.9	580.2	276.8
Charged to expense
Dry hole expense	16.0	(1.9)	0.4
Geophysical and other costs	13.4	9.7	5.7
Total charged to expense	29.4	7.8	6.1
Property additions	1,709.5	572.4	270.7
Canada [Member]
Property acquisition costs
Proved			206.7
Total acquisition costs			206.7
Exploration costs	0.6	0.6	3.6
Development costs	373.8	273.8	165.1
Total costs incurred	374.4	274.4	375.4
Charged to expense
Geophysical and other costs	0.6	0.5	3.6
Total charged to expense	0.6	0.5	3.6
Property additions	373.8	273.9	371.8
Malaysia [Member]
Property acquisition costs
Exploration costs	2.2	(8.9)	6.0
Development costs	145.9	35.7	102.9
Total costs incurred	148.1	26.8	108.9
Charged to expense
Dry hole expense	0.1	0.7	4.5
Geophysical and other costs	2.1	1.7	0.7
Total charged to expense	2.2	2.4	5.2
Property additions	145.9	24.4	103.7
Other Regions [Member]
Property acquisition costs
Unproved	0.2	13.0
Total acquisition costs	0.2	13.0
Exploration costs	35.1	73.8	42.0
Development costs	16.6	1.1	0.3
Total costs incurred	51.9	87.9	42.3
Charged to expense
Dry hole expense	4.5	(3.0)	10.2
Geophysical and other costs	31.3	53.3	33.4
Total charged to expense	35.8	50.3	43.6
Property additions	16.1	37.6	(1.3)
Asset Retirement Obligation Costs [Member]
Property acquisition costs
Development costs	373.5	52.3	13.7
Total costs incurred	373.5	52.3	13.7
Asset Retirement Obligation Costs [Member] \| United States [Member]
Property acquisition costs
Development costs	366.0	37.6	0.9
Total costs incurred	366.0	37.6	0.9
Asset Retirement Obligation Costs [Member] \| Canada [Member]
Property acquisition costs
Development costs		6.3	10.5
Total costs incurred		6.3	10.5
Asset Retirement Obligation Costs [Member] \| Malaysia [Member]
Property acquisition costs
Development costs	7.3	8.4	2.3
Total costs incurred	7.3	$ 8.4	$ 2.3
Asset Retirement Obligation Costs [Member] \| Other Regions [Member]
Property acquisition costs
Development costs	0.2
Total costs incurred	$ 0.2

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

^[2]

Dec. 31, 2016

Revenues

^[1]

$ 2,586.6

^[2]

$ 2,078.5

$ 1,862.9

^[3]

^[1]

18.0

^[2]

132.4

5.1

^[3]

^[1]

2,604.6

^[2]

2,210.9

1,868.0

^[3]

^[1]

555.9

^[2]

468.4

559.4

^[3]

^[1]

52.1

^[2]

43.7

43.8

^[3]

^[1]

63.8

^[2]

61.0

58.5

^[3]

^[1]

40.1

^[2]

61.8

43.4

^[3]

^[1]

954.0

^[2]

939.9

1,037.3

^[3]

^[1]

44.6

^[2]

42.6

46.7

^[3]

20.0

^[2]

95.1

^[3]

11.3

^[1],[2]

15.0

39.1

^[1],[3]

^[1]

110.1

^[2]

123.7

131.7

^[3]

^[1]

5.2

^[2]

30.7

29.6

^[3]

^[1]

1,857.1

^[2]

1,786.8

2,084.6

^[3]

^[1]

747.5

^[2]

424.1

(216.6)

^[3]

^[1]

200.6

^[2]

133.8

(132.9)

^[3]

Crude Oil and Natural Gas Liquids [Member]

546.9

^[1],[2]

290.3

^[1]

(83.7)

^[3]

Revenues

^[1]

2,251.4

^[2]

1,747.3

1,570.2

^[3]

Revenues

^[1]

335.2

^[2]

331.2

292.7

^[3]

Revenues

1,288.2

^[2]

941.6

749.2

^[3]

1.4

^[2]

2.7

(0.1)

^[3]

1,289.6

^[2]

944.3

749.1

^[3]

230.5

^[2]

198.5

218.6

^[3]

50.9

^[2]

42.2

37.0

^[3]

29.4

^[2]

7.8

6.1

^[3]

36.8

^[2]

60.2

38.4

^[3]

519.5

^[2]

546.1

600.5

^[3]

19.5

^[2]

17.4

17.1

^[3]

^[2]

20.0

49.0

^[2]

61.8

54.0

^[3]

23.0

^[2]

20.0

7.3

^[3]

978.6

^[2]

954.0

979.0

^[3]

311.0

^[2]

(9.7)

(229.9)

^[3]

68.1

^[2]

(0.8)

(65.7)

^[3]

United States [Member] | Crude Oil and Natural Gas Liquids [Member]

242.9

^[2]

(8.9)

(164.2)

^[3]

Revenues

United States [Member] | Natural Gas [Member]

1,245.3

^[2]

903.7

714.1

^[3]

Revenues

Canada [Member] | Conventional [Member]

42.9

^[2]

37.9

35.1

^[3]

Revenues

438.8

^[2]

358.8

301.7

^[3]

(0.2)

^[2]

126.7

(0.7)

^[3]

438.6

^[2]

485.5

301.0

^[3]

122.6

^[2]

101.1

102.6

^[3]

1.2

^[2]

1.5

4.3

^[3]

0.6

^[2]

0.5

3.6

^[3]

0.8

^[2]

1.6

4.5

^[3]

232.4

^[2]

185.4

186.7

^[3]

7.7

^[2]

7.9

10.9

^[3]

^[3]

95.1

26.8

^[2]

28.3

28.2

^[3]

(19.1)

^[2]

2.3

7.9

^[3]

373.0

^[2]

328.6

443.8

^[3]

65.6

^[2]

156.9

(142.8)

^[3]

14.5

^[2]

44.4

(58.9)

^[3]

Canada [Member] | Synthetic Oil [Member]

51.1

^[2]

112.5

(83.9)

^[3]

Revenues

^[3]

60.7

^[3]

3.6

^[3]

64.3

^[3]

69.8

^[3]

2.5

^[3]

16.5

^[3]

2.4

^[3]

0.5

^[3]

91.7

^[3]

(27.4)

^[3]

(75.4)

Canada [Member] | Crude Oil and Natural Gas Liquids [Member] | Conventional [Member]

^[3]

48.0

Revenues

Canada [Member] | Crude Oil and Natural Gas Liquids [Member] | Synthetic Oil [Member]

291.2

^[2]

203.7

171.7

^[3]

Revenues

Canada [Member] | Natural Gas [Member] | Conventional [Member]

^[3]

60.7

Revenues

147.6

^[2]

155.1

130.0

^[3]

Revenues

853.5

^[2]

778.1

751.3

^[3]

0.7

^[2]

3.0

2.1

^[3]

854.2

^[2]

781.1

753.4

^[3]

202.1

^[2]

168.8

168.4

^[3]

2.2

^[2]

2.4

5.2

^[3]

198.6

^[2]

204.6

227.7

^[3]

17.4

^[2]

17.3

16.3

^[3]

11.3

^[2]

15.0

39.1

^[3]

10.8

^[2]

14.0

15.4

^[3]

(1.0)

^[2]

8.4

24.3

^[3]

441.4

^[2]

430.5

496.4

^[3]

412.8

^[2]

350.6

257.0

^[3]

143.3

^[2]

126.4

85.9

^[3]

Malaysia [Member] | Crude Oil and Natural Gas Liquids [Member]

269.5

^[2]

224.2

171.1

^[3]

Revenues

Malaysia [Member] | Natural Gas [Member]

708.8

^[2]

639.9

623.7

^[3]

Revenues

144.7

^[2]

138.2

127.6

^[3]

Other Regions [Member]

Revenues

^[2]

6.1

16.1

^[2]

0.2

^[3]

22.2

^[2]

0.2

^[3]

^[2]

0.7

31.6

^[2]

50.3

43.6

^[3]

2.5

^[2]

0.5

^[3]

3.5

^[2]

3.8

5.9

^[3]

23.5

^[2]

19.6

33.6

^[3]

2.3

^[2]

(9.9)

^[3]

64.1

^[2]

73.7

^[3]

(41.9)

^[2]

(73.7)

(73.5)

^[3]

(25.3)

^[2]

(36.2)

(18.8)

^[3]

Other Regions [Member] | Crude Oil and Natural Gas Liquids [Member]

(16.6)

^[2]

$ (37.5)

$ (54.7)

^[3]

Revenues

Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]

^[2]

$ 6.1

[1]	1 Results exclude corporate overhead, interest and discontinued operations. 2018 includes noncontrolling interest in MP GOM.
[2]	Results exclude corporate overhead, interest and discontinued operations. 2018 includes noncontrolling interest in MP GOM.
[3]	Results exclude corporate overhead, interest and discontinued operations.

Supplemental Oil and Gas Information (Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves) (Details) - USD ($)
$ in Millions

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

^[1]

$ 34,423.0

$ 21,992.1

$ 17,549.3

^[1]

(5,159.2)

(3,793.5)

(3,598.5)

^[1]

(12,785.9)

(9,577.7)

(8,972.5)

^[1]

(2,924.9)

(1,287.0)

(273.5)

10% annual discount for estimated timing of cash flows

^[1]

13,553.0

7,333.9

4,704.8

^[1]

(5,273.1)

(3,411.0)

(2,124.8)

Standardized measure of discounted future net cash flows

^[1]

8,279.9

3,922.9

2,580.0

$ 3,859.1

Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]

^[1]

23,473.9

12,885.8

9,477.9

^[1]

(3,279.1)

(2,079.5)

(1,691.1)

^[1]

(7,279.5)

(4,765.3)

(3,981.6)

^[1]

(2,216.5)

(893.7)

(118.9)

10% annual discount for estimated timing of cash flows

^[1]

10,698.8

5,147.3

3,686.3

^[1]

(4,295.4)

(2,698.2)

(1,799.5)

Standardized measure of discounted future net cash flows

^[1]

6,403.4

2,449.1

1,886.8

Canada [Member]

Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]

^[1]

5,437.5

4,714.3

3,752.7

^[1]

(1,362.7)

(1,081.7)

(1,143.6)

^[1]

(2,693.0)

(2,507.4)

(2,329.7)

^[1]

(236.4)

(161.1)

(81.3)

10% annual discount for estimated timing of cash flows

^[1]

1,145.4

964.1

198.1

^[1]

(531.4)

(394.6)

(95.0)

Standardized measure of discounted future net cash flows

^[1]

614.0

569.5

103.1

Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]

^[1]

5,511.6

4,392.0

4,318.7

^[1]

(517.4)

(632.3)

(763.8)

^[1]

(2,813.4)

(2,305.0)

(2,661.2)

^[1]

(472.0)

(232.2)

(73.3)

10% annual discount for estimated timing of cash flows

^[1]

1,708.8

1,222.5

820.4

^[1]

(446.3)

(318.2)

(230.3)

Standardized measure of discounted future net cash flows

^[1]

$ 1,262.5

$ 904.3

$ 590.1

[1]	2018 includes noncontrolling interest in MP GOM.

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, 2018

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Supplemental Oil and Gas Information [Abstract]

Net changes in prices and production costs

^[1]

$ 2,972.6

$ 2,428.4

$ (1,476.1)

Net changes in development costs

^[1]

(1,891.1)

(724.4)

544.9

Sales and transfers of oil and gas produced, net of production costs

^[1]

(1,978.6)

(1,576.0)

(1,196.3)

Net change due to extensions and discoveries

^[1]

1,930.3

807.9

280.5

Net change due to purchases and sales of proved reserves

^[1]

3,152.4

85.9

(583.4)

Development costs incurred

^[1]

1,017.3

802.7

479.6

Accretion of discount

^[1]

469.5

270.9

428.1

Revisions of previous quantity estimates

^[1]

(347.8)

(109.5)

(49.2)

Net change in income taxes

^[1]

(967.6)

(643.0)

292.8

Net increase (decrease)

^[1]

4,357.0

1,342.9

(1,279.1)

Standardized measure

^[1]

$ 8,279.9

$ 3,922.9

$ 2,580.0

$ 3,859.1

[1]	2018 includes noncontrolling interest in MP GOM.

Supplemental Oil and Gas Information (Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	$ 842.3	$ 830.3
Proved oil and gas properties	21,634.8	19,349.5
Gross capitalized costs	22,477.1	20,179.8
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	(368.2)	(402.0)
Proved oil and gas properties	(12,486.0)	(11,696.2)
Net capitalized costs	9,622.9	8,081.6
United States [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	394.2	360.9
Proved oil and gas properties	11,678.3	9,606.4
Gross capitalized costs	12,072.5	9,967.3
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	(129.3)	(149.5)
Proved oil and gas properties	(5,433.7)	(4,893.8)
Net capitalized costs	6,509.5	4,924.0
Canada [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	250.0	286.8
Proved oil and gas properties	3,693.0	3,603.4
Gross capitalized costs	3,943.0	3,890.2
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	(213.5)	(230.7)
Proved oil and gas properties	(2,088.8)	(2,027.9)
Net capitalized costs	1,640.7	1,631.6
Malaysia [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	21.2	20.5
Proved oil and gas properties	6,263.5	6,139.7
Gross capitalized costs	6,284.7	6,160.2
Accumulated depreciation, depletion and amortization
Proved oil and gas properties	(4,963.5)	(4,774.5)
Net capitalized costs	1,321.2	1,385.7
Other Regions [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	176.9	162.1
Gross capitalized costs	176.9	162.1
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	(25.4)	(21.8)
Net capitalized costs	$ 151.5	$ 140.3

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

3 Months Ended

12 Months Ended

Dec. 31, 2018

^[1]

Sep. 30, 2018

^[1]

Jun. 30, 2018

^[1]

Mar. 31, 2018

^[1]

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

^[2]

Dec. 31, 2016

^[2]

Supplemental Quarterly Information [Abstract]

Revenue from contract with customers

$ 664,700

$ 659,800

$ 655,200

$ 606,900

$ 580,500

$ 511,200

$ 477,600

$ 509,000

$ 2,586,627

$ 2,078,548

$ 1,862,891

Income (loss) from continuing operations before income taxes

106,200

146,800

82,300

97,000

2,400

(63,600)

(21,900)

154,900

432,338

71,802

(493,115)

Income (loss) from continuing operations

112,600

95,800

45,900

168,700

(284,800)

(66,300)

(17,300)

57,500

423,008

(310,936)

(273,943)

Net income (loss) including noncontrolling interest

111,800

93,900

45,500

168,300

419,486

(311,789)

(275,970)

Net income (loss) attributable to Murphy

$ 103,400

$ 93,900

$ 45,500

$ 168,300

$ (286,800)

$ (65,900)

$ (17,600)

$ 58,500

$ 411,094

$ (311,789)

$ (275,970)

Income (loss) from continuing operations per Common share, Basic

$ 0.60

$ 0.55

$ 0.26

$ 0.98

$ (1.65)

$ (0.38)

$ (0.10)

$ 0.33

$ 2.39

$ (1.81)

$ (1.59)

Income (loss) from continuing operations per Common share, Diluted

0.59

0.55

0.26

0.97

(1.65)

(0.38)

(0.10)

0.33

2.37

(1.81)

(1.59)

Net income (loss) per Common share, Basic

0.60

0.54

0.26

0.97

(1.66)

(0.38)

(0.10)

0.34

2.38

(1.81)

(1.60)

Net income (loss) per Common share, Diluted

0.59

0.54

0.26

0.96

(1.66)

(0.38)

(0.10)

0.34

2.36

(1.81)

(1.60)

Cash dividend per Common share

$ 0.25

$ 1.00

$ 1.20

[1]	2018 includes noncontrolling interest in MP GOM.
[2]	Reclassified to conform to current presentation (see Note B).

Schedule II - Valuation Accounts and Reserves (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Allowance for doubtful accounts [Member]

Valuation and Qualifying Accounts Disclosure [Line Items]

Balance at January 1

$ 1.6

Charged (Credited) to Expense

Deductions

Deferred tax asset valuation allowance [Member]

^[1]

Balance at December 31

1.6

Valuation and Qualifying Accounts Disclosure [Line Items]

Balance at January 1

476.3

305.4

294.4

Charged (Credited) to Expense

3.3

18.6

25.7

Deductions