UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

~~FORM 10-Q~~

(Mark One)

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2019

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 1-8590

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)

Delaware
	~~(Mark One)~~
~~[X]~~	~~QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934~~
	~~For the quarterly period ended September 30, 2017~~
	OR
~~[ ]~~	~~TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE~~ ~~ACT OF 1934~~
	~~For the transition period from~~ to
	~~Commission file number 1-8590~~

~~MURPHY OIL CORPORATION~~

~~(Exact name of registrant as specified in its charter)~~


~~Delaware~~	71-0361522
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

300 Peach Street, P.O. Box 7000,
El Dorado, Arkansas		71731-7000
(Address of principal executive offices)		(Zip Code)

(870) 862-6411

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
~~[X]~~ [X] Yes [ ] No

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ such files).
~~[X]~~ [X] Yes [ ] No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, ~~or a~~ smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated ~~filer”,~~filer,” “smaller reporting ~~company”~~company,” and “emerging growth company” in Rule 12b-2 of the Exchange act.

Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ] Smaller reporting company [ ]

Emerging growth company [ ]

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

~~Emerging growth company [ ]~~

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

[ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). [ ] Yes [X] No

Number of shares of Common Stock, $1.00 par value, outstanding at ~~October 31, 2017~~April 30, 2019 was ~~172,572,873.~~173,626,998.

MURPHY OIL CORPORATION

TABLE OF CONTENTS


		Page
Part I – Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets		2
Consolidated Statements of Operations		3
Consolidated Statements of Comprehensive Income ~~(Loss)~~		4
Consolidated Statements of Cash Flows		5
Consolidated Statements of Stockholders’ Equity		6
Notes to Consolidated Financial Statements		7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		2324
Item 3. Quantitative and Qualitative Disclosures About Market Risk		3633
Item 4. Controls and Procedures		3633
Part II – Other Information		3633
Item 1. Legal Proceedings		3633
Item 1A. Risk Factors		3633
Item 6. Exhibits		3633
Signature		3734

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS (unaudited)

(Thousands of dollars)



	September 30,		December 31,		March 31,		December 31,
	2017		2016		2019		2018 1
ASSETS
Current assets					$
Cash and cash equivalents	$	997,207		872,797		286,281		359,923
Canadian government securities with maturities greater than 90 days at the date of acquisition		–		111,542
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2017 and 2016		267,209		357,099
Inventories, at lower of cost or market		120,066		127,071
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2019 and 2018						349,768		231,686
Inventories						77,278		80,024
Prepaid expenses		39,427		63,604		45,349		34,316
Assets held for sale		23,248		27,070		1,879,568		173,865
Total current assets		1,447,157		1,559,183		2,638,244		879,814
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,027,902 in 2017 and $12,607,815 in 2016		8,283,738		8,316,188
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $8,359,120 in 2019 and $8,070,487 in 2018						8,559,143		8,432,133
Operating lease assets						618,123		–
Deferred income taxes		406,703		365,935		124,679		146,197
Deferred charges and other assets		55,161		54,554		42,928		49,435
Non-current assets held for sale						–		1,545,008
Total assets	$	10,192,759		10,295,860	$	11,983,117		11,052,587
LIABILITIES AND STOCKHOLDERS’ EQUITY
Liabilities and Stockholders' Equity
Current liabilities
Current maturities of long-term debt	$	9,781		569,817	$	679		668
Accounts payable		584,025		784,975		475,559		348,026
Income taxes payable		57,687		13,920		15,450		15,309
Other taxes payable		30,160		28,167		14,283		17,649
Operating lease liabilities						155,534		–
Other accrued liabilities		146,607		102,777		157,031		177,948
Liabilities associated with assets held for sale		3,270		2,776		819,694		286,458
Total current liabilities		831,530		1,502,432		1,638,230		846,058
Long-term debt, including capital lease obligation		2,908,285		2,422,750		3,110,098		3,109,318
Deferred income taxes		108,756		69,081
Asset retirement obligations		747,602		681,528		783,495		752,519
Deferred credits and other liabilities		616,452		617,490		471,099		624,436
Liabilities associated with assets held for sale		–		85,900
Stockholders’ equity
Non-current operating lease liabilities						468,427		–
Deferred income taxes						185,091		129,894
Non-current liabilities associated with assets held for sale						–		392,720
Equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued		–		–		–		–
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,055,724 shares in 2017 and 2016		195,056		195,056
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,083,364 shares in 2019 and 195,076,924 shares in 2018						195,083		195,077
Capital in excess of par value		910,936		916,799		924,904		979,642
Retained earnings		5,575,175		5,729,596		5,627,081		5,513,529
Accumulated other comprehensive loss		(425,504)		(628,212)		(580,999)		(609,787)
Treasury stock		(1,275,529)		(1,296,560)		(1,217,293)		(1,249,162)
Total stockholders’ equity		4,980,134		4,916,679
Murphy Shareholders' Equity						4,948,776		4,829,299
Noncontrolling interest						377,901		368,343
Total equity						5,326,677		5,197,642
Total liabilities and stockholders’ equity	$	10,192,759		10,295,860	$	11,983,117		11,052,587

1 Reclassified to conform to current presentation (see Note A).

See Notes to Consolidated Financial Statements, page 7.

~~The Exhibit Index is on page~~ 38.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(Thousands of dollars, except per share amounts)


		Three Months Ended		Nine Months Ended			Three Months Ended
	September 30,			September 30,		March 31,
	2017		2016*	2017	2016*	2019		2018 1

Revenues
Sales and other operating revenues	$	498,202	486,276	1,552,473	1,326,587
Gain (loss) on sale of assets		117	(730)	130,765	3,101
Revenue from sales to customers						$	590,550	396,329
Loss on crude contracts							–	(29,502)
Gain on sale of assets and other income							454	7,963
Total revenues		498,319	485,546	1,683,238	1,329,688		591,004	374,790

Costs and expenses
Lease operating expenses		112,751	119,663	346,072	435,296		131,696	88,833
Severance and ad valorem taxes		10,816	9,592	32,771	35,668		10,097	12,157
Exploration expenses		28,492	19,866	77,356	83,910
Exploration expenses, including undeveloped lease amortization							32,538	28,738
Selling and general expenses		56,672	55,523	168,259	196,143		63,360	48,096
Depreciation, depletion and amortization		243,636	255,900	714,782	797,288		229,406	182,743
Accretion of asset retirement obligations		10,654	11,043	31,638	35,514		9,340	6,372
Impairment of assets		–	–	–	95,088
Other expense (benefit)		2,454	6,486	10,988	(1,446)		30,005	(11,045)
Total costs and expenses		465,475	478,073	1,381,866	1,677,461		506,442	355,894

Operating income (loss) from continuing operations		32,844	7,473	301,372	(347,773)
Operating income from continuing operations							84,562	18,896

Other income (loss)
Interest and other income (loss)		(47,721)	14,987	(93,524)	38,602		(4,748)	4,587
Interest expense, net		(48,681)	(39,219)	(138,423)	(103,889)		(46,069)	(44,541)
Total other loss		(96,402)	(24,232)	(231,947)	(65,287)		(50,817)	(39,954)

Income (loss) from continuing operations before income taxes		(63,558)	(16,759)	69,425	(413,060)		33,745	(21,058)
Income tax expense (benefit)		2,760	(2,176)	95,602	(201,897)		10,822	(111,639)
Loss from continuing operations		(66,318)	(14,583)	(26,177)	(211,163)
Income (loss) from discontinued operations, net of income taxes		425	(1,593)	1,177	(885)
Income from continuing operations							22,923	90,581
Income from discontinued operations, net of income taxes							49,846	77,672
Net income including noncontrolling interest							72,769	168,253
Less: Net income attributable to noncontrolling interest							32,587	–

NET LOSS	$	(65,893)	(16,176)	(25,000)	(212,048)
NET INCOME ATTRIBUTABLE TO MURPHY						$	40,182	168,253

INCOME (LOSS) PER COMMON SHARE – BASIC
Continuing operations	$	(0.38)	(0.08)	(0.15)	(1.23)	$	(0.06)	0.52
Discontinued operations		-	(0.01)	0.01	(0.01)		0.29	0.45
Net loss	$	(0.38)	(0.09)	(0.14)	(1.24)
Net Income						$	0.23	0.97

INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations	$	(0.38)	(0.08)	(0.15)	(1.23)	$	(0.06)	0.52
Discontinued operations		-	(0.01)	0.01	(0.01)		0.29	0.44
Net loss	$	(0.38)	(0.09)	(0.14)	(1.24)
Net Income						$	0.23	0.96

Cash dividends per Common share		0.25	0.25	0.75	0.95		0.25	0.25

Average Common shares outstanding (thousands)
Basic		172,573	172,199	172,509	172,165		173,341	172,805
Diluted		172,573	172,199	172,509	172,165		174,491	174,620

1 Reclassified to conform to current presentation (see Note A).

See Notes to Consolidated Financial Statements, page 7.

*Reclassified to conform to current presentation (see Note A).

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME ~~(LOSS)~~ (unaudited)

(Thousands of dollars)



	Three Months Ended			Nine Months Ended		Three Months Ended
	September 30,			September 30,		March 31,
	2017		2016	2017	2016	2019		2018

Net loss	$	(65,893)	(16,176)	(25,000)	(212,048)
Net income						$	40,182	168,253
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation		101,210	(37,369)	194,094	124,522
Net (loss) gain from foreign currency translation							25,449	(52,275)
Retirement and postretirement benefit plans		2,396	2,515	7,169	7,544		2,754	3,170
Deferred loss on interest rate hedges reclassified to interest expense		482	482	1,445	1,445		585	585
Reclassification of certain tax effects to retained earnings							–	(30,237)
Other							–	(3,737)
Other comprehensive income (loss)		104,088	(34,372)	202,708	133,511		28,788	(82,494)
COMPREHENSIVE INCOME (LOSS)	$	38,195	(50,548)	177,708	(78,537)
COMPREHENSIVE INCOME						$	68,970	85,759

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)



	Nine Months Ended				Three Months Ended
	September 30,				March 31,
	2017		2016		2019		2018 1
Operating Activities
Net loss	$	(25,000)	(212,048)
Adjustments to reconcile net loss to net cash provided by continuing operations activities:
Net income including noncontrolling interest					$	72,769	168,253
Adjustments to reconcile net income to net cash provided by continuing operations activities:						–	–
(Income) loss from discontinued operations		(1,177)	885			(49,846)	(77,672)
Depreciation, depletion and amortization		714,782	797,288			229,406	182,743
Impairment of assets		–	95,088
Amortization of deferred major repair costs		–	3,794
Dry hole costs (credits)		(1,139)	15,226
Previously suspended exploration costs (credits)						13,251	(5)
Amortization of undeveloped leases		40,859	35,828			8,045	13,168
Accretion of asset retirement obligations		31,638	35,514			9,340	6,372
Deferred and noncurrent income tax benefits		(3,567)	(345,157)
Pretax gains from disposition of assets		(130,765)	(3,101)
Deferred income tax charge (benefit)						15,589	(147,716)
Pretax (gain) loss from sale of assets						(12)	339
Mark to market and revaluation of contingent consideration						13,530	–
Mark to market of crude contracts						–	14,350
Long-term non-cash compensation						22,388	14,057
Net (increase) decrease in noncash operating working capital		1,070	(152,618)	1		(98,505)	(3,553)
Other operating activities, net		192,867	9,651			(18,758)	(59,449)
Net cash provided by continuing operations activities		819,568	280,350			217,197	110,887

Investing Activities
Property additions and dry hole costs		(706,417)	(781,668)	2		(270,338)	(247,054)
Proceeds from sales of property, plant and equipment		69,146	1,154,623			–	260
Purchases of investment securities3		(212,661)	(651,218)
Proceeds from maturity of investment securities3		320,828	712,863
Other investing activities, net		–	(7,229)
Net cash (required) provided by investing activities		(529,104)	427,371
Net cash required by investing activities						(270,338)	(246,794)

Financing Activities
Borrowings of debt, net of issuance costs		541,772	541,444
Repayments of debt		(550,000)	(600,000)
Capital lease obligation payments		(14,687)	(7,808)			(160)	–
Withholding tax on stock-based incentive awards		(7,151)	(1,138)			(6,991)	(6,642)
Issue cost of debt facility		–	(13,971)
Distribution to noncontrolling interest						(18,437)	–
Cash dividends paid		(129,421)	(163,586)			(43,398)	(43,258)
Other financing activities, net		–	(20)
Net cash required by financing activities		(159,487)	(245,079)			(68,986)	(49,900)

Cash Flows from Discontinued Operations
Operating activities		12,134	2,830			123,469	167,386
Changes in cash included in current assets held for sale		(12,904)	(2,830)
Net change in cash and cash equivalents of discontinued operations		(770)	–
Investing activities						(26,438)	(26,848)
Financing activities						(2,547)	(2,405)
Net cash provided by discontinued operations						94,484	138,133
Cash transferred from discontinued operations to continuing operations						46,080	371,656
Effect of exchange rate changes on cash and cash equivalents		(5,797)	7,268			2,405	21,051
Net increase in cash and cash equivalents		124,410	469,910
Net increase (decrease) in cash and cash equivalents						(73,642)	206,900
Cash and cash equivalents at beginning of period		872,797	283,183			359,923	630,433
Cash and cash equivalents at end of period	$	997,207	753,093		$	286,281	837,333

1~~2016 balance includes payments for deepwater rig contract exit of $266.6 million.~~Reclassified to conform to current presentation (See Note A).

2~~Includes costs of $206.7 million associated with acquisition of Kaybob Duvernay and~~ ~~Placid Montney.~~

3~~Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.~~

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

(Thousands of dollars)




	Nine Months Ended				Three Months Ended
	September 30,				March 31,
	2017		2016		2019		2018
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued	$	–		–	$	–		–
Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,055,724 shares at September 30, 2017 and 2016.
Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,083,364 shares at March 31, 2019 and 195,065,341 shares at March 31, 2018
Balance at beginning of period		195,056		195,056		195,077		195,056
Exercise of stock options		–		–		6		9
Balance at end of period		195,056		195,056		195,083		195,065
Capital in Excess of Par Value
Balance at beginning of period		916,799		910,074		979,642		917,665
Exercise of stock options, including income tax benefits						(123)		(175)
Restricted stock transactions and other		(26,553)		(10,078)		(38,732)		(32,486)
Stock-based compensation		20,767		21,918		8,636		6,187
Other		(77)		(239)
Adjustments to acquisition valuation						(24,519)		–
Balance at end of period		910,936		921,675		924,904		891,191
Retained Earnings
Balance at beginning of period		5,729,596		6,212,201		5,513,529		5,245,242
Net loss for the period		(25,000)		(212,048)
Net income (loss) for the period						40,182		168,253
Reclassification of certain tax effects from accumulated other comprehensive loss						–		30,237
Sale and leaseback gain recognized upon adoption of ASC 842, net of tax impact						116,768		–
Cash dividends		(129,421)		(163,586)		(43,398)		(43,258)
Balance at end of period		5,575,175		5,836,567		5,627,081		5,400,474

Accumulated Other Comprehensive Loss
Balance at beginning of period		(628,212)		(704,542)		(609,787)		(462,243)
Foreign currency translation gain, net of income taxes		194,094		124,522
Foreign currency translation (loss) gain, net of income taxes						25,449		(52,275)
Retirement and postretirement benefit plans, net of income taxes		7,169		7,544		2,754		3,170
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes		1,445		1,445		585		585
Reclassification of certain tax effects to retained earnings						–		(30,237)
Other						–		(3,737)
Balance at end of period		(425,504)		(571,031)		(580,999)		(544,737)
Treasury Stock
Balance at beginning of period		(1,296,560)		(1,306,061)		(1,249,162)		(1,275,529)
Sale of stock under employee stock purchase plan		145		389
Awarded restricted stock, net of forfeitures		20,886		8,993		31,869		25,843
Balance at end of period – 22,482,851 shares of Common Stock in 2017 and 22,855,649 shares of Common Stock in 2016, at cost		(1,275,529)		(1,296,679)
Total Stockholders’ Equity	$	4,980,134		5,085,588
Balance at end of period – 21,456,366 shares of Common Stock in 2019 and 22,027,336 shares of Common Stock in 2018, at cost						(1,217,293)		(1,249,686)
Murphy Shareholders’ Equity						4,948,776		4,692,307
Noncontrolling Interest
Balance at beginning of year						368,343		–
Acquisition closing adjustments						(4,592)		–
Net income attributable to noncontrolling interest						32,587		–
Distributions to noncontrolling Interest Owners						(18,437)		–
Balance at end of year						377,901		–
Total Equity					$	5,326,677		4,692,307

See Notes to Consolidated Financial Statements, page 7.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 2 through 6 of this Form 10-Q report.

Note A – Nature of Business and Interim Financial Statements

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~~Canada and conducts oil and natural gas exploration activities worldwide.

As of the end of the first quarter 2019 Malaysia was classified as held for sale; and effective January 1, 2019 Malaysia was reported as discontinued operations as the sale represents a strategic shift that has a major effect on the Company’s operations and financial results. Prior periods have been reclassified to conform with the current presentation. See Note E for more information regarding the pending sale of this asset.

INTERIM FINANCIAL STATEMENTS – In the opinion of Murphy's management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company's financial position at ~~September 30, 2017~~March 31, 2019 and December 31, ~~2016,~~2018, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended ~~September 30, 2017~~March 31, 2019 and ~~2016,~~2018, in conformity with accounting principles generally accepted in the United States of America (U.S.). In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the U.S., 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.

Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company's ~~2016~~2018 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the ~~three-month and nine-month periods~~three-months ended ~~September 30, 2017~~March 31, 2019 are not necessarily indicative of future results.

~~Beginning~~Note B – New Accounting Principles and Recent Accounting Pronouncements

Accounting Principles Adopted

Leases. In February 2016, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) 2016-02 (Topic 842) to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous Generally Accepted Accounting Principles (GAAP) and this ASU is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. The company adopted the standard in the ~~period ended September 30, 2017, certain reclassifications~~first quarter of 2019 utilizing the modified retrospective transition method through a cumulative-effect adjustment at the beginning of the first quarter of 2019. The Company has elected the package of practical expedients, which allows the Company not to reassess (1) whether any expired or existing contracts as of the adoption date are or contain a lease, (2) lease classification for any expired or existing leases as of the adoption date and (3) initial direct costs for any existing leases as of the adoption date. The Company did not elect to apply the hindsight practical expedient when determining lease term and assessing impairment of right-of-use assets. The adoption of ASU 2016-02 resulted in ~~presentation have been made~~the recognition of right-of-use assets of $618.1 million, current lease liabilities for operating leases of approximately $155.5 million, non-current lease liabilities of $468.4 million and a cumulative-effect adjustment to ~~the~~credit retained earnings of $116.8 million on its Consolidated Balance Sheets, with no material impact to its Consolidated Statements of Operations. See Note P for further information regarding the impact of the adoption of ASU 2016-02 on the Company's financial statements.

Compensation – Stock Compensation. In June 2018, the FASB issued an ASU 2018-07 which supersedes existing guidance for equity-based payments to nonemployees and expands the scope of guidance for stock compensation to include all share-based payment arrangements related to the acquisition of goods and services from both nonemployees and employees. As a result, the same guidance that provides for employee share-based payments, including most of its requirements related to classification and measurement, applies to nonemployee share-based payment arrangements. The Company ~~now presents~~adopted this guidance during the first quarter of 2019 and it did not have material impact on its consolidated financial statements.

Recent Accounting Pronouncements

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 ~~separate “Operating income (loss)~~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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note B – New Accounting Principles and Recent Accounting Pronouncements (Contd.)

Recent Accounting Pronouncements (Contd.)

Compensation-Retirement Benefits-Defined Benefit Plans-General. In August 2018, the FASB issued ASU 2018-14 which modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. For public companies, the amendments in this ASU are effective for fiscal years beginning after December 15, 2020, with early adoption permitted, and is to be applied on a retrospective basis to all periods presented. The Company is currently assessing the potential impact of this ASU to its consolidated financial statements.

Note C – Revenue from ~~continuing operations” subtotal~~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 two key geographic segments: the U.S. and Canada. Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil and condensate, natural gas liquids, and natural gas.

For operated oil and 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.

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. Revenue recognized is largely index based with price adjustments for floating market differentials.

Canada- Primarily, 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 ~~Consolidated Statements~~volumes on the bill of ~~Operations. Additionally, “Interest~~lading and ~~other income (loss),” which includes foreign exchange gains~~point of custody transfer.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Disaggregation of Revenue

The Company reviews performance based on two key geographical segments and ~~losses, has been reclassified~~between onshore and offshore sources of Revenue within these geographies.

For the three months ended March 31, 2019 and 2018, the Company recognized $590.6 million and $396.3 million, respectively, from ~~a component~~contracts with customers for the sales of ~~total revenues~~oil, natural gas liquids and ~~is now presented below Operating income (loss)~~natural gas.


		Three Months Ended
		March 31,
(Thousands of dollars)		2019	2018
Net crude oil and condensate revenue
United States – Onshore	$	133,590	182,650
– Offshore		316,023	71,528
Canada – Onshore		27,344	21,293
– Offshore		43,846	54,315
Other		2,852	–
Total crude oil and condensate revenue		523,655	329,786

Net natural gas liquids revenue
United States – Onshore		6,141	12,134
– Offshore		4,176	1,639
Canada – Onshore		3,458	3,469
Total natural gas liquids revenue		13,775	17,242

Net natural gas revenue
United States – Onshore		5,864	6,770
– Offshore		2,506	2,937
Canada – Onshore		44,750	39,594
Total natural gas revenue		53,120	49,301
Total revenue from contracts with customers		590,550	396,329

Gain (loss) on crude contracts		–	(29,502)
Other operating income		442	8,302
Gain on sale of assets		12	(339)
Total revenue	$	591,004	374,790

Contract Balances and Asset Recognition

As of March 31, 2019, and December 31, 2018, receivables from ~~continuing operations. “Interest expense”~~contracts with customers, net of royalties and ~~“Capitalized interest” have also been combined into~~associated payables, on the “Interest expense, net” line item and is now presented below Operating income (loss) from continuing operations. Previously reported periods have been changed to conform to the current period presentation. These reclassifications did not impact previously reported Income (loss)balance sheet from continuing operations, ~~before income taxes, Loss~~were $266.5 million and $147.6 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on historical collections and ability of customers to pay, the Company did not recognize any impairment losses on receivables or contract assets arising from ~~continuing operations,~~customer contracts during the reporting periods.

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

The Company does not employ sales incentive strategies such as commissions or ~~Net Loss.~~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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Performance Obligations

The Company recognizes oil and gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer. Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity.

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

The Company has entered into several long-term, fixed-price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the company’s long-term strategy. The contractually stated price for each unit of commodity transferred under these contracts represents the stand-alone selling price of the commodity.

As of March 31, 2019, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of 12 months or more starting at the inception of the contract:


Current Long-Term Contracts Outstanding at March 31, 2019
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.	Oil, 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

Fixed price contracts are accounted for as normal sales and purchases for accounting purposes.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note BD – Property, Plant and Equipment

Exploratory Wells

Under ~~Financial Accounting Standards Board (FASB)~~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 ~~September 30, 2017,~~March 31, 2019, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of ~~$178.4~~$227.1 million. The following table reflects the net changes in capitalized exploratory well costs during the ~~nine-month~~three-month periods ended ~~September 30, 2017~~March 31, 2019 and ~~2016.~~

2018.



(Thousands of dollars)	2017		2016	2019		2018
Beginning balance at January 1	$	148,500	130,514	$	207,855	155,103
Additions pending the determination of proved reserves		51,614	847		32,416	549
Reclassifications to proved properties based on the determination of proved reserves		(13,370)	–
Capitalized exploratory well costs charged to expense		(8,360)	–		(13,145)	–
Other adjustments		–	(3,205)
Balance at September 30	$	178,384	128,156
Balance at March 31				$	227,126	155,652

The capitalized well costs charged to expense during the first ~~nine~~three months of ~~2017~~2019 included the ~~Marakas-01~~CM-1X and the CT-1X wells in Vietnam Block 11-2/11. The wells were originally drilled in 2017. There were no capitalized well ~~in Block SK314A, offshore Malaysia in which development~~costs charged to expense during the first three months of ~~the well could not be justified due to noncommercial hydrocarbon quantities found and change in development plan due to commodity prices.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)~~

~~Note B – Property, Plant and Equipment~~ ~~(Contd.)~~

2018.

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



		September 30,								March 31,
	2017				2016				2019				2018
(Thousands of dollars)	Amount		No. of Wells	No. of Projects	Amount		No. of Wells	No. of Projects	Amount		No. of Wells	No. of Projects	Amount		No. of Wells	No. of Projects
Aging of capitalized well costs:
Zero to one year	$	41,609	3	2	$	10,563	2	2	$	78,016	3	2	$	13,642	2	1
One to two years		8,430	2	2		53,101	3	3		–	–	–		27,757	1	1
Two to three years		43,197	1	1		31,627	2	–		27,270	1	1		49,642	2	2
Three years or more		85,148	7	1		32,865	4	–		121,840	5	1		64,611	6	–
	$	178,384	13	6	$	128,156	11	5	$	227,126	9	4	$	155,652	11	4

Of the ~~$136.8~~$149.1 million of exploratory well costs capitalized more than one year at ~~September 30, 2017, $70.4~~March 31, 2019, $57.0 million is in Brunei, ~~$43.2~~$64.9 million is in Vietnam, and ~~$23.2~~$27.3 million is in ~~Malaysia.~~the U.S. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

Divestments

In January 2017, a Canadian subsidiary of the Company completed its disposition of the Seal field in Western Canada. Total cash consideration to Murphy upon closing of the transaction was approximately $49.0 million. Additionally, the buyer assumed the asset retirement obligation of approximately $85.9 million. A $132.4 million pretax gain was reported in the first quarter of 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 $19.4 million. There were no gains or losses recorded related to these sales.

During the second quarter 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 in the nine-month period ended September 30, 2016 associated with the Syncrude divestiture.

~~During the second quarter~~ 2016, a Canadian subsidiary of the Company completed a divestiture of natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia. Total cash consideration received upon closing was $414.1 million. A gain on sale of approximately $187.0 million was deferred, up to December 31, 2018, and iswas being recognized straight line over the ~~next 19 years~~life of the contract in the Canadian operating segment. The ~~Company amortized approximately $5.3 million and $3.4 million~~ ~~of the deferred gain during the nine-month periods ended September 30, 2017 and 2016, respectively. The~~ remaining deferred gain of ~~$185.0~~$116 million, net of tax, was included as a component of ~~deferred~~Deferred credits and other liabilities in the Company’s Consolidated Balance Sheet as of ~~September 30, 2017.~~December 31, 2018. As required by ASC 842, the previously deferred gain related to the sale and leaseback transaction have been transferred to equity upon adoption, lowering liabilities but increasing retained earnings by approximately $116 million, net of tax. The Company amortized approximately $1.9 million of the deferred gain during the first three months of 2018.

~~Acquisitions~~

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

~~During the second quarter~~

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

Acquisitions

In 2016, a Canadian subsidiary of Murphy Oil acquired a ~~70 percent~~70% operated working interest (WI) ofin Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a ~~30 percent~~30% non-operated WI ofin 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~~As part of the ~~joint venture, the total consideration amounts~~transaction, Murphy agreed to ~~approximately $375.0 million of which Murphy paid $206.7 million in cash at closing, subject to normal closing adjustments, and~~pay an additional $168.0 million in the form of a carried interest on the Kaybob Duvernay property. As of ~~September 30, 2017, $32.0~~March 31, 2019, $124.0 million of the carried interest had been paid. The remaining carry is to be paid over a period ~~of up to five years from 2016.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)~~

~~Note B – Property, Plant and Equipment~~ ~~(Contd.)~~

~~Impairments~~

Declines in future oil and gas prices in early 2016 led to impairments in certain of the Company’s producing properties and the nine-month period in 2016 included pretax non-cash 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 at Seal. 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. See also Note J.

through 2019.

Other

~~The Company has an interest in~~In 2006, the Kakap field in Block K ~~Malaysia.~~was unitized with the Gumusut field in an adjacent block under a Unitization and Unit Operating Agreement (UUOA) between the operators. The ~~Kakap field~~Gumusut-Kakap Unit is operated by another ~~company and was jointly developed with the Gumusut field owned by others. As required by the agreements governing the field, a redetermination (unitization) review was required in 2016.~~company. In the fourth quarter 2016, the operators completed the first redetermination process for a revision to the blocks’ tract participation interest, and the operator of the unitized field sought the approval of Petronas to effect the change in 2017. In 2016, the Company recorded an estimated redetermination expense of$39.1 million ~~in redetermination expense~~($24.1 million after tax) related to an expected ~~reduction~~revision in the Company’s working interest covering the period from inception through year-end 2016 at Kakap. In February 2017, ~~PETRONAS officially approved~~the Company received Petronas’ approval to the redetermination change that reduced the Company’s working interest ~~from 8.6%~~in oil operations to ~~approximately 6.7%~~6.67% effective April 1, 2017. ~~The Company partially settled $21.8 million~~Working interest redeterminations are required at different points within the life of the unitized field. Following a partial payment, the remaining redetermination ~~expense in cash~~liability of $17.3 million was included as a component of Liabilities associated with held for sale in the ~~second quarter~~Company’s Consolidated Balance Sheet as of ~~2017. The~~March 31, 2019.

Following a further Unitization Framework Agreement (UFA) between the governments of Brunei and Malaysia, the Company ~~currently expects to settle the remainder of the redetermination costs in future periods. It is possible that the final adjustment amount could be different than the current estimate. Due to the change in working~~now has a 6.37% interest ~~the future payments under a capital lease of a floating, production and storage facility~~ in the Kakap field ~~are lower~~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 ~~reduced~~recorded an estimated redetermination liability of $15.0 million related to Company’s revised working interest, which was included as a component of Liabilities associated with held for sale in the ~~total debt recorded on the~~Company’s Consolidated Balance Sheet ~~in the second quarter 2017 by approximately $56.7 million, with a similar reduction to Property, plant and equipment.~~as of March 31, 2019.

Note CE – Discontinued Operations and Assets Held for Sale

On March 21, 2019, Murphy Oil Corporation announced that a subsidiary had signed a sale and purchase agreement to divest the fully issued share capital of its two primary Malaysian subsidiaries, Murphy Sabah Oil Co., Ltd. and Murphy Sarawak Oil Co., Ltd., to a subsidiary of PTT Exploration and Production Public Company Limited (PTTEP). PTTEP will pay Murphy $2.127 billion in an all-cash transaction, payable upon closing and subject to customary closing adjustments, plus up to a $100 million bonus payment contingent upon certain future exploratory drilling results prior to October 2020.

The transaction has an effective date of January 1, 2019, with the closing expected to occur by the end of the second quarter 2019. Closing of the transaction is subject to customary conditions precedent including, among other things, necessary regulatory approvals. Murphy will exit the country of Malaysia.

The Company has accounted for its Malaysian exploration and production operations, along with the former U.K. ~~and~~, U.S. refining and marketing operations as discontinued operations for all periods presented. The results of operations associated with discontinued operations for the three-month period ended March 31, 2019 and ~~nine-month periods ended September 30, 2017 and 2016~~2018 were as follows:

Three Months

Nine Months

Ended September 30,

Ended September 30,
(Thousands of dollars)

2017

2016

2017

2016
Revenues (costs)
$
598

5

853

1,454
Income (loss) before income taxes

425

(1,593)

1,177

(885)
Income tax benefit

–

–

–

–
Income (loss) from discontinued operations
$
425

(1,593)

1,177

(885)


	Three Months Ended
	March 31,
(Thousands of dollars)		2019	2018
Revenues	$	195,412	210,815
Costs and expenses
Lease operating expenses		62,716	47,610
Depreciation, depletion and amortization		31,353	47,991
Other costs and expenses (benefits)		13,080	(2,451)
Total costs and expenses		88,263	117,665
Income tax expense		38,417	39,993
Income from discontinued operations	$	49,846	77,672

~~Certain reclassifications have been made to 2016 Revenues to align with current period presentation (see Note A).~~

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note E – Discontinued Operations and Assets Held for Sale (Contd.)

The following table presents the carrying value of the major categories of assets and liabilities of the Malaysian exploration and production and the U.K. refining and marketing operations ~~and Seal operations in Canada~~ reflected as held for sale on the ~~company’s~~Company’s Consolidated Balance Sheets at ~~September 30, 2017~~March 31, 2019 and December 31, ~~2016.~~2018.



		September 30,	December 31,		March 31,	December 31,
(Thousands of dollars)		2017	2016		2019	2018
Current assets
Cash	$	17,030	4,126	$	93,072	44,669
Accounts receivable		6,218	22,944		98,268	103,158
Total current assets held for sale	$	23,248	27,070
Inventories					8,881	7,887
Prepaid expenses and other					28,248	18,151
Property, Plant, and Equipment, net					1,316,985
Deferred income taxes and other assets					214,103
Operating lease asset					120,011
Total current assets associated with assets held for sale					1,879,568	173,865
Non-current assets
Property, Plant, and Equipment, net					–	1,325,431
Deferred income taxes and other assets					–	219,577
Operating lease asset					–	–
Total non-current assets associated with assets held for sale				$	–	1,545,008
Current liabilities
Accounts payable	$	605	270	$	209,012	203,236
Refinery decommissioning cost		2,665	2,506
Other accrued liabilities					50,524	55,273
Current maturities of long-term debt					10,067	9,915
Taxes payable					35,032	18,034
Current operating lease liabilities					45,982	–
Long-term debt					115,264
Asset retirement obligation					279,784	–
Non-current operating lease liabilities					74,029	–
Total current liabilities associated with assets held for sale	$	3,270	2,776	$	819,694	286,458
Non-current liabilities
Asset retirement obligation - Seal asset	$	–	85,900
Long-term debt					–	117,816
Asset retirement obligation					–	274,904
Total non-current liabilities associated with assets held for sale				$	–	392,720

~~Note C – Discontinued Operations and Assets Held for Sale (Contd.~~)

The asset retirement obligation at December 31, 2016 relates to well and facility abandonment obligations at the Seal field in Canada which were assumed by the purchasing company upon the sale in January 2017.

Note DF – Financing Arrangements and Debt

~~At September 30, 2017,~~As of March 31, 2019, the Company has a ~~$1.1~~ $1.6 billion revolving credit facility (2018 facility). The 2018 facility is a senior unsecured guaranteed ~~credit~~ facility ~~(2016 facility) with a major banking consortium,~~ which expires in ~~August 2019.~~ November 2023. At ~~September 30, 2017,~~March 31, 2019, the Company had no outstanding borrowings of $325.0 million under the ~~2016~~2018 facility ~~however, there were $84.8~~and $25.0 million of outstanding letters of credit, which reduce the borrowing capacity of the ~~2016~~2018 facility. ~~Advances~~At March 31, 2019, the interest rate in effect on borrowings under the ~~2016~~ facility will accrue interest based, at the Company’s option, on either the London Interbank Offered rate plus an applicable margin (Eurodollar rate) or the alternate base rate (as defined in the 2016 facility agreement) plus an applicable margin. Had there been any amounts borrowed under the 2016 facility at September 30, 2017, the applicable base interest rate would have been 4.50%was 4.105%. At ~~September 30, 2017,~~March 31, 2019, the Company was in compliance with all covenants related to the ~~2016~~2018 facility.

~~The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 2018.~~

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 $8.2 million on the issue of these new notes. The new notes pay interest semi-annually on February 15 and August 15 of each year. The initial interest payment will be paid on February 15, 2018. The proceeds of the $550 million notes were used to redeem the Company’s 2.50% notes in September 2017. The 2.50% notes had an original maturity of December 2017.

In August 2016, the Company reduced its then existing $2.0 billion unsecured revolving credit facility (2011 facility) to $630 million (facility has since expired) and entered into a separate $1.2 billion senior unsecured guaranteed credit facility (2016 facility, subsequently reduced to $1.1 billion), with a major banking consortium that expires in August 2019. The Company incurred transaction costs of approximately $14.0 million to place the 2016 facility which were included in financing activities in the Consolidated Statement of Cash Flows. Also in August 2016, the Company sold $550 million of notes that bear interest at the rate of 6.875% and mature on August 15, 2024. The proceeds of the $550 million notes were used for general corporate purposes.

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, 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 $9.8 million and $136.5 million, respectively, associated with this lease at September 30, 2017.

813

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note EG – Other Financial Information

Additional disclosures regarding cash flow activities are provided below.

Nine Months Ended September 30,

(Thousands of dollars)
2017

2016

Net (increase) decrease in operating working capital other than
cash and cash equivalents:

Decrease in accounts receivable
$
90,614

75,841

Decrease (increase) in inventories

5,869

(15,768)

Decrease in prepaid expenses

25,285

122,399

Decrease in other

–

720

Decrease in accounts payable and accrued liabilities

(115,977)

(376,310)
*
(Decrease) increase in current income tax liabilities

(4,721)

40,500

Net (increase) decrease in noncash operating working capital
$
1,070

(152,618)

Supplementary disclosures:

Cash income taxes paid, net of refunds
$
25,118

(3,911)

Interest paid, net of amounts capitalized of $3,338 in 2017
and $3,318 in 2016

95,899

52,287

Non-cash investing activities:

Asset retirement costs capitalized
$
38,992

13,959

Decrease in capital expenditure accrual

42,403

179,203


	Three Months Ended March 31,
(Thousands of dollars)	2019		2018
Net (increase) decrease in operating working capital other than cash and cash equivalents:
(Increase) decrease in accounts receivable	$	(112,673)	4,227
Decrease in inventories		3,930	15,637
(Increase) decrease in prepaid expenses		(10,763)	3,446
Increase (decrease) in accounts payable and accrued liabilities		21,131	(26,908)
Increase(decrease) in income taxes payable		(130)	45
Net (increase) decrease in noncash operating working capital	$	(98,505)	(3,553)
Supplementary disclosures:
Cash income taxes paid, net of refunds	$	–	(1,104)
Interest paid, net of amounts capitalized of $0 in 2019 and 2018		39,024	35,158

Non-cash investing activities:
Asset retirement costs capitalized	$	486	727
(Increase) decrease in capital expenditure accrual		(63,328)	(17,592)

*2016 balance included payments for deepwater rig contract exit of $266.6 million.

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)~~

Note FH – Employee and Retiree Benefit Plans

The Company has defined benefit pension plans that are principally noncontributory and cover most ~~North American~~ full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plan and the U.S. director’s 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 ~~active and~~ retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.

The table that follows provides the components of net periodic benefit expense for the three-month ~~and nine-month~~ periods ended ~~September 30, 2017~~March 31, 2019 and ~~2016.~~2018.



	Three Months Ended September 30,							Three Months Ended March 31,
	Pension Benefits			Other Postretirement Benefits				Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2017	2016	2017		2016			2019	2018	2019		2018
Service cost	$	2,037	2,610		427		674	$	2,062	2,255		420		494
Interest cost		7,261	5,913		966		1,109		7,151	6,737		945		874
Expected return on plan assets		(8,070)	(6,626)		–		–		(6,460)	(7,506)		–		–
Amortization of prior service cost (credit)		259	323		(18)		(21)		247	257		(98)		(10)
Amortization of transitional asset		–	–		–		2
Recognized actuarial loss		3,610	3,617		–		38		3,514	5,215		–		–
Net periodic benefit expense	$	5,097	5,837		1,375		1,802	$	6,514	6,958		1,267		1,358

	Nine Months Ended September 30,
	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2017	2016	2017		2016
Service cost	$	6,099	8,533		1,276		2,022
Interest cost		20,267	20,386		2,899		3,324
Expected return on plan assets		(21,730)	(21,709)		–		–
Amortization of prior service cost (credit)		767	963		(55)		(62)
Amortization of transitional asset		–	–		–		4
Recognized actuarial loss		10,673	10,864		–		113
Curtailments		–	822		–		(19)
Net periodic benefit expense	$	16,076	19,859		4,120		5,382

~~Curtailment~~The components of net periodic benefit expense ~~for~~other than the ~~nine months ended September 30, 2016, shown~~service cost component are included in the ~~table above, relates to restructuring activities~~line item “Interest and other income (loss)” in ~~the U.S. undertaken by the Company in the first quarter~~Consolidated Statements of ~~2016.~~

Operations.

During the ~~nine-month~~three-month period ended ~~September 30, 2017,~~March 31, 2019, the Company made contributions of ~~$24.0~~$6.9 million to its defined benefit pension and postretirement benefit plans. Remaining ~~required~~ funding in ~~2017~~2019 for the Company’s defined benefit pension and postretirement plans is anticipated to be ~~$6.8~~$25.6 million.

1014

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note GI – Incentive Plans

The costs resulting from all share-based and cash-based incentive plans payment transactions are recognized as an expense in the Consolidated Statements of Operations using a fair value-based measurement method over the periods that the awards vest.

The ~~2012~~2017 Annual Incentive Plan ~~(2012~~(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 ~~2012~~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 ~~2012~~2018 Long-Term Incentive Plan ~~(2012~~(2018 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives. The ~~2012~~2018 Long-Term Plan expires in ~~2022.~~2028. A total of ~~8,700,000~~6,750,000 shares are issuable during the life of the ~~2012~~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.

The Company also has a ~~2013~~ Stock Plan for Non-Employee Directors ~~(Director 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 had an Employee Stock Purchase Plan (ESPP) that permitted the issuance of Company shares during 2016 and~~In the first ~~six months~~quarter of ~~2017. The ESPP terminated on June 30, 2017 and was not renewed by the Company.~~

~~In February 2017,~~2019, the Committee granted ~~stock options for 599,000 shares at an exercise price of $28.505 per share. The Black-Scholes valuation for these awards was $7.96 per option. The Committee also granted 556,000~~957,600 performance-based

~~RSU~~ RSUs and ~~282,000~~327,900 time-based ~~RSU in February 2017.~~RSUs to certain employees. The fair value of the performance-based ~~RSU,~~RSUs, using a Monte Carlo valuation model, ~~ranged from $24.10 to $28.28~~was $28.09 per unit. The fair value of the time-based ~~RSU~~RSUs was estimated based on the fair market value of the Company’s stock on the date of ~~grant, which~~grant. The fair value of the time-based RSUs granted was ~~$28.505~~$28.16 per ~~share.~~unit. Additionally, in February 2019, the Committee granted ~~329,400 SAR and 154,150 units of~~1,025,900 cash-settled ~~RSU (RSUC)~~RSUs (CRSU) to certain employees. The ~~SAR and RSUC~~CRSUs are to be settled in cash, net of applicable income taxes, and are accounted for as liability-type awards. The initial fair value of ~~these SAR~~the CRSUs granted in February 2019 was ~~equivalent to the stock options granted, while the initial value of RSUC was equivalent to equity-settled restricted stock units granted.~~$28.16. Also in February, the Committee granted ~~83,220~~78,716 shares of time-based ~~RSU~~RSUs to the Company’s non-employee Directors under the 2018 Stock Plan for Non-Employee ~~Director Plan.~~Directors. These ~~shares~~units are scheduled to vest on the third anniversary of the date of grant. The estimated fair value of these awards was ~~$28.84~~$27.95 per unit on date of grant.

~~For all periods presented,~~All stock option exercises are non-cash transactions for the ~~Company had no~~Company. The employee receives net shares, after applicable withholding taxes, upon each stock ~~options exercised.~~

option exercise. The actual income tax benefit realized from the tax deductions related to stock option exercises of the share-based payment arrangements were immaterial for the three-month period ended March 31, 2019.

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



	Nine Months Ended			Three Months Ended
	September 30,			March 31,
(Thousands of dollars)		2017	2016		2019	2018
Compensation charged against income (loss) before tax benefit	$	28,264	35,948
Compensation charged against income before tax benefit				$	15,514	7,549
Related income tax benefit recognized in income		8,695	11,796		2,342	894

Certain incentive compensation granted to the Company’s named executive officers, to the extent their total compensation exceeds $1.0 million per executive per year, is not eligible for a U.S. income tax deduction under the Tax Cuts and Jobs Act (2017 Tax Act).

1115

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note HJ – Earnings per Share

Net ~~loss~~income attributable to Murphy was used as the numerator in computing both basic and diluted income per Common share for the

three-month ~~and nine-month~~ periods ended ~~September 30, 2017~~March 31, 2019 and ~~2016.~~2018. The following table reconciles the weighted-average shares outstanding used for these computations.



	Three Months Ended		Nine Months Ended		Three Months Ended
	September 30,		September 30,		March 31,
(Weighted-average shares)	2017	2016	2017	2016	2019	2018
Basic method	172,572,873	172,199,350	172,509,418	172,164,683	173,341,304	172,805,065
Dilutive stock options and restricted stock units*	–	–	–	–
Dilutive stock options and restricted stock units					1,150,039	1,814,459
Diluted method	172,572,873	172,199,350	172,509,418	172,164,683	174,491,343	174,619,524

*~~Due~~The following table reflects certain options to ~~net losses recognized by~~purchase shares of common stock that were outstanding during the ~~Company for all~~ periods presented ~~no unvested stock awards~~but were not included in the computation of diluted ~~earnings per share~~shares above because the ~~effect would have been anti-dilutive.~~

incremental shares from the assumed conversion were antidilutive.



	Three Months Ended				Nine Months Ended				Three Months Ended
		September 30,			September 30,					March 31,
		2017	2016		2017		2016			2019	2018
Antidilutive stock options excluded from diluted shares		5,257,718		5,884,201		5,578,495		5,822,036		3,140,065		3,798,792
Weighted average price of these options	$	46.46	$	49.00	$	46.86	$	49.82	$	46.18	$	50.77

Note IK – Income Taxes

The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income ~~(loss)~~from continuing operations before income ~~tax expense.~~taxes. For the three-month ~~and nine-month~~ periods ended ~~September 30, 2017~~March 31, 2019 and ~~2016,~~2018, the Company’s effective income tax rates were as follows:

2017

2016

Three months ended September 30
(4.3%)

13.0%

Nine months ended September 30
137.7%

48.9%


	2019	2018
Three months ended March 31	32.1%	530.2%

The effective tax rates for most periods where earnings are generated, generally exceed the U.S. statutory tax rate ~~of 35%~~ due to several factors, including: the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates that are higher than the U.S. Federal rate; U.S. state tax expense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are available or are not presently being recorded due to a lack of reasonable certainty of adequate future revenue against which to utilize these expenses as deductions. Conversely, the effective tax rates for most periods where losses are incurred generally are lower than U.S. statutory tax rate of ~~35%~~21% due to similar reasons.

The effective tax rate for the three-month period ended September 30, 2017 was below the U.S. statutory tax rate of 35% primarily due to the tax effect of expenses in foreign jurisdictions not fully deductible from losses at the U.S. statutory tax rate, an estimated U.S. tax charge for undistributed foreign earnings and Canadian foreign exchange losses not fully deductible at 35%. These impacts were partially offset by the U.S. tax benefit recognized from the reversal of an uncertain tax position for federal tax years 2011-2013.

~~The effective tax rate for the nine-month period ended September 30, 2017~~March 31, 2019 was above the U.S. statutory tax rate of ~~35%~~21% primarily due to ~~an estimated U.S.~~exploration expenses in certain foreign jurisdictions in which no income tax ~~charge for undistributed foreign earnings and Canadian foreign exchange losses.~~benefit is available. These impacts were partially offset by no tax applied to the U.S. tax benefit recognized from the reversal of an uncertain tax position for federal tax years 2011-2013 and other items. During the first nine-months of 2017, the Company determined that prospective earnings from its Malaysian and Canadian subsidiaries will not be considered reinvested into local operations. Due to this change in assertion, the Company recorded a deferred tax charge of $65.2 million in the nine-month period 2017 associated with the estimated tax consequencepre-tax income of the future repatriation of these subsidiaries earnings during the first nine months 2017. This decision provides greater financial flexibility as it considers future domestic investment opportunities. The Company expects to incur further tax chargesnoncontrolling interest in ~~the fourth quarter 2017 for additional 2017 foreign earnings as they arise.~~

~~Note I – Income Taxes (Contd.)~~

MP GOM.

The effective tax rate for the three-month period ended ~~September 30, 2016~~March 31, 2018 was ~~less than~~above the ~~U.S.~~ statutory tax rate primarily due to ~~expenses in foreign jurisdictions for which no tax benefits were recognized. The effective tax rate~~the impact of the IRS’s April 2, 2018 guidance allowing for the ~~nine-month period ended September 30, 2016 was above~~preservation of 2017 operating loss carryforwards under the ~~U.S. statutory~~2017 Tax Act’s taxation of unrepatriated foreign earnings. The preservation of the tax ~~rate primarily due to~~loss carryforward reduced the deferred tax ~~benefits recognized related~~expense by $156 million and resulted in a $36 million charge to ~~the Canadian asset dispositions and income~~taxes payable for a net $120 million tax ~~benefits on investments in foreign areas.~~

benefit.

The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take multiple 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 ~~September 30, 2017,~~March 31, 2019, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – ~~2014;~~2015; Canada – ~~2012;~~2013; Malaysia – ~~2010;~~2012; and United Kingdom – ~~2015.~~2017.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note JL – Financial Instruments and Risk Management

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 Accumulated ~~Other Comprehensive Loss~~other comprehensive loss until the anticipated transactions occur. ~~This deferred cost is being reclassified to Interest expense, net in the Consolidated Statements of Operations over the period until the associated notes mature in 2022.~~

Commodity ~~Purchase~~ Price Risks

~~The Company is subject to commodity price risk related to crude oil it produces and sells. During the first nine months 2017 and 2016,~~At March 31, 2019, the Company had ~~West Texas Intermediate (WTI)~~no WTI crude oil swap financial contracts ~~to economically hedge a portion~~outstanding.

At March 31, 2018, the Company had 21,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during the remainder of ~~its United States production.~~ 2018 at an average price of $54.88. Under ~~these contracts,~~this contract, which matured monthly, the Company paid the average monthly price in effect and received the fixed contract prices. At September 30, 2017, the Company had 22,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during the remainder of 2017 at an average price of $50.41 and 6,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2018 at an average price of $51.83. At September 30, 2017, the fair value of WTI contracts of $3.2 million was included in Accounts Payable. The impact of marking to market these commodity derivative contracts increased the loss before income taxes by $3.2 million for the nine-month period ended September 30, 2017.

At September 30, 2016, the Company had 25,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2016. At September 30, 2016, the fair value of WTI contracts of $0.2 million was included in Accounts Receivable. The impact of marking to market these 2016 commodity derivative contracts decreased the loss before income taxes by $3.9 million for the nine-month period ended September 30, 2016.

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)~~

~~Note J – Financial Instruments and Risk Management~~ ~~(Contd.)~~

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 derivatives outstanding at ~~September 30, 2017.~~

March 31, 2019 and 2018.

At September 30, 2016, short-term derivative instruments were outstanding in Canada for approximately $25.2 million, to manage the currency risks of certain U.S. dollar accounts receivable associated with sale of Canadian crude oil. The fair values of open foreign currency derivative contracts were assets of $0.1 million at September 30, 2016.

~~At September 30, 2017~~March 31, 2019 and December 31, ~~2016,~~2018, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

September 30, 2017

December 31, 2016

March 31, 2019

December 31, 2018

(Thousands of dollars)

Asset (Liability) Derivatives

Type of Derivative Contract

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Commodity

Accounts payable

(3,226)

Accounts payable

(48,864)

Accounts payable

–

Accounts receivable

3,837

Foreign exchange

Accounts receivable

–

Accounts payable

(73)

For the three-month period ended March 31, 2019 and ~~nine-month periods ended September 30, 2017 and 2016,~~March 31, 2018 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)						Gain (Loss)
		Three Months Ended			Nine Months Ended			Three Months Ended
(Thousands of dollars)		September 30,			September 30,			March 31,
Type of Derivative Contract	Statement of Operations Location		2017	2016	2017	2016	Statement of Operations Location		2019	2018
Commodity	Sales and other operating revenues	$	(13,573)	11,871	50,365	(22,678)	Gain (loss) on crude contracts	$	–	(29,502)
Foreign exchange	Interest and other income (loss)		–	143	73	26,929
		$	(13,573)	12,014	50,438	4,251

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 ~~nine-month~~three-month periods ended ~~September 30, 2017~~March 31, 2019 and ~~2016, $2.2~~2018, $0.7 million of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statement of Operations. The remaining loss (net of tax) deferred on these matured contracts at ~~September 30, 2017~~March 31, 2019 was ~~$8.9~~$7.3 million, which is recorded, net of income taxes of ~~$4.8~~$1.9 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheet. The Company expects to charge approximately ~~$0.7~~$2.2 million of this deferred loss to Interest expense, net in the Consolidated Statement of Operations during the remaining ~~three~~nine months of ~~2017.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)~~

~~Note J – Financial Instruments and Risk Management~~ ~~(Contd.)~~

2019.

Fair Values – Recurring

The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Fair Values – Recurring (Contd.)

The carrying value of assets and liabilities recorded at fair value on a recurring basis at ~~September 30, 2017~~March 31, 2019 and December 31, ~~2016~~2018 are presented in the following table.

September 30, 2017

December 31, 2016

March 31, 2019

December 31, 2018

(Thousands of dollars)

Level 1

Level 2

Level 3

Total

Level 1

Level 2

Level 3

Total

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

15,161

–

15,161

13,904

–

13,904

15,436

–

15,436

13,845

–

13,845

Commodity derivative contracts

–

3,226

–

3,226

–

48,864

–

48,864

Foreign currency exchange
derivative contracts

–

Contingent consideration

–

61,260

–

47,730

15,161

3,226

–

18,387

13,904

48,937

–

62,841

15,436

–

61,260

76,696

13,845

–

47,730

61,575

The fair value of WTI crude oil derivative contracts in ~~2017 and 2016 was~~2018 were based on active market quotes for WTI crude oil. The fair value of foreign exchange derivative contracts in each year was based on market quotes for similar contracts at the balance sheet dates. The income effect of changes in the fair value of crude oil derivative contracts is recorded in ~~Sales and other operating revenues~~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. 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 offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were no offsetting positions recorded at ~~September 30, 2017~~March 31, 2019 and December 31, ~~2016.~~2018.

Subsequent to the balance sheet date, the Company has entered into derivative instruments to manage certain risks related to commodity prices.

Note M – Accumulated Other Comprehensive Loss

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



					Deferred
			Retirement		Loss on
		Foreign	and		Interest
		Currency	Postretirement		Rate
		Translation	Benefit Plan		Derivative
(Thousands of dollars)		Gains (Losses)	Adjustments		Hedges		Total
Balance at December 31, 2018	$	(419,852)	(182,036)		(7,899)		(609,787)
2019 components of other comprehensive income (loss):
Before reclassifications to income and retained earnings		25,449	–		–		25,449
Reclassifications to income		–	2,754	1	585	2	3,339
Net other comprehensive loss		25,449	2,754		585		28,788
Balance at March 31, 2019	$	(394,403)	(179,282)		(7,314)		(580,999)

1 Reclassifications before taxes of $3,530 are included in the computation of net periodic benefit expense for the three-month period ended March 31, 2019. See Note H for additional information. Related income taxes of $776 are included in Income tax expense (benefit) for the three-month period ended March 31, 2019.

2 Reclassifications before taxes of $741 are included in Interest expense, net, for the three-month period ended March 31, 2019. Related income taxes of $156 are included in Income tax expense (benefit) for the three-month period ended March 31, 2019. See Note L for additional information.

1418

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note ~~J – Financial Instruments and Risk Management~~ ~~(Contd.)~~

~~Fair Values – Nonrecurring~~

As a result of the fall in forward commodity prices during the first nine-month period ended September 30, 2016, the Company recognized approximately $95.1 million in pretax non-cash impairment charges related to producing properties. The fair value information associated with these impaired properties is presented in the following table.

Nine-months ended September 30, 2016

Total

Net Book

Pretax

Value

(Noncash)

Fair Value

Prior to

Impairment

Level 1

Level 2

Level 3

Impairment

Expense
(Thousands of dollars)

Assets:

Impaired proved properties

Canada

$
–

–

71,967

167,055

95,088

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.

~~Note K – Accumulated Other Comprehensive Loss~~

The components of Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets at December 31, 2016 and September 30, 2017 and the changes during the nine-month period ended September 30, 2017 are presented net of taxes in the following table.

Deferred

Loss on

Foreign

Retirement and

Interest

Currency

Postretirement

Rate

Translation

Benefit Plan

Derivative

(Thousands of dollars)

Gains (Losses)

Adjustments

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

194,094

3

–

194,097
Reclassifications to income

–

7,166
1
1,445
2
8,611
Net other comprehensive income

194,094

7,169

1,445

202,708
Balance at September 30, 2017
$
(252,461)

(164,136)

(8,907)

(425,504)

1Reclassifications before taxes of $11,039 for the nine-month period ended September 30, 2017 are included in the computation of net periodic benefit expense. See Note G for additional information. Related income taxes of $3,873 for the nine-month period ended September 30, 2017 are included in Income tax expense.

2Reclassifications before taxes of $2,222 for the nine-month period ended September 30, 2017 are included in Interest expense, net. Related income taxes of $777 for the nine-month period ended September 30, 2017 are included in Income tax expense.

~~Note L~~N – Environmental and Other 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 ~~increases,~~legislation changes, including tax rate changes and retroactive tax claims; royalty and revenue sharing changes; 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 ~~and~~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.

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)~~

~~Note L – Environmental and Other Contingencies (Contd~~.)

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. The Company has not retained any environmental exposure associated with Murphy’s former U.S. marketing operations. 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.

During 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, the Company recorded $43.9 million in Other expense during 2015 associated with the estimated costs of remediating the site. As of September 30, 2017, the Company has a remaining accrued liability of $5.8 million associated with this event. During the first nine months of 2017, the Company’s Canadian subsidiary paid approximately $130 thousand as the complete and final resolution of administrative penalties assessed by the Alberta Energy Regulator regarding this matter. Further refinements in the estimated total cost to remediate the site are anticipated in future periods including possible insurance recoveries. It is possible that the ultimate net remediation costs to the Company associated with the condensate leak or leaks will exceed the amount of liability recorded. The Company retained the responsibility for this remediation upon sale of the Seal field in the first quarter of 2017.

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.

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.

~~Note M – Commitments~~

The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2017 to 2020 natural gas sales volumes in Western Canada. During the period from October to December 2017 the natural gas sales contracts call for deliveries of 124 million cubic feet per day at Cdn $2.97 per MCF. During the period from January 2018 through December 2020 the natural gas sales contracts call for deliveries of 59 million cubic feet per day at Cdn $2.81 per MCF. During the period from November 2017 through March 2018 the natural gas sales contracts call for deliveries of 20 million cubic feet per day at US $3.51 per MCF.

~~These natural gas contracts have been accounted for as normal sales for accounting purposes.~~

1619

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note NO – Business Segments

Information about business segments and geographic operations is reported in the following ~~tables.~~table. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate, including interest income, ~~miscellaneous~~other gains and losses (including foreign exchange ~~gains~~gains/losses and ~~losses)~~realized/unrealized gains/losses on crude oil contracts), interest expense and unallocated overhead, is shown in the tables to reconcile the business segments to consolidated totals. ~~Certain reclassifications have been made to 2016 Corporate External Revenue to align with current period presentation (see Note A).~~


				Three Months Ended		Three Months Ended				Three Months Ended		Three Months Ended
	Total Assets			September 30, 2017		September 30, 2016		Total Assets		March 31, 2019		March 31, 2018
	at September 30,			External	Income	External	Income	at March 31,		External	Income	External	Income
(Millions of dollars)	2017			Revenues	(Loss)	Revenues	(Loss)	2019		Revenues	(Loss)	Revenues	(Loss)
Exploration and production*
Exploration and production 1
United States	$	5,439.1		195.9	(19.9)	201.8	(27.1)	$	6,615.5	469.2	116.2	278.1	36.2
Canada		1,711.1		81.9	(3.2)	80.9	(4.8)		2,252.8	118.9	7.5	118.3	24.4
Malaysia		1,755.3		220.5	67.7	202.7	65.0
Other		139.9		–	(11.0)	0.2	(8.1)		225.2	2.9	(28.3)	–	(15.4)
Total exploration and production		9,045.4		498.3	33.6	485.6	25.0		9,093.5	591.0	95.4	396.4	45.2
Corporate		1,124.2		–	(99.9)	(0.1)	(39.6)		1,010.0	–	(72.4)	(21.6)	45.4
Assets/revenue/loss from continuing operations		10,169.6		498.3	(66.3)	485.5	(14.6)
Assets/revenue/income from continuing operations									10,103.5	591.0	23.0	374.8	90.6
Discontinued operations, net of tax		23.2		–	0.4	–	(1.6)		1,879.6	–	49.8	–	77.7
Total	$	10,192.8		498.3	(65.9)	485.5	(16.2)	$	11,983.1	591.0	72.8	374.8	168.3

				Nine Months Ended		Nine Months Ended
				September 30, 2017		September 30, 2016
				External	Income	External	Income
(Millions of dollars)				Revenues	(Loss)	Revenues	(Loss)
Exploration and production*
United States			$	696.7	11.0	520.2	(158.5)
Canada				388.1	102.6	264.4	(36.9)
Malaysia				594.4	173.9	541.4	135.1
Other				–	(10.9)	0.2	(39.2)
Total exploration and production				1,679.2	276.6	1,326.2	(99.5)
Corporate				4.0	(302.8)	3.5	(111.7)
Revenue/loss from continuing operations				1,683.2	(26.2)	1,329.7	(211.2)
Discontinued operations, net of tax				–	1.2	–	(0.8)
Total			$	1,683.2	(25.0)	1,329.7	(212.0)

*1Additional details about results of oil and gas operations are presented in the tables on pages 29 ~~and~~ 30.

~~Note O – New Accounting Principles Adopted~~

~~Business Combinations~~

In January 2017, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) to clarify the definition of a business to assist entities in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The standard is intended to narrow the definition of a business by specifying the minimum inputs and processes and by narrowing the definition of outputs. The update is effective for annual periods beginning after December 15, 2017, including interim periods within those periods. The prospective approach is required for adoption and early adoption is permitted for transactions not previously reported in issued financial statements. The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures.

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)~~

~~Note O – New Accounting Principles Adopted (Contd~~.)

~~Compensation – Stock Compensation~~

In March 2016, the FASB issued an ASU intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification within the statement of cash flows. The amendments in this ASU were effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures as there were no exercises of Company options during the period.

Note P – ~~Recent~~Leases

Significant Accounting ~~Pronouncements~~Policy

~~Compensation – Stock Compensation~~

~~In May 2017, FASB issued~~At inception, contracts are assessed for the presence of a lease according to criteria laid out by ASC 842. If a lease is present, further criteria is assessed to determine if the lease should be classified as an ~~ASU which amends the scope of modification accounting for share-based payment arrangements and provides guidance~~operating or finance lease. Operating leases are presented on the ~~type of changes to~~Consolidated Balance Sheet as Operating lease assets with 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. Early adoption is permitted. The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.

~~Compensation – Retirement Benefits~~

~~In March 2017, the FASB issued an ASU requiring that the service cost component of pension and postretirement benefit costs be~~corresponding lease liabilities presented in Operating lease liabilities and Non-current operating lease liabilities. Finance lease assets are presented on the ~~same line item as other current employee compensation costs~~Consolidated Balance Sheet within Property, plant and ~~other components~~equipment, net with the corresponding liabilities presented in Current maturities of ~~those benefit costs be presented separately from~~long-term debt and Long-term debt.

Generally, lease liabilities are recognized at commencement and based on the service cost component and 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 periods beginning after December 15, 2017 and interim periods within the annual period. Application is retrospective for the presentationpresent value of the components of these benefit costs and prospective for the capitalization of only service costs. Early adoption is permitted. The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.

~~Revenue from Contracts with Customers~~

Operating leases are expensed according to their nature and recognized in ~~exchange for those goods~~Lease operating expenses, Selling and general expenses or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainly of revenue and cash flows from contracts with customers. The Company is required to adopt the new standardcapitalized in the ~~first quarter~~Consolidated Financial Statement. Finance leases are depreciated with expenses recognized in Depreciation, depletion, and amortization and Interest expense, net on the Consolidated Statement of ~~2018 using either the modified retrospective or cumulative effect transition method.~~ Operations.

Nature of Leases

The Company has ~~performed~~entered into various operating leases such as a ~~review~~gas processing plant, floating production storage and off-take vessels, buildings, marine vessels, vehicles, drilling rigs, pipelines, and other oil and gas field equipment. Remaining lease terms range from 1 year to 17 years, some of ~~contracts in each~~which may include options to extend leases for multi-year periods and others which include options to terminate the leases within 1 month. Options to extend lease terms are at the Company’s discretion. Early lease terminations are a combination of ~~its revenue streams~~both at Company discretion and ~~is developing accounting policies and applicable disclosures to address the provisions of the ASU. While~~mutual agreement between the Company ~~does not currently expect net earnings to be materially impacted, the Company is analyzing whether total revenues~~ and expenses will be significantly impacted. The Company continues to evaluate the impact of this and other provisions of these ASU’s on its accounting policies, internal controls, and consolidated financial statements and related disclosures, and has not finalized any estimates of the potential impacts. The Company will adopt the new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings as necessary.

~~Leases~~

In February 2016, FASB issued an ASU to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous Generally Accepted Accounting Principles (GAAP) and this ASU is the recognition of right-of-use assets and lease liabilities by lesseeslessor. Purchase options also exist for those leases classified as operating leases under previous GAAP. 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 anticipates adopting this guidance in the first quarter of 2019 and is currently analyzing its portfolio of contracts to assess the impact future adoption of this ASU may have on its consolidated financial statements.certain leases.

1820

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note P – ~~Recent Accounting Pronouncements (~~Leases ~~Contd~~(Contd.)

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

Related Expenses


			Three Months Ended
(Thousands of dollars)	Financial Statement Category		March 31, 2019
Operating lease 1,2	Lease operating expenses	$	58,523
Operating lease 2	Selling and general expense		3,109
Operating lease 2	Property, plant and equipment		23,447
Operating lease 2	Asset retirement obligations		3,024
Finance lease
Amortization of asset	Depreciation, depletion and amortization		210
Interest on lease liabilities	Interest expense, net		101
Sublease income	Other income		(217)
Net lease expense		$	88,197

1 .Includes variable lease expenses of $7.2 million primarily related to additional volumes processed at a gas processing plant.

2 Includes $12.0 million for Lease operating expense, $1.1 million for Selling and general expense, $20.1 million for Property, plant and equipment, net and $3.0 million for Asset retirement obligations relating to short-term leases. Expenses primarily relate to drilling rigs and other oil and gas field equipment.

Maturity of Lease Liabilities


(Thousands of dollars)		Operating Leases 1	Finance Leases	Total
2019	$	164,979	801	165,780
2020		109,790	1,069	110,859
2021		58,415	1,069	59,484
2022		53,639	1,069	54,708
2023		53,140	1,069	54,209
Remaining		465,611	5,610	471,221
Total future minimum lease payments		905,574	10,687	916,261
Less imputed interest		(281,613)	(2,234)	(283,847)
Present value of lease liabilities 2	$	623,961	8,453	632,414

1 Excludes $272.2 million of minimum lease payments for leases entered but not yet commenced. These payments relate to an expansion of an existing gas processing plant and payments are anticipated to commence at the end of 2019 for 20 years.

2 Includes both the current and long-term portion of the lease liabilities.

Lease Term and Discount Rate


		March 31, 2019
Weighted average remaining lease term:
Operating leases		11 years
Finance leases		10 years
Weighted average discount rate:
Operating leases		5.07%
Finance leases		4.80%

Other Information


		Three Months Ended
(Thousands of dollars)		March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	44,730
Operating cash flows from finance leases		102
Financing cash flows from finance leases		160
Right-of-use assets obtained in exchange for lease liabilities:
Operating leases	$	311

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note Q – Acquisition

In December 2018, the Company announced the completion of a transaction with Petrobras Americas Inc. (PAI) which was effective October 1, 2018. Through this transaction, Murphy acquired all 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.

Under the terms of the transaction, Murphy paid cash consideration of $788.7 million and transferred a 20% interest in MP Gulf of Mexico, LLC (MP GOM), a subsidiary of Murphy, to PAI. Murphy also has an obligation to pay additional contingent consideration up to $150 million if certain sales thresholds are exceeded beginning in 2019 through 2025. Both companies contributed all of their current producing Gulf of Mexico assets into MP GOM. 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	$	788,724
Fair value of net assets contributed		154,469
Contingent consideration		52,540
NCI in acquired assets		248,933
Total purchase consideration	$	1,244,666

(Thousands of dollars)
Fair value of Property, plant and equipment	$	1,627,429
Other assets		5,628
Less: Asset retirement obligations		(388,391)
Total net assets	$	1,244,666

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 acquired PAI assets and assumed liabilities as well as 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 of November 30, 2018, during which time the value of the assets and liabilities may be revised as appropriate.

Results of Operations

Murphy’s Consolidated Statement of Operations for the three months ended March 31, 2019 included additional revenues of $234.0 million and pre-tax income of $147.7 million attributable to the acquired PAI assets.

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, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable. 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, 2018; furthermore, the financial information is not intended to be a projection of future results.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note Q – Acquisition (Contd.)

~~Statement of Cash Flows~~

~~In August 2016,~~


	Three Months Ended
(Thousands of dollars, except per share amounts)		March 31, 2018
Revenues	$	579,080
Net Income Attributable to Murphy		211,497

Net Income Attributable to Murphy per Common Share
Basic	$	1.22
Diluted		1.21

Note R – Subsequent Event

On April 23,2019 the ~~FASB issued~~Company announced that its wholly owned subsidiary, Murphy Exploration & Production Company USA, has entered into a definitive agreement to acquire deep water Gulf of Mexico assets from LLOG Exploration Offshore, L.L.C. and LLOG Bluewater Holdings, L.L.C., (LLOG) for cash consideration of $1.375 billion. The transaction will have an ~~ASU~~effective date of January 1, 2019 and is expected to ~~reduce diversity in practice in how certain transactions are classified~~close in the ~~statement~~second quarter, subject to normal closing adjustments. This acquisition will be funded by a combination of cash ~~flows.~~ on hand and availability under the company’s $1.6 billion revolving credit facility.

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,Company could owe additional contingent consideration payments ~~made after a business combination, proceeds~~up to $200 million in the event that revenue from ~~the settlement of insurance claims, proceeds~~certain properties exceeds certain contractual thresholds between 2019 and 2022; and $50 million following first oil from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees. The ASU is effective for annual and interim periods beginning after December 15, 2017. The Company is currently assessing the potential impact of this ASU on its consolidated financial statements.certain development projects.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS

Overall Review

~~During~~On March 21, 2019, Murphy Oil Corporation announced that a subsidiary has signed a sale and purchase agreement to divest the ~~three-month~~fully issued share capital of its two primary Malaysian subsidiaries, Murphy Sabah Oil Co., Ltd. and ~~nine-month periods ended September 30, 2017, worldwide benchmark oil~~Murphy Sarawak Oil Co., Ltd., to a subsidiary of PTT Exploration and natural gas prices were above average comparable benchmark prices during 2016. Although prices were above 2016 levels, unrealized losses from foreign exchange movements along with higher tax expenseProduction Public Company Limited (PTTEP). As such the assets and liabilities of the Malaysia business have been classified as held for sale on ~~earnings~~the consolidated balance sheet and the Malaysia results of ~~foreign subsidiaries more than offset this increase in revenue~~operations have been reported as discontinued operations in the ~~third quarter.~~

statement of operations.

For the three months ended ~~September 30, 2017,~~March 31, 2019, the Company produced 154 thousand barrels of oil equivalent per day. There was no production in the 2017 quarter from Canadian synthetic and heavy oil assets due to the 2016 and 2017 divestures of Syncrude and Seal assets, respectively. The Company invested $287 million in capital expenditure in the third quarter of 2017 primarily in the United States and Canada. The Company reported a net loss of $65.9 million, for the three months ended September 30, 2017, which included a foreign exchange after-tax loss of $43.9 million, principally on intercompany loans in the quarter and an after-tax loss of $11.8 million in the third quarter relating to crude oil derivative contracts.

For the nine-month period ended September 30, 2017, the Company reported a net loss of $25.0 million, which included an after-tax gain of $96.0 million on the sale of the Seal heavy oil property in Canada. The Company produced 162 thousand barrels of oil equivalent per day from continuing operations which excludes Malaysia and is held for ~~the nine-month 2017 period and~~sale. The Company invested ~~$702~~$347 million in capital expenditures, ~~principally~~on a value of work done basis, in the ~~United States and Canada.~~first quarter of 2019. The Company ~~incurred~~reported net income from continuing operations of $23.0 million for the three months ended March 31, 2019.

In the first three months of 2018, the Company produced 117 thousand barrels of oil equivalent per day from continuing operations which excludes Malaysia and is held for sale. The Company invested $281 million in capital expenditures, on a ~~non-cash deferred~~value of work done basis, in 2018. The Company reported net income from continuing operations of $90.6 million for the three months ended March 31, 2018, which included an income tax gain of $120.0 million as a result of a 2018 Internal Revenue Service (IRS) interpretation of the 2017 Tax Act enacted in the fourth quarter of 2017.

During the three-month period ended March 31, 2019, worldwide benchmark oil prices were below average comparable benchmark prices during 2018. For the quarter, crude oil and condensate volumes were higher than the prior year quarter. In the quarter the gains from higher volume were partially offset by higher lease operating expense in the ~~first nine months~~Gulf of ~~2017 of $65.2 million on earnings of foreign subsidiaries, the majority of which was recorded~~Mexico and Canada Onshore businesses. The results are explained in ~~first quarter of 2017 and recorded a foreign exchange after-tax loss of $86.6 million, principally on intercompany loans in the first nine months of 2017. Further~~more detail ~~and discussion is provided in the narrative~~ below.

Results of Operations

Murphy’s income (loss) by type of business is presented below.



	Income (Loss)							Income (Loss)
	Three Months Ended			Nine Months Ended				Three Months Ended
	September 30,			September 30,				March 31,
(Millions of dollars)	2017		2016	2017		2016		2019		2018
Exploration and production	$	33.6	25.0		276.6		(99.5)	$	95.4	45.2
Corporate and other		(99.9)	(39.6)		(302.8)		(111.7)		(72.4)	45.4
Loss from continuing operations		(66.3)	(14.6)		(26.2)		(211.2)
Income from continuing operations									23.0	90.6
Discontinued operations		0.4	(1.6)		1.2		(0.8)		49.8	77.7
Net loss	$	(65.9)	(16.2)		(25.0)		(212.0)
Net income including noncontrolling interest								$	72.8	168.3

~~Third quarter 2017 vs. 2016~~

For the third quarter of 2017, Murphy’s net loss was $65.9 million ($0.38 per diluted share) compared to net loss of $16.2 million ($0.09 per diluted share) in the third quarter of 2016. Loss from continuing operations fell lower from a loss of $14.6 million ($0.08 per diluted share) in the 2016 quarter to a loss of $66.3 million ($0.38 per diluted share) in the 2017 period. The Company’s exploration and production (E&P) continuing operations earned $33.6 million in the 2017 quarter compared to earnings of $25.0 million in the 2016 quarter. The E&P results in the 2017 quarter were favorably impacted by higher revenues due to higher realized oil and natural gas sales prices, lower lease operating expenses, lower depreciation expense and lower dry hole costs, partially offset by lower volume sold, higher selling and general expenses and higher deferred tax expense on earnings of foreign subsidiaries. The corporate function had after-tax costs of $99.9 million in the 2017 third quarter compared to after-tax costs of $39.6 million in the 2016 period with the unfavorable variance in the current period due to losses from foreign exchange effects in the 2017 period versus gains in the same period of 2016, higher net interest expense and deferred tax charges in 2017 on undistributed earnings of certain foreign subsidiaries, offset in part by lower administrative costs in the current quarter. The third quarter of 2017 included gains from discontinued operations of $0.4 million ($0.00 per diluted share) compared to losses from discontinued operations of $1.6 million ($0.01 per diluted share) in the third quarter of 2016.

~~Nine months 2017 vs. 2016~~

For the first nine months of 2017, Murphy’s net loss was $25.0 million ($0.14 per diluted share) compared to a net loss of $212.0 million ($1.24 per diluted share) for the same period in 2016. Loss from continuing operations improved from a loss of $211.2 million ($1.23 per diluted share) in the first nine months of 2016 to a loss of $26.2 million ($0.15 per diluted share) in 2017. In the first nine months of 2017, the Company’s E&P continuing operations earned $276.6 million compared to a loss of $99.5 million in the same period of 2016. The results for the first nine months of 2017 were favorably impacted

~~ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)~~

~~Results of Operations~~ ~~(Contd.)~~

~~Nine months 2017 vs. 2016 (contd.)~~

by higher revenues due to higher realized oil and natural gas sales prices, gain on sale of the Seal property in Western Canada, lower lease operating expenses, lower depreciation expense, non-recurring impairment expense in 2016, lower selling and general expenses, lower dry hole costs and higher tax benefits on investments in foreign areas, partially offset by higher non-cash deferred tax expense on earnings of foreign subsidiaries, higher other expense related primarily to rig demobilization in Malaysia and lower oil and natural gas volume sold. The corporate function had after-tax costs of $302.8 million in the first nine months of 2017 compared to after-tax costs of $111.7 million in the 2016 period with the unfavorable variance in the current period due to losses from foreign exchange effects in the 2017 period versus gains in the same period of 2016, higher net interest expense and non-cash deferred tax charges in 2017 on undistributed earnings of certain foreign subsidiaries, offset in part by lower administrative costs. Income from discontinued operations was $1.2 million ($0.01 per diluted share) in the first nine months of 2017 compared to a loss of $0.8 million ($0.01 per diluted share) in the 2016 period.

Exploration and Production

Results of E&P continuing operations are presented by geographic segment below.



		Income (Loss)
	Three Months Ended
	March 31,
(Millions of dollars)	2019		2018
Exploration and production
United States	$	116.2	36.2
Canada		7.5	24.4
Other International		(28.3)	(15.4)
Total	$	95.4	45.2

Income (Loss)

Three Months Ended

Nine Months Ended

September 30,

September 30,
(Millions of dollars)
2017

2016

2017

2016
Exploration and production

United States
$
(19.9)

(27.1)

11.0

(158.5)
Canada

(3.2)

(4.8)

102.6

(36.9)
Malaysia

67.7

65.0

173.9

135.1
Other International

(11.0)

(8.1)

(10.9)

(39.2)
Total
$
33.6

25.0

276.6

(99.5)

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)

~~Third~~Results of Operations (Contd.)

First quarter ~~2017~~2019 vs. ~~2016~~

2018

United States E&P operations reported ~~a net loss~~earnings of ~~$19.9~~$116.2 million in the ~~third~~first quarter of ~~2017~~2019 compared to income of $36.2 million in the first quarter of 2018. Results were $80.0 million favorable in the 2019 quarter compared to the 2018 period due to higher revenues ($191.1 million), lower exploration charges ($11.1 million), partially offset by higher depreciation, depletion and amortization ($42.3 million), lease operating expenses ($33.9 million), other operating expense ($29.8 million) and G&A ($2.9 million). Higher revenues were primarily due to higher volumes at the MP GOM fields in the U.S. Gulf of Mexico. Lower exploration charges were due to lower lease amortization and lower geological and geophysical expense. Higher lease operating expenses and depreciation expense was due primarily to higher volumes. Higher other operating expense is due to higher business development spend relating to MP GOM business integration and the revaluation of the contingent consideration from higher prices.

Canadian E&P operations reported earnings of $7.5 million in the first quarter 2019 compared to income of $24.4 million in the 2018 quarter. Results were unfavorable $16.9 million compared to the 2018 period due to higher lease operating expense ($8.6 million), higher depreciation ($3.8 million) and lower other income ($11.9 million) related to the Seal insurance proceeds received in the prior year. Higher lease operating expenses and depreciation are a result of higher volumes sold at Kaybob.

Other international E&P operations reported a loss from continuing operations of $28.3 million in the first quarter of 2019 compared to a net loss of ~~$27.1~~$15.4 million in the ~~2016~~prior year quarter. ~~Results improved $7.2~~The result was $12.9 million unfavorable in the ~~2017 quarter compared~~2019 period versus 2018 primarily due to write-off of previously suspended exploration costs of $13.2 million attributable to the ~~2016 period. Higher~~CM-1X and the CT-1X wells (originally drilled in 2017) in Vietnam.

Total hydrocarbon production from continuing operations averaged 161,601 barrels of oil ~~and natural gas realized sales prices more than offset impacts~~equivalent per day in the first quarter of ~~lower volumes sold. Lease operating expenses decreased due to lower costs~~2019, which represented a 39% increase from the 116,604 barrels per day produced in ~~Eagle Ford Shale compared to~~ the ~~same quarter in 2016 with most of the reduction~~2018 quarter. The increase is principally due to the ~~Company’s continuous focus on improving its cost structure. Depreciation expense decreased in 2017 compared to 2016 due primarily to lower volume sold in both Eagle Ford Shale and~~acquisition of producing Gulf of Mexico assets as part of the MP GOM transaction in the fourth quarter 2018.

Average crude oil and ~~lower average unit rates~~condensate production from continuing operations was 101,830 barrels per day in the first quarter of 2019 compared to 57,299 barrels per day in the first quarter of 2018. The increase of 44,531 barrels per day was principally due to higher volumes in the Gulf of Mexico (48,432 barrels per day) due to the acquisition of assets as part of the MP GOM transaction and higher volumes at Dalmatian, higher volumes at Canada Onshore (2,099 barrels per day), partially off-set by lower volumes at Eagleford Shale (5,544 barrels per day) due to timing of new wells brought online. On a worldwide basis, the Company's crude oil and condensate prices averaged $55.93 per barrel in the ~~2017 period. Amortization of undeveloped leases were higher~~first quarter 2019 compared to $63.49 per barrel in the ~~2017~~2018 period, a decrease of 12% quarter ~~due~~ to ~~costs related to certain offshore leases expiring in 2017 and 2018. Revenue~~quarter.

Total production of natural gas liquids (NGL) from continuing operations was 9,153 barrels per day in the ~~U.S. decreased by $5.9 million~~first quarter 2019 compared to 8,437 barrels per day in the ~~period as the~~2018 period. The average sales price for U.S. ~~segment recorded $18.1 million unrealized losses on open crude oil contracts in 2017 versus losses of $1.3 million~~NGL was $14.22 per barrel in the 2016 period. This was offset in part by higher oil and gas sales revenue. Selling and general expenses increased in the third quarter of 2017 primarily due to higher allocated benefit costs in the current period versus 2016.

Canadian E&P operations reported a net loss of $3.2 million in the third quarter 2017 compared to a loss of $4.8 million in the 2016 quarter. Canadian results of operations improved $1.6 million in the 20172019 quarter compared to ~~the 2016 period due to higher~~$20.26 per barrel in 2018. The average sales ~~prices received~~price for NGL in 2017 for both oil and natural gas and lower lease operating expenses, partially offset by non-recurring 2016 income tax benefits associated with divestiture of Montney midstream assets in 2016 and a gain on sale of its synthetic operations completedCanada was $35.16 per barrel in the ~~third~~2019 quarter ~~2016.~~ compared to $43.58 per barrel in 2018 due in part to the higher value of product produced at the Kaybob and Placid assets.

Natural gas sales volumes ~~increased~~from continuing operations averaged 304 million cubic feet per day (MMCFD) in ~~2017~~the first quarter 2019 compared to 305 MMCFD in 2018. The decrease of 1 MMCFD was a result of lower volumes in Canada (6 MMCFD) and Eagleford Shale (2 MMCFD), partially offset by higher volumes in the Gulf of Mexico (7 MMCFD). Lower volumes in Canada was a result of fewer wells online and capacity restrictions on the downstream ‘takeaway’ pipeline. Higher volumes in the Gulf of Mexico are due to ~~new production~~the acquisition of assets related to the MP GOM transaction.

Natural gas prices for the total Company averaged $1.94 per thousand cubic feet (MCF) in the ~~Kaybob Duvernay and Placid Montney areas of Western Canada.~~

~~Malaysia E&P operations reported earnings of $67.7 million~~2019 quarter, versus $1.79 per MCF average in the ~~third~~same quarter of ~~2017 and compared to earnings of $65.0 million~~2018. Average prices in the ~~comparable 2016 period. Results~~US and Canada in the quarter were ~~favorable to 2016 in Malaysia as higher average~~$1.90 and $1.95 respectively.

Additional details about results of oil and ~~natural~~ gas prices realized, were mostly offset by lower natural gas volume sold, higher lease operating expense, higher depreciation expense, higher administrative expense and higher income tax expense. Crude oil and natural gas sales volumes in Malaysia were loweroperations are presented in the 2017 quarter versus 2016, primarily due to a maintenance shutdown in Sarawak in 2017. Depreciation expense was higher in 2017 compared to the 2016 quarter primarily due to higher unit rates in Block K and Sarawak partly offset by lower volumes sold in Block K and Sarawak.tables on pages 29.

2025

ITEM 2. ~~MANAGEMENT'S~~MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

~~Third quarter 2017 vs. 2016 (Contd.)~~The following table contains hydrocarbons produced during the three-month periods ended March 31, 2019 and 2018.

~~Other international E&P operations reported a loss from continuing operations of $11.0 million in the third quarter of 2017 compared~~


		Three Months Ended
		March 31,
Barrels per day unless otherwise noted		2019	2018
Continuing operations
Net crude oil and condensate
United States	Onshore	25,880	31,553
	Gulf of Mexico 1	61,048	12,615
Canada	Onshore	6,457	4,358
	Offshore	7,928	8,189
Other		507	585
Total net crude oil and condensate - continuing operations		101,820	57,300
Net natural gas liquids
United States	Onshore	5,301	6,745
	Gulf of Mexico 1	2,760	808
Canada	Onshore	1,093	884
Total net natural gas liquids - continuing operations		9,154	8,437
Net natural gas – thousands of cubic feet per day
United States	Onshore	29,279	31,233
	Gulf of Mexico 1	19,575	12,670
Canada	Onshore	254,904	261,305
Total net natural gas - continuing operations		303,758	305,208
Total net hydrocarbons - continuing operations including NCI 2,3		161,600	116,605
Noncontrolling interest
Net crude oil and condensate – barrels per day		(12,185)	–
Net natural gas liquids – barrels per day		(554)	–
Net natural gas – thousands of cubic feet per day		(3,895)	–
Total noncontrolling interest		(13,388)	–
Total net hydrocarbons - continuing operations excluding NCI 2,3		148,212	116,605

Discontinued operations
Net crude oil and condensate – barrels per day		25,954	31,233
Net natural gas liquids – barrels per day		744	455
Net natural gas – thousands of cubic feet per day 2		101,592	115,276
Total discontinued operations		43,630	50,901
Total net hydrocarbons produced excluding NCI 2,3		191,842	167,506

12019 includes net volumes attributable to a ~~loss of $8.1 million~~noncontrolling interest in the 2016 quarter. The results were $2.9 million lower in the 2017 period versus 2016 primarily related to higher exploration expenses and lower income tax benefits on investments in foreign areas, partially offset by lower selling and general expenses resulting from restructuring activity in 2016.

~~Total hydrocarbon production averaged 153,842 barrels of oil equivalent per day in the 2017 third quarter, which represented~~MP GOM, a 9% decrease from the 169,844 barrels of oil equivalents per day produced in the 2016 quarter. When the Seal asset sold in 2017 is excluded, the Company’s worldwide production decreased 8% in 2017 compared to 2016.

Average crude oil and condensate production was 84,230 barrels per day in the third quarter of 2017 compared to 96,476 barrels per day in the third quarter of 2016. Crude oil production in the Eagle Ford Shale area of South Texas in the 2017 quarter was essentially flat to the same quarter in 2016. Crude oil production in the Gulf of Mexico was lower in the 2017 quarter due to well decline and unplanned downtime. Heavy oil production from the Seal area in Western Canada was divested in mid-January 2017. Onshore oil production in Canada improved in the 2017 quarter in the Company’s Kaybob Duvernay and Placid Montney areas acquired in the third quarterjoint venture.

2Natural gas converted on an energy equivalent basis of 2016. Oil production offshore Eastern Canada was lower during 2017 primarily due to unplanned downtime at both Hibernia and Terra Nova fields. Lower oil production in 2017 in Malaysia was primarily attributable to less net oil volumes produced in Block K due to lower working6:1

3NCI – noncontrolling interest in ~~the Kakap field subsequent to the redetermination of working interest. On~~MP GOM, a worldwide basis, the Company's crude oil and condensate prices averaged $49.82 per barrel in the third quarter 2017 compared to $44.64 per barrel in the 2016 period, an increase of 12% quarter to quarter.

Total production of natural gas liquids (NGL) was 9,128 barrels per day in the 2017 third quarter compared to 9,703 barrels per day in the same 2016 period. The decrease in NGL production was primarily associated with lower natural gas liquids volumes in the U.S, offset by higher volumes in Canada. The average sales price for U.S. NGL was $18.02 per barrel in the 2017 quarter compared to $11.38 per barrel in 2016. Average NGL prices in Malaysia in the third quarter of 2017 and 2016 were $49.66 per barrel and $45.12 per barrel, respectively.

Natural gas sales volumes averaged 363 million cubic feet per day in the third quarter 2017 compared to 382 million cubic feet per day in 2016. Natural gas sales volumes increased in North America for the 2017 period due primarily to new volumes in the Kaybob Duvernay and Placid Montney areas of Western Canada acquired in the third quarter of 2016, and growth in the Tupper Montney business, offset in part by lower volumes produced in both offshore Gulf of Mexico and in Eagle Ford Shale. Natural gas production volumes in Malaysia decreased in the 2017 period due to lower demand and planned downtime at Sarawak in the current period. North American natural gas sales prices averaged $1.93 per thousand cubic feet (MCF) in the 2017 quarter, 2% below the $1.96 per MCF average in the same quarter of 2016. The average realized price for natural gas produced in the 2017 quarter at fields offshore Sarawak was $3.60 per MCF, compared to a price of $3.01 per MCF in the 2016 quarter.

~~Nine months 2017 vs. 2016~~

United States E&P operations reported earnings of $11.0 million in the first nine months of 2017 compared to a loss of $158.5 million in the 2016 period, an improvement of $169.5 million in 2017 compared to the 2016 period. Revenue in the U.S. was $176.5 million in the period as oil and natural gas realized sales prices and unrealized gains on crude oil derivative contracts more than offset lower sales volume. Lease operating expenses decreased by $33.9 million primarily due to lower costs in Eagle Ford Shale and Gulf of Mexico mainly related to cost structure improvements coupled with lower variable costs based on volumes produced. Depreciation expense decreased $54.2 million in 2017 compared to 2016 due to lower unit rates in the Gulf of Mexico in the 2017 period and lower U.S. volume sold. Exploration expenses were $6.6 million higher in the 2017 period primarily related to higher undeveloped lease amortization expense compared to the same period of 2016. Income taxes increased by $87.7 million in the 2017 period due to improvements in net income.joint venture.

2126

ITEM 2. ~~MANAGEMENT'S~~MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

~~Nine months 2017 vs. 2016 (Contd.)~~The following table contains hydrocarbons sold during the three-month periods ended March 31, 2019 and 2018.

~~Canadian E&P operations reported earnings of $102.6 million in the first nine months of 2017 compared~~


		Three Months Ended
		March 31,
Barrels per day unless otherwise noted		2019	2018
Continuing operations
Net crude oil and condensate
United States	Onshore	25,880	31,553
	Gulf of Mexico 1	63,289	12,615
Canada	Onshore	6,457	4,358
	Offshore	7,932	9,188
Other		467	–
Total net crude oil and condensate - continuing operations		104,025	57,714
Net natural gas liquids
United States	Onshore	5,301	6,745
	Gulf of Mexico 1	2,760	808
Canada	Onshore	1,093	884
Total net natural gas liquids - continuing operations		9,154	8,437
Net natural gas sold – thousands of cubic feet per day
United States	Onshore	29,279	31,233
	Gulf of Mexico 1	19,575	12,670
Canada	Onshore	254,904	261,305
Total net natural gas - continuing operations		303,758	305,208
Total net hydrocarbons - continuing operations including NCI 2,3		163,805	117,019
Noncontrolling interest
Net crude oil and condensate – barrels per day		(12,633)	–
Net natural gas liquids – barrels per day		(554)	–
Net natural gas – thousands of cubic feet per day 2		(3,895)	–
Total noncontrolling interest		(13,836)	–
Total net hydrocarbons - continuing operations excluding NCI 2,3		149,969	117,019

Discontinued operations
Net crude oil and condensate – barrels per day		26,260	29,954
Net natural gas liquids – barrels per day		663	966
Net natural gas – thousands of cubic feet per day 2		101,592	115,276
Total discontinued operations		43,855	50,133
Total net hydrocarbons sold excluding NCI 2,3		193,824	167,152

12019 includes net volumes attributable to a ~~loss~~noncontrolling interest in MP GOM, a Gulf of ~~$36.9 million~~Mexico joint venture.

2Natural gas converted on an energy equivalent basis of 6:1

3NCI – noncontrolling interest in ~~the 2016 period. Results for conventional operations improved by $187.2 million in 2017 due to~~MP GOM, a ~~gain~~Gulf of $132.4 million on the sale of Seal heavy oil assets in 2017, lower impairment expense of $95.1 million in 2017 and higher average realized sales prices for crude oil and natural gas, partially offset by lower oil volume sold (from the sale of Seal and Syncrude assets in quarter 1 2017 and quarter 2 2016, respectively), higher lease operating expense for conventional operations and non-recurring income tax benefits recognized on the sale of certain Montney midstream assets in 2016.Mexico joint venture.

Malaysia E&P operations reported earnings of $173.9 million in the first nine months of 2017 compared to earnings of $135.1 million during the same period in 2016. Results improved $38.8 million in 2017 in Malaysia primarily due to higher revenue of $53.0 million driven by higher commodity prices received and higher natural gas volume sold in Sarawak, partially offset by lower oil volume sold (from Block K due to normal field decline). Depreciation expense was $10.1 million lower in 2017 compared to the same period in 2016 primarily due to lower unit rates in Sarawak and lower oil volume sold, partly offset by higher natural gas volume sold in Sarawak and higher unit rates at Block K.

Other international E&P operations reported a loss of $10.9 million in the first nine months of 2017 compared to a loss of $39.2 million in the 2016 period. The 2017 period included lower dry hole costs of $10.4 million, with the higher 2016 costs primarily associated with unsuccessful drilling in Block 11-2/11 in Vietnam. The 2017 period also included income tax benefits on investments in foreign areas of $32.9 million. Other exploration expenses were $5.9 million higher in the current year, mostly attributable to costs in Mexico, Australia and Brazil. Other expenses were $8.8 million higher in the 2017 period primarily related to no repeat of a credit from an adjustment of previously recorded exit costs in 2016 in the Republic of Congo.

Total worldwide production averaged 161,917 barrels of oil equivalent per day during the nine months ended September 30, 2017, a 9% decrease from 178,319 barrels of oil equivalent produced in the same period in 2016. When Seal and Syncrude are excluded, the Company’s worldwide production decreased by 4%. Crude oil and condensate production in the first nine months of 2017 averaged 89,580 barrels per day compared to 106,279 barrels per day in 2016. Crude oil production decreased at Eagle Ford Shale in 2017 due to production decline associated with significantly less drilling in response to lower prices and phasing of capital expenditures into late 2017. Heavy oil production declined in 2017 in the Seal area of Western Canada primarily due to divestment of the asset in January 2017. Synthetic oil production in Canada also was nil in 2017 due to the Company’s divestiture of Syncrude Canada Ltd. in the second quarter of 2016. Lower oil production in 2017 in Block K Malaysia was primarily attributable to lower working interest in Kakap field subsequent to the redetermination of working interest. For the first nine months of 2017, the Company’s sales price for crude oil and condensate averaged $49.41 per barrel, up from $40.67 per barrel in 2016.

Total production of NGLs was 9,140 barrels per day in the 2017 period compared to 9,275 barrels per day in 2016. The sales price for U.S. NGLs averaged $16.33 per barrel in 2017 compared to $10.31 per barrel in 2016.

Natural gas sales volumes increased from 377 million cubic feet per day in 2016 to 379 million cubic feet per day in 2017. Natural gas sales volume increased, primarily due to less unplanned downtime in 2017 in Sarawak. North American natural gas volumes were flat as improvement in Canada due to the 2017 volumes from Kaybob Duvernay and Placid Montney fields were offset in part by lower U.S. volume due to natural field decline. The average sales price for North American natural gas in the first nine months of 2017 was $2.08 per MCF, up from $1.58 per MCF realized in 2016. Natural gas production at fields offshore Sarawak was sold at an average realized price of $3.50 per MCF in 2017 compared to $3.25 per MCF in 2016.

~~Additional details about results of oil and gas operations are presented in the tables on pages~~ 29 ~~and~~ 30.

2227

ITEM 2. ~~MANAGEMENT'S~~MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

~~Selected operating statistics~~The following table contains the weighted average sales prices including transportation cost deduction for the three-month ~~and nine-month~~ periods ended ~~September 30, 2017~~March 31, 2019 and ~~2016 follow.~~

2018.

Three Months Ended

Nine Months Ended

September 30,

September 30,

2017

2016

2017

2016
Net crude oil and condensate produced – barrels per day

84,230

96,476

89,580

106,279
United States – Eagle Ford Shale

33,070

33,307

33,281

36,790
                             – Gulf of Mexico and other

10,240

11,722

11,309

12,791
Canada – onshore

3,240

1,288

2,729

791
                    – offshore

6,225

9,400

8,100

8,483
                    – heavy1

–

2,678

201

2,732
                    – synthetic1

–

–

–

6,194
Malaysia – Sarawak

11,508

12,889

12,727

13,288
                        – Block K

19,947

25,192

21,233

25,210

Net crude oil and condensate sold – barrels per day

92,033

97,542

89,597

104,525
United States – Eagle Ford Shale

33,070

33,307

33,281

36,790
                             – Gulf of Mexico and other

10,240

11,722

11,309

12,791
Canada – onshore

3,240

1,288

2,729

791
                    – offshore

6,533

9,027

7,812

8,576
                    – heavy1

–

2,678

201

2,732
                    – synthetic1

–

–

–

6,194
Malaysia – Sarawak

13,083

12,641

13,350

12,024
                        – Block K

25,867

26,879

20,915

24,627

Net natural gas liquids produced – barrels per day

9,128

9,703

9,140

9,275
United States – Eagle Ford Shale

6,669

6,940

6,812

6,972
                             – Gulf of Mexico and other

910

1,502

967

1,399
Canada

510

307

410

162
Malaysia – Sarawak

1,039

954

951

742

Net natural gas liquids sold – barrels per day

9,213

8,770

9,165

9,289
United States – Eagle Ford Shale

6,669

6,940

6,812

6,972
                             – Gulf of Mexico

910

1,502

967

1,399
Canada

510

307

410

162
Malaysia – Sarawak

1,124

21

976

756

Net natural gas sold – thousands of cubic feet per day

362,901

381,988

379,182

376,592
United States – Eagle Ford Shale

29,476

34,900

32,862

36,430
                             – Gulf of Mexico and other

11,232

16,873

11,654

19,012
Canada

223,032

204,816

220,121

206,458
Malaysia – Sarawak

90,181

115,535

106,481

103,327
                        – Block K

8,980

9,864

8,064

11,365

Total net hydrocarbons produced – equivalent barrels per day2

153,842

169,844

161,917

178,319
Total net hydrocarbons sold – equivalent barrels per day2

161,730

169,977

161,959

176,579



		Three Months Ended
		March 31,
			2019	2018

Weighted average Exploration and Production sales prices
Continuing operations
Crude oil and condensate – dollars per barrel
United States	Onshore	$	57.36	64.28
	Gulf of Mexico 1		55.48	63.00
Canada 2	Onshore		47.06	54.29
	Offshore		61.42	65.69
Other			67.90	–
Natural gas liquids – dollars per barrel
United States	Onshore	$	12.89	19.93
	Gulf of Mexico 1		16.81	22.57
Canada 2	Onshore		35.16	43.58
Natural gas – dollars per thousand cubic feet
United States	Onshore	$	2.22	2.40
	Gulf of Mexico 1		1.42	2.58
Canada 2	Onshore		1.95	1.68
Discontinued operations
Crude oil and condensate – dollars per barrel				–
Malaysia 3	Sarawak		62.70	64.48
	Block K		65.40	63.18
Natural gas liquids – dollars per barrel
Malaysia 3	Sarawak		52.44	71.21
Natural gas – dollars per thousand cubic feet
Malaysia 3	Sarawak		4.54	3.37
	Block K		0.24	0.22

1~~The Company sold the Seal area heavy oil field in January 2017 and its 5% non-operated~~Prices include noncontrolling interest ~~in Syncrude Canada Ltd. in June 2016.~~for MP GOM, a U.S. Gulf of Mexico joint venture.

2~~Natural gas converted on an energy equivalent basis of 6:1~~

~~ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)~~

~~Results of Operations~~ ~~(Contd.)~~

~~Exploration and Production~~ ~~(Contd.)~~

Three Months Ended

Nine Months Ended

September 30,

September 30,

2017

2016

2017

2016
Weighted average sales prices

Crude oil and condensate – dollars per barrel

United States – Eagle Ford Shale
$
48.49

44.59

48.42

40.65
                      – Gulf of Mexico

47.82

43.93

47.48

40.53
          Canada1    – onshore

43.15

36.36

43.64

41.04
                           – offshore

51.26

45.87

50.35

40.15
                           – heavy2

–

19.50

25.12

14.20
                           – synthetic2

–

–

–

35.59
Malaysia – Sarawak3

52.62

47.05

52.07

43.62
  – Block K3

51.36

46.24

50.95

43.70

    Natural gas liquids – dollars per barrel

United States – Eagle Ford Shale
$
17.89

10.89

16.12

10.06
                       – Gulf of Mexico

19.00

13.65

17.84

11.60
Canada1

22.77

39.23

22.48

41.04
Malaysia – Sarawak3

49.66

45.12

49.94

37.50

    Natural gas – dollars per thousand cubic feet

United States – Eagle Ford Shale
$
2.44

2.24

2.53

1.69
                       – Gulf of Mexico

2.49

2.35

2.56

1.81
Canada1

1.84

1.88

1.99

1.58
Malaysia – Sarawak3

3.60

3.01

3.50

3.25
  – Block K

0.25

0.23

0.24

0.24

1U.S. dollar equivalent.

2~~The Company sold the Seal area heavy oil field in January 2017 and its 5% non-operated interest in Syncrude Canada Ltd. in June 2016.~~

3Prices are net of payments under the terms of the respective production sharing contracts.

2428

ITEM 2. ~~MANAGEMENT'S~~MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED ~~SEPTEMBER 30, 2017~~MARCH 31, 2019 AND ~~2016~~2018




	United						United
(Millions of dollars)	States		Canada	Malaysia	Other	Total	States 1		Canada	Other	Total
Three Months Ended September 30, 2017
Three Months Ended March 31, 2019
Oil and gas sales and other operating revenues	$	195.9	81.9	220.5	–	498.3	$	469.2	118.9	2.9	591.0
Lease operating expenses		43.5	28.7	40.6	–	112.8		92.4	39.0	0.3	131.7
Severance and ad valorem taxes		10.5	0.3	–	–	10.8		9.8	0.3	–	10.1
Depreciation, depletion and amortization		128.4	45.9	63.7	1.0	239.0		163.9	59.5	1.0	224.4
Accretion of asset retirement obligations		4.3	2.0	4.4	–	10.7		7.8	1.5	–	9.3
Exploration expenses
Dry holes		(0.6)	–	(2.5)	–	(3.1)
Dry holes and previously suspended exploration costs								0.1	–	13.1	13.2
Geological and geophysical		0.1	–	–	1.5	1.6		0.5	–	5.5	6.0
Other		1.5	0.2	–	7.7	9.4
Other exploration								1.2	0.1	4.0	5.3
		1.0	0.2	(2.5)	9.2	7.9		1.8	0.1	22.6	24.5
Undeveloped lease amortization		20.4	0.2	–	–	20.6		6.9	0.3	0.8	8.0
Total exploration expenses		21.4	0.4	(2.5)	9.2	28.5		8.7	0.4	23.4	32.5
Selling and general expenses		16.6	6.9	4.8	5.1	33.4		17.3	7.6	5.6	30.5
Other expenses		0.8	0.5	1.2	–	2.5
Other								30.6	0.2	0.3	31.1
Results of operations before taxes		(29.6)	(2.8)	108.3	(15.3)	60.6		138.7	10.4	(27.7)	121.4
Income tax provisions (benefits)		(9.7)	0.4	40.6	(4.3)	27.0		22.5	2.9	0.6	26.0
Results of operations (excluding corporate overhead and interest)	$	(19.9)	(3.2)	67.7	(11.0)	33.6	$	116.2	7.5	(28.3)	95.4


Three Months Ended September 30, 2016
Three Months Ended March 31, 2018
Oil and gas sales and other operating revenues	$	201.8	80.9	202.7	0.2	485.6	$	278.1	118.3	–	396.4
Lease operating expenses		59.6	30.7	29.4	–	119.7		58.5	30.4	–	88.9
Severance and ad valorem taxes		8.5	1.1	–	–	9.6		11.8	0.4	–	12.2
Depreciation, depletion and amortization		141.1	46.5	62.0	1.5	251.1		121.6	55.7	0.8	178.1
Accretion of asset retirement obligations		4.2	2.8	4.0	–	11.0		4.4	2.0	–	6.4
Exploration expenses
Dry holes		0.8	–	0.4	(0.2)	1.0
Geological and geophysical		(0.1)	–	0.1	0.5	0.5		5.9	–	2.9	8.8
Other		2.5	–	–	5.5	8.0
Other exploration								1.2	0.1	5.4	6.7
		3.2	–	0.5	5.8	9.5		7.1	0.1	8.3	15.5
Undeveloped lease amortization		9.3	1.1	–	–	10.4		12.7	0.2	0.3	13.2
Total exploration expenses		12.5	1.1	0.5	5.8	19.9		19.8	0.3	8.6	28.7
Selling and general expenses		14.7	5.2	0.2	7.4	27.5		14.4	7.7	5.9	28.0
Other expenses		1.0	–	5.4	0.1	6.5
Other								0.8	(11.7)	(0.1)	(11.0)
Results of operations before taxes		(39.8)	(6.5)	101.2	(14.6)	40.3		46.8	33.5	(15.2)	65.1
Income tax provisions (benefits)		(12.7)	(1.7)	36.2	(6.5)	15.3		10.6	9.1	0.2	19.9
Results of operations (excluding corporate overhead and interest)	$	(27.1)	(4.8)	65.0	(8.1)	25.0	$	36.2	24.4	(15.4)	45.2

1 2019 includes results attributable to a noncontrolling interest in MP GOM, a Gulf of Mexico joint venture.

2529

ITEM 2. ~~MANAGEMENT'S~~MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

~~Results of Operations (Contd~~.)

~~Exploration and Production~~ ~~(Contd.)~~

OI~~L AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2017 AND 2016~~

Canada

United

Conven-

(Millions of dollars)

States

tional

Synthetic*

Malaysia

Other

Total
Nine Months Ended September 30, 2017

Oil and gas sales and other operating revenues

$
696.7

388.1

–

594.4

–

1,679.2
Lease operating expenses

135.7

76.8

–

133.6

–

346.1
Severance and ad valorem taxes

31.6

1.2

–

–

–

32.8
Depreciation, depletion and amortization

402.3

136.6

–

160.0

2.9

701.8
Accretion of asset retirement obligations

12.8

5.9

–

12.9

–

31.6
Exploration expenses

Dry holes

(1.9)

–

–

0.8

–

(1.1)
Geological and geophysical

1.0

0.1

–

–

6.0

7.1
Other

5.5

0.3

–

–

24.8

30.6

4.6

0.4

–

0.8

30.8

36.6
Undeveloped lease amortization

39.4

1.4

–

–

–

40.8
Total exploration expenses

44.0

1.8

–

0.8

30.8

77.4
Selling and general expenses

48.7

21.2

–

10.5

15.0

95.4
Other expenses

1.5

0.4

–

9.1

–

11.0
Results of operations before taxes

20.1

144.2

–

267.5

(48.7)

383.1
Income tax provisions (benefits)

9.1

41.6

–

93.6

(37.8)

106.5
Results of operations (excluding corporate
overhead and interest)

$
11.0

102.6

–

173.9

(10.9)

276.6

Nine Months Ended September 30, 2016

Oil and gas sales and other operating revenues

$
520.2

200.2

64.2

541.4

0.2

1,326.2
Lease operating expenses

169.6

73.3

69.9

122.5

–

435.3
Severance and ad valorem taxes

30.0

3.2

2.5

–

–

35.7
Depreciation, depletion and amortization

456.5

137.5

16.5

170.0

4.6

785.1
Accretion of asset retirement obligations

12.8

8.2

2.4

12.1

–

35.5
Impairment of assets

–

95.1

–

–

–

95.1
Exploration expenses

Dry holes

0.4

–

–

4.5

10.4

15.3
Geological and geophysical

0.6

2.9

–

0.6

4.8

8.9
Other

4.5

0.5

–

–

18.9

23.9

5.5

3.4

–

5.1

34.1

48.1
Undeveloped lease amortization

31.9

3.4

–

–

0.5

35.8
Total exploration expenses

37.4

6.8

–

5.1

34.6

83.9
Selling and general expenses

49.9

20.9

0.5

8.6

26.6

106.5
Other expenses (benefits)

1.1

–

–

6.3

(8.8)

(1.4)
Results of operations before taxes

(237.1)

(144.8)

(27.6)

216.8

(56.8)

(249.5)
Income tax provisions (benefits)

(78.6)

(60.2)

(75.3)

81.7

(17.6)

(150.0)
Results of operations (excluding corporate
overhead and interest)

$
(158.5)

(84.6)

47.7

135.1

(39.2)

(99.5)

*~~The Company sold its 5% non-operated interest in Syncrude Canada Ltd. on June 23, 2016.~~

~~ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)~~

Results of Operations (~~Contd~~.(Contd.)

Corporate

First quarter 2019 vs. 2018

Corporate activities, which include interest income and expense, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to operating functions, had net cost of $99.9 million in the 2017 third quarter compared to $39.6 million in the same 2016 quarter. The $60.3 million increased cost in the 2017 period is primarily due to after-tax foreign currency exchange losses of $43.9 million in the 2017 period versus gains in the 2016 period, higher net interest expense of $9.5 million in 2017 and deferred tax charges on undistributed earnings of certain foreign subsidiaries of $4.7 million in 2017, partially offset by lower administrative costs in the current quarter. Net interest costs increased in the 2017 period primarily due to accelerated interest payment upon the early repayment of the December 2017 notes, additional interest on $550 million notes issued in August 2017 (2025 maturity) and an increase of 1.00% on the coupon rates on $950 million of the Company’s outstanding notes effective September 1, 2016 following a downgrade by Moody’s Investor Services in February 2016. Selling and general expenses decreased $4.7 million in the third quarter of 2017 primarily related to restructuring activity that occurred in 2016 and continual monitoring of the cost structure.

~~During the first nine months of 2017, Corporate activities had~~reported a net ~~cost~~loss of $302.8 million compared to $111.7 million for the same period of 2016. The $191.1 million increased cost in the 2017 period compared to the 2016 period was primarily due to after-tax losses from foreign currency exchange of $86.6 million in the 2017 period versus gains in the 2016 period, deferred tax charges in 2017 on undistributed earnings of certain foreign subsidiaries of $65.2 million and higher net interest expense of $34.5 million in 2017 due to additional interest on the $550 million notes issued in August 2017 and an increase of 1.00% on the coupon rates on $950 million of the Company’s notes. These were partially offset by lower administrative costs in 2017. During the first nine months of 2017, the Company’s determined that prospective earnings from its Malaysian and Canadian subsidiaries will not be considered reinvested into local operations. Due to this change in assertion, the Company recorded a deferred tax charge of $65.2$72.4 million in the first ~~nine month~~quarter 2019 compared to net income of ~~2017 associated with~~$45.9 million in the ~~estimated~~2018 quarter. The $118.3 million unfavorable variance is due to a 2018 income tax ~~consequence~~credit ($120.0 million, related to an IRS interpretation of the ~~future repatriation~~Tax Act), higher general and administrative expenses ($12.3 million, due to the fair value revaluation of these subsidiaries’ nine-month 2017 earnings. This decision provides greater financial flexibility as it considers future domestic investment opportunities. The Company expects to incur further tax chargeslong-term cash-based compensation), foreign exchange losses ($3.8 million vs gains in ~~the fourth quarter 2017 for additional 2017 foreign earnings as they arise.~~

2018 of $6.9 million), 2018 OIL insurance dividend income ($7.9 million); partially off-set by 2018 losses on forward swap commodity contracts ($29.5 million).

Discontinued Operations

The Company has presented its Malaysia E&P operations and former U.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements. The after-tax results of these operations for the three-month ~~and nine-month~~ periods ended ~~September 30, 2017~~March 31, 2019 and ~~2016~~2018 are reflected in the following table.

Three Months Ended

Nine Months Ended

September 30,

September 30,
(Millions of dollars)

2017

2016

2017

2016
U.S. refining and marketing

$
(0.7)

–

(0.7)

–
U.K. refining and marketing

1.1

(1.0)

1.9

(1.1)
U.K. exploration and production

–

(0.6)

–

0.3
Income (loss) from discontinued operations

$
0.4

(1.6)

1.2

(0.8)


		Three Months Ended
		March 31,
(Millions of dollars)		2019	2018
Malaysia exploration and production	$	57.2	78.1
U.S. refining		(1.2)	(0.6)
U.K. refining and marketing		(6.2)	0.2
Income from discontinued operations	$	49.8	77.7

Malaysia E&P operations reported earnings of $57.2 million in the first quarter of 2019 and compared to earnings of $78.1 million in the comparable 2018 period. Results were unfavorable by $13.8 million due to lower revenues ($15.4 million), higher lease operating expenses ($15.1 million), partially off-set by lower depreciation ($16.4 million). Lower revenues are principally due to timing of volumes sold. Higher lease operating expenses are due to additional sub-sea maintenance at the Sarawak Asset. The lower depreciation is due to lower volumes sold.

Financial Condition

Net cash provided by continuing operating activities was ~~$819.6~~$217.2 million for the first ~~nine~~three months of ~~2017~~2019 compared to ~~$280.3~~$110.9 million during the same period in ~~2016.~~2018. The ~~improvement in~~higher cash ~~provided by continuing operations~~from operating activities ~~in 2017 was~~is primarily attributable to higher ~~realized sales prices for~~cash higher cash revenues from the Company’s oil and gas production, lower lease operating and administrative expenses, and rig cancellation payments in 2016 which are discussed below, partially offset by lower volume sold in the current year and higher interest costs.MP GOM acquisition. Changes in operating working capital from continuing operations ~~increased~~decreased cash by ~~$1.1~~$98.5 million during the first ~~nine~~three months of ~~2017,~~2019, compared to ~~a use of cash of $152.6~~$3.5 million in 2016. The use of cash in 2016 included $266.6 million associated with pay-off of cancelled deepwater rig contracts that were previously charged to expense in 2015. Proceeds from sales of property and equipment generated cash of $69.1 million in 20172018, primarily relating to proceeds from the sale of the Seal field in Western Canada and the sale of certain areas of Eagle Ford Shale in South Texas, while the 2016 period generated cash of $1,154.6 million mainly relatedattributable to the ~~sale~~timing of ~~Syncrude Canada Limited and certain midstream assets in the Tupper area of Western Canada. Other significant sources of cash included $320.8 million in the 2017 period and $712.9 million in 2016~~receipts on sales from ~~maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition.~~MP GOM.

~~ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)~~

~~Financial Condition~~ ~~(Contd.)~~

Cash used for property additions and dry holes, which includes amounts expensed, were ~~$706.4~~$270.3 million and ~~$781.7~~$247.1 million in the ~~nine-month period~~three-month periods ended ~~September 30, 2017~~March 31, 2019 and ~~2016,~~2018, respectively. Total cash dividends to shareholders amounted to ~~$129.4~~$43.4 million for the ~~nine-months~~three months ended ~~September 30, 2017~~March 31, 2019 compared to ~~$163.6~~$43.3 million in the same period of ~~2016 as the~~ ~~Company lowered the dividend from $1.40 per share to $1.00 per share effective in the third quarter 2016. The purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $212.7 million in the 2017 period and $651.2 million in the 2016 period.~~ The proceeds of the $550 million notes issued in August 2017, were used to redeem the Company’s $550 million 2.50% notes in September 2017. The 2.50% notes had a maturity date of December 2017 and were retired early. ~~The Company repaid debt in the amount of $600.0 million in the nine-month period of 2016 using proceeds from the sale of assets.~~

2018.

Total accrual basis capital expenditures were as follows:


	Nine Months Ended				Three Months Ended
	September 30,				March 31,
(Millions of dollars)	2017		2016		2019		2018
Capital Expenditures
Exploration and production	$	694.7		614.6	$	342.5		276.2
Corporate		6.9		20.7		4.1		5.1
Total capital expenditures	$	701.6		635.3	$	346.6		281.3

The increase in capital expenditures in the exploration and production business in 2017 compared to 2016 was primarily attributable to higher developmental drilling activities in Eagle Ford Shale and Kaybob Duvernay and Placid Montney assets, partially offset by 2016 acquisition costs in the Kaybob Duvernay and liquids rich Placid Montney properties in Canada and lower spending in Malaysia.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Financial Condition (Contd.)

A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.



	Nine Months Ended				Three Months Ended
	September 30,				March 31,
(Millions of dollars)	2017		2016		2019		2018
Property additions and dry hole costs per cash flow statements	$	706.4		781.7	$	270.4		247.1
Geophysical and other exploration expenses		37.7		32.8		11.3		15.5
Capital expenditure accrual changes and other		(42.5)		(179.2)		64.9		18.7
Total capital expenditures	$	701.6		635.3	$	346.6		281.3

The increase in capital expenditures in the exploration and production business in 2019 compared to 2018 was primarily attributable to higher development drilling activities in Eagle Ford Shale.

Working capital (total current assets less total current ~~liabilities)~~liabilities – excluding assets and liabilities held for sale) at ~~September 30, 2017~~March 31, 2019 was ~~$615.6~~($59.9 million), $206.2 million ~~$558.8 million more~~lower than December 31, ~~2016,~~2018, with the ~~increase~~decrease primarily attributable to ~~the Company redeeming the $550 million in 2.50% notes in September 2017,~~lower cash and higher ~~cash~~accounts payable and operating lease liability balances ~~and lower~~offset by higher accounts ~~payable.~~

receivable.

At ~~September 30, 2017,~~March 31, 2019, long-term debt of ~~$2,908.3~~$3,110.1 million had increased by ~~$485.5~~$0.8 million compared to December 31, ~~2016.~~2018. A summary of capital employed at ~~September 30, 2017~~March 31, 2019 and December 31, ~~2016~~2018 follows.



	September 30, 2017				December 31, 2016				March 31, 2019				December 31, 2018
(Millions of dollars)	Amount		%		Amount		%		Amount		%		Amount		%
Capital employed
Long-term debt	$	2,908.3	36.9	%	$	2,422.8	33.0	%	$	3,110.1	36.9	%	$	3,109.3	37.4	%
Stockholders' equity		4,980.1	63.1	%		4,916.7	67.0	%
Total equity										5,326.7	63.1	%		5,197.6	62.6	%
Total capital employed	$	7,888.4	100.0	%	$	7,339.5	100.0	%		8,436.8	100.0	%		8,307.0	100.0	%
Total capital employed excluding noncontrolling interest									$	8,058.9	n/a		$	7,938.7	n/a

Cash and invested cash are maintained in several operating locations outside the United States. At ~~September 30, 2017,~~March 31, 2019, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately ~~$495.5~~$87.1 million in Canada and ~~$261.6~~$12.3 million in ~~Malaysia.~~Mexico. In addition, ~~$17.0~~$16.9 million of cash was held in the United Kingdom and $76.1 million was held in Malaysia but was reflected in current Assets ~~Held~~held for ~~Sale~~sale on the Company’s Consolidated Balance Sheet at ~~September 30, 2017.~~March 31, 2019. In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. This could occur due to withholding taxes and/or potential additional U.S. tax burden when less than the U.S. Federal tax rate of 35% has been paid for cash taxes in foreign locations. A lower cash tax rate is often paid in foreign countries in the early years of operations when accelerated tax deductions are permitted to incentivize oil and gas investments; cash tax rates are generally higher in later years after accelerated tax deductions in early years are exhausted. Canada currently collects a 5% withholding tax on

~~Financial Condition~~ ~~(Contd.)~~

any ~~cash~~earnings repatriated to the ~~United States through a dividend to the~~ U.S. ~~parent. See the “Corporate” section on page~~

Accounting changes and recent accounting pronouncements – see Note B

31 ~~of this Form 10-Q report regarding the Company’s change in assertion for indefinite reinvestment on prospective earnings from its Malaysian and Canadian subsidiaries.~~

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

~~Accounting and Other Matters~~

~~Business Combinations~~

~~Compensation – Stock Compensation~~

In May 2017, FASB issued an ASU 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. Early adoption is permitted. The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.

~~Compensation – Retirement Benefits~~

In March 2017, the FASB issued an ASU 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 and 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 periods beginning after December 15, 2017 and interim periods within the annual period. Application is retrospective for the presentation of the components of these benefit costs and prospective for the capitalization of only service costs. Early adoption is permitted. The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.

~~Revenue from Contracts with Customers~~

In May 2014, the FASB issued an ASU to establish a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition requirements and industry-specific guidance. The codification was amended through additional ASU’s and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainly of revenue and cash flows from contracts with customers. The Company is required to adopt the new standard in the first quarter of 2018 using either the modified retrospective or cumulative effect transition method. The Company has performed a review of contracts in each of its revenue streams and is developing accounting policies and applicable disclosures to address the provisions of the ASU. While the Company does not currently expect net earnings to be materially impacted, the Company is analyzing whether total revenues and expenses will be significantly impacted. The Company continues to evaluate the impact of this and other provisions of these ASU’s on its accounting policies, internal controls, and consolidated financial statements and related disclosures, and has not finalized any estimates of the potential impacts. The Company will adopt the new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings as necessary.

~~Accounting and Other Matters~~ ~~(Contd.)~~

~~Leases~~

In February 2016, FASB issued an ASU to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous Generally Accepted Accounting Principles (GAAP) and this ASU is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. The 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 anticipates adopting this guidance in the first quarter of 2019 and is currently analyzing its portfolio of contracts to assess the impact future adoption of this ASU may have on its consolidated financial statements.

~~Statement of Cash Flows~~

In August 2016, the FASB issued an ASU 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 ASU is effective for annual and interim periods beginning after December 15, 2017. The Company is currently assessing the potential impact of this ASU on its consolidated financial statements.

Outlook

Average worldwide crude oil prices ~~in October 2017~~at the end of April 2019 have ~~slightly improved~~increased from the average prices during the ~~third~~first quarter of ~~2017.~~2019. North American natural gas prices have decreased ~~slightly~~ in ~~October from~~April compared to the ~~2017 third quarter.~~first quarter of 2019. The Company expects its total oil and natural gas production to average ~~170,000~~155,000 – ~~172,000~~159,000 barrels of oil equivalent per day in the ~~fourth~~second quarter ~~2017.~~2019 (including noncontrolling interest of 12,000 BOEPD). The Company currently anticipates total capital expenditures for the full year ~~2017~~2019 to be ~~approximately $940 million.~~between $1.15 and $1.35 billion (excluding noncontrolling interest of $48 million).

The Company will primarily fund its remaining capital program in ~~2017~~2019 using operating cash flow and available cash but will supplement funding where necessary ~~using~~ borrowings under available credit facilities. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or additional borrowings might be required during the remainder of year to maintain funding of the Company’s ongoing development projects.

As of ~~November 1, 2017,~~April 30, 2019, the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:


	~~Contract or~~		Average
Commodities	Contract or Location	Dates	Volumes per Day		Average Prices
U.S. Oil	West Texas Intermediate	~~Oct.~~May – Dec. ~~2017~~2019		~~22,000~~20,000 bbls/d	$~~50.41~~63.64 per bbl.
U.S. Oil	West Texas Intermediate	Jan. – Dec. ~~2018~~2020		~~7,000~~20,000 bbls/d	$~~51.92~~60.10 per bbl.

Canada Natural Gas	~~TCPL–~~NOVA ~~System~~Gas Transmission Ltd.	~~Jul.~~Apr. 2019 – Dec. ~~2017~~		~~124 mmcf/d~~	~~C$2.97 per mcf~~
~~Natural Gas~~	~~TCPL–NOVA System~~	~~Jan. – Dec. 2018~~2020		59 mmcf/d	C$2.81 per mcf
~~Natural Gas~~	~~Alberta Alliance~~	~~Nov. 2017 – Mar. 2018~~		~~20 mmcf/d~~	~~US$3.51 per mcf~~	*

*~~Title transfer at Alberta Alliance pipeline. Sale price fixed and transported to Chicago Gate~~.

~~ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)~~

Forward-Looking Statements

This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements include, but are not limited to: our ability to complete the acquisition of the Gulf of Mexico assets or the Malaysia divestiture due to the failure to obtain regulatory approvals, the failure of the respective counterparties to perform their obligations under the relevant transaction agreements or the failure to satisfy all closing conditions, the volatility and level of crude oil and natural gas prices, the level and success rate of Murphy’s exploration programs, the Company’s ability to maintain production rates and replace reserves, customer demand for Murphy’s products, adverse foreign exchange movements, political and regulatory instability, adverse developments in the U.S. or global capital markets, credit markets or economies generally and uncontrollable natural hazards. For further discussion of risk factors, see Murphy’s ~~2016~~2018 Annual Report on Form 10-K on file with the U.S. Securities and

Exchange Commission and page 36 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note JL to this Form 10-Q report, Murphy makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.

There were no commodity transactions in place at ~~September 30, 2017~~March 31, 2019, covering certain future U.S. crude oil sales volumes in 2017. A 10% increase in the respective benchmark price of these commodities would have decreased the recorded net receivable associated with these derivative contracts by approximately $21.9 million, while a 10% decrease would have increased the recorded net receivable by a similar amount.

2019. There were no derivative foreign exchange contracts in place at ~~September 30, 2017.~~March 31, 2019.

ITEM 4. CONTROLS AND PROCEDURES

Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

During the quarter ended ~~September 30, 2017,~~March 31, 2019, there were no ~~other~~ changes in the Company's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Murphy is engaged in a number of 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.

ITEM 1A. RISK FACTORS

The Company’s operations in the oil and gas business naturally lead to various risks and uncertainties. These risk factors are discussed in Item 1A Risk Factors in its ~~2016~~2018 Form 10-K filed on February ~~24, 2017.~~27, 2019. The Company has not identified any additional risk factors not previously disclosed in its ~~2016~~2018 Form 10-K report.

ITEM 6. EXHIBITS

The Exhibit Index on page 3835 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	MURPHYOILCORPORATION
	(Registrant)

	By	/s/ CHRISTOPHER D. HULSE
		Christopher D. Hulse,
		Vice President and Controller
		(Chief Accounting Officer and Duly Authorized Officer)

~~November 1, 2017~~May 2, 2019

(Date)

EXHIBIT INDEX



Exhibit
No.

10.1		Amendment to Severance Protection Agreement dated as of August 7, 2013, between Murphy Oil Corporation and Roger W. Jenkins

10.2		Form of Severance Protection Agreement

10.3*		Share Sale and Purchase Agreement between Canam Offshore Limited and PTTEP HK Offshore Limited for the sale and purchase of the entire issued share capital of Murphy Sarawak Oil Co., Ltd. and Murphy Sabah Oil Co., Ltd., dated 21 March 2019

31.1		Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32		Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101. INS		XBRL Instance Document

101. SCH		XBRL Taxonomy Extension Schema Document

101. CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101. DEF		XBRL Taxonomy Extension Definition Linkbase Document

101. LAB		XBRL Taxonomy Extension Labels Linkbase Document

101. PRE		XBRL Taxonomy Extension Presentation Linkbase

*Certain information has been excluded from this exhibit because it is both (i.) not material and (ii) would be competitively harmful if publicly disclosed.

Exhibits other than those listed above have been omitted since they are either not required or not applicable.

2935


	Three Months			Nine Months
	Ended September 30,			Ended September 30,
(Thousands of dollars)		2017	2016	2017	2016
Revenues (costs)	$	598	5	853	1,454
Income (loss) before income taxes		425	(1,593)	1,177	(885)
Income tax benefit		–	–	–	–
Income (loss) from discontinued operations	$	425	(1,593)	1,177	(885)



	2017	2016
Three months ended September 30	(4.3%)	13.0%
Nine months ended September 30	137.7%	48.9%


	Nine-months ended September 30, 2016
						Total
					Net Book	Pretax
					Value	(Noncash)
	Fair Value				Prior to	Impairment
		Level 1	Level 2	Level 3	Impairment	Expense
(Thousands of dollars)
Assets:
Impaired proved properties
Canada	$	–	–	71,967	167,055	95,088




			Canada
	United		Conven-
(Millions of dollars)	States		tional	Synthetic*	Malaysia	Other	Total
Nine Months Ended September 30, 2017
Oil and gas sales and other operating revenues	$	696.7	388.1	–	594.4	–	1,679.2
Lease operating expenses		135.7	76.8	–	133.6	–	346.1
Severance and ad valorem taxes		31.6	1.2	–	–	–	32.8
Depreciation, depletion and amortization		402.3	136.6	–	160.0	2.9	701.8
Accretion of asset retirement obligations		12.8	5.9	–	12.9	–	31.6
Exploration expenses
Dry holes		(1.9)	–	–	0.8	–	(1.1)
Geological and geophysical		1.0	0.1	–	–	6.0	7.1
Other		5.5	0.3	–	–	24.8	30.6
		4.6	0.4	–	0.8	30.8	36.6
Undeveloped lease amortization		39.4	1.4	–	–	–	40.8
Total exploration expenses		44.0	1.8	–	0.8	30.8	77.4
Selling and general expenses		48.7	21.2	–	10.5	15.0	95.4
Other expenses		1.5	0.4	–	9.1	–	11.0
Results of operations before taxes		20.1	144.2	–	267.5	(48.7)	383.1
Income tax provisions (benefits)		9.1	41.6	–	93.6	(37.8)	106.5
Results of operations (excluding corporate overhead and interest)	$	11.0	102.6	–	173.9	(10.9)	276.6


Nine Months Ended September 30, 2016
Oil and gas sales and other operating revenues	$	520.2	200.2	64.2	541.4	0.2	1,326.2
Lease operating expenses		169.6	73.3	69.9	122.5	–	435.3
Severance and ad valorem taxes		30.0	3.2	2.5	–	–	35.7
Depreciation, depletion and amortization		456.5	137.5	16.5	170.0	4.6	785.1
Accretion of asset retirement obligations		12.8	8.2	2.4	12.1	–	35.5
Impairment of assets		–	95.1	–	–	–	95.1
Exploration expenses
Dry holes		0.4	–	–	4.5	10.4	15.3
Geological and geophysical		0.6	2.9	–	0.6	4.8	8.9
Other		4.5	0.5	–	–	18.9	23.9
		5.5	3.4	–	5.1	34.1	48.1
Undeveloped lease amortization		31.9	3.4	–	–	0.5	35.8
Total exploration expenses		37.4	6.8	–	5.1	34.6	83.9
Selling and general expenses		49.9	20.9	0.5	8.6	26.6	106.5
Other expenses (benefits)		1.1	–	–	6.3	(8.8)	(1.4)
Results of operations before taxes		(237.1)	(144.8)	(27.6)	216.8	(56.8)	(249.5)
Income tax provisions (benefits)		(78.6)	(60.2)	(75.3)	81.7	(17.6)	(150.0)
Results of operations (excluding corporate overhead and interest)	$	(158.5)	(84.6)	47.7	135.1	(39.2)	(99.5)