MURPHY OIL CORP - Quarter Report: 2019 June (Form 10-Q)

Six Months Ended
June 30,

(Thousands of dollars)

Compensation charged against income before tax benefit

Related income tax benefit recognized in income

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



(Mark One)
☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 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		71-0361522
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)
300 Peach Street, P.O. Box 7000		71731-7000
El Dorado,	Arkansas	(Zip Code)
(Address of principal executive offices)
(870)		862-6411
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading Symbol	Name of each exchange on which registered
Common Stock, $1.00 Par Value	MUR	New York Stock Exchange

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. ☒ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). ☒ Yes ☐ No

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



Large accelerated filer	☒	Accelerated filer	☐	Non-accelerated filer	☐	Smaller reporting company	☐	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. o

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

Number of shares of Common Stock, $1.00 par value, outstanding at July 31, 2019 was 162,250,593.

Table of Contents

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	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	26
Item 3. Quantitative and Qualitative Disclosures About Market Risk	37
Item 4. Controls and Procedures	37
Part II – Other Information	38
Item 1. Legal Proceedings	38
Item 1A. Risk Factors	38
Item 6. Exhibits	38
Signature	39

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS (unaudited)

(Thousands of dollars)



	June 30, 2019			December 31, 2018 ¹
ASSETS
Current assets
Cash and cash equivalents	$	326,044		359,923
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2019 and 2018	425,845			231,686
Inventories	86,701			80,024
Prepaid expenses	49,477			34,316
Assets held for sale	1,863,825			173,865
Total current assets	2,751,892			879,814
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of 8,656,715 in 2019 and $8,070,487 in 2018	10,041,184			8,432,133
Operating lease assets	590,938			—
Deferred income taxes	104,368			146,197
Deferred charges and other assets	47,642			49,435
Non-current assets held for sale	—			1,545,008
Total assets	$	13,536,024		11,052,587
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt	$	687		668
Short-term loan payable	500,000			—
Accounts payable	598,466			348,026
Income taxes payable	17,245			15,309
Other taxes payable	20,325			17,649
Operating lease liabilities	128,635			—
Other accrued liabilities	164,782			177,948
Liabilities associated with assets held for sale	772,751			286,458
Total current liabilities	2,202,891			846,058
Long-term debt, including capital lease obligation	4,185,875			3,109,318
Asset retirement obligations	824,053			752,519
Deferred credits and other liabilities	587,826			624,436
Non-current operating lease liabilities	468,168			—
Deferred income taxes	168,667			129,894
Non-current liabilities associated with assets held for sale	—			392,720
Total liabilities	8,437,480			5,854,945
Equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued	—			—
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	933,944			979,642
Retained earnings	5,677,248			5,513,529
Accumulated other comprehensive loss	(549,045		)	(609,787	)
Treasury stock	(1,517,217		)	(1,249,162	)
Murphy Shareholders' Equity	4,740,013			4,829,299
Noncontrolling interest	358,531			368,343
Total equity	5,098,544			5,197,642
Total liabilities and equity	$	13,536,024		11,052,587

¹Reclassified to conform to current presentation (see Note A). See Notes to Consolidated Financial Statements, page 7.

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Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(Thousands of dollars, except per share amounts)



	Three Months Ended June 30,					Six Months Ended June 30,
	2019			2018 ¹		2019		2018 ¹
Revenues
Revenue from sales to customers	$	646,114		426,767		1,236,664		823,096
Gain (loss) on crude contracts	57,916			(37,624	)	57,916		(67,126	)
Gain on sale of assets and other income	5,019			437		5,473		8,400
Total revenues	709,049			389,580		1,300,053		764,370
Costs and expenses
Lease operating expenses	137,132			81,236		268,828		170,069
Severance and ad valorem taxes	13,072			12,876		23,169		25,033
Exploration expenses, including undeveloped lease amortization	30,674			18,889		63,212		47,627
Selling and general expenses	57,532			56,295		120,892		104,391
Depreciation, depletion and amortization	264,302			190,751		493,708		373,494
Accretion of asset retirement obligations	9,897			6,396		19,237		12,768
Other expense (benefit)	25,437			658		55,442		(10,387	)
Total costs and expenses	538,046			367,101		1,044,488		722,995
Operating income from continuing operations	171,003			22,479		255,565		41,375
Other income (loss)
Interest and other income (loss)	(8,968		)	(717	)	(13,716	)	3,870
Interest expense, net	(54,096		)	(44,325	)	(100,165	)	(88,866	)
Total other loss	(63,064		)	(45,042	)	(113,881	)	(84,996	)
Income (loss) from continuing operations before income taxes	107,939			(22,563	)	141,684		(43,621	)
Income tax expense (benefit)	9,115			2,622		19,937		(109,017	)
Income (loss) from continuing operations	98,824			(25,185	)	121,747		65,396
Income from discontinued operations, net of income taxes	24,418			70,704		74,264		148,376
Net income including noncontrolling interest	123,242			45,519		196,011		213,772
Less: Net income attributable to noncontrolling interest	30,970			—		63,557		—
NET INCOME ATTRIBUTABLE TO MURPHY	$	92,272		45,519		132,454		213,772
INCOME (LOSS) PER COMMON SHARE – BASIC
Continuing operations	$	0.40		(0.14	)	0.34		0.38
Discontinued operations	0.15			0.41		0.44		0.86
Net Income	$	0.55		0.27		0.78		1.24

INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations	$	0.40		(0.15	)	0.34		0.37
Discontinued operations	0.14			0.40		0.43		0.85
Net Income	$	0.54		0.25		0.77		1.22

Cash dividends per Common share	0.25			0.25		0.50		0.50

Average Common shares outstanding (thousands)
Basic	168,538			173,043		170,556		172,908
Diluted	169,272			173,983		171,433		174,927

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

See Notes to Consolidated Financial Statements, page 7.

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Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

(Thousands of dollars)



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019	2018

Net income	$	92,272	45,519		132,454	213,772
Other comprehensive income (loss), net of tax
Net (loss) gain from foreign currency translation	28,606		(34,910	)	54,055	(87,185	)
Retirement and postretirement benefit plans	2,762		3,938		5,516	7,108
Deferred loss on interest rate hedges reclassified to interest expense	586		586		1,171	1,171
Reclassification of certain tax effects to retained earnings	—		—		—	(30,237	)
Other	—		—		—	(3,737	)
Other comprehensive income (loss)	31,954		(30,386	)	60,742	(112,880	)
COMPREHENSIVE INCOME	$	124,226	15,133		193,196	100,892

See Notes to Consolidated Financial Statements, page 7.

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Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)



	Six Months Ended June 30,
	2019			2018 ¹
Operating Activities
Net income including noncontrolling interest	$	196,011		213,772
Adjustments to reconcile net income to net cash provided by continuing operations activities:
(Income) loss from discontinued operations	(74,264		)	(148,376	)
Depreciation, depletion and amortization	493,708			373,494
Previously suspended exploration costs (credits)	12,901			(8	)
Amortization of undeveloped leases	15,150			22,774
Accretion of asset retirement obligations	19,237			12,768
Deferred income tax charge (benefit)	18,001			(148,653	)
Pretax (gain) loss from sale of assets	(12		)	118
Mark to market and revaluation of contingent consideration	28,890			—
Mark to market of crude contracts	(50,831		)	27,088
Long-term non-cash compensation	44,755			29,010
Net (increase) decrease in noncash operating working capital	(5,366		)	22,498
Other operating activities, net	(42,749		)	(72,804	)
Net cash provided by continuing operations activities	655,431			331,681
Investing Activities
Acquisition of oil and gas properties	(1,226,261		)	—
Property additions and dry hole costs	(645,169		)	(565,237	)
Proceeds from sales of property, plant and equipment	16,816			621
Net cash required by investing activities	(1,854,614		)	(564,616	)
Financing Activities
Borrowings on revolving credit facility	1,075,000			—
Proceeds from term loan	500,000			—
Repurchase of common stock	(299,924		)	—
Capital lease obligation payments	(335		)	—
Withholding tax on stock-based incentive awards	(6,991		)	(6,922	)
Distribution to noncontrolling interest	(68,776		)	—
Cash dividends paid	(85,503		)	(86,517	)
Net cash provided (required) by financing activities	1,113,471			(93,439	)
Cash Flows from Discontinued Operations ²
Operating activities	122,272			290,849
Investing activities	(49,798		)	(49,910	)
Financing activities	(4,914		)	(4,648	)
Net cash provided by discontinued operations	67,560			236,291
Cash transferred from discontinued operations to continuing operations	48,565			464,258
Effect of exchange rate changes on cash and cash equivalents	3,268			24,382
Net increase (decrease) in cash and cash equivalents	(33,879		)	162,266
Cash and cash equivalents at beginning of period	359,923			630,433
Cash and cash equivalents at end of period	$	326,044		792,699

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

² Cash flows from discontinued operations are not part of the cash flow reconciliation.

See Notes to Consolidated Financial Statements, page 7.

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Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

(Thousands of dollars)



	Three Months Ended June 30,					Six Months Ended June 30,
	2019			2018		2019		2018
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued	$	—		—		—		—
Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,083,364 shares at June 30, 2019 and 195,065,341 shares at June 30, 2018
Balance at beginning of period	195,083			195,065		195,077		195,056
Exercise of stock options	—			—		6		9
Balance at end of period	195,083			195,065		195,083		195,065
Capital in Excess of Par Value
Balance at beginning of period	924,904			891,191		979,642		917,665
Exercise of stock options, including income tax benefits	—			—		(123	)	(175	)
Restricted stock transactions and other	—			(280	)	(38,732	)	(32,766	)
Stock-based compensation	9,040			7,215		17,676		13,402
Adjustments to acquisition valuation	—			—		(24,519	)	—
Balance at end of period	933,944			898,126		933,944		898,126
Retained Earnings
Balance at beginning of period	5,627,081			5,400,474		5,513,529		5,245,242
Net income (loss) for the period	92,272			45,519		132,454		213,772
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	(42,105		)	(43,259	)	(85,503	)	(86,517	)
Balance at end of period	5,677,248			5,402,734		5,677,248		5,402,734
Accumulated Other Comprehensive Loss
Balance at beginning of period	(580,999		)	(544,737	)	(609,787	)	(462,243	)
Foreign currency translation (loss) gain, net of income taxes	28,606			(34,910	)	54,055		(87,185	)
Retirement and postretirement benefit plans, net of income taxes	2,762			3,938		5,516		7,108
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes	586			586		1,171		1,171
Reclassification of certain tax effects to retained earnings	—			—		—		(30,237	)
Other	—			—		—		(3,737	)
Balance at end of period	(549,045		)	(575,123	)	(549,045	)	(575,123	)
Treasury Stock
Balance at beginning of period	(1,217,293		)	(1,249,686	)	(1,249,162	)	(1,275,529	)
Purchase of treasury shares	(299,924		)	—		(299,924	)	—
Awarded restricted stock, net of forfeitures	—			524		31,869		26,367
Balance at end of period – 32,832,771 shares of Common Stock in 2019 and 22,018,095 shares of Common Stock in 2018, at cost	(1,517,217		)	(1,249,162	)	(1,517,217	)	(1,249,162	)
Murphy Shareholders’ Equity	4,740,013			4,671,640		4,740,013		4,671,640
Noncontrolling Interest
Balance at beginning of period	377,901			—		368,343		—
Acquisition closing adjustments	—			—		(4,592	)	—
Net income attributable to noncontrolling interest	30,970			—		63,557		—
Distributions to noncontrolling Interest Owners	(50,340		)	—		(68,777	)	—
Balance at end of period	358,531			—		358,531		—
Total Equity	$	5,098,544		4,671,640		5,098,544		4,671,640

See Notes to Consolidated Financial Statements, page 7.

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

Malaysia has been classified as held for sale on the accompanying balance sheets; 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 Notes E and R for more information regarding the sale of this asset.

In connection with the LLOG acquisition, further discussed in Note Q, we now hold a 0.5% interest in two variable interest entities (VIEs), Delta House Oil and Gas Lateral LLC and Delta House FPS LLC (collectively Delta House). These VIEs have not been consolidated because we are not considered the primary beneficiary. These non-consolidated VIEs are not material to our financial position or results of operations. As of June 30, 2019, our maximum exposure to loss was $3.7 million, which represents our net investment in Delta House. We have not provided any financial support to Delta House other than amounts previously required by our membership interest.

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 June 30, 2019 and December 31, 2018, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended June 30, 2019 and 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 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 six-month periods ended June 30, 2019 are not necessarily indicative of future results.

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 first quarter of 2019 utilizing the modified retrospective transition method through a cumulative-effect adjustment at the beginning of the first quarter of 2019. The Company has elected the package of practical expedients, which allows the Company not to reassess (1) whether any expired or existing contracts as of the adoption date are or contain a lease, (2) lease classification for any expired or existing leases as of the adoption date and (3) initial direct costs for any existing leases as of the adoption date. The Company did not elect to apply the hindsight practical expedient when determining lease term and assessing impairment of right-of-use assets. The adoption of ASU 2016-02 resulted in the recognition of right-of-use assets of $618.1 million, current lease liabilities for operating leases of approximately $155.5 million, non-current lease liabilities of $468.4 million and a cumulative-effect adjustment to credit retained earnings of $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 adopted this guidance during the first quarter of 2019 and it did not have material impact on its consolidated financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

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 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.

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 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- In Canada, contracts are primarily long-term floating commodity index priced, except for certain natural gas physical forward sales fixed-price contracts. For the Onshore business in Canada, the recorded revenue is net of transportation costs and any gain or loss on spot purchases made to meet committed volumes on sales contracts for the month. For the Offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load based on the volumes on the bill of lading and point of custody transfer.

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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 between onshore and offshore sources of revenue within these geographies.

For the three-months ended June 30, 2019 and 2018, the Company recognized $646.1 million and $426.8 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas. For the six-months ended June 30, 2019 and 2018 the Company recognized $1,236.7 million and $823.1 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas.



		Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of dollars)		2019		2018		2019	2018
Net crude oil and condensate revenue
United States	Onshore	$	192,182	198,823		325,772	381,472
	Offshore	334,189		94,393		650,212	165,922
Canada	Onshore	26,472		28,426		53,816	49,719
	Offshore	41,518		48,316		85,364	102,631
Other		3,123		—		5,975	—
Total crude oil and condensate revenue		597,484		369,958		1,121,139	699,744

Net natural gas liquids revenue
United States	Onshore	6,384		13,236		12,525	25,370
	Offshore	2,988		2,920		7,164	4,559
Canada	Onshore	2,771		3,447		6,229	6,916
Total natural gas liquids revenue		12,143		19,603		25,918	36,845

Net natural gas revenue
United States	Onshore	5,533		6,292		11,397	13,062
	Offshore	6,643		2,825		9,149	5,762
Canada	Onshore	24,311		28,089		69,061	67,683
Total natural gas revenue		36,487		37,206		89,607	86,507
Total revenue from contracts with customers		646,114		426,767		1,236,664	823,096

Gain (loss) on crude contracts		57,916		(37,624	)	57,916	(67,126	)
Gain on sale of assets and other income		5,019		437		5,473	8,400
Total revenue		$	709,049	389,580		1,300,053	764,370

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Contract Balances and Asset Recognition

As of June 30, 2019, and December 31, 2018, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet from continuing operations, were $191.6 million and $147.6 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on historical collections and ability of customers to pay, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods.

The Company has not entered into any upstream oil and gas sale contracts that have financing components as at June 30, 2019.

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

Performance Obligations

The Company recognizes oil and 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 June 30, 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 June 30, 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – Property, Plant and Equipment

Exploratory Wells

Under FASB guidance exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

At June 30, 2019, the Company had total capitalized exploratory well costs for continuing operations pending the determination of proved reserves of $245.0 million. The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30, 2019 and 2018.



(Thousands of dollars)	2019			2018
Beginning balance at January 1	$	207,855		155,103
Additions pending the determination of proved reserves	50,307			30,493
Capitalized exploratory well costs charged to expense	(13,145		)	—
Balance at June 30	$	245,017		185,596

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

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



	June 30,
	2019				2018

(Thousands of dollars)	Amount		No. of Wells	No. of Projects	Amount		No. of Wells	No. of Projects
Aging of capitalized well costs:
Zero to one year	$	33,125	3	2	$	34,779	2	2
One to two years	61,293		1	1	35,934		2	1
Two to three years	27,266		1	1	50,272		2	2
Three years or more	123,333		5	—	64,611		6	—
	$	245,017	10	4	$	185,596	12	5

Of the $211.9 million of exploratory well costs capitalized more than one year at June 30, 2019, $57.2 million is in Brunei, $66.1 million is in Vietnam, $61.3 million is in the Gulf of Mexico and $27.3 million is in the U.S. In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

Divestments

In 2016, a Canadian subsidiary of the Company completed a divestiture of natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia. Total cash consideration received upon closing was $414.1 million. A gain on sale of approximately $187.0 million was deferred, up to December 31, 2018, and was being recognized straight line over the life of the contract in the Canadian operating segment. The remaining deferred gain of $116.8 million, net of tax, was included as a component of Deferred credits and other liabilities in the Company’s Consolidated Balance Sheet as of December 31, 2018. As required by ASC 842, effective January 1, 2019, the previously deferred gain related to the sale and leaseback transaction has been transferred to equity upon adoption, lowering liabilities but increasing retained earnings by approximately $116.8 million, net of tax. The Company amortized approximately $3.8 million of the deferred gain during the first six months of 2018.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Acquisitions

In 2016, a Canadian subsidiary of Murphy Oil acquired a 70% operated working interest (WI) in Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30% non-operated WI in Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta, the majority of which was unproved. As part of the transaction, Murphy agreed to pay an additional $168.0 million in the form of a carried interest on the Kaybob Duvernay property. As of June 30, 2019, $126.9 million of the carried interest had been paid. The remaining carry is to be paid over a period through 2020.

Note E – 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 subsidiaries conducting Malaysian operations, Murphy Sabah Oil Co., Ltd. and Murphy Sarawak Oil Co., Ltd., to a subsidiary of PTT Exploration and Production Public Company Limited (PTTEP). The sale of the Malaysian business closed on July 10, 2019. See Note R for more information regarding the sale of this asset.

The Company has accounted for its Malaysian exploration and production operations, along with the former U.K., 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 and six-month period ended June 30, 2019 and 2018 were as follows:



	Three Months Ended June 30,			Six Months Ended June 30,
(Thousands of dollars)	2019		2018	2019	2018
Revenues	$	159,961	228,621	355,373	439,436
Costs and expenses
Lease operating expenses	58,160		55,406	120,876	103,016
Depreciation, depletion and amortization	2,345		47,249	33,698	95,240
Other costs and expenses (benefits)	57,401		21,474	70,481	19,023
Income before taxes	42,055		104,492	130,318	222,157
Income tax expense	17,637		33,788	56,054	73,781
Income from discontinued operations	$	24,418	70,704	74,264	148,376

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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 reflected as held for sale on the Company’s Consolidated Balance Sheets at June 30, 2019 and December 31, 2018.



(Thousands of dollars)	June 30, 2019		December 31, 2018
Current assets
Cash	$	63,649	44,669
Accounts receivable	111,250		103,158
Inventories	8,652		7,887
Prepaid expenses and other	16,929		18,151
Property, Plant, and Equipment, net	1,355,229		—
Deferred income taxes and other assets	199,386		—
Operating lease asset	108,730		—
Total current assets associated with assets held for sale	1,863,825		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	$	211,570	203,236
Other accrued liabilities	46,829		55,273
Current maturities of long-term debt	10,194		9,915
Taxes payable	2,340		18,034
Current operating lease liabilities	46,336		—
Long-term debt	112,680		—
Asset retirement obligation	280,408		—
Non-current operating lease liabilities	62,394		—
Total current liabilities associated with assets held for sale	772,751		286,458
Non-current liabilities
Long-term debt	—		117,816
Asset retirement obligation	—		274,904
Total non-current liabilities associated with assets held for sale	$	—	392,720

Note F – Financing Arrangements and Debt

On May 30, 2019, the Company entered into a $500 million term loan credit facility (the New Term Credit Facility). The New Term Credit Facility was a senior unsecured guaranteed facility with an original maturity date of December 2, 2019. The covenants within the New Term Credit Facility were substantially consistent with those in the Company’s revolving credit facility (see 2018 facility below), and borrowings under the New Term Credit Facility bore interest at comparable rates to those incurred under the 2018 facility. The New Term Credit Facility was prepayable at any time by the Company and had to be repaid no later than 30 days after closing of the Company’s previously announced Malaysia divestiture. Subsequent to quarter end, the Company closed the previously announced Malaysia divestiture, repaid and terminated the New Term Credit Facility.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note F – Financing Arrangements and Debt (Contd.)

As of June 30, 2019, the Company has a $1.6 billion revolving credit facility (2018 facility). The 2018 facility is a senior unsecured guaranteed facility which expires in November 2023. At June 30, 2019, the Company had outstanding borrowings of $1.4 billion under the 2018 facility and $23.4 million of outstanding letters of credit, which reduce the borrowing capacity of the 2018 facility. At June 30, 2019, the interest rate in effect on borrowings under the facility was 3.905%. At June 30, 2019, the Company was in compliance with all covenants related to the 2018 facility. Subsequent to quarter end, the Company closed the previously announced Malaysia divestiture and repaid the 2018 facility in full.

Note G – Other Financial Information

Additional disclosures regarding cash flow activities are provided below.໿



	Six Months Ended June 30,
(Thousands of dollars)	2019			2018
Net (increase) decrease in operating working capital other than cash and cash equivalents:
(Increase) decrease in accounts receivable	$	(141,793	)	(26,533	)
(Increase) decrease in inventories	(617		)	21,683
(Increase) decrease in prepaid expenses	(12,190		)	1,276
Increase (decrease) in accounts payable and accrued liabilities	147,569			26,673
Increase (decrease) in income taxes payable	1,665			(601	)
Net (increase) decrease in noncash operating working capital	$	(5,366	)	22,498
Supplementary disclosures:
Cash income taxes paid, net of refunds	$	79		(1,780	)
Interest paid, net of amounts capitalized of $0 in 2019 and 2018	102,802			78,373

Non-cash investing activities:
Asset retirement costs capitalized ¹	$	38,396		1,608
(Increase) decrease in capital expenditure accrual	(65,830		)	35,837

¹ Includes asset retirement obligations assumed as part of the LLOG acquisition of $37.3 million. See Note Q.

Note H – Employee and Retiree Benefit Plans

The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental 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 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 six-month periods ended June 30, 2019 and 2018.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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



	Three Months Ended June 30,
	Pension Benefits					Other Postretirement Benefits
(Thousands of dollars)	2019			2018		2019		2018
Service cost	$	2,062		2,254		420		493
Interest cost	7,100			6,707		943		874
Expected return on plan assets	(6,370		)	(7,453	)	—		—
Amortization of prior service cost (credit)	246			256		(97	)	(9	)
Recognized actuarial loss	3,508			5,181		—		—
Net periodic benefit expense	$	6,546		6,945		1,266		1,358



	Six Months Ended June 30,
	Pension Benefits					Other Postretirement Benefits
(Thousands of dollars)	2019			2018		2019		2018
Service cost	$	4,124		4,509		840		987
Interest cost	14,251			13,444		1,888		1,748
Expected return on plan assets	(12,830		)	(14,959	)	—		—
Amortization of prior service cost (credit)	493			513		(195	)	(19	)
Recognized actuarial loss	7,022			10,396		—		—
Net periodic benefit expense	$	13,060		13,903		2,533		2,716

The components of net periodic benefit expense other than the service cost component are included in the line item “Interest and other income (loss)” in Consolidated Statements of Operations.

During the six-month period ended June 30, 2019, the Company made contributions of $14.1 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2019 for the Company’s defined benefit pension and postretirement plans is anticipated to be $18.3 million.

Note I – 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 2017 Annual Incentive Plan (2017 Annual Plan) authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees. Cash awards under the 2017 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee.

The 2018 Long-Term Incentive Plan (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 2018 Long-Term Plan expires in 2028. A total of 6,750,000 shares are issuable during the life of the 2018 Long-Term Plan, with annual grants limited to 1% of Common shares outstanding; allowed shares not granted in an earlier year may be granted in future years.

The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.

In the first quarter of 2019, the Committee granted 957,600 performance-based RSUs and 327,900 time-based RSUs to certain employees. The fair value of the performance-based RSUs, using a Monte Carlo valuation model, was $28.09 per unit. The fair value of the time-based RSUs was estimated based on the fair market value of the Company’s stock on the date of grant. The fair value of the time-based RSUs granted was $28.16 per unit. Additionally, in February 2019, the Committee granted 1,025,900 cash-settled RSUs (CRSU) to certain employees. The 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 the CRSUs granted in February 2019 was $28.16. Also in February, the Committee granted 78,716 shares of time-based RSUs to the Company’s non-employee Directors

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – Incentive Plans (Contd.)

under the 2018 Stock Plan for Non-Employee Directors. These units are scheduled to vest on the third anniversary of the date of grant. The estimated fair value of these awards was $27.95 per unit on date of grant.

All stock option exercises are non-cash transactions for the Company. The employee receives net shares, after applicable withholding taxes, upon each stock 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 six-month period ended June 30, 2019.

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

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).

Note J – Earnings per Share

Net income attributable to Murphy was used as the numerator in computing both basic and diluted income per Common share for the three-month and six-month periods ended June 30, 2019 and 2018. The following table reconciles the weighted-average shares outstanding used for these computations.



	Three Months Ended June 30,		Six Months Ended June 30,
(Weighted-average shares)	2019	2018	2019	2018
Basic method	168,537,896	173,042,626	170,555,685	172,907,537
Dilutive stock options and restricted stock units	734,567	939,994	877,007	2,019,525
Diluted method	169,272,463	173,982,620	171,432,692	174,927,062

The following table reflects certain options to purchase shares of common stock that were outstanding during the periods presented but were not included in the computation of diluted shares above because the incremental shares from the assumed conversion were antidilutive.



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Antidilutive stock options excluded from diluted shares	2,927,469		3,396,951		3,066,166		3,622,106
Weighted average price of these options	$	45.38	$	50.22	$	45.66	$	50.56

Note K – Income Taxes

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



	2019	2018
Three months ended June 30,	8.4%	(11.6)%
Six months ended June 30,	14.1%	249.9%

The effective tax rate for the three-month period ended June 30, 2019 was below the U.S. statutory tax rate of 21% due to an enacted future change in the Alberta provincial corporate income tax rate in Canada that reduced the future deferred tax liability by $13.0 million and no tax applied to the pre-tax income of the noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K– Income Taxes (Contd.)

The effective tax rate for the three-month period ended June 30, 2018 was below the statutory tax rate primarily due to net losses and exploration expenses in certain foreign jurisdictions for which no income tax benefits will be realized, and income generated in foreign jurisdictions which have income tax rates higher than the U.S. statutory tax rate. As a result of a reported pretax loss, these items lowered the effective tax rate.

The effective tax rate for the six-month period ended June 30, 2019 was below the U.S. statutory tax rate of 21% due to an enacted future change in the Alberta provincial corporate income tax rate in Canada that reduced the future deferred tax liability by $13.0 million and no tax applied to the pre-tax income of the noncontrolling interest in MP GOM.

For the six-month period ended June 30, 2018 the effective tax rate is higher than the statutory tax rate of 21% because the Company reported a pre-tax loss and a tax benefit resulting from a favorable tax adjustment related to the 2017 Tax Act. The IRS’s April 2, 2018 guidance allowed for the preservation of 2017 operating loss carryforwards under the 2017 Tax Act’s taxation of unrepatriated foreign earnings. The preservation of the tax loss carryforward reduced the deferred tax expense by $156 million and resulted in a $36 million charge to taxes payable for a net $120 million tax 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 June 30, 2019, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2015; Canada – 2013; Malaysia – 2012; and United Kingdom – 2017.

Note L – Financial Instruments and Risk Management

Murphy 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 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 until the anticipated transactions occur.

Commodity Price Risks

At June 30, 2019, the Company had 20,000 barrels per day in WTI crude oil swap financial contracts maturing through the end of 2019 at an average price of $63.64 and 20,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2020 at an average price of $60.10. Under these contracts, which matured monthly, the Company pays the average monthly price in effect and receives the fixed contract prices.

At June 30, 2018, the Company had 21,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2018.

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 June 30, 2019 and 2018.

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

June 30, 2019

December 31, 2018

(Thousands of dollars)

Asset (Liability) Derivatives

Type of Derivative Contract

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Commodity

Accounts receivable

56,193

Accounts receivable

3,837

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

For the three-month and six-month periods ended June 30, 2019 and June 30, 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)
(Thousands of dollars)		Three Months Ended June 30,				Six months ended June 30,
Type of Derivative Contract	Statement of Operations Location	2019		2018		2019	2018
Commodity	Gain (loss) on crude contracts	$	57,916	(37,624	)	57,916	(67,126	)

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 years notes sold in May 2012 to match the payment of interest on these notes through 2022. During each of the six-month periods ended June 30, 2019 and 2018, $1.5 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 June 30, 2019 was $6.7 million, which is recorded, net of income taxes of $1.8 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheet. The Company expects to charge approximately $1.5 million of this deferred loss to Interest expense, net in the Consolidated Statement of Operations during the remaining six months of 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.

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



	June 30, 2019					December 31, 2018
(Thousands of dollars)	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
Assets:
Commodity derivative contracts	$	—	56,193	—	56,193	—	3,837	—	3,837
	$	—	56,193	—	56,193	—	3,837	—	3,837

Liabilities:
Nonqualified employee savings plans	$	16,061	—	—	16,061	13,845	—	—	13,845
Contingent consideration	—		—	178,409	178,409	—	—	47,730	47,730
	$	16,061	—	178,409	194,470	13,845	—	47,730	61,575

The fair value of WTI crude oil derivative contracts in 2018 and 2019 were based on active market quotes for WTI crude oil. The income effect of changes in the fair value of crude oil derivative contracts is recorded in Gain (loss) on crude contracts in the Consolidated Statements of Operations.

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 contingent consideration, related to two recent acquisitions, is valued using a Monte Carlo simulation model. The income effect of changes in the fair value of the contingent consideration is recorded in Other (income) expense in the Consolidated Statements of Operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

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 June 30, 2019 and December 31, 2018.

Subsequent to the balance sheet date, the Company has entered into additional 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 June 30, 2019 and the changes during the six-month period ended June 30, 2019 are presented net of taxes in the following table.



(Thousands of dollars)	Foreign Currency Translation Gains (Losses)			Retirement and Postretirement Benefit Plan Adjustments			Deferred Loss on Interest Rate Derivative Hedges			Total
Balance at December 31, 2018	$	(419,852	)	(182,036	)		(7,899	)		(609,787	)
2019 components of other comprehensive income (loss):
Before reclassifications to income and retained earnings	54,055			—			—			54,055
Reclassifications to income	—			5,516		¹	1,171		²	6,687
Net other comprehensive income (loss)	54,055			5,516			1,171			60,742
Balance at June 30, 2019	$	(365,797	)	(176,520	)		(6,728	)		(549,045	)

¹Reclassifications before taxes of $7,061 are included in the computation of net periodic benefit expense for the six-month period ended June 30, 2019. See Note H for additional information. Related income taxes of $1,545 are included in Income tax expense (benefit) for the six-month period ended June 30, 2019.

²Reclassifications before taxes of $1,482 are included in Interest expense, net, for the six-month period ended June 30, 2019. Related income taxes of $311 are included in Income tax expense (benefit) for the six-month period ended June 30, 2019. See Note L for additional information.

Note 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 legislation changes, including tax rate changes and retroactive tax claims; royalty and revenue sharing changes; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences or may be taken in response to actions of other governments. It is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note N– Environmental and Other Contingencies (Contd.)

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 and operational 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.

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 O – Business Segments

Information about business segments and geographic operations is reported in the following table. For geographic purposes, revenues are attributed to the country in which the sale occurs. Corporate, including interest income, other gains and losses (including foreign exchange gains/losses and realized/unrealized gains/losses on crude oil contracts), interest expense and unallocated overhead, is shown in the tables to reconcile the business segments to consolidated totals.໿



(Millions of dollars)	Total Assets at June 30, 2019		Three Months Ended June 30, 2019			Three Months Ended June 30, 2018
(Millions of dollars)	Total Assets at June 30, 2019		External Revenues	Income (Loss)		External Revenues		Income (Loss)
Exploration and production ¹
United States	$	8,089.6	549.0	133.0		318.8		72.5
Canada	2,271.6		94.8	(5.9	)	108.4		9.9
Other	257.6		3.1	(3.4	)	—		(15.1	)
Total exploration and production	10,618.8		646.9	123.7		427.2		67.3
Corporate	1,053.4		62.1	(25.0	)	(37.6	)	(92.5	)
Assets/revenue/income from continuing operations	11,672.2		709.0	98.7		389.6		(25.2	)
Discontinued operations, net of tax	1,863.8		—	24.5		—		70.7
Total	$	13,536.0	709.0	123.2		389.6		45.5

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note O – Business Segments (Contd.)



(Millions of dollars)	Six Months Ended June 30, 2019				Six Months Ended June 30, 2018
(Millions of dollars)	External Revenues		Income (Loss)		External Revenues		Income (Loss)
Exploration and production ¹
United States	$	1,018.2	249.2		596.9		108.7
Canada	213.7		1.6		226.7		34.3
Other	6.0		(31.7	)	—		(30.5	)
Total exploration and production	1,237.9		219.1		823.6		112.5
Corporate	62.2		(97.4	)	(59.2	)	(47.1	)
Assets/revenue/income from continuing operations	1,300.1		121.7		764.4		65.4
Discontinued operations, net of tax	—		74.3		—		148.4
Total	$	1,300.1	196.0		764.4		213.8

¹ Additional details about results of oil and gas operations are presented in the tables on pages 31 and 32.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note P – Leases

Significant Accounting Policy

At inception, contracts are assessed for the presence of a lease according to criteria laid out by ASC 842. If a lease is present, further criteria is assessed to determine if the lease should be classified as an operating or finance lease. Operating leases are presented on the Consolidated Balance Sheet as Operating lease assets with the corresponding lease liabilities presented in Operating lease liabilities and Non-current operating lease liabilities. Finance lease assets are presented on the Consolidated Balance Sheet within Property, plant and equipment, net with the corresponding liabilities presented in Current maturities of long-term debt and Long-term debt.

Generally, lease liabilities are recognized at commencement and based on the present value of the future minimum lease payments to be made over the lease term. Lease assets are then recognized based on the value of the lease liabilities. Where implicit lease rates are not determinable, the minimum lease payments are discounted using the Company’s collateralized incremental borrowing rates.

Operating leases are expensed according to their nature and recognized in Lease operating expenses, Selling and general expenses or capitalized in the Consolidated Financial Statements. Finance leases are depreciated with expenses recognized in Depreciation, depletion, and amortization and Interest expense, net on the Consolidated Statement of Operations.

Nature of Leases

The Company has entered into various operating leases such as a 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 which may include options to extend leases for multi-year periods and others which include options to terminate the leases within 1 month. Options to extend lease terms are at the Company’s discretion. Early lease terminations are a combination of both at Company discretion and mutual agreement between the Company and lessor. Purchase options also exist for certain leases.

Related Expenses

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



(Thousands of dollars)	Financial Statement Category	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
Operating lease ^1,2	Lease operating expenses	$	57,381		115,904
Operating lease ²	Selling and general expense	3,235			6,344
Operating lease ²	Other operating expense	894			894
Operating lease ²	Property, plant and equipment	32,115			55,562
Operating lease ²	Asset retirement obligations	—			3,024
Finance lease
Amortization of asset	Depreciation, depletion and amortization	210			420
Interest on lease liabilities	Interest expense, net	101			202
Sublease income	Other income	(422		)	(639	)
Net lease expense		$	93,514		181,711

¹ For the three months and six months ended June 30, 2019, includes variable lease expenses of $6.6 million and $13.8 million, respectively, primarily related to additional volumes processed at a gas processing plant.

² For the three months ended includes $10.4 million for Lease operating expense, $1.2 million for Selling and general expense, $28.7 million for Property, plant and equipment, net relating to short-term leases due within 12 months. For the six months ended includes $22.4 million for Lease operating expense, $2.3 million for Selling and general expense, $48.8 million for Property, plant and equipment, net and $3.0 million for Asset retirement obligations relating to short-term leases due within 12 months. Expenses primarily relate to drilling rigs and other oil and gas field equipment.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note P – Leases (Contd.)

Maturity of Lease Liabilities໿



(Thousands of dollars)	Operating Leases ¹			Finance Leases		Total
2019	$	112,185		534		112,719
2020	107,652			1,069		108,721
2021	59,788			1,069		60,857
2022	54,548			1,069		55,617
2023	54,041			1,069		55,110
Remaining	474,598			5,610		480,208
Total future minimum lease payments	862,812			10,420		873,232
Less imputed interest	(266,009		)	(2,083	)	(268,092	)
Present value of lease liabilities²	$	596,803		8,337		605,140

¹ Excludes $271.8 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



	June 30, 2019
Weighted average remaining lease term:
Operating leases	12 years
Finance leases	10 years
Weighted average discount rate:
Operating leases	5.0	%
Finance leases	4.7	%

Other Information໿



(Thousands of dollars)	Six Months Ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	90,598
Operating cash flows from finance leases	204
Financing cash flows from finance leases	335
Right-of-use assets obtained in exchange for lease liabilities:
Operating leases	$	6,033

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note Q– Acquisitions

PAI 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 approximately 97 MMBOE (including noncontrolling interest, NCI) of proven reserves at December 31, 2018.

Under the terms of the transaction, Murphy paid cash consideration of $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.

LLOG Acquisition:

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

Under the terms of the transaction, Murphy paid cash consideration of $1.2 billion and has an obligation to pay additional contingent consideration of up to $200 million in the event that certain revenue thresholds are exceeded between 2019 and 2022; and $50 million following first oil from certain development projects.

The following table contains the preliminary purchase price allocation at fair value:



(Thousands of dollars)	PAI			LLOG
Cash consideration paid	$	788,724		1,226,261
Fair value of net assets contributed	154,469			—
Contingent consideration	52,540			89,444
NCI in acquired assets	248,933			—
Total purchase consideration	$	1,244,666		1,315,705
(Thousands of dollars)
Fair value of Property, plant and equipment	$	1,627,429		1,340,206
Other assets	5,628			12,771
Less: Asset retirement obligations	(388,391		)	(37,272	)
Total net assets	$	1,244,666		1,315,705

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

Certain data necessary to complete the purchase price allocations are not yet available, and includes, but is not limited to, analysis of the underlying tax basis of the acquired assets and assumed liabilities as well as the final purchase price adjustments to be settled in 2019. We expect to complete the purchase price allocations during the 12-month periods following the acquisition dates of November 30, 2018 and May 31, 2019, during which time the value of the assets and liabilities may be revised as appropriate.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note Q– Acquisitions (Contd.)

Results of Operations

Murphy’s Consolidated Statement of Operations for the three months ended June 30, 2019 included additional revenues of $388.9 million and pre-tax income of $136.8 million attributable to the acquired PAI assets. For the six months ended June 30, 2019, additional revenues of $622.9 million and pre-tax income of $284.5 million attributable to the acquired PAI assets were included in the Consolidated Statement of Operations.

Murphy’s Consolidated Statement of Operations for the three-month and six-month periods ended June 30, 2019 included additional revenues of $43.6 million and pre-tax income of $8.0 million attributable to the acquired LLOG assets.

Pro Forma Financial Information

The following pro forma condensed combined financial information was derived from historical financial statements of Murphy PAI and LLOG and gives effect to the transaction as if it had occurred on January 1, 2018. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable. 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.



(Thousands of dollars, except per share amounts)	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
Revenues	$	874,631	1,453,711
Net Income Attributable to Murphy	246,889		458,386

Net Income Attributable to Murphy per Common Share
Basic	$	1.43	2.65
Diluted	1.42		2.62

Note R – Subsequent Event

In July 2019, the Company announced the completion of a transaction with PTT Exploration and Production Public Company Limited (PTTEP) which was effective January 1, 2019. Through this transaction, Murphy divested its fully issued share capital of the entities conducting Murphy’s operations in Malaysia for $2.0 billion in an all-cash transaction. Murphy is entitled to receive a $100.0 million bonus payment contingent upon certain future exploratory drilling results prior to October 2020. The gain on the sale of approximately $960.0 million will be reported in Murphy’s Consolidated Statements of Operations during the third quarter. The Company does not anticipate tax liabilities related to the transaction.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

Overall Review

On May 31, 2019, Murphy Oil Corporation completed a transaction with LLOG Exploration Offshore L.L.C. and LLOG Bluewater Holdings, L.L.C., (LLOG) which was effective January 1, 2019. Through this transaction, Murphy acquired deepwater Gulf of Mexico assets which added approximately 67 MMBOE of proven reserves as of May 31, 2019 in exchange for cash of $1.2 billion paid to LLOG.

During the second quarter of 2019, the Company completed $300 million in share repurchases. Murphy purchased 11.4 million shares outstanding at an average price of $26.34 per share. The current share repurchase program for up to $500 million in share repurchases expires year-end 2020.

On March 21, 2019, Murphy Oil Corporation announced that a subsidiary has signed a sale and purchase agreement to divest the fully issued share capital of its two subsidiaries conducting Malaysian operations, Murphy Sabah Oil Co., Ltd. and Murphy Sarawak Oil Co., Ltd., to a subsidiary of PTT Exploration and Production Public Company Limited (PTTEP). As such the assets and liabilities of the Malaysia business have been classified as held for sale on the consolidated balance sheets and the Malaysia results of operations have been reported as discontinued operations in the statement of operations for all periods presented.

For the three months ended June 30, 2019, the Company produced 171 thousand barrels of oil equivalent per day from continuing operations which excludes Malaysia as it is held for sale. The Company invested $1.6 billion in capital expenditures, on a value of work done basis, in the second quarter of 2019, which included the LLOG acquisition of $1.2 billion. The Company reported net income from continuing operations (which includes income attributable to noncontrolling interest of $31.0 million) of $98.8 million for the three months ended June 30, 2019.

For the six months ended June 30, 2019, the Company produced 166 thousand barrels of oil equivalent per day from continuing operations which excludes Malaysia as it is held for sale. The Company invested $2.0 billion in capital expenditures, on a value of work done basis, in the first half of 2019, which included the LLOG acquisition of $1.2 billion. The Company reported net income from continuing operations (which includes income attributable to noncontrolling interest of $63.6 million) of $121.7 million for the six months ended June 30, 2019.

In the second quarter of 2018, the Company produced 122 thousand barrels of oil equivalent per day from continuing operations which excludes Malaysia as it is held for sale. The Company invested $275 million in capital expenditures, on a value of work done basis, in the second quarter of 2018. The Company reported net loss from continuing operations of $25.2 million for the three months ended June 30, 2018.

For the six months ended June 30, 2018, the Company produced 119 thousand barrels of oil equivalent per day from continuing operations which excludes Malaysia as it is held for sale. The Company invested $554 million in capital expenditures, on a value of work done basis, in the first half of 2018. The Company reported net income from continuing operations of $65.4 million for the six months ended June 30, 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 and six-month periods ended June 30, 2019, crude oil and condensate volumes were higher than the prior periods as a result of two Gulf of Mexico acquisitions. The additional income from higher volumes was off-set by lower benchmark oil prices that were below average comparable benchmark prices during 2018. The results are explained in more detail below.

Results of Operations

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



	Income (Loss)
	Three Months Ended June 30,					Six Months Ended June 30,
(Millions of dollars)	2019			2018		2019		2018
Exploration and production	$	123.7		67.3		219.1		112.5
Corporate and other	(24.9		)	(92.5	)	(97.4	)	(47.1	)
Income from continuing operations	98.8			(25.2	)	121.7		65.4
Discontinued operations	24.4			70.7		74.3		148.4
Net income including noncontrolling interest	$	123.2		45.5		196.0		213.8

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

Results of Operations (contd.)

Exploration and Production

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



	Income (Loss)
	Three Months Ended June 30,					Six Months Ended June 30,
(Millions of dollars)	2019			2018		2019		2018
Exploration and production
United States	$	133.0		72.6		249.2		108.7
Canada	(5.9		)	9.7		1.6		34.3
Other International	(3.4		)	(15.0	)	(31.7	)	(30.5	)
Total	$	123.7		67.3		219.1		112.5

Second quarter 2019 vs. 2018

United States E&P operations reported earnings of $133.0 million in the second quarter of 2019 compared to income of $72.6 million in the second quarter of 2018. Results were $60.4 million favorable in the 2019 quarter compared to the 2018 period due to higher revenues ($230.2 million) and lower income tax expense ($3.9 million), partially offset by higher depreciation, depletion and amortization ($72.9 million), lease operating expenses ($47.7 million), other operating expense ($19.9 million) other exploration costs ($12.6 million) and G&A ($2.4 million). Higher revenues were primarily due to higher volumes in the U.S. Gulf of Mexico (as a result of the MP GOM transaction in the fourth quarter of 2018 and the LLOG acquisition in the second quarter of 2019). 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 acquisition transaction costs and the fair market revaluation of the acquisition contingent consideration. Higher exploration charges were due to higher geological and geophysical expense principally in the Gulf of Mexico.

Canadian E&P operations reported a loss of $5.9 million in the second quarter 2019 compared to income of $9.7 million in the 2018 quarter. Results were unfavorable $15.6 million compared to the 2018 period due to lower revenue ($13.6 million) higher lease operating expense ($7.7 million). Lower revenue is principally due to lower gas, oil and condensate prices. 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 $3.4 million in the second quarter of 2019 compared to a net loss of $15.0 million in the prior year quarter. The result was $11.6 million favorable in the 2019 period versus 2018 primarily due to higher revenues from Brunei and higher tax credits.

Six months 2019 vs. 2018

United States E&P operations reported earnings of $249.2 million in the first half of 2019 compared to income of $108.7 million in the first half of 2018. Results were $140.5 million favorable in the 2019 quarter compared to the 2018 period due to higher revenues ($421.3 million), partially offset by higher depreciation, depletion and amortization ($115.2 million), lease operating expenses ($81.6 million), other operating expense ($50.8 million) and G&A ($5.3 million). Higher revenues were primarily due to higher volumes in the U.S. Gulf of Mexico (as a result of the MP GOM transaction in the fourth quarter of 2018 and the LLOG acquisition in the second quarter of 2019). 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 acquisition transaction costs and the fair market revaluation of acquisition contingent consideration.

Canadian E&P operations reported earnings of $1.6 million in the first half of 2019 compared to income of $34.3 million in the first half of 2018. Results were unfavorable $32.7 million compared to the 2018 period primarily due to lower revenue ($13.0 million), higher lease operating expense ($16.4 million), lower other income ($11.8 million) related to the Seal insurance proceeds received in 2018; and partially off-set by lower tax charges ($11.3 million). Lower revenues are due to lower oil and condensate prices than the prior year. Higher lease operating expenses are due to higher costs at Tupper as a result of a 2018 credit relating to a gain on a sale and lease-back transaction on the disposal of a gas processing plant; in 2018 this gain was being credited to operating expenses equally over the life of the lease. In 2019 this gain was transferred to equity as a result of the implementation of ASC 842 (see Note D).

Other international E&P operations reported a loss from continuing operations of $31.7 million in the first half of 2019 compared to a net loss of $30.5 million in the prior year quarter. The 2019 result includes the write-off of previously suspended exploration

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

Results of Operations (contd.)

costs of $13.2 million attributable to the CM-1X and the CT-1X wells (originally drilled in 2017) in Vietnam; and is partially off-set by higher revenues in Brunei ($6.0 million) and lower tax credits ($7.6 million).

Second quarter 2019 vs. 2018

Total hydrocarbon production from continuing operations averaged 170,885 barrels of oil equivalent per day in the second quarter of 2019, which represented a 40% increase from the 122,317 barrels per day produced in the 2018 quarter. The increase is principally due to the acquisition of producing Gulf of Mexico assets as part of the MP GOM transaction in the fourth quarter 2018 and the addition of further Gulf of Mexico assets as part of the LLOG acquisition in the second quarter of 2019.

Average crude oil and condensate production from continuing operations was 107,283 barrels per day in the second quarter of 2019 compared to 61,117 barrels per day in the second quarter of 2018. The increase of 46,166 barrels per day was principally due to higher volumes in the Gulf of Mexico (45,697 barrels per day) due to the acquisition of assets as part of the MP GOM transaction and the LLOG acquisition. On a worldwide basis, the Company’s crude oil and condensate prices averaged $62.46 per barrel in the second quarter 2019 compared to $67.88 per barrel in the 2018 period, a decrease of 8% quarter to quarter.

Total production of natural gas liquids (NGL) from continuing operations was 10,168 barrels per day in the second quarter 2019 compared to 9,248 barrels per day in the 2018 period. The average sales price for U.S. NGL was $11.74 per barrel in the 2019 quarter compared to $21.28 per barrel in 2018. The average sales price for NGL in Canada was $28.37 per barrel in the 2019 quarter compared to $36.66 per barrel in 2018. NGL prices are higher in Canada due to the higher value of product produced at the Kaybob and Placid assets.

Natural gas sales volumes from continuing operations averaged 321 million cubic feet per day (MMCFD) in the second quarter 2019 compared to 312 MMCFD in 2018. The increase of 9 MMCFD was a result of higher volumes in the Gulf of Mexico (25 MMCFD), partially offset by lower volumes in Canada (15 MMCFD). Higher volumes in the Gulf of Mexico are due to the acquisition of assets related to the MP GOM transaction and the LLOG acquisition. Lower volumes in Canada was a result of a Tupper processing plan turnaround in the 2019 quarter.

Natural gas prices for the total Company averaged $1.25 per thousand cubic feet (MCF) in the 2019 quarter, versus $1.31 per MCF average in the same quarter of 2018. Average prices in the US and Canada in the quarter were $1.88 and $1.07 respectively.

Six months 2019 vs. 2018

Total hydrocarbon production from continuing operations averaged 166,269 barrels of oil equivalent per day in the first half of 2019, which represented a 39% increase from the 119,477 barrels per day produced in the first half of 2018. The increase is principally due to the acquisition of producing Gulf of Mexico assets as part of the MP GOM transaction in the fourth quarter 2018 and the addition of further Gulf of Mexico assets as part of the LLOG acquisition in the second quarter of 2019.

Average crude oil and condensate production from continuing operations was 104,567 barrels per day in the first half of 2019 compared to 59,219 barrels per day in the first half of 2018. The increase of 45,348 barrels per day was principally due to higher volumes in the Gulf of Mexico (46,942 barrels per day) due to the acquisition of assets as part of the MP GOM transaction and the LLOG acquisition. On a worldwide basis, the Company’s crude oil and condensate prices averaged $59.23 per barrel in the first half of 2019 compared to $64.55 per barrel in the 2018 period, a decrease of 8.25% quarter to quarter.

Total production of natural gas liquids (NGL) from continuing operations was 9,664 barrels per day in the first half of 2019 compared to 8,845 barrels per day in the 2018 period. The average sales price for U.S. NGL was $12.68 per barrel in the 2019 quarter compared to $20.97 per barrel in 2018. The average sales price for NGL in Canada was $31.78 per barrel in the 2019 quarter compared to $39.83 per barrel in 2018. NGL prices are higher in Canada due to the higher value of product produced at the Kaybob and Placid assets.

Natural gas sales volumes from continuing operations averaged 312 million cubic feet per day (MMCFD) in the first half quarter 2019 compared to 308 MMCFD in 2018. The increase of 4 MMCFD was a result of higher volumes in the Gulf of Mexico (16 MMCFD) partially offset by lower volumes in Canada (11 MMCFD). Lower volumes in Canada was a result of a Tupper processing plant turnaround in the second quarter of 2019. Higher volumes in the Gulf of Mexico are due to the acquisition of assets related to the MP GOM transaction and the LLOG acquisition.

Natural gas prices for the total Company averaged $1.59 per thousand cubic feet (MCF) in the 2019 quarter, versus $1.55 per MCF average in the same quarter of 2018. Average prices in the US and Canada in the quarter were $1.89 and $1.51 respectively.

Additional details about results of oil and gas operations are presented in the tables on pages 31 and 32.

Table of Contents

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

Results of Operations (contd.)

The following table contains hydrocarbons produced during the three-month and six-month periods ended June 30, 2019 and 2018.



		Three Months Ended June 30,			Six Months Ended June 30,
Barrels per day unless otherwise noted		2019		2018	2019		2018
Continuing operations
Net crude oil and condensate
United States	Onshore	33,145		31,936	29,532		31,630
	Gulf of Mexico ¹	61,062		15,365	61,055		14,113
Canada	Onshore	5,943		5,254	6,199		4,809
	Offshore	6,685		7,982	7,304		8,085
Other		448		580	477		582
Total net crude oil and condensate - continuing operations		107,283		61,117	104,567		59,219
Net natural gas liquids
United States	Onshore	5,977		6,824	5,641		6,772
	Gulf of Mexico ¹	3,118		1,391	2,940		1,114
Canada	Onshore	1,073		1,033	1,083		959
Total net natural gas liquids - continuing operations		10,168		9,248	9,664		8,845
Net natural gas – thousands of cubic feet per day
United States	Onshore	32,209		32,679	30,752		31,894
	Gulf of Mexico ¹	39,029		14,284	29,356		13,548
Canada	Onshore	249,367		264,748	252,120		263,036
Total net natural gas - continuing operations		320,605		311,711	312,228		308,478
Total net hydrocarbons - continuing operations including NCI ^2,3		170,885		122,317	166,269		119,477
Noncontrolling interest
Net crude oil and condensate – barrels per day		(11,160	)	—	(11,669	)	—
Net natural gas liquids – barrels per day		(458	)	—	(506	)	—
Net natural gas – thousands of cubic feet per day		(4,507	)	—	(4,203	)	—
Total noncontrolling interest		(12,369	)	—	(12,876	)	—
Total net hydrocarbons - continuing operations excluding NCI ^2,3		158,516		122,317	153,394		119,477
Discontinued operations
Net crude oil and condensate – barrels per day		21,556		28,950	23,744		30,084
Net natural gas liquids – barrels per day		529		872	636		665
Net natural gas – thousands of cubic feet per day ²		93,382		113,125	97,465		114,195
Total discontinued operations		37,649		48,676	40,624		49,782
Total net hydrocarbons produced excluding NCI ^2,3		196,165		170,993	194,018		169,259

¹2019 includes net volumes attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM).

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

³NCI – noncontrolling interest in MP GOM.

Table of Contents

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

Results of Operations (contd.)

The following table contains hydrocarbons sold during the three-month and six-month periods ended June 30, 2019 and 2018.



		Three Months Ended June 30,			Six Months Ended June 30,
Barrels per day unless otherwise noted		2019		2018	2019		2018
Continuing operations
Net crude oil and condensate
United States	Onshore	33,145		31,936	29,532		31,630
	Gulf of Mexico ¹	58,842		15,365	61,053		14,113
Canada	Onshore	5,943		5,254	6,199		4,809
	Offshore	6,723		7,333	7,324		8,255
Other		470		—	468		—
Total net crude oil and condensate - continuing operations		105,123		59,888	104,576		58,807
Net natural gas liquids
United States	Onshore	5,977		6,824	5,641		6,772
	Gulf of Mexico ¹	3,118		1,391	2,940		1,114
Canada	Onshore	1,073		1,033	1,083		959
Total net natural gas liquids - continuing operations		10,168		9,248	9,664		8,845
Net natural gas – thousands of cubic feet per day
United States	Onshore	32,209		32,679	30,752		31,894
	Gulf of Mexico ¹	39,029		14,284	29,356		13,548
Canada	Onshore	249,367		264,748	252,120		263,036
Total net natural gas - continuing operations		320,605		311,711	312,228		308,478
Total net hydrocarbons - continuing operations including NCI ^2,3		168,725		121,088	166,278		119,065
Noncontrolling interest
Net crude oil and condensate – barrels per day		(10,715	)	—	(11,669	)	—
Net natural gas liquids – barrels per day		(458	)	—	(506	)	—
Net natural gas – thousands of cubic feet per day²		(4,507	)	—	(4,203	)	—
Total noncontrolling interest		(11,924	)	—	(12,876	)	—
Total net hydrocarbons - continuing operations excluding NCI ^2,3		156,801		121,088	153,403		119,065

Discontinued operations
Net crude oil and condensate – barrels per day		21,121		30,107	23,676		30,031
Net natural gas liquids – barrels per day		498		632	580		798
Net natural gas – thousands of cubic feet per day²		93,382		113,125	97,465		114,195
Total discontinued operations		37,183		49,593	40,500		49,862
Total net hydrocarbons sold excluding NCI ^2,3		193,984		170,681	193,903		168,927

¹2019 includes net volumes attributable to a noncontrolling interest in MP GOM.

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

³NCI – noncontrolling interest in MP GOM.

Table of Contents

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

Results of Operations (contd.)

The following table contains the weighted average sales prices including transportation cost deduction for the three-month and six-month periods ended June 30, 2019 and 2018.໿



		Three Months Ended June 30,			Six Months Ended June 30,
		2019		2018	2019	2018
Weighted average Exploration and Production sales prices
Continuing operations
Crude oil and condensate – dollars per barrel
United States	Onshore	$	63.72	68.14	60.95	66.24
	Gulf of Mexico ¹	62.41		68.11	58.84	65.81
Canada ²	Onshore	48.94		59.45	47.97	57.12
	Offshore	67.86		72.40	64.39	68.69
Other		73.05		—	70.50	—
Natural gas liquids – dollars per barrel
United States	Onshore	11.73		21.29	12.29	20.62
	Gulf of Mexico ¹	10.53		23.27	13.46	23.01
Canada ²	Onshore	28.37		36.66	31.78	39.83
Natural gas – dollars per thousand cubic feet
United States	Onshore	1.89		2.11	2.04	2.25
	Gulf of Mexico ¹	1.87		2.18	1.72	2.36
Canada ²	Onshore	1.07		1.17	1.51	1.42
Discontinued operations
Crude oil and condensate – dollars per barrel
Malaysia ³	Sarawak	78.25		69.72	70.32	67.13
	Block K	65.79		67.20	65.56	65.20
Natural gas liquids – dollars per barrel
Malaysia ³	Sarawak	40.81		69.61	47.42	70.57
Natural gas – dollars per thousand cubic feet
Malaysia ³	Sarawak	2.57		3.86	3.60	3.62
	Block K	0.24		0.25	0.24	0.24

¹ Prices include the effect of noncontrolling interest share for MP GOM.

²U.S. dollar equivalent.

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

Table of Contents

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

Results of Operations (contd.)

OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED JUNE 30, 2019 AND 2018



(Millions of dollars)	United States ¹			Canada		Other		Total
Three Months Ended June 30, 2019
Oil and gas sales and other operating revenues	$	549.0		94.8		3.1		646.9
Lease operating expenses	99.7			36.9		0.6		137.2
Severance and ad valorem taxes	12.8			0.3		—		13.1
Depreciation, depletion and amortization	201.2			56.8		1.3		259.3
Accretion of asset retirement obligations	8.4			1.5		—		9.9
Exploration expenses
Dry holes and previously suspended exploration costs	(0.2		)	—		—		(0.2	)
Geological and geophysical	15.4			—		2.4		17.8
Other exploration	2.8			0.1		3.1		6.0
	18.0			0.1		5.5		23.6
Undeveloped lease amortization	5.9			0.4		0.9		7.2
Total exploration expenses	23.9			0.5		6.4		30.8
Selling and general expenses	12.9			6.1		6.1		25.1
Other	27.9			0.2		0.1		28.2
Results of operations before taxes	162.2			(7.5	)	(11.4	)	143.3
Income tax provisions (benefits)	29.2			(1.6	)	(8.0	)	19.6
Results of operations (excluding corporate overhead and interest)	$	133.0		(5.9	)	(3.4	)	123.7

Three Months Ended June 30, 2018
Oil and gas sales and other operating revenues	$	318.8		108.4		—		427.2
Lease operating expenses	52.0			29.2		—		81.2
Severance and ad valorem taxes	12.7			0.2		—		12.9
Depreciation, depletion and amortization	128.3			56.8		0.7		185.8
Accretion of asset retirement obligations	4.5			1.9		—		6.4
Exploration expenses
Geological and geophysical	0.2			—		0.7		0.9
Other exploration	2.4			—		5.9		8.3
	2.6			—		6.6		9.2
Undeveloped lease amortization	8.7			0.2		0.7		9.6
Total exploration expenses	11.3			0.2		7.3		18.8
Selling and general expenses	10.5			6.6		5.9		23.0
Other	6.9			0.3		1.1		8.3
Results of operations before taxes	92.6			13.2		(15.0	)	90.8
Income tax provisions (benefits)	20.0			3.5		—		23.5
Results of operations (excluding corporate overhead and interest)	$	72.6		9.7		(15.0	)	67.3

¹ 2019 includes results attributable to a noncontrolling interest in MP GOM.

Table of Contents

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

Results of Operations (contd.)

OIL AND GAS OPERATING RESULTS – SIX MONTHS ENDED JUNE 30, 2019 AND 2018



(Millions of dollars)	United States ¹			Canada		Other		Total
Six Months Ended June 30, 2019
Oil and gas sales and other operating revenues	$	1,018.2		213.7		6.0		1,237.9
Lease operating expenses	192.1			75.9		0.9		268.9
Severance and ad valorem taxes	22.6			0.6		—		23.2
Depreciation, depletion and amortization	365.1			116.3		2.3		483.7
Accretion of asset retirement obligations	16.2			3.0		—		19.2
Exploration expenses
Dry holes and previously suspended exploration costs	(0.1		)	—		13.1		13.0
Geological and geophysical	15.9			—		7.9		23.8
Other exploration	4.0			0.2		7.1		11.3
	19.8			0.2		28.1		48.1
Undeveloped lease amortization	12.8			0.7		1.7		15.2
Total exploration expenses	32.6			0.9		29.8		63.3
Selling and general expenses	30.2			13.7		11.7		55.6
Other	58.5			0.4		0.4		59.3
Results of operations before taxes	300.9			2.9		(39.1	)	264.7
Income tax provisions (benefits)	51.7			1.3		(7.4	)	45.6
Results of operations (excluding corporate overhead and interest)	$	249.2		1.6		(31.7	)	219.1

Six months ended June 30, 2018
Oil and gas sales and other operating revenues	$	596.9		226.7		—		823.6
Lease operating expenses	110.5			59.5		—		170.0
Severance and ad valorem taxes	24.5			0.5		—		25.0
Depreciation, depletion and amortization	249.9			112.5		1.5		363.9
Accretion of asset retirement obligations	8.9			3.9		—		12.8
Exploration expenses
Geological and geophysical	6.2			—		3.6		9.8
Other exploration	3.6			0.1		11.3		15.0
	9.8			0.1		14.9		24.8
Undeveloped lease amortization	21.4			0.4		1.0		22.8
Total exploration expenses	31.2			0.5		15.9		47.6
Selling and general expenses	24.9			14.3		11.9		51.1
Other	7.7			(11.4	)	1.0		(2.7	)
Results of operations before taxes	139.3			46.9		(30.3	)	155.9
Income tax provisions (benefits)	30.6			12.6		0.2		43.4
Results of operations (excluding corporate overhead and interest)	$	108.7		34.3		(30.5	)	112.5

¹ 2019 includes results attributable to a noncontrolling interest in MP GOM.

Table of Contents

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

Results of Operations (contd.)

Corporate

Second quarter 2019 vs. 2018

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to Exploration and Production, reported a net loss of $24.9 million in the second quarter 2019 compared to net loss of $92.5 million in the 2018 quarter. The $67.6 million favorable variance is principally due to 2019 gains on forward swap commodity contracts ($57.9 million) compared to losses on forward contracts ($37.6 million) in the second quarter of 2018, and OIL insurance dividend ($4.5 million); off-set by higher taxes, foreign exchange and other ($24.0 million) and higher net interest expenses ($14.0 million).

Six months 2019 vs. 2018

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on crude oil contracts and corporate overhead not allocated to Exploration and Production, reported a net loss of $97.4 million in the first half of 2019 compared to net loss of $47.1 million in the first half of 2018. The $50.3 million unfavorable variance is due to 2019 gains on forward swap commodity contracts ($57.9 million) compared to losses on forward contracts ($67.1 million) in 2018, off-set by a 2018 income tax credit ($120.0 million, related to an IRS interpretation of the Tax Act), higher general and administrative expenses ($12.0 million), higher interest charges ($10.0 million), higher tax charges ($6.8 million), foreign exchange losses ($6.1 million; versus an $8.4 million gain in 2018), and lower OIL insurance dividend income ($3.6 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.

Malaysia E&P operations reported earnings of $37.2 million in the second quarter of 2019 compared to earnings of $71.1 million in the comparable 2018 period. Results for the second quarter 2019 were unfavorable by $33.9 million primarily due to lower revenues ($68.7 million), higher operating expenses ($31.4 million), partially off-set by lower depreciation ($47.5 million). Lower revenues are principally due to lower volumes sold. Higher operating expenses are due to higher lease operating expenses and commercial settlements prior to the divestiture. The lower depreciation is due to the cessation of charges as a result of the assets being classified as held for sale.

For the six months ended June 30, 2019, Malaysia E&P operations reported earnings of $94.4 million compared to $149.2 million in the 2018 period. Results for the six months ended June 30, 2019 were unfavorable by $54.8 million primarily due to lower revenues ($84.1 million), higher operating expenses ($47.1 million), partially off-set by lower depreciation ($63.8 million) and lower income taxes ($13.4 million). Lower revenues are principally due to lower volumes sold. Higher operating expenses are due to higher lease operating expenses and commercial settlement prior to the divestiture. The lower depreciation is due to the cessation of charges as a result of the assets being classified as held for sale.

Financial Condition

Cash Provided by Operating Activities

Net cash provided by continuing operating activities was $655.4 million for the first six months of 2019 compared to $331.7 million during the same period in 2018. The increased cash from operating activities is primarily attributable to higher cash revenues from the Gulf of Mexico acquisitions (see above). Changes in operating working capital from continuing operations decreased cash by $5.4 million during the first six months of 2019, compared to an increase of $22.5 million in 2018.

Cash Used in Investing Activities

Cash used for property additions and dry holes, which includes amounts expensed, were $645.2 million and $565.2 million in the six-month periods ended June 30, 2019 and 2018, respectively. Property additions in 2019 principally relate to exploration and development capital expenditures at Eagleford in the U.S., Kaybob in Canada and U.S. Gulf of Mexico. Cash used for the acquisition of oil and gas properties of $1.2 billion is attributable to acquisition of certain Gulf of Mexico assets from LLOG (see above).

Table of Contents

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

Financial Condition (contd.)

Cash Used in Investing Activities (contd.)

Total accrual basis capital expenditures, which includes $1.2 billion for the LLOG acquisition were as follows:



	Six Months Ended June 30,
(Millions of dollars)	2019		2018
Capital Expenditures
Exploration and production	$	1,966.9	546.4
Corporate	5.6		7.9
Total capital expenditures	$	1,972.5	554.3

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



	Six Months Ended June 30,
(Millions of dollars)	2019		2018
Property additions and dry hole costs per cash flow statements	$	645.2	565.2
Acquisition of oil and gas properties	1,226.3		—
Geophysical and other exploration expenses	32.0		21.8
Capital expenditure accrual changes and other	69.0		(32.7	)
Total capital expenditures	$	1,972.5	554.3

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 and the LLOG acquisition ($1,226.3 million).

Cash Provided by Financing Activities

Net cash provided by financing activities was $1.1 billion for the first six months of 2019 compared to net cash used by financing activities of $93.4 million during the same period. In 2019, the cash provided was principally from net borrowings on our revolver ($1,075.0 million) and a short-term loan ($500.0 million) to fund the LLOG acquisition (see above). These borrowings were repaid in July 2019 following the completion of the Malaysia divestment for net sales proceeds of $2.0 billion. In the quarter the Company used cash to buy back issued ordinary shares of $299.9 million. Total cash dividends to shareholders amounted to $85.5 million for the six months ended June 30, 2019 compared to $86.5 million in the same period of 2018.

Working Capital

Working capital (total current assets less total current liabilities – excluding assets and liabilities held for sale) at June 30, 2019 was a liability of $542.1 million, $688.4 million lower than December 31, 2018, with the decrease primarily attributable to a short-term loan payable ($500.0 million; subsequently repaid in July 2019 - see above); higher accounts payable ($250.4 million), higher operating lease liabilities ($128.6 million; as a result of the implementation of ASC 842, Leases), and partially offset by higher accounts receivable ($194.2 million). The increase in accounts payable and receivable is attributable to the increased operating activity from the two Gulf of Mexico acquisitions.

Capital Employed

At June 30, 2019, long-term debt of $4,185.9 million had increased by $1,076.6 million compared to December 31, 2018, as a result of funding from the revolving credit facility (subsequently repaid in July 2019) to fund the LLOG acquisition. A summary of capital employed at June 30, 2019 and December 31, 2018 follows.

Capital Employed (contd.)

Table of Contents

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

Financial Condition (contd.)



	June 30, 2019				December 31, 2018
(Millions of dollars)	Amount		%		Amount	%
Capital employed
Long-term debt	$	4,185.9	45.1	%	3,109.3	37.4	%
Total equity	5,098.5		54.9	%	5,197.6	62.6	%
Total capital employed	9,284.4		100.0	%	8,307.0	100.0	%
Total capital employed excluding noncontrolling interest	$	8,925.9	n/a		7,938.6	n/a

Cash and invested cash are maintained in several operating locations outside the United States. At June 30, 2019, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $68.6 million in Canada and $16.3 million in Brunei. In addition, $15.9 million of cash was held in the United Kingdom and $47.8 million was held in Malaysia but was reported in current Assets held for sale on the Company’s Consolidated Balance Sheet at June 30, 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. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.

Accounting changes and recent accounting pronouncements – see Note B

Outlook

Average worldwide crude oil prices at the end of July 2019 have decreased from the average prices during the second quarter of 2019. The Company expects its total oil and natural gas production to average 203,600 – 207,600 barrels of oil equivalent per day in the third quarter 2019 (including noncontrolling interest of 11,700 BOEPD). The Company currently anticipates total capital expenditures for the full year 2019 to be between $1.35 and $1.45 billion (excluding noncontrolling interest of $48 million).

The Company will primarily fund its remaining capital program in 2019 using operating cash flow but will supplement funding where necessary with 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 July 31, 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:



Commodities	Contract or Location	Dates	Average Volumes per Day	Average Prices
U.S. Oil	West Texas Intermediate	July 2019	20,000 bbls/d	$63.64 per bbl.
U.S. Oil	West Texas Intermediate	Aug. – Dec. 2019	23,000 bbls/d	$63.17 per bbl.
U.S. Oil	West Texas Intermediate	Jan. – Dec. 2020	24,000 bbls/d	$59.67 per bbl.
Canada Natural Gas	NOVA Gas Transmission Ltd.	Apr. 2019 – Dec. 2020	59 mmcf/d	C$2.81 per mcf

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: 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 2018 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and page 37 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 L 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 commodity transactions in place at June 30, 2019, covering certain future U.S. crude oil sales volumes in 2019 and 2020. A 10% increase in the respective benchmark price of these commodities would have decreased the net receivable associated with these derivative contracts by approximately $62.3 million, while a 10% decrease would have increased the recorded receivable by a similar amount.

There were no derivative foreign exchange contracts in place at June 30, 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 June 30, 2019, there were no 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 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 2018 Form 10-K filed on February 27, 2019. The Company has not identified any additional risk factors not previously disclosed in its 2018 Form 10-K report.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCCEEDS

Issuer Purchase of Equity Securities:



Period	Total Number of Share Purchased	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under Plans or Programs¹
April 1 through April 30, 2019	—	$	—	—	$	500,000
May 1 through May 31, 2019	8,980,005	$	26.76	8,980,005	$	260,000
June 1 through June 30, 2019	2,396,400	$	24.78	2,396,400	$	200,000

¹In March 2019, the Company’s Board of Directors authorized a stock repurchase plan of up to $500 million of Murphy Common Stock. This share repurchase program expires December 31, 2020. Maximum approximate values reported represent amounts at end of month.

ITEM 6. EXHIBITS

The Exhibit Index on page 39 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.



	MURPHY OIL CORPORATION
	(Registrant)

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

August 8, 2019

(Date)

EXHIBIT INDEX



Exhibit No.

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

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