10-Q 1 mur-20180630x10q.htm 10-Q Q2 2018 10Q





















UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549





 

 



FORM 10-Q

 







 



(Mark One)

[X]

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



For the quarterly period ended June 30, 2018



OR

[  ]

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



For the transition period from              to



Commission file number 1-8590









 

Picture 3

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)







 

 

 

Delaware

 

 

71-0361522

(State or other jurisdiction of incorporation or organization)

 

 

(I.R.S. Employer Identification Number)



 

 

 

300 Peach Street, P.O. Box 7000,

 

 

 

El Dorado, Arkansas

 

 

71731-7000

(Address of principal executive offices)

 

 

(Zip Code)







(870) 862-6411

(Registrant’s telephone number, including area code)



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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). [X] 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 [X]                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. [  ]



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



Number of shares of Common Stock, $1.00 par value, outstanding at July 31, 2018 was 173,047,246.

 



 


 



MURPHY OIL CORPORATION



TABLE OF CONTENTS



 

1

 


 

 

PART I – FINANCIAL INFORMATION



ITEM 1.  FINANCIAL STATEMENTS



Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS (unaudited)

(Thousands of dollars)





 

 

 

 

 

 



 

 

 

 

 

 



 

June 30,

 

December 31,



 

2018

 

2017

ASSETS

 

 

 

 

 

 

Current assets

 

 

 

 

 

 

Cash and cash equivalents

 

$

901,308 

 

 

964,988 

Accounts receivable, less allowance for doubtful accounts of $1,605 in 
   2018 and 2017

 

 

258,366 

 

 

243,472 

Inventories, at lower of cost or market

 

 

91,376 

 

 

105,127 

Prepaid expenses

 

 

42,638 

 

 

35,087 

Assets held for sale

 

 

21,667 

 

 

22,929 

Total current assets

 

 

1,315,355 

 

 

1,371,603 

Property, plant and equipment, at cost less accumulated depreciation,
   depletion and amortization of $12,625,179 in 2018 and $12,280,741 in 2017

 

 

8,208,142 

 

 

8,220,031 

Deferred income taxes

 

 

370,641 

 

 

211,543 

Deferred charges and other assets

 

 

51,311 

 

 

57,765 



 

 

 

 

 

 

Total assets

 

$

9,945,449 

 

 

9,860,942 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

 

Current liabilities

 

 

 

 

 

 

Current maturities of long-term debt

 

$

9,674 

 

 

9,902 

Accounts payable

 

 

632,072 

 

 

595,916 

Income taxes payable

 

 

91,072 

 

 

44,604 

Other taxes payable

 

 

18,683 

 

 

23,574 

Other accrued liabilities

 

 

148,910 

 

 

156,681 

Liabilities associated with assets held for sale

 

 

3,146 

 

 

3,530 

Total current liabilities

 

 

903,557 

 

 

834,207 

Long-term debt, including capital lease obligation

 

 

2,897,345 

 

 

2,906,520 

Deferred income taxes

 

 

127,350 

 

 

159,098 

Asset retirement obligations

 

 

693,300 

 

 

709,299 

Deferred credits and other liabilities

 

 

652,259 

 

 

631,627 

Stockholders’ equity

 

 

 

 

 

 

    Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued
        

 

 

– 

 

 

– 

    Common Stock, par $1.00, authorized 450,000,000 shares, issued
          195,065,341 shares in 2018 and 195,055,724 in 2017

 

 

195,065 

 

 

195,056 

    Capital in excess of par value

 

 

898,126 

 

 

917,665 

    Retained earnings

 

 

5,402,732 

 

 

5,245,242 

    Accumulated other comprehensive loss

 

 

(575,123)

 

 

(462,243)

    Treasury stock

 

 

(1,249,162)

 

 

(1,275,529)

Total stockholders’ equity

 

 

4,671,638 

 

 

4,620,191 

Total liabilities and stockholders’ equity

 

$

9,945,449 

 

 

9,860,942 



See Notes to Consolidated Financial Statements, page 7.

2


 

 

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(Thousands of dollars, except per share amounts)







 

 

 

 

 

 

 

 



 

Three Months Ended

 

Six Months Ended



June 30,

 

June 30,



2018

 

2017 1

 

2018

 

2017 1



 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

 

     Revenue from sales to customers

$

655,150 

 

477,560 

 

1,262,104 

 

986,595 

     (Loss) gain on crude contracts

 

(37,624)

 

26,861 

 

(67,126)

 

63,938 

     Gain on sale of assets and other income

 

668 

 

3,858 

 

8,821 

 

134,386 

Total revenues

 

618,194 

 

508,279 

 

1,203,799 

 

1,184,919 



 

 

 

 

 

 

 

 

Costs and expenses

 

 

 

 

 

 

 

 

     Lease operating expenses

 

136,589 

 

111,179 

 

273,085 

 

233,321 

     Severance and ad valorem taxes

 

12,876 

 

10,742 

 

25,033 

 

21,955 

     Exploration expenses, including undeveloped
lease amortization

 

19,145 

 

20,201 

 

48,073 

 

48,864 

     Selling and general expenses

 

57,800 

 

52,809 

 

109,217 

 

102,774 

     Depreciation, depletion and amortization

 

237,997 

 

234,992 

 

468,730 

 

471,146 

     Accretion of asset retirement obligations

 

11,028 

 

10,428 

 

20,942 

 

20,984 

     Other expense (benefit)

 

659 

 

6,377 

 

(10,389)

 

8,534 

Total costs and expenses

 

476,094 

 

446,728 

 

934,691 

 

907,578 

Operating income from continuing operations

 

142,100 

 

61,551 

 

269,108 

 

277,341 



 

 

 

 

 

 

 

 

Other income (loss)

 

 

 

 

 

 

 

 

     Interest and other income (loss)

 

(15,051)

 

(38,305)

 

33 

 

(54,616)

     Interest expense, net

 

(44,723)

 

(45,145)

 

(89,772)

 

(89,742)

Total other loss

 

(59,774)

 

(83,450)

 

(89,739)

 

(144,358)



 

 

 

 

 

 

 

 

Income (loss) from continuing operations before income taxes

 

82,326 

 

(21,899)

 

179,369 

 

132,983 

Income tax expense (benefit)

 

36,410 

 

(4,545)

 

(35,237)

 

92,842 

Income (loss) from continuing operations

 

45,916 

 

(17,354)

 

214,606 

 

40,141 

Income (loss) from discontinued operations,
    net of income taxes

 

(398)

 

(217)

 

(835)

 

752 



 

 

 

 

 

 

 

 

NET INCOME (LOSS)

$

45,518 

 

(17,571)

 

213,771 

 

40,893 



 

 

 

 

 

 

 

 

INCOME (LOSS) PER COMMON SHARE – BASIC

 

 

 

 

 

 

 

 

     Continuing operations

$

0.26 

 

(0.10)

 

1.25 

 

0.23 

     Discontinued operations

 

 -

 

 -

 

(0.01)

 

0.01 

         Net Income (Loss)

$

0.26 

 

(0.10)

 

1.24 

 

0.24 



 

 

 

 

 

 

 

 

INCOME (LOSS) PER COMMON SHARE – DILUTED

 

 

 

 

 

 

 

 

     Continuing operations

$

0.26 

 

(0.10)

 

1.23 

 

0.23 

     Discontinued operations

 

 -

 

 -

 

(0.01)

 

0.01 

         Net Income (Loss)

$

0.26 

 

(0.10)

 

1.22 

 

0.24 



 

 

 

 

 

 

 

 

Cash dividends per Common share

 

0.25 

 

0.25 

 

0.50 

 

0.50 



 

 

 

 

 

 

 

 

Average Common shares outstanding (thousands)

 

 

 

 

 

 

 

 

     Basic

 

173,043 

 

172,558 

 

172,907 

 

172,482 

     Diluted

 

173,983 

 

172,558 

 

174,927 

 

173,017 





1 Reclassified to conform to current presentation (see Notes A and B). 



See Notes to Consolidated Financial Statements, page 7.







3


 

 



Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

(Thousands of dollars)









 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 



Three Months Ended

 

Six Months Ended

 



June 30,

 

June 30,

 



2018

 

2017

 

2018

 

2017

 



 

 

 

 

 

 

 

 

 

Net income

$

45,518 

 

(17,571)

 

213,771 

 

40,893 

 

Other comprehensive income (loss), net of tax

 

 

 

 

 

 

 

 

 

Net (loss) gain from foreign currency translation

 

(34,910)

 

70,220 

 

(87,185)

 

92,884 

 

Retirement and postretirement benefit plans

 

3,938 

 

2,386 

 

7,108 

 

4,773 

 

Deferred loss on interest rate hedges reclassified to interest
expense

 

586 

 

481 

 

1,171 

 

963 

 

Reclassification of certain tax effects to retained earnings

 

– 

 

– 

 

(30,237)

 

– 

 

Other

 

– 

 

– 

 

(3,737)

 

– 

 

Other comprehensive (loss) income

 

(30,386)

 

73,087 

 

(112,880)

 

98,620 

 

COMPREHENSIVE INCOME

$

15,132 

 

55,516 

 

100,891 

 

139,513 

 





See Notes to Consolidated Financial Statements, page 7.

 

4


 

 



Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)





 

 

 

 

 



 

 

 

 

 



Six Months Ended

 



June 30,

 



2018

 

2017

 

Operating Activities

 

 

 

 

 

Net income

$

213,771 

 

40,893 

 

Adjustments to reconcile net income to net cash provided by continuing operations 

 activities:

 

 

 

 

 

Loss (Income) from discontinued operations

 

835 

 

(752)

 

Depreciation, depletion and amortization

 

468,730 

 

471,146 

 

Dry hole costs (credits)

 

(11)

 

1,904 

 

Amortization of undeveloped leases

 

22,774 

 

20,306 

 

Accretion of asset retirement obligations

 

20,942 

 

20,984 

 

Deferred income tax (benefit) charge

 

(156,489)

 

33,130 

 

Pretax (gain) loss from disposition of assets

 

118 

 

(130,648)

 

Net decrease in noncash operating working capital

 

85,440 

 

42,581 

 

Other operating activities, net

 

(31,564)

 

91,918 

 

Net cash provided by continuing operations activities

 

624,546 

 

591,462 

 



 

 

 

 

 

Investing Activities

 

 

 

 

 

Property additions and dry hole costs

 

(615,144)

 

(431,654)

 

Proceeds from sales of property, plant and equipment

 

623 

 

64,303 

 

Purchases of investment securities  1

 

– 

 

(212,661)

 

Proceeds from maturity of investment securities 1

 

– 

 

284,193 

 

Net cash required by investing activities

 

(614,521)

 

(295,819)

 



 

 

 

 

 

Financing Activities

 

 

 

 

 

Capital lease obligation payments

 

(4,648)

 

(11,983)

 

Withholding tax on stock-based incentive awards

 

(6,922)

 

(7,081)

 

Cash dividends paid

 

(86,517)

 

(86,278)

 

Net cash required by financing activities

 

(98,087)

 

(105,342)

 



 

 

 

 

 

Effect of exchange rate changes on cash and cash equivalents

 

24,382 

 

(4,611)

 

Net increase (decrease) in cash and cash equivalents

 

(63,680)

 

185,690 

 



 

 

 

 

 

Cash and cash equivalents at beginning of period

 

964,988 

 

872,797 

 



 

 

 

 

 

Cash and cash equivalents at end of period

$

901,308 

 

1,058,487 

 





 

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



See Notes to Consolidated Financial Statements, page 7.

5


 

 





Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

(Thousands of dollars)





 

 

 

 

 



 

 

 

 

 



Six Months Ended



June 30,



2018

 

2017

Cumulative Preferred Stock – par $100, authorized 400,000 shares,
   none issued

$

– 

 

 

– 

Common Stock – par $1.00, authorized 450,000,000 shares, issued 195,065,341
    shares at June 30, 2018 and 195,055,724 shares at  June 30, 2017

 

 

 

 

 

Balance at beginning of period

 

195,056 

 

 

195,056 

Exercise of stock options

 

 

 

– 

Balance at end of period

 

195,065 

 

 

195,056 

Capital in Excess of Par Value

 

 

 

 

 

Balance at beginning of period

 

917,665 

 

 

916,799 

Exercise of stock options, including income tax benefits

 

(175)

 

 

– 

Restricted stock transactions and other

 

(32,766)

 

 

(26,483)

Stock-based compensation

 

13,402 

 

 

13,302 

Other

 

– 

 

 

(76)

Balance at end of period

 

898,126 

 

 

903,542 

Retained Earnings

 

 

 

 

 

Balance at beginning of period

 

5,245,242 

 

 

5,729,596 

Net income for the period

 

213,771 

 

 

40,893 

Reclassification of certain tax effects from accumulated other comprehensive loss

 

30,237 

 

 

– 

Cash dividends

 

(86,518)

 

 

(86,278)

Balance at end of period

 

5,402,732 

 

 

5,684,211 

Accumulated Other Comprehensive Loss

 

 

 

 

 

Balance at beginning of period

 

(462,243)

 

 

(628,212)

Foreign currency translation (loss) gain, net of income taxes

 

(87,185)

 

 

92,884 

Retirement and postretirement benefit plans, net of income taxes

 

7,108 

 

 

4,773 

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

 

1,171 

 

 

963 

Reclassification of certain tax effects to retained earnings

 

(30,237)

 

 

– 

Other

 

(3,737)

 

 

– 

Balance at end of period

 

(575,123)

 

 

(529,592)

Treasury Stock

 

 

 

 

 

Balance at beginning of period

 

(1,275,529)

 

 

(1,296,560)

Sale of stock under employee stock purchase plan

 

– 

 

 

145 

Awarded restricted stock, net of forfeitures

 

26,367 

 

 

20,886 

Balance at end of period – 22,018,095 shares of Common Stock in
   2018 and 22,482,581 shares of Common Stock in 2017, at cost

 

(1,249,162)

 

 

(1,275,529)

Total Stockholders’ Equity

$

4,671,638 

 

 

4,977,688 



See Notes to Consolidated Financial Statements, page 7.



 

6


 

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 produces oil and natural gas in the United States, Canada and Malaysia and conducts oil and natural gas exploration activities worldwide.

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, 2018 and December 31, 2017, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended June 30, 2018 and 2017, 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 2017 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report.  Financial results for the six-month period ended June 30, 2018 are not necessarily indicative of future results.

Beginning in the period ended September 30, 2017, certain reclassifications in presentation have been made to the Consolidated Statements of Operations.  The Company now presents a separate “Operating income (loss) from continuing operations” subtotal on the Consolidated Statements of Operations.  Additionally, “Interest and other income (loss),” which includes foreign exchange gains and losses, has been reclassified from a component of total revenues and is now presented below Operating income (loss) from continuing operations.  “Interest expense” and “Capitalized interest” have also been combined into the “Interest expense, net” line item and is now presented below “Operating income (loss) from continuing operations.”  Previously reported periods have been reclassified to conform to the current period presentation.  These reclassifications did not impact previously reported Income from continuing operations before income taxes, Income from continuing operations, or Net income.



Note B – New Accounting Principles and Recent Accounting Pronouncements

Accounting Principles Adopted

Revenue from Contracts with Customers.  In May 2014, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU), which established a comprehensive model of accounting for revenue arising from contracts with customers that superseded most revenue recognition requirements and industry-specific guidance.  Under the new standard, the Company recognizes revenue when it transfers control of the commodity to customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for the commodity.  Additional disclosures are required to describe the nature, amount, timing and uncertainly of revenue and cash flows from contracts with customers.  The Company adopted the new standard in the first quarter of 2018 using the modified retrospective method.  The Company performed a review of contracts in each of its revenue streams and implemented accounting policies and internal controls to address the requirements of the ASU.  Prior to January 1, 2018, the Company followed the sales method of revenue recognition under Accounting Standards Codification (ASC) Topic 605 and recorded revenue when deliveries occured and legal ownership of the commodity transferred to the customer.

There was no adjustment to the opening balance of stockholders’ equity as at January 1, 2018, resulting from application of the new ASU promulgated in ASC Topic 606 using the modified retrospective method.  The comparative information has not been adjusted and continues to be reported under ASC Topic 605 – Revenue Recognition.  See also Note C for further discussion of Revenue Recognition. 

Statement of Cash Flows.  In August 2016, the FASB issued an ASU to reduce diversity in practice in how certain transactions are classified in the statement of cash flows.  The amendment provides guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instrument with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees.  The amendments in this ASU were effective for annual and interim periods beginning after December 15, 2017.  The Company adopted this guidance in the first quarter of 2018 and it did not have a material impact on its consolidated financial statements.





7


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

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

Accounting Principles Adopted (Cont.)

Compensation – Retirement Benefits.  In March 2017, the FASB issued an ASU requiring that the service cost component of pension and postretirement benefit costs be presented in the same line item as other current employee compensation costs and other components of those benefit costs be presented separately from the service cost component outside a subtotal of income from operations, if presented.  The update also requires that only the service cost component of pension and postretirement benefit cost is eligible for capitalization.  The update is effective for annual and interim periods beginning after December 15, 2017.  The Company adopted the standard in the first quarter of 2018 and it did not have a material impact on its consolidated financial statements.

Compensation – Stock Compensation.  In May 2017, the FASB issued an ASU which amends the scope of modification accounting for share-based payment arrangements and provides guidance on the type of changes to the terms and conditions of share-based payment awards to which an entity would be required to apply modification accounting.  The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period.  The Company adopted this accounting standard in the first quarter of 2018 and it did not have material impact on its consolidated financial statements.

Statement of Operations – Reporting Comprehensive Income.  In February 2018, the FASB issued an ASU, which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act.  The Company elected to early adopt this accounting standard during the first quarter of 2018 and recorded discrete adjustments from accumulated other comprehensive income to retained earnings of $28.4 million related to retirement and postretirement obligations and $1.8 million related to deferred loss on interest rate derivative hedges.  The adoption of this ASU will have no future impact.

Recent Accounting Pronouncements

Leases.  In February 2016, the FASB issued an ASU to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements.  The main difference between previous Generally Accepted Accounting Principles (GAAP) and this ASU is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP.  The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods.  Early adoption is permitted for all entities.  The Company anticipates adopting this guidance in the first quarter of 2019 and is currently assessing internal processes and analyzing its portfolio of contracts to assess the impact future adoption of this ASU will have on its consolidated financial statements.

Compensation – Stock Compensation.  In June 2018, the FASB issued an ASU which supersedes existing guidance for equity-based payments to nonemployees and expands the scope of guidance for stock compensation to include all share-based payment arrangements related to the acquisition of goods and services from both nonemployees and employees.  As a result, the same guidance that provides for employee share-based payments, including most of its requirements related to classification and measurement, applies to nonemployee share-based payment arrangements. The ASU is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods.  Early adoption is permitted.  The Company anticipates adopting this guidance for the first quarter of 2019 and does not expect it to have a material impact on its consolidated financial statements.



Note C – Revenue from Contracts with Customers

Significant Accounting Policy

Revenue is recognized when the Company satisfies a performance obligation by transferring control over a commodity to a customer; the amount of revenue recognized reflects the consideration expected in exchange for those commodities.  The Company measures revenue based on consideration specified in a contract and excludes taxes and other amounts collected on behalf of third parties.

Revenue is presented as Company share net of certain costs associated with generation of Revenue. Examples of costs that reduce revenue include transportation, gathering, compression, and processing fees in U.S. and Canada, as well as certain required payments associated with production sharing contracts (PSCs) and export taxes in Malaysia

Nature of Goods and Services

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

8


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

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

For operated oil and gas production where the non-operated working interest owner does not take-in-kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production. 

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

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

Malaysia-  In Malaysia, the Company has interests in nine separate PSCs. The Company serves as the operator of all these areas except for the unitized Kakap-Gumusut field. Crude oil contracts in Malaysia share similar features of largely fixed cargo quantities, variable index-based pricing, and potential discounts at the point of meeting the performance obligation when the vessel is loaded.  Malaysia also has three long term Gas Sales Agreements (GSA) with terms until the end of the field life, economic life, or PSC term.

Disaggregation of Revenue

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

For the three months ended June 30, 2018 and 2017, the Company recognized $655.2 million and $477.6 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas.  For the six months ended June 30, 2018 and 2017, the Company recognized $1,262.1 million and $986.6 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas. 

9


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

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









 

 

 

 

 

 

 

 



 

Three Months Ended

 

Six Months Ended



 

June 30,

 

June 30,

(Thousands of dollars)

 

2018

 

2017

 

2018

 

2017

Net crude oil and condensate revenue

 

 

 

 

 

 

 

 

United States – Onshore

$

198,823 

 

143,684 

 

381,472 

 

293,671 

– Offshore

 

94,393 

 

47,669 

 

165,922 

 

101,481 

Canada    – Onshore

 

28,425 

 

11,658 

 

49,719 

 

20,778 

– Offshore

 

48,316 

 

38,863 

 

102,631 

 

75,877 

Malaysia – Sarawak

 

85,596 

 

59,758 

 

162,902 

 

125,542 

– Block K

 

101,609 

 

76,741 

 

196,181 

 

164,572 

Total crude oil and condensate revenue

 

557,162 

 

378,373 

 

1,058,827 

 

781,921 



 

 

 

 

 

 

 

 

Net natural gas liquids revenue

 

 

 

 

 

 

 

 

United States – Onshore

 

13,236 

 

9,077 

 

25,370 

 

18,724 

– Offshore

 

2,920 

 

1,209 

 

4,559 

 

3,125 

Canada    – Onshore

 

3,448 

 

881 

 

6,916 

 

1,313 

Malaysia – Sarawak

 

4,002 

 

3,358 

 

10,193 

 

8,541 

Total natural gas liquids revenue

 

23,606 

 

14,525 

 

47,038 

 

31,703 



 

 

 

 

 

 

 

 

Net natural gas revenue

 

 

 

 

 

 

 

 

United States – Onshore

 

6,291 

 

8,006 

 

13,062 

 

15,041 

– Offshore

 

2,826 

 

2,718 

 

5,762 

 

5,381 

Canada    – Onshore

 

28,089 

 

37,951 

 

67,683 

 

77,798 

Malaysia – Sarawak

 

36,997 

 

35,829 

 

69,380 

 

74,418 

– Block K

 

179 

 

158 

 

352 

 

333 

Total natural gas revenue

 

74,382 

 

84,662 

 

156,239 

 

172,971 

Total revenue from contracts with customers

 

655,150 

 

477,560 

 

1,262,104 

 

986,595 



 

 

 

 

 

 

 

 

Gain (loss) on crude contracts

 

(37,624)

 

26,861 

 

(67,126)

 

63,938 

Other operating income (loss)

 

448 

 

5,191 

 

8,939 

 

3,738 

Gain (loss) on sale of assets

 

220 

 

(1,333)

 

(118)

 

130,648 

Total revenue

$

618,194 

 

508,279 

 

1,203,799 

 

1,184,919 



Contract Balances and Asset Recognition

As of June 30, 2018, and December 31, 2017, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet, were $190.7 million and $203.4 million, respectively. Payment terms for Murphy’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, 2018.

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













10


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

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

Performance Obligations

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

For contracts with market or index-based pricing, which represent the majority of Murphy’s 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 at June 30, 2018, 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, 2018

Location

 

Commodity

 

End Date

 

Description

 

Approximate Volumes

U.S. Onshore

 

Oil

 

Q2 2019

 

Fixed quantity delivery in Eagle Ford

 

4,000 BOE/Day

U.S. Onshore

 

Oil

 

Q3 2019

 

Fixed quantity delivery in Eagle Ford

 

2,000 BOE/Day

U.S. Onshore

 

Oil

 

Q4 2021

 

Fixed quantity delivery in Eagle Ford

 

2018: 19,000 BOE/Day
2019-2021: 13,000 BOE/Day

U.S. Onshore

 

Gas and NGL

 

Q2 2026

 

Deliveries from dedicated acreage in
   Eagle Ford

 

As produced

Canada Onshore

 

Gas

 

Q4 2020

 

Contracts to sell natural gas
at Alberta AECO Cdn dollar 2.81/MCF

 

59 MMCF/Day

Canada Onshore

 

Gas

 

Q4 2020

 

Contracts to sell natural gas at USD Index
pricing

 

60 MMCF/Day

Canada Onshore

 

Gas

 

Q4 2024

 

Contracts to sell natural gas at USD Index
pricing

 

30 MMCF/Day

Canada Onshore

 

Gas

 

Q4 2026

 

Contracts to sell natural gas at USD Index
pricing

 

38 MMCF/Day









11


 

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, 2018, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $206.4 million.  The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30, 2018 and 2017.





 

 

 

 

 



 

 

 

 

 

(Thousands of dollars)

2018

 

 

2017

Beginning balance at January 1

$

175,640 

 

 

148,500 

Additions pending the determination of proved reserves

 

30,731 

 

 

48,764 

Reclassifications to proved properties based on the determination of proved reserves

 

– 

 

 

(13,370)

Capitalized exploratory well costs charged to expense

 

– 

 

 

(8,360)

Balance at June 30

$

206,371 

 

 

175,534 

There were no capitalized well costs charged to expense during the first six months of 2018.  The capitalized well costs charged to expense during the first six months of 2017 included the Marakas-01 well in Block SK314A, offshore Malaysia, in which development of the well could not be justified due to noncommercial hydrocarbon quantities found.

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





 

 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 

 

 



 

June 30,



2018

 

2017

(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

$

34,779 

 

 

 

$

57,900 

 

 

One to two years

 

35,934 

 

 

 

 

53,023 

 

 

Two to three years

 

50,272 

 

 

 

 

– 

 

– 

 

– 

Three years or more

 

85,386 

 

 

 

 

64,611 

 

 

– 



$

206,371 

 

13 

 

 

$

175,534 

 

12 

 



Of the $171.6 million of exploratory well costs capitalized more than one year at June 30, 2018, $70.4 million is in Brunei, $52.6 million is in Vietnam, $27.8 million is in the U.S. and $20.8 million is in Malaysia.  In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. 

Divestments

In January 2017, a Canadian subsidiary of the Company completed its disposition of the Seal field in Western Canada.  Total cash consideration to Murphy upon closing of the transaction was approximately $48.8 million.  Additionally, the buyer assumed the asset retirement obligation of approximately $85.9 million.  A $132.4 million pretax gain was reported in the 2017 period related to the sale.  Also, in 2017, a U.S. subsidiary of the Company completed its disposition of certain non-core properties in the Eagle Ford Shale area.  Total cash consideration to Murphy upon closing of the transaction was approximately $19.6 million.  There were no gains or losses recorded related to these non-core Eagle Ford Shale sales.

In 2016, a Canadian subsidiary of the Company completed a divestiture of natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia.  Total cash consideration received upon closing was $414.1 million.  A gain on sale of approximately $187.0 million was deferred and is being recognized over approximately the next 18 years in the Canadian operating segment.  The Company amortized approximately $3.8 million and $3.4 million of the deferred gain during the first six months of 2018 and 2017, respectively.  The remaining deferred gain of $170.2 million was included as a component of Deferred credits and other liabilities in the Company’s Consolidated Balance Sheet as of June 30, 2018.

12


 

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) of Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30% non-operated WI of Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta, the majority of which was unproved.  Under the terms of the joint venture, the total consideration amounts to approximately $375.0 million of which Murphy paid $206.7 million in cash at closing, subject to normal closing adjustments, and an additional $168.0 million in the form of a carried interest on the Kaybob Duvernay property.  As of June 30, 2018, $75.4 million of the carried interest had been paid.  The carry is to be paid over a period up to 2021.

Other

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

Following a further Unitization Framework Agreement (UFA) between the governments of Brunei and Malaysia, the Company now has a 6.37% interest in the Kakap field in Block K Malaysia.  The UFA unitized the Gumusut/Kakap (GK) and Geronggong/Jagus East fields effective November 23, 2017.  In the fourth quarter 2017, the Company recorded an estimated redetermination expense of $15.0 million ($9.3 million after tax) related to Company’s revised working interest. The remaining redetermination liability of $15.0 million was included as a component of Other current liabilities in the Company’s Consolidated Balance Sheet as of June 30, 2018.



Note E – Discontinued Operations and Assets Held for Sale

The Company has accounted for its former U.K. and U.S. refining and marketing operations as discontinued operations for all periods presented.  The results of operations associated with discontinued operations for the three-month and six-month periods ended June 30, 2018 and 2017 were as follows:





 

 

 

 

 

 

 

 

 



Three Months

 

Six Months

 



Ended June 30,

 

Ended June 30,

 

(Thousands of dollars)

 

2018

 

2017

 

2018

 

2017

 

Revenues

$

 

126 

 

 

256 

 

Income (loss) before income taxes

 

(398)

 

(217)

 

(835)

 

752 

 

Income tax benefit

 

– 

 

– 

 

– 

 

– 

 

Income (loss) from discontinued operations

$

(398)

 

(217)

 

(835)

 

752 

 



The following table presents the carrying value of the major categories of assets and liabilities of U.K. refining and marketing operations reflected as held for sale on the Company’s Consolidated Balance Sheets at June 30, 2018 and December 31, 2017.



 

 

 

 



 

 

 

 



 

June 30,

 

December 31,

(Thousands of dollars)

 

2018

 

2017

Current assets

 

 

 

 

Cash

$

14,609 

 

16,631 

Accounts receivable

 

7,058 

 

6,298 

Total current assets held for sale

$

21,667 

 

22,929 

Current liabilities

 

 

 

 

Accounts payable

$

488 

 

837 

Refinery decommissioning cost

 

2,658 

 

2,693 

Total current liabilities associated with assets held for sale

$

3,146 

 

3,530 



13


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 



Note F – Financing Arrangements and Debt

At June 30, 2018, the Company had a $1.1 billion senior unsecured guaranteed credit facility (2016 facility) with a major banking consortium, which expires in August 2021.  At June 30, 2018, the Company had no outstanding borrowings under the 2016 facility, however, there were $27.9 million of outstanding letters of credit, which reduce the borrowing capacity of the 2016 facility.  Advances under the 2016 facility will accrue interest based, at the Company’s option, on either the London Interbank Offered rate plus an applicable margin (Eurodollar rate) or the alternate base rate (as defined in the 2016 facility agreement) plus an applicable margin. Had there been any amounts borrowed under the 2016 facility at June 30, 2018, the applicable base interest rate would have been 5.5375%.  At June 30, 2018, the Company was in compliance with all covenants related to the 2016 facility.

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

The Company and its partners are parties to a 25-year lease of production equipment at the Kakap field offshore Malaysia.  The lease has been accounted for as a capital lease, and payments under the agreement are to be made over a 15-year period through March 2029.  Current maturities of long-term debt and long-term debt on the Consolidated Balance Sheet included $9.7 million and $122.9 million, respectively, associated with this lease at June 30, 2018.



Note G – Other Financial Information

Additional disclosures regarding cash flow activities are provided below.





 

 

 

 

 



Six Months Ended June 30,

 

(Thousands of dollars)

2018

 

2017

 

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

 

 

 

 

 

(Increase) decrease in accounts receivable

$

(15,528)

 

125,283 

 

Decrease in inventories

 

16,929 

 

5,918 

 

(Increase) decrease in prepaid expenses

 

(7,890)

 

9,206 

 

Increase (decrease) in accounts payable and accrued liabilities

 

49,311 

 

(136,500)

 

Increase in income taxes payable

 

42,618 

 

38,674 

 

Net decrease in noncash operating working capital

$

85,440 

 

42,581 

 

Supplementary disclosures:

 

 

 

 

 

Cash income taxes paid, net of refunds

$

36,618 

 

9,448 

 

Interest paid, net of amounts capitalized of $2,377 in 2018
and $2,449 in 2017

 

79,279 

 

72,136 

 



 

 

 

 

 

Non-cash investing activities:

 

 

 

 

 

Asset retirement costs capitalized

$

1,608 

 

797 

 

Decrease in capital expenditure accrual

 

39,322 

 

43,370 

 





14


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note H – Employee and Retiree Benefit Plans

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

The table that follows provides the components of net periodic benefit expense for the three-month and six-month periods ended June 30, 2018 and 2017.







 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 



Three Months Ended June 30,



Pension Benefits

 

Other Postretirement Benefits

(Thousands of dollars)

 

2018

 

 

2017

 

2018

 

2017

Service cost

$

2,254 

 

 

2,030 

 

 

493 

 

 

424 

Interest cost

 

6,707 

 

 

6,287 

 

 

874 

 

 

967 

Expected return on plan assets

 

(7,453)

 

 

(6,475)

 

 

– 

 

 

– 

Amortization of prior service cost (credit)

 

256 

 

 

254 

 

 

(9)

 

 

(19)

Recognized actuarial loss

 

5,181 

 

 

3,509 

 

 

– 

 

 

– 

Net periodic benefit expense

$

6,945 

 

 

5,605 

 

 

1,358 

 

 

1,372 



 

 

 

 

 

 

 

 

 

 

 



Six Months Ended June 30,



Pension Benefits

 

Other Postretirement Benefits

(Thousands of dollars)

 

2018

 

 

2017

 

2018

 

2017

Service cost

$

4,509 

 

 

4,062 

 

 

987 

 

 

849 

Interest cost

 

13,444 

 

 

13,006 

 

 

1,748 

 

 

1,933 

Expected return on plan assets

 

(14,959)

 

 

(13,660)

 

 

– 

 

 

– 

Amortization of prior service cost (credit)

 

513 

 

 

508 

 

 

(19)

 

 

(37)

Recognized actuarial loss

 

10,396 

 

 

7,063 

 

 

– 

 

 

– 

Net periodic benefit expense

$

13,903 

 

 

10,979 

 

 

2,716 

 

 

2,745 

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, 2018, the Company made contributions of $13.2 million to its defined benefit pension and postretirement benefit plans.  Remaining funding in 2018 for the Company’s defined benefit pension and postretirement plans is anticipated to be $16.5 million. 

15


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

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 2012 Long-Term Incentive Plan (2012 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees.  These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives.  The 2012 Long-Term Plan expires in 2022.  A total of 8,700,000 shares are issuable during the life of the 2012 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 had a 2013 Stock Plan for Non-Employee Directors (Director Plan) that permitted the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.  This plan expired in May 2018.

At the Annual Shareholder Meeting held in May 2018, shareholders approved the 2018 Stock Plan for Non-Employee Directors and the 2018 Long-Term Incentive Plan.  No further awards will be granted under the 2012 Long-Term Plan.

The Company had an Employee Stock Purchase Plan (ESPP) that permitted the issuance of Company shares during the first six months of 2017.  The ESPP terminated on June 30, 2017 and was not renewed by the Company.

In the first quarter of 2018, the Committee granted 905,500 performance-based RSUs and 736,000 time-based RSUs to certain employees.  The fair value of the performance-based RSUs, using a Monte Carlo valuation model, ranged from $28.27 to $30.56 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 February 6, 2018 was $28.42 per unit, the fair value of the time-based RSUs granted February 20, 2018 was $26.56 per unit, and the fair value of the time-based RSUs granted March 1, 2018 was $25.69 per unit.  Additionally, on February 6, 2018 the Committee granted 715,100 cash-settled RSUs (RSUC) to certain employees, and on March 9, 2018 granted 29,000 RSUCs to certain employees.  The RSUC 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 RSUCs was equivalent to the equity-settled restricted stock units granted.  Also in February, the Committee granted 77,803 shares of time-based RSUs to the Company’s Directors under the Non-Employee Director Plan.  These units are scheduled to vest on the third anniversary of the date of grant. The estimated fair value of these awards was $28.28 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, 2018.

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







 

 

 

 



 

 

 

 



Six Months Ended



June 30,

(Thousands of dollars)

 

2018

 

2017

Compensation charged against income before tax benefit

$

18,970 

 

16,722 

Related income tax benefit recognized in income

 

2,463 

 

5,425 

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).



16


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note J – Earnings per Share

Net income 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, 2018 and 2017.  The following table reconciles the weighted-average shares outstanding used for these computations.





 

 

 

 

 

 

 



 

 

 

 

 

 

 



Three Months Ended

 

Six Months Ended



June 30,

 

June 30,

(Weighted-average shares)

2018

 

2017

 

2018

 

2017

Basic method

173,042,626 

 

172,557,978 

 

172,907,537 

 

172,482,223 

Dilutive stock options and restricted stock units

939,994 

 

– 

1

2,019,525 

 

534,441 

   Diluted method

173,982,620 

 

172,557,978 

 

174,927,062 

 

173,016,664 

1Due to a net loss in the three-month period ended June 30, 2017, no unvested stock awards were included in the computation of diluted earnings per shares because the effect would have been anti-dilutive.



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 assumed conversion were antidilutive.



 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 



Three Months Ended

 

Six Months Ended



 

June 30,

 

June 30,



 

2018

 

2017

 

2018

 

2017

Antidilutive stock options excluded from diluted shares

 

3,396,951 

 

 

5,578,634 

 

 

3,622,106 

 

 

4,903,084 

Weighted average price of these options

$

50.22 

 

$

46.64 

 

$

50.56 

 

$

52.01 





 

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, 2018 and 2017, the Company’s effective income tax rates were as follows:



 

 

 



2018

 

2017

Three months ended June 30

44.2%

 

20.7%

Six months ended June 30

(19.6)%

 

69.8%

The effective tax rates for most periods where earnings are generated, generally exceed the U.S. statutory tax rate (21% in 2018, 35% in 2017) due to several factors, including:  the effects of income generated in foreign tax jurisdictions, certain of which have income tax rates that are higher than the U.S. Federal rate; U.S. state tax expense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are available or are not presently being recorded due to a lack of reasonable certainty of adequate future revenue against which to utilize these expenses as deductions.  Conversely, the effective tax rates for most periods where losses are incurred generally are lower than U.S. statutory tax rate of 21% due to similar reasons. 

Due to uncertainty related to language in Section 965(n) of the 2017 Tax Act, and specifically whether current operating losses from 2017 were required to be applied to offset a company’s deemed taxable repatriation of foreign earnings under the 2017 Tax Act, the Company’s provisional tax expense recorded in the Company’s December 31, 2017 financial statements reflected use of all the estimated 2017 tax operating loss against the deemed repatriation.  This resulted in no loss carryover of 2017 tax operating losses from 2017 into 2018, and foreign tax credits of $228.2 million were fully provided for in the Company’s December 31, 2017 financial statements.  On April 2, 2018, the Internal Revenue Service issued new guidance related to the Section 965(n) election.  This guidance resolved the ambiguity and allowed the Company to preserve the 2017 tax net operating loss as a carryforward by allowing the crediting of the previously unused foreign tax credits against all but $36 million of current income tax on the deemed repatriation of foreign earnings.  The preservation of the tax loss carryforward reduced the deferred tax expense for the first quarter of 2018 by $156 million and resulted in a $36 million charge to taxes payable relating to the deemed inclusion.  The Company anticipates paying this $36 million tax payable over eight years as permitted by the 2017 Tax Act.

17


 

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 above the U.S. statutory tax rate of 21% primarily due to higher tax rates in certain foreign tax jurisdictions combined with expenses in foreign jurisdictions not fully deductible from income at the U.S. statutory rate.  The effective tax rate for the three-month period ended June 30, 2017 was below the U.S. statutory tax rate primarily due to a tax benefit related to certain foreign investments, partially offset by income tax expense related to undistributed foreign earnings.

The effective tax rate for the six-month period ended June 30, 2018 was below the U.S. statutory tax rate of 21% primarily due to the discrete tax effect of the new guidance relating to Section 965(n), offset by higher tax rates in certain foreign tax jurisdictions.  These impacts were partially offset by higher tax rates in certain foreign tax jurisdictions and expenses in foreign jurisdictions not fully deductible from income at the U.S. statutory tax rate.  The effective tax rate for the six-month period ended June 30, 2017 was above the U.S. statutory tax rate due to the Company recording a deferred tax charge of $60.4 million associated with the estimated tax consequence of future repatriation of foreign earnings not considered reinvested into local operations. 

The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities.  These audits often take years to complete and settle.  Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters.  As of June 30, 2018, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2014; Canada – 2012; Malaysia – 2011; and United Kingdom – 2016.



Note L – Financial Instruments and Risk Management

Murphy often uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates.  The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management.  The Company reports gains and losses on derivative instruments in the Corporate segment.  The Company does not hold any derivatives for speculative purposes and it does not use derivatives with leveraged or complex features.  Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges, such as the New York Mercantile Exchange (NYMEX).  The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks.  For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations.  Certain interest rate derivative contracts were accounted for as hedges and the gain or loss associated with recording the fair value of these contracts was deferred in Accumulated other comprehensive loss until the anticipated transactions occur.  This deferred cost is being reclassified to Interest expense, net in the Consolidated Statements of Operations over the period until the associated notes mature in 2022.

Commodity Price Risks

The Company is subject to commodity price risk related to crude oil it produces and sells.  During the first half of 2018 and 2017, the Company had West Texas Intermediate (WTI) crude oil swap financial contracts to economically hedge a portion of its United States production.  Under these contracts, which matured monthly, the Company paid the average monthly price in effect and received the fixed contract prices.  At June 30, 2018, the Company had 21,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during the remainder of 2018 at an average price of $54.88

At June 30, 2017, the Company had 22,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2017. 

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, 2018 and 2017.

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







 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 



 

June 30, 2018

 

December 31, 2017

(Thousands of dollars)

 

Asset (Liability) Derivatives

 

Asset (Liability) Derivatives

Type of Derivative Contract

 

Balance Sheet Location

 

Fair Value

 

Balance Sheet Location

 

Fair Value

Commodity

 

Accounts payable

 

$

(68,882)

 

Accounts payable

 

$

(39,093)





18


 

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







 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

Gain (Loss)



 

 

 

Three Months Ended

 

Six Months Ended

(Thousands of dollars)

 

 

 

June 30,

 

June 30,

Type of Derivative Contract

 

Statement of Operations Location

 

 

2018

 

2017

 

2018

 

2017

Commodity

 

Gain (loss) on crude contracts

 

$

(37,624)

 

26,861 

 

(67,126)

 

63,938 

Foreign exchange

 

Interest and other income (loss)

 

 

– 

 

(152)

 

– 

 

73 



 

 

 

$

(37,624)

 

26,709 

 

(67,126)

 

64,011 

Interest Rate Risks

Under hedge accounting rules, the Company deferred the net cost associated with derivative contracts purchased to manage interest rate risk associated with 10-year notes sold in May 2012 to match the payment of interest on these notes through 2022.  During each of the six-month periods ended June 30, 2018 and 2017, $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, 2018 was $9.1 million, which is recorded, net of income taxes of $2.4 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 2018.

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, 2018 and December 31, 2017 are presented in the following table.