UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549





















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, or a smaller reporting 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 [  ]



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

(§240.12b-2 of this chapter). Emerging growth company [  ]



If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to

Section 13(a) of the Exchange Act.  [  ]



Number of shares of Common Stock, $1.00 par value, outstanding at July 31, 2017 was 172,572,873





 

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MURPHY OIL CORPORATION



TABLE OF CONTENTS



 

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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)





See Notes to Consolidated Financial Statements, page 7.



The Exhibit Index is on page 35.

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Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(Thousands of dollars, except per share amounts)







See Notes to Consolidated Financial Statements, page 7. 

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Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (unaudited)

(Thousands of dollars)









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)









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



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)





See Notes to Consolidated Financial Statements, page 7.

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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, 2017 and December 31, 2016, and the results of operations,  cash flows and changes in stockholders’ equity for the interim periods ended June  30, 2017 and 2016, in conformity with accounting principles generally accepted in the United States of America (U.S.).  In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the U.S., management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities.  Actual results may differ from the estimates.



Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company's 2016 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, 2017 are not necessarily indicative of future results.



Note B – Property, Plant and Equipment





Exploratory Wells



Under Financial Accounting Standards Board (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, 2017, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $175.5 million.  The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30,  2017 and 2016.





 

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



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.





Of the $117.6 million of exploratory well costs capitalized more than one year at June 30, 2017, $70.4 million is in Brunei, $43.2 million is in Vietnam and $4.0 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.  The capitalized well costs charged to expense during the first six months of 2017 included one well in Block H, offshore Malaysia in which development of the well could not be justified due to noncommercial hydrocarbon quantities found and change in development plan due to low commodity prices.



Divestments



In January 2017, a Canadian subsidiary of the Company completed its disposition of the Seal field in Western Canada.  Total cash consideration to Murphy upon closing of the transaction was approximately $49.0 million.  Additionally, the buyer assumed the asset retirement obligation of approximately $85.9 million.  A  $132.4 million pretax gain was reported in the first quarter of 2017 related to the sale. Also, in January 2017, a U.S. subsidiary of the Company completed its disposition of several non-core properties in the North Tilden area of Eagle Ford Shale.  Total cash consideration to Murphy upon closing of the transaction was approximately $14.8 million.  There was no gain or loss recorded related to this sale.



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



During the second quarter 2016, a Canadian subsidiary of the Company completed a divestiture of natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia.  A gain on sale of approximately $187.0 million was deferred and is being recognized over the next 19 years in the Canadian operating segment.  The Company amortized approximately $3.4 million of the deferred gain during the six-month period ended June 30, 2017.  The remaining deferred gain of $179.8 million was included as a component of deferred credits and other liabilities in the Company’s Consolidated Balance Sheets.



Acquisitions



During the second quarter 2016, a Canadian subsidiary acquired a 70 percent operated working interest (WI) of Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30 percent 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.   $24.7 million of the carried interest had been paid at June 30, 2017.  The carry is to be paid over a period of up to five years from 2016.

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



Impairments



During the first quarter of 2016, declines in future oil and gas prices led to impairments in certain of the Company’s producing properties and the Company recorded pretax noncash impairment charges of $95.1 million to reduce the carrying values to their estimated fair values for the Terra Nova field offshore Canada and the Western Canada onshore heavy oil producing properties at Seal.  The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, costs, and a discount rate believed to be consistent with those used by principal market participants in the applicable region. 



Other



The Company has an interest in the Kakap field in Block K Malaysia.  The Kakap field is operated by another company and was jointly developed with the Gumusut field owned by others.  As required by the agreements governing the field, a redetermination (unitization) review was required in 2016.  In the fourth quarter 2016, the Company recorded $39.1 million in redetermination (unitization) expense related to an expected reduction in the Company’s working interest covering the period from inception through year-end 2016 at Kakap.  In February 2017, PETRONAS officially approved the redetermination that reduces the Company’s working interest, from 8.6% to approximately 6.7%,  effective April 1, 2017.  The Company partially settled $21.8 million of the redetermination expense in cash in the second quarter of 2017. The Company currently expects to settle the remainder in the third quarter of 2017.  It is possible that the final adjustment amount could be different than the current estimate.    Due to the change in working interest, the future payments under a capital lease of a floating, production and storage facility in the Kakap field are lower and the Company has reduced the total debt recorded on the Consolidated Balance Sheet by approximately $56.7 million, with a similar reduction to Property, plant and equipment.



Note C – Discontinued Operations



The Company has accounted for its former U.K. 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, 2017 and 2016 were as follows:







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, 2017 and December 31, 2016.  





 

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Note D – Financing Arrangements and Debt



At June 30, 2017, the Company has a $1.1 billion senior unsecured guaranteed credit facility (2016 facility) with a major banking consortium, which expires in August 2019.  At June 30, 2017, the Company had no outstanding borrowings under the 2016 facility, however, there were $178.1 million of outstanding letters of credit.    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, 2017, the applicable base rate would have been 5.25%.  At June 30, 2017, 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 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 June 2028.  Current maturities of long-term debt and long-term debt on the Consolidated Balance Sheet included $9.6 million and $137.9 million, respectively, associated with this lease at June 30, 2017.



Note E – Other Financial Information



Additional disclosures regarding cash flow activities are provided below.







*    2016 balances included payments for deepwater rig contract exit of $261.8 million.



 



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Note F – 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.  Additionally, most U.S. retired employees are covered by a life insurance benefit plan.  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, 2017 and 2016.







During the six-month period ended June 30, 2017, the Company made contributions of $16.1 million to its defined benefit pension and postretirement benefit plans.  Remaining required funding in 2017 for the Company’s defined benefit pension and postretirement plans is anticipated to be $14.7 million.  Curtailment expense for the six months ended June 30, 2016, shown in the table above relate to restructuring activities in the U.S. undertaken by the Company in the first quarter 2016.

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Note G – Incentive Plans



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



The 2012 Annual Incentive Plan (2012 Annual Plan) authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees.  Cash awards under the 2012 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 has a 2013 Stock Plan for Non-Employee Directors (Director Plan) that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.



The Company had an Employee Stock Purchase Plan (ESPP) that permitted the issuance of Company shares during 2016 and the first six months of 2017.    The ESPP terminated on June 30, 2017 and was not renewed by the Company.



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

RSU and 282,000 time-based RSU in February 2017.  The fair value of the performance-based RSU, using a Monte Carlo valuation model, ranged from $24.10 to $28.28 per unit.  The fair value of time-based RSU was estimated based on the fair market value of the Company’s stock on the date of grant, which was $28.505 per share.  Additionally, the Committee granted 329,400 SAR and 154,150 units of cash-settled RSU (RSUC) to certain employees.  The SAR and 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 these SAR was equivalent to the stock options granted, while the initial value of RSUC was equivalent to equity-settled restricted stock units granted.  Also in February, the Committee granted 83,220 shares of time-based RSU to the Company’s Directors under the Non-Employee Director Plan.  These shares vest on the third anniversary of the date of grant. The estimated fair value of these awards was $28.84 per unit on date of grant.



For the first six months of 2017 and 2016,  the Company had no stock options exercised.



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









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Note H – Earnings per Share



Net income (loss) 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, 2017 and 2016.  The following table reconciles the weighted-average shares outstanding used for these computations.







     *Due to net losses recognized by the Company for the three-month period ended June 30, 2017 and for the six-month period ended June 30, 2016, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been anti-dilutive.







 

Note I – Income Taxes



The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss) before income tax expense.  For the three-month and six-month periods ended June 30, 2017 and 2016, the Company’s effective income tax rates were as follows:





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



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 recorded in the current period related to investments in foreign areas, partially offset by income tax expense in the same period related to undistributed foreign earnings in the amount of $5.8 million.



The effective tax rate for the six-month period ended June 30, 2017 was above the U.S. statutory tax rate primarily due to tax expense recorded in the current period related to undistributed foreign earnings partially offset by income tax benefit on investment in foreign areas.    During the first six-months of 2017, the Company determined that prospective earnings from its Malaysian and Canadian subsidiaries will not be considered reinvested into local operations.  Due to this change in assertion, the Company recorded a deferred tax charge of $60.4 million in the six-month period 2017 associated with the estimated tax consequence of the future repatriation of these subsidiaries earnings during the first six months 2017.  This decision provides greater financial flexibility as it considers future domestic investment opportunities.  The Company expects to incur further tax charges in future 2017 quarters for additional 2017 foreign earnings as they arise. 



The effective tax rate benefit for both the three-month and six-month periods ended June 30, 2016 was above the U.S. statutory tax rate primarily due to deferred tax benefits recognized related to the Canadian asset dispositions and income tax benefits on investments in foreign areas.





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Note I – Income Taxes  (Contd.)



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, 2017, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2011; Canada – 2012; Malaysia – 2010; and United Kingdom – 2014.





Note J – Financial Instruments and Risk Management



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



Commodity Purchase Price Risks



The Company is subject to commodity price risk related to crude oil it produces and sells.  During the first six months 2017 and 2016, 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, 2017, the Company had 22,000 barrels per day in

WTI crude oil swap financial contracts maturing ratably during 2017 at an average price of $50.41.  At June 30, 2017, the fair value of WTI contracts of $18.3 million was included in Accounts Receivable.  The impact of marking to market these 2017 commodity derivative contracts reduced the loss before income taxes by $14.9 million for the six-month period ended June 30, 2017.



At June 30, 2016, the Company had 25,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2016.  At June 30, 2016, the fair value of WTI contracts of $1.7 million was included in Accounts Receivable.  The impact of marking to market these 2016 commodity derivative contracts decreased the loss before income taxes by $2.6 million for the six-month period ended June 30, 2016.

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



Foreign Currency Exchange Risks



The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange short-term derivatives outstanding at June 30, 2017.



At June 30,  2016, short-term derivative instruments were outstanding in Canada for approximately $5.8 million, to manage the currency risks of certain U.S. dollar accounts receivable associated with sale of Canadian crude oil.  The fair values of open foreign currency derivative contracts were liabilities of $0.1 million at June 30, 2016.



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







For the three-month and six-month periods ended June 30, 2017 and 2016, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.





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, 2017 and 2016,  $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 deferred on these matured contracts at June 30, 2017 was $9.4 million, which is recorded, net of income taxes of $5.1 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 in the Consolidated Statement of Operations during the remaining six months of 2017.

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



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, 2017 and December 31, 2016 are presented in the following table.