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.











The fair value of WTI crude oil derivative contracts in 2017 and 2016 was based on active market quotes for WTI crude oil.  The fair value of foreign exchange derivative contracts in each year was based on market quotes for similar contracts at the balance sheet dates.  The income effect of changes in the fair value of crude oil derivative contracts is recorded in Sales and other operating revenues in the Consolidated Statements of Operations,  while the effects of changes in fair value of foreign exchange derivative contracts is recorded in Interest and other income.  The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds.  The fair value of this liability was based on quoted prices for these equity securities and mutual funds.  The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and general expenses in the Consolidated Statements of Operations.



The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists.  There were no offsetting positions recorded at June 30, 2017 and December 31, 2016.

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



Fair Values – Nonrecurring



As a result of the fall in forward commodity prices during the first six months of 2016, the Company recognized approximately $95.1 million in pretax noncash impairment charges related to producing properties.  The fair value information associated with these impaired properties is presented in the following table.







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



Note K – Accumulated Other Comprehensive Loss



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



1All amounts are presented net of income taxes.

2Reclassifications before taxes of $7,354 for the six-month period ended June 30, 2017 are included in the computation of net periodic benefit expense.  See Note G for additional information.  Related income taxes of $2,581 for the six-month period ended June 30, 2017 are included in Income tax expense.

3Reclassifications before taxes of $1,482 for the six-month period ended June 30, 2017 are included in Interest expense.  Related income taxes of $519 for the six-month period ended June 30, 2017 are included in Income tax expense.

 

Note L – Environmental and Other Contingencies



The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world.  Examples of such governmental action include, but are by no means limited to: tax increases, tax rate changes and retroactive tax claims; royalty and revenue sharing changes; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others.  Governmental actions are often motivated by political considerations, may be taken without full consideration of their consequences, and may be taken in response to actions of other governments.   It is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.

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Note L – Environmental and Other Contingencies  (Contd.)



Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment. Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays.  A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result.



The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination.  Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup and the Company is investigating the extent of any such liability and the availability of applicable defenses.  The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011.  The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries.  The Company has not retained any environmental exposure associated with Murphy’s former U.S. marketing operations.  The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.



During 2015, the Company’s subsidiary in Canada identified a leak or leaks at an infield condensate transfer pipeline at the Seal field in a remote area of Alberta.  The pipeline was immediately shut down and the Company’s emergency response plan was activated.  In cooperation with local governmental regulators, and with the assistance of qualified consultants, an investigation and remediation plan is progressing as planned and the Company’s insurers were notified.  Based on the assessments done, the Company recorded $43.9 million in Other expense during 2015 associated with the estimated costs of remediating the site.  As of June 30, 2017, the Company has a remaining accrued liability of $6.7 million associated with this event.    During the first six months of 2017, the Company’s Canadian subsidiary paid approximately $130.0 thousand as the complete and final resolution of administrative penalties assessed by the Alberta Energy Regulator regarding this matter.  Further refinements in the estimated total cost to remediate the site are anticipated in future periods including possible insurance recoveries.  It is possible that the ultimate net remediation costs to the Company associated with the condensate leak or leaks will exceed the amount of liability recorded.  The Company retained the responsibility for this remediation upon sale of the Seal field in the first quarter of 2017.



There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.



Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business.  Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.



Note M – Commitments



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



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







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Note N – Business Segments





*Additional details about results of oil and gas operations are presented in the tables on pages 27 and 28.



Note O – New Accounting Principles Adopted



Business Combinations



In January 2017, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) update to clarify the definition of a business with the objective of adding guidance to assist entities in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses.  The standard is intended to narrow the definition of a business by specifying the minimum inputs and processes and by narrowing the definition of outputs.  The update is effective for annual and interim periods beginning in 2018 and is required to be adopted using a prospective approach, with early adoption permitted for transactions not previously reported in issued financial statements.  The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures



Compensation-Stock Compensation



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

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Note P – Recent Accounting Pronouncements



Compensation-Stock Compensation 



In May 2017, FASB issued an ASU which amends the scope of modification accounting for share-based payment arrangements and provides guidance on the type of changes to the terms and conditions of share-based payment awards to which an entity would be required to apply modification accounting.  The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period.    Early adoption is permitted.  The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.



Compensation –  Retirement Benefits



In March 2017, the FASB issued an update requiring that the service cost component of pension and postretirement benefit costs be presented in the same line item as other current employee compensation costs and other components of those benefit costs be presented separately from the service cost component and outside a subtotal of income from operations, if presented.  The update also requires that only the service cost component of pension and postretirement benefit cost is eligible for capitalization.  The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period.  Application is retrospective for the presentation of the components of these benefit costs and prospective for the capitalization of only service costs.  Early adoption is permitted.  The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.



Revenue from Contracts with Customers



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



Leases



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



Statement of Cash Flows



In August 2016, the FASB issued an ASU to reduce diversity in practice in how certain transactions are classified in the statement of cash flows.  The amendment provides guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instrument with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees.  The ASU is effective for annual and interim periods beginning after December 15, 2017.  The Company is currently assessing the potential impact of this ASU on its consolidated financial statements.