MURPHY OIL CORP - Quarter Report: 2016 September (Form 10-Q)





















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” and “smaller reporting company” in Rule 12b-2 of the Exchange act.



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



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



Number of shares of Common Stock, $1.00 par value, outstanding at September 30, 2016 was 172,200,075.





 

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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)









12016 balance includes payments for deepwater rig contract exit of $266.6 million.

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

3Investments 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.  The Company sold its interest in a Canadian synthetic oil operation in the second quarter of 2016.  The Company acquired 70% interest in Duvernay Shale and a 30% interest in liquids rich Montney properties during the second quarter 2016.



INTERIM FINANCIAL STATEMENTS – In the opinion of Murphy's management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company's financial position at September 30, 2016 and December 31, 2015, and the results of operations,  cash flows and changes in stockholders’ equity for the interim periods ended September 30, 2016 and 2015, 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 2015 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report.  Financial results for the nine-month period ended September 30, 2016 are not necessarily indicative of future results.



Note B – Property, Plant and Equipment



Under U.S. generally accepted accounting principles for companies that use the successful efforts method of accounting, exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project.



At September 30, 2016, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $128.2 million.  The following table reflects the net changes in capitalized exploratory well costs during the

nine-month periods ended September 30, 2016 and 2015.







 

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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 September 30, 2016,  $64.5 million is in Brunei, $31.4 million is in Vietnam and $21.7 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.



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



In April 2016, a Canadian subsidiary of the Company completed its transaction to divest 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 by Murphy upon closing of the transaction was $414.1 million.  A gain on sale of approximately $187 million is being deferred and recognized over the next 20 years in the Canadian operating segment.  The Company has amortized $3.4 million of the deferred gain during 2016.  The remaining deferred gain is included as a component of deferred credits and other liabilities on the Company’s Consolidated Balance Sheet.



In a separate transaction, the same Canadian subsidiary signed a definitive agreement to acquire 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 Montney lands in Alberta, the majority of which is unproved.  Under the terms of the joint venture the total consideration amounts to approximately $375 million, of which Murphy paid $206.7 million in cash at closing, subject to normal closing adjustments, and the remaining $168.0 million in the form of a carried interest for a period of up to five years.  The transaction closed in the second quarter of 2016.



During the first quarter of 2016, declines in crude oil and natural gas prices from year end 2015 provided indications of possible impairments in certain of the company’s producing properties.  As a result of management’s assessments, the Company recognized pretax non-cash impairments charges of $95.1 million in the nine-month period ended September 30, 2016, to reduce the carrying value to their estimated fair value for its Terra Nova field offshore Canada and its Western Canada onshore heavy oil producing properties.  The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, estimates of future costs, and a discount rate believed to be consistent with those used by principal market participants in the region. 



During the third quarter 2015, declines in future oil and gas prices provided indications of possible impairments in certain of the Company’s producing properties.  As a result of management’s assessments, during the third quarter of 2015, the Company recognized a pretax noncash impairment charge of approximately $2.3 billion to reduce the carrying value of certain producing properties in the Gulf of Mexico, Western Canada and Malaysia to their estimated fair value.  The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, estimates of future costs, and a discount rate believed to be consistent with those used by principal market participants in the applicable region.

 

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



During 2015, the Company completed the second phase of the sale of 30% of its oil and gas assets in Malaysia and received net cash proceeds of $417.2 million.  The Company recorded an after-tax gain of $218.8 million on the sale of the final 10% portion of the total 30% sold.

 

Note C – Discontinued Operations



The Company has accounted for its U.K. refining and marketing operations as discontinued operations for all periods presented.  The Company completed its agreement to sell the remaining U.K. downstream assets at the end of the second quarter of 2015.  The 2015 nine-month period includes an adjustment to the impairment recognized as a result of the final sale of the U.K. downstream assets.



The results of operations associated with discontinued operations for the three-month and nine-month periods ended September 30, 2016 and 2015 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 September 30, 2016 and December 31, 2015.





 





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Note D – Financing Arrangements and Debt



In August 2016 the Company reduced its existing $2.0 billion unsecured revolving credit facility (“2011 facility”) to $630 million and entered into a separate $1.2 billion senior unsecured guaranteed credit facility (“2016 facility”) with a major banking consortium that expires in August 2019.  Facility fees of 0.5% are charged annually on the full $1.2 billion commitment.  The Company incurred transaction costs of approximately $14.0 million to place the 2016 facility which are included in financing activities in the Consolidated Statement of Cash Flows.  At September 30, 2016, the Company had no outstanding borrowings under either credit facility, however, there was approximately $88 million of issued letters of credit under the 2016 facility.  The 2016 facility is unsecured, with guarantees from certain domestic and foreign subsidiaries.  Should the Company make substantial asset sales, the facility size would be automatically reduced to a minimum of $1.0 billion.  Borrowings under the 2016 facility are subject to varying interest rates ranging from LIBOR plus 250 basis points to LIBOR plus 450 basis points.  The terms of the 2016 facility include covenants that impose certain restrictions on the Company.  These financial covenants include a minimum adjusted EBITDAX of 2.5 times consolidated interest expense, consolidated debt not to exceed 3.75 times adjusted EBITDAX and minimum liquidity from U.S. and Canadian entities equal to or greater than $500 million.  Also beginning March 31, 2017, if the Company’s total leverage ratio exceeds 3.25 times the Company’s trailing twelve month consolidated adjusted EBITDAX, as defined in the 2016 facility, the facility will become secured, subject to limitations set forth in the Company’s existing notes.  The existing unsecured 2011 facility, which expires in June 2017, includes a financial covenant under which the Company may not have total debt in excess of 60% of its total capital employed (debt borrowed plus stockholders’ equity).  As of September 30, 2016, the Company was in compliance with all financial covenants contained in both credit facilities.  The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 2018.



In August 2016, the Company sold $550 million of new notes that bear interest at the rate of 6.875% and mature on August 15, 2024.  The new notes pay interest semi-annually on February 15 and August 15 of each year.  The initial interest payment is to be made on February 15, 2017.  The proceeds of the $550 million notes were used for general corporate purposes.



The Company and its partners are parties to a 25-year lease of production equipment at the Kakap field offshore Malaysia.  The lease has been accounted for as a capital lease, and payments under the agreement are to be made over a 15-year period through September 2028.  Current maturities and long-term debt on the Consolidated Balance Sheet included $20.4 million and $202.7 million, respectively, associated with this lease at September 30, 2016.



Note E – Cash Flow Disclosures



Additional disclosures regarding cash flow activities are provided below.









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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 full-time employees.  All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors’ 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 nine-month periods ended September 30, 2016 and 2015.







Curtailment expense for the nine months ended September 30, 2016 shown in the table above, relates to restructuring activities in the U.S. undertaken by the Company in the first quarter 2016.  Termination and curtailment expenses for the nine months ended September 30, 2015 relate to restructuring activities in the U.S. undertaken by the Company in the second quarter 2015.  During the nine-month period ended September 30, 2016, the Company made contributions of $10.0 million to its defined benefit pension and postretirement benefit plans.  Remaining required funding in 2016 for the Company’s defined benefit pension and postretirement benefit plans is anticipated to be $2.9 million.

 



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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 other key 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 and other stock-based incentives 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.  The Company has an Employee Stock Purchase Plan that permits the issuance of up to 980,000 shares through September 30, 2017.  The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock and stock options or a combination thereof to the Company’s Directors. 



In February 2016, the Committee granted stock options for 862,000 shares at an exercise price of $17.57 per share.  The Black-Scholes valuation for these awards was $5.03 per option.  The Committee also granted 394,000 performance-based RSU and 417,500 time-based RSU in February and April 2016.  The fair value of the performance-based RSU, using a Monte Carlo valuation model, ranged from $12.21 to $16.34 per unit.  The fair values of time-based RSU was estimated based on the fair market value of the Company’s stock on the date of grant, which ranged from $17.57 to 24.075 per share.  Additionally, the Committee granted 708,200 SAR and 507,470 units of cash-settled RSU (RSU-C) to certain employees in 2016.  The SAR and RSU-C 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 RSU-C was equivalent to equity-settled restricted stock units granted.  Also in February 2016, the Committee granted 85,679 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 $19.26 per unit on date of grant.



Amounts recognized in the financial statements with respect to share-based plans are as follows:











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Note H – Earnings per Share



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

three-month and nine-month periods ended September 30, 2016 and 2015.  The following table reconciles the weighted-average shares outstanding used for these computations.







     *Due to a net loss recognized by the Company for the three-month and nine-month periods ended September 30, 2016 and 2015, 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 taxes.  For the three-month and nine-month periods in 2016 and 2015, the Company’s effective income tax rates were as follows:





The effective tax rates for most periods differ from 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 September 30, 2016 was less than the U.S. statutory tax rate primarily due to expenses in foreign jurisdictions for which no tax benefits were recognized.  The effective tax rate for the nine-month period ended September 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.  The effective tax rate for the three-month period ended September 30, 2015 was less than the U.S. statutory tax rate primarily due to a deferred tax expense associated with an enacted increase in the statutory tax rate in Alberta.  The effective tax rate for the nine-month period ended September 30, 2015 was above the U.S. statutory tax rate primarily due to a deferred tax benefit associated with the sale of Malaysian assets, partially offset by expenses in foreign jurisdictions for which no tax benefits were recognized and the enacted increase in statutory rate in Alberta.



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 September 30, 2016, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2011; Canada – 2008; Malaysia – 2009; and United Kingdom – 2014.

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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 net payment upon settlement recording the fair value of these contracts was deferred in Accumulated Other Comprehensive Loss.  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, natural gas liquids and natural gas it produces and sells.  The Company had open derivative contracts at September 30, 2016 and 2015.  The impact from marking to market these commodity derivative contracts increased the loss before income taxes by $3.9 million for the nine-month period ended September 30, 2016 and reduced the loss before income taxes by $7.4 million for the nine-month period ended September 30, 2015.



Open West Texas Intermediate (WTI) contracts were as follows:











Foreign Currency Exchange Risks

The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S.  At September 30, 2016 and 2015 short-term derivative instruments were outstanding in Canada for approximately $25.2 million and $6.2 million, respectively, to manage the currency risks of certain U.S. dollar accounts receivable associated with sale of Canadian crude oil.  The impact from marking to market these foreign currency derivative contracts was insignificant for the nine-month periods ended September 30, 2016 and 2015, respectively.



After signing an agreement to sell its five percent non-operated working interest in Syncrude, the Company’s Canadian subsidiary entered into forward sales contracts for C$1.0 billion at a fixed rate to lock in the U.S. dollar value of the proceeds and protect the Company from exposure to weakening of the Canadian dollar.  Upon completion of the sale and settlement of the forward sale contracts, the Company recognized income of approximately $26.8 million in the second quarter of 2016 due to weakening of the Canadian dollar subsequent to entering into the contracts.



At September 30, 2016 and December 31, 2015, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.







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



For the three-month and nine-month periods ended September 30, 2016 and 2015, 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

In 2011 the Company entered into a series of derivative contracts known as forward starting interest rate swaps to manage interest rate risk associated with $350 million of 10-year notes that were sold in May 2012.  These interest rate swaps matured in May 2012.  Under hedge accounting rules, the Company deferred the net cost associated with these contracts to match the payment of interest on these notes through 2022.  During each of the nine-month periods ended September 30, 2016 and 2015, $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 September 30, 2016 was $10.8 million, which was recorded, net of income taxes of $5.8 million, in Accumulated Other Comprehensive Loss in the Consolidated Balance Sheet.  The Company expects to charge approximately $0.7 million of this deferred loss to Interest expense in the Consolidated Statement of Operations during the remaining three months of 2016.





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 September 30, 2016 and December 31, 2015 are presented in the following table.







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



The fair value of WTI crude oil derivative contracts was determined based on active market quotes for WTI crude oil at the balance sheet date.  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 September 30, 2016 and December 31, 2015.



Fair Values – Nonrecurring

As a result of significantly lower commodity prices during the nine-month periods ended September 30, 2016 and 2015, the Company recognized $95.1 million and $2.3 billion, respectively, in pretax noncash impairment charges related to producing properties.  The fair value information associated with these impaired properties is presented in the following tables.











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



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Note K – Accumulated Other Comprehensive Loss



The components of Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets at December 31, 2015 and September 30, 2016 and the changes during the nine-month period ended September 30, 2016 are presented net of taxes in the following table.



1All amounts are presented net of income taxes.

2Reclassifications before taxes of $11,602 for the nine-month period ended September 30, 2016 are included in the computation of net periodic benefit expense.  See Note G for additional information.  Related income taxes of $4,055 for the nine-month period ended September 30, 2016 are included in Income tax expense.

3Reclassifications before taxes of $2,222 for the nine-month period ended September 30, 2016 are included in Interest expense.  Related income taxes of $777 for the nine-month period ended September 30, 2016 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 and retroactive tax claims; royalty and revenue sharing increases; 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.  Because governmental actions are often motivated by political considerations and 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.



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

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Note L – Environmental and Other Contingencies(Contd.)



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 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 have been notified.  The Company has not yet established a complete estimate of the costs to remediate the site.  Based on the assessments done to date, the Company recorded $43.9 million in other expense during 2015 associated with the estimated costs of remediating the site.  The Company has spent $32.8 million to date associated with this event.  Further refinements in the estimated total cost to remediate the site are anticipated in future periods, including possible fines from regulators and 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 expense recorded through September 30, 2016.



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 these matters 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 2016 to 2020 natural gas sales volumes in Western Canada.  The natural gas sales contracts call for deliveries during the last thee months of 2016 of approximately 99 million cubic feet per day (MMCFD) at C$3.00 per MCF,  79 MMCFD at C$2.83 per MCF from January 2017 to December 2017 and 59 MMCFD at C$2.81 per MCF from January 2018 through December 2020.    In October 2016, the Company entered into an additional 20 MMCFD of natural gas sales contracts for the January 2017 through December 2020 period at C$3.12 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.





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Note O – New Accounting Principles and Recent Accounting Pronouncements



Leases 

In February 2016, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (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 lease 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 2019 and is currently evaluating the standard and its 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.  Early adoption is permitted for any entity in any interim period or annual period.  The Company will adopt this guidance in 2017 and is currently evaluating the impact on its consolidated financial statements and footnote disclosures.



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 ASUs 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.  The Company is required to adopt the new standard in the first quarter of 2018 using either the retrospective or cumulative effect transition method.  The Company has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures.



Statement of Cash Flows

In August 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-15, Statement of Cash Flows (Topic 230):  Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15)”).  ASU 2016-15 reduces diversity in practice in how certain transactions are classified in the statement of cash flows.  The amendments in ASU 2016-15 provide guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments 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.  ASU 2016-15 is effective for annual and interim periods beginning after December 5, 2017.  The Company is currently assessing the potential impact of ASU 2016-15 on its consolidated financial statements.