MURPHY OIL CORP - Quarter Report: 2017 March (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”, “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 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 March 31, 2017 was 172,546,147





 

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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 32.

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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 $253.2 million.

2Investments 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 March 31, 2017 and December 31, 2016, and the results of operations,  cash flows and changes in stockholders’ equity for the interim periods ended March 31, 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 period ended March 31, 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 March 31, 2017, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $166.4 million.  The following table reflects the net changes in capitalized exploratory well costs during the

three-month periods ended March 31, 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 $118.2 million of exploratory well costs capitalized more than one year at March 31, 2017, $64.5 million is in Brunei, and $53.7 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.  The capitalized well costs charged to expense in the first quarter 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.



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.  In the fourth quarter 2016, the Company recorded $39.0 million in redetermination 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 effective April 1, 2017.  The Company currently expects to settle the redetermination in cash in the second quarter of 2017.  It is possible that the final adjustment amount could be different than the current estimate.



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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 periods ended March 31, 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 March  31, 2017 and December 31, 2016.  





 





Note D – Financing Arrangements and Debt



At March 31, 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 March 31, 2017, the Company had no outstanding borrowings under the 2016 facility, however, there were $171.9 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.  The Eurodollar rate and the applicable base rate, had there been any amounts borrowed under the 2016 facility at March 31, 2017, would have been 5.0% and 7.0%, respectively.  The Company also has a $630.0 million unsecured revolving credit facility (2011 facility) with a major banking consortium, which expires in June 2017.  At March 31, 2017,  the Company had no outstanding borrowings or letters of credit under the 2011 facility.  Advances under the 2011 facility will accrue interest based, at the Company’s option, on either the Eurodollar rate or the alternate base rate (as defined in the 2011 facility agreement) plus an applicable margin.  The Eurodollar rate and the applicable base rate, had there been any amounts borrowed under the 2011 facility at March 31, 2017, would have been 2.45% and 4.45%, respectively.    At March 31, 2017, the Company was in compliance with all covenants related to both the 2016 facility and the 2011 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 and long-term debt on the Consolidated Balance Sheet included $13.0 million and $193.5 million, respectively, associated with this lease at March 31, 2017.

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Note E – Other Financial Information



Additional disclosures regarding cash flow activities are provided below.







*    2016 balances included payments for deepwater rig contract exit of $253.2 million.



In April 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 20 years in the Canadian operating segment.  The Company amortized approximately $1.7 million of the deferred gain during first quarter ended March 31, 2017.  The remaining deferred gain of $176.7 million was included as a component of deferred credits and other liabilities in the Company’s Consolidated Balance Sheets.

 

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.

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



The table that follows provides the components of net periodic benefit expense for the three-month periods ended March 31, 2017 and 2016.







Curtailment expense for the three months ended March 31, 2016, shown in the table above relate to restructuring activities in the U.S. undertaken by the Company in the first quarter 2016.  During the three-month period ended March 31, 2017, the Company made contributions of $9.7 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 $21.1 million.

 

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 has an Employee Stock Purchase Plan (ESPP) that permits the issuance of up to 980,000 shares.    The ESPP will terminate on June 30, 2017 and will not be renewed by the Company.  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. 



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 (RSU-C) to certain employees.  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, 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.

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Note G – Incentive Plans( Contd.)



For the first quarter 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:















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-months ended March 31, 2017 and 2016.  The following table reconciles the weighted-average shares outstanding used for these computations.







     *Due to a net loss, recognized by the Company for the 2016 period, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been anti-dilutive.









 



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Note I – Income Taxes



The Company’s effective income tax rate is calculated as the amount of income tax expense divided by income before income tax expense.  For the three-month periods in 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 March 31, 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 quarter 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 $54.6 million in the first quarter 2017 associated with the estimated tax consequence of the future repatriation of these subsidiaries’ first quarter earnings.  This decision allows the Company to have additional funding options and 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 for the three-month period ended March 31, 2016 was below the U.S. statutory tax rate primarily due to effects of losses incurred in its Canadian operations and exploration and other expenses in certain foreign jurisdictions that have little or no realized tax benefits.



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 March 31, 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 quarter 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 March 31, 2017, the Company had 22,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2017.  At March 31, 2017, the fair value of WTI contracts of $7.8 million was included in Accounts Payable.  The impact of marking to market these 2017 commodity derivative contracts increased the loss before income taxes by $7.8 million for the three-month period ended March 31, 2017.  At March 31, 2016, the Company





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



had 20,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2016.  At March 31, 2016, the fair value of WTI contracts of $65.5 million was included in Accounts Receivable.  The impact of marking to market these

2016 commodity derivative contracts decreased the loss before income taxes by $56.8 million for the three-month period ended March 31, 2016.



Foreign Currency Exchange Risks



The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S.  At March 31, 2017 and 2016 short-term derivative instrument were outstanding in Canada for approximately $18.5 million and $11.3 million, respectively, to manage the currency risks of certain U.S. dollar accounts receivable associated with sale of Canadian crude oil in both years.  The fair values of open foreign currency derivative contracts were assets of $0.2 million at March 31, 2017 and $0.3 million at March 31, 2016.



At March 31, 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 period ended March 31, 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 three-month periods ended March 31, 2017 and 2016,  $0.7 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 March 31, 2017 was $9.9 million, which is recorded, net of income taxes of $5.3 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheet.  The Company expects to charge approximately $2.1 million of this deferred loss to Interest expense in the Consolidated Statement of Operations during the remaining nine months of 2017.





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.

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



The carrying value of assets and liabilities recorded at fair value on a recurring basis at March 31, 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 March 31, 2017 and December 31, 2016.



Fair Values – Nonrecurring



As a result of significantly lower commodity prices during the first quarter 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.

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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, 2016 and March 31, 2017 and the changes during the three-month period ended March 31, 2017 are presented net of taxes in the following table.



1All amounts are presented net of income taxes.

2Reclassifications before taxes of $3,678 for the three-month period ended March 31, 2017 are included in the computation of net periodic benefit expense.  See Note  F for additional information.  Related income taxes of $1,291 for the three-month period ended March 31, 2017 are included in Income tax expense.

3Reclassifications before taxes of $741 for the three-month period ended March 31, 2017 are included in Interest expense.  Related income taxes of $259 for the three-month period ended March 31, 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 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, 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 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 affect on Murphy’s net income, financial condition or liquidity in a future period.

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Note L – Environmental and Other Contingencies  (Contd.)



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.  The Company has not yet established a complete estimate of the costs to remediate the site.  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 March 31, 2017, the Company has a remaining accrued liability of $7.1 million associated with this event.    During the first quarter 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 April to December 2017 the natural gas sales contracts call for deliveries of approximately 124 million cubic feet per day at Cdn $2.97 per MCF.  Additional contracts call for deliveries from January 2018 through December 2020 of approximately 59 million cubic feet per day at Cdn $2.81 per MCF.  These natural gas contracts have been accounted for as normal sales for accounting purposes.







Note N – Business Segments





*Additional details about results of oil and gas operations are presented in the table on page 25.



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Note O – New Accounting Principles



Business Combinations



In January 2017, the FASB issued an 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 Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (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.



Note P – Recent Accounting Pronouncements



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 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 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 ASUs 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.



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Note P – Recent Accounting Pronouncements (Contd.)



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.



Note Q – Subsequent Event



On April 1, 2017, the Company’s effective working interest in the Kakap field in Block K Malaysia was reduced from 8.6% to approximately 6.7%.  Due to the change in interest, the future payments under a lease of production equipment in the Kakap field accounted for as a capital lease will be lower.  As a result, the Company anticipates the total debt recorded on its balance sheet to be reduced by approximately $56.7 million, with a similar reduction to Property, plant and equipment.

 

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Overall Review



During the first quarter 2017, worldwide benchmark oil and natural gas prices were significantly above average comparable benchmark prices during the first quarter 2016, some of which traded at 14 year lows in the prior year.  The oil and natural gas prices received in the first quarter 2017, together with a gain on sale of its heavy oil property in Canada, have resulted in the Company recording net income in the 2017 first quarter.  The Company continually monitors the prices for its main products and often alters its operations and spending plans based on these prices.



Results of Operations



Murphy’s income by type of business is presented below.





Murphy’s net income in the first quarter of 2017 was $58.5 million ($0.34 per diluted share) compared to net loss of $198.8 million ($1.16 per diluted share) in the first quarter of 2016.  Income (loss) from continuing operations improved from a loss of $199.5 million ($1.16 per diluted share) in the 2016 quarter to earnings of $57.5 million ($0.33 per diluted share) in 2017.  In the 2017 first quarter, the Company’s exploration and production continuing operations earned $175.1 million compared to a loss of $156.8 million in the 2016 quarter.  The results in the 2017 quarter were favorably impacted by higher revenues due to significantly higher realized oil and natural gas sales prices, gain on sale of its Seal property in Western Canada, lower lease operating expenses, lower depreciation expense and lower selling and general expenses, partially offset by lower volume sold.  The corporate function had after-tax costs of $117.6 million in the 2017 first quarter compared to after-tax costs of $42.7 million in the 2016 period with the unfavorable variance in the current period due to losses from foreign exchange effects in the 2017 period versus gains in the same period of 2016, higher net interest expense, and deferred tax charges in 2017 on undistributed earnings of certain foreign subsidiaries, offset in part by lower administrative costs.  The 2017 first quarter included income from discontinued operations of $1.0 million ($0.01 per diluted share) compared to income of $0.7 million ($0.00 per diluted share) in the 2016 period.





 

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Results of Operations (Contd.)



Exploration and Production



Results of exploration and production continuing operations are presented by geographic segment below.







First quarter 2017 vs. 2016



United States exploration and production operations reported earnings of $23.0 million in the first quarter of 2017 compared to a loss of $65.6 million in the 2016 quarter.  Results improved $88.6 million in the 2017 quarter compared to the 2016 period due to higher revenues, lower supply costs and lower selling and general expenses.  Revenue in the U.S. increased by $86.6 million in the period as higher oil and natural gas realized sales prices more than offset impacts of lower volumes sold.  Additionally, the U.S. segment benefited from unrealized gains on its open crude oil contract positions of $40.0 million versus losses of $20.5 million in the same period a year ago.   Lease operating expenses decreased by $7.5 million due to lower costs in Eagle Ford Shale compared to the same quarter in 2016 with most of the reduction due to the Company’s continuous focus on improving its cost structure.  Depreciation expense decreased $30.5 million in 2017 compared to 2016 due primarily to lower volume sold in both Eagle Ford Shale and Gulf of Mexico and lower average unit rates in the Gulf of Mexico in the 2017 period.  Selling and general expenses were down $7.0 million in the first quarter of 2017 primarily related to restructuring activity that occurred in 2016 and continual monitoring of its cost structure.



Operations in Canada earned $100.6 million in the first quarter 2017 compared to a loss of $87.3 million in the 2016 quarter.  Canadian results of operations improved by $187.9 million in the 2017 quarter due to higher average sales prices received for both oil and natural gas, a $96.0 million after-tax gain on sale of its Seal property in Western Canada that was completed in January 2017, and lower impairment expense.  In the second quarter of 2016, the Company divested its holding of Syncrude and completed an entry into the Kaybob Duvernay and Placid Montney plays. Natural gas sales volumes increased in 2017 due to new production in the Kaybob/Placid areas of Western Canada.  Lease operating expenses associated with conventional operations were $5.0 million higher in the 2017 quarter primarily due to higher natural gas processing costs.  Impairment expense was $95.1 million lower in 2017 due to a write down of heavy oil properties at Seal in Western Canada and the Terra Nova field offshore East Coast Canada in 2016.  Both impairments were the result of weak oil sales prices at March 31, 2016.   



Malaysia operations reported earnings of $58.6 million in the 2017 quarter compared to earnings of $22.3 million during the same period in 2016.  Results were up $36.3 million in 2017 in Malaysia primarily due to higher average oil prices received and higher natural gas volume sold in Sarawak, partially offset by lower oil volume sold and lower average Sarawak natural gas sales prices received.  Crude oil sales volumes in Malaysia were lower in the 2017 quarter, primarily due to natural field decline while natural gas sales volume improved due to higher demand and less unplanned downtime versus the 2016 period.  Lease operating expenses increased in the 2017 period by $3.6 million due to mix of volume sold compared to 2016.  Depreciation expense was $6.2 million lower in 2017 compared to the 2016 quarter primarily due to lower unit rates in Sarawak and lower volumes sold in Block K, partially offset by higher sales volume in Sarawak.

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Results of Operations (Contd.)



Exploration and Production (Contd.)



First quarter 2017 vs. 2016 (Contd.)



Other international operations reported a loss of $7.1 million in the first quarter of 2017 compared to a loss of $26.2 million in the 2016 quarter.  The $19.1 million improvement in the 2017 period was primarily related to lower selling and general expenses resulting from restructuring activity during 2016 and income tax benefits on investments in foreign areas in 2017. 



Total hydrocarbon production averaged 169,224 barrels of oil equivalent per day in the 2017 first quarter, which represented a 13.9% decrease from the 196,568 barrels of oil equivalents per day produced in the 2016 quarter.  Average crude oil and condensate production was 95,604 barrels per day in the first quarter of 2017 compared to 123,475 barrels per day in the first quarter of 2016.  Crude oil production decreased 8,935 barrels in the Eagle Ford Shale area of South Texas in 2017 due to well decline associated with significantly less drilling in 2016 due to lower capital spending.  Crude oil production in the Gulf of Mexico was lower by 1,734 barrels in the 2017 quarter due to well decline and unplanned downtime, partly offset by higher production at Kodiak, which started up late in the first quarter of 2016.  Heavy oil production from the Seal area in Western Canada was lower in 2017 due to its divestiture in mid-January 2017.  Light oil production in Canada improved in the 2017 quarter in the Company’s Kaybob and Placid areas acquired in the second quarter of 2016.  Oil production offshore Eastern Canada was higher during 2017 primarily due to improved uptime at both Hibernia and Terra Nova fields.  Lower oil production in 2017 in Malaysia was primarily attributable to less net oil volumes produced in Block K due to well decline and slightly lower entitlement percentage.  On a worldwide basis, the Company's crude oil and condensate prices averaged $50.10 per barrel in the first quarter 2017 compared to $34.19 per barrel in the 2016 period, an increase of 47% quarter to quarter. 



Total production of natural gas liquids (NGL) was 8,916 barrels per day in the 2017 first quarter compared to 9,235 barrels per day in the same 2016 period.  The decrease in NGL production was primarily associated with lower natural gas volumes sold in the U.S.  The average sales price for U.S. NGL was $16.84 per barrel in the 2017 quarter compared to $8.36 per barrel in 2016. 



Natural gas sales volumes averaged 388 million cubic feet per day in the first quarter 2017 compared to 383 million cubic feet per day in 2016.  Natural gas sales volumes decreased in North America for 2017 due primarily to lower volumes produced both offshore Gulf of Mexico and in Eagle Ford Shale but was partially offset by new volumes in the Kaybob and Placid areas of Western Canada.  Natural gas production volumes in Malaysia increased in the 2017 period due to both higher demand and less downtime in the current period.  North American natural gas sales prices averaged $2.17 per thousand cubic feet (MCF) in the 2017 quarter, 38% above the $1.57 per MCF average in the same quarter of 2016.  The average realized price for natural gas produced in the 2017 quarter at fields offshore Sarawak was $3.50 per MCF, compared to a price of $3.67 per MCF in the 2016 quarter.



Additional details about results of oil and gas operations are presented in the tables on page 25.

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Results of Operations (Contd.)



Exploration and Production (Contd.)



Selected operating statistics for the three-month periods ended March 31, 2017 and 2016 follow.







1  The Company sold the Seal area heavy oil field in January 2017 and its 5% non-operated interest in Syncrude Canada Ltd. in June 2016.

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

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Results of Operations (Contd.)



Exploration and Production (Contd.)







1  U.S. dollar equivalent.

2  The Company sold the Seal area heavy oil field in January 2017 and its 5% non-operated interest in Syncrude Canada Ltd. in June 2016.

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





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Results of Operations (Contd.)



Exploration and Production (Contd.)



OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED MARCH 31, 2017 AND 2016

















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Results of Operations (Contd.)



Corporate



Corporate activities, which include interest income and expense, foreign exchange effects, and corporate overhead not allocated to operating functions, had net cost of $117.6 million in the 2017 first quarter compared to a net cost of $42.7 million in the same 2016 quarter.  The $74.9 million increased cost in the 2017 period is primarily due to deferred tax charges on undistributed earnings of certain foreign subsidiaries, foreign currency exchange losses in the 2017 period and higher net interest expense, offset by lower administrative costs.  An after-tax loss of $11.6 million occurred in 2017 on transactions denominated in foreign currencies, while the 2016 quarter had an after-tax gain of $1.7 million.  Net interest costs increased $14.4 million in the 2017 period primarily due to issuance of $550 million in notes in August 2016 that matures in 2024 and an increase of 1.00% on the coupon rates on $1.5 billion of the Company’s outstanding notes effective June 1, 2016 following a downgrade by Moody’s Investor Services in February 2016.  During the first quarter 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 $54.6 million in the first quarter 2017 associated with the estimated tax consequence of the future repatriation of these subsidiaries’ first quarter earnings.  This decision allows the Company to have additional funding options and 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.  Selling and general expenses decreased in the first quarter of 2017 primarily related to restructuring activity that occurred in 2016 and continual monitoring of its cost structure.



Discontinued Operations



The Company has presented its former U.K. refining and marketing operations as discontinued operations in its consolidated financial statements.    The after-tax results of these operations for the three-month period ended March 31, 2017 and 2016 are reflected in the following table.





Financial Condition



Net cash provided by continuing operating activities was $305.5 million for the first three months of 2017 compared to $43.3 million during the same period in 2016.  The improvement in cash provided by continuing operations activities in 2017 was primarily attributable to payments in the 2016 period relating to exit of deepwater rig contracts, higher realized sales prices for the Company’s oil and gas production, lower lease operating and administrative expenses, partially offset by lower volume sold in the current year and higher interest costs.  Changes in working capital from continuing operations provided cash of $43.4 million during the first three months of 2017, compared to a use of cash of $104.3 million in 2016.  The use of cash in 2016 included $253.2 million associated with pay-off of cancelled deepwater rig contracts that were previously charged to expense in 2015.  Proceeds from sales of property and equipment generated cash of $64.1 million in 2017 primarily relating to proceeds from the sale of the Seal field in Western Canada.  Other significant sources of cash included $113.2 million in the 2017 period and $87.0 million in 2016 from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition.  The Company had no borrowings in the three-month period of 2017 compared to net borrowings of $371.0 million in the 2016 quarter.  The net borrowings in 2016 were primarily used to fund capital development activities.

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Financial Condition (Contd.)



The most significant use of cash in both years was for property additions and dry holes, which including amounts expensed, were $211.6 million and $210.0 million in the three-month periods ended March 31, 2017 and 2016, respectively.  Total cash dividends to shareholders amounted to $43.1 million in 2017 and $60.3 million in 2016.  Also, the purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $212.7 million in the 2017 period and $49.3 million in the 2016 period.



Total accrual basis capital expenditures were as follows:







The increase in capital expenditures in the exploration and production business in 2017 compared to 2016 was primarily attributable to higher development drilling in both the Eagle Ford Shale area in the United States and the Kaybob/Placid areas of Canada.



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





Working capital (total current assets less total current liabilities) at March 31, 2017 was $141.2 million, $76.4 million more than December 31, 2016, with the increase primarily attributable to higher invested cash in Canadian government marketable securities.



At March 31, 2017, long-term debt of $2,421.6 million had decreased by $1.2 million compared to December 31, 2016.  A summary of capital employed at March 31, 2017 and December 31, 2016 follows.









Cash and invested cash are maintained in several operating locations outside the United States.  At March 31, 2017, cash, cash equivalents and cash temporarily invested in Canadian government securities held outside the U.S. included U.S. dollar equivalents of approximately $302.0 million in Canada and $323.7 million in Malaysia.  In addition $16.3 million of cash was held in the United Kingdom, but was reflected in current Assets Held for Sale on the Company’s Consolidated Balance Sheet at March 31, 2017.  In certain cases, the Company could incur taxes or other costs should these cash balances be repatriated to the U.S. in future periods.  This could occur due to withholding taxes and/or potential additional U.S. tax burden when less than the U.S. Federal tax rate of 35% has been paid for cash taxes in foreign locations.  A lower cash tax rate is often paid in foreign countries in the early years of operations when accelerated tax deductions are permitted to spur oil and gas investments; cash tax rates are generally higher in later years after accelerated tax deductions in early years are exhausted.  Canada collects a 5% withholding tax on any cash repatriated to the United States through a dividend to the U.S. parent.  See the “Corporate” section on page 26 regarding the Company’s change in assertion for indefinite reinvestment on prospective earnings from its Malaysian and Canadian subsidiaries.

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Accounting and Other Matters



Business Combinations



In January 2017, the FASB issued an 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 Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (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.



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 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 the ASU 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.



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 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.





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Accounting and Other Matters (Contd.)



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.



Outlook



Average worldwide crude oil prices in April 2017 have slightly declined from the average prices during the first quarter of 2017.  Global crude oil balances continue to tighten as the OPEC/non-OPEC production accord reaches its fourth month.

North American natural gas prices increased slightly in April from the 2017 first quarter as the year on year storage deficit persists and production remains more than 3% behind year ago levels.    The Company expects its total oil and natural gas production to average 160,000 to 164,000 barrels of oil equivalent per day in the second quarter 2017.  The Company currently anticipates total capital expenditures for the full year 2017 to be approximately $890 million.



The Company will primarily fund its capital program in 2017 using operating cash flow, but will supplement funding where necessary using borrowings under available credit facilities.  The Company’s 2017 projections call for repayment of $550 million of 2.5% notes due December 2017.   If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or additional borrowings might be required during the year to maintain funding of the Company’s ongoing development projects. 



As of May 2, 2017, the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:



Forward-Looking Statements



This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995.  These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties.  Factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements include, but are not limited to, the volatility and level of crude oil and natural gas prices, the level and success rate of Murphy’s exploration programs, the Company’s ability to maintain production rates and replace reserves, customer demand for Murphy’s products, adverse foreign exchange movements, political and regulatory instability, adverse developments in the U.S. or global capital markets, credit markets or economies generally and uncontrollable natural hazards.  For further discussion of risk factors, see Murphy’s 2016 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and page 30 of this Form 10-Q report.  Murphy undertakes no duty to publicly update or revise any forward-looking statements.