MURPHY OIL CORP - Quarter Report: 2016 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” 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 March 31, 2016 was 172,195,169





 

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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 31.

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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.  The Company has an interest in a Canadian synthetic oil operation.



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, 2016 and December 31, 2015, and the results of operations,  cash flows and changes in stockholders’ equity for the interim periods ended March 31, 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 three-month period ended March 31, 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 March 31, 2016, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $129.6 million.  The following table reflects the net changes in capitalized exploratory well costs during the

three-month periods ended March 31, 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.







Exploratory well costs capitalized more than one year at March 31, 2016 are in Brunei.  Development options are under review for these multiple gas discoveries in Brunei.



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 to reduce the carrying value of its Terra Nova field offshore Canada and for Western Canada onshore heavy oil producing properties 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, costs, and a discount rate believed to be consistent with those used by principal market participants in the region. 



During the first quarter 2015, the Company completed the sale of 10% 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 $199.5 million on the sale in the first quarter of 2015.



 



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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 and results subsequent to the sale are related to winding up of these operations.



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





 





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Note D – Financing Arrangements and Debt



The Company has a $2.0 billion committed credit facility with a major banking consortium that expires in June 2017.  Borrowings under the facility bear interest at 1.45% above LIBOR based on the Company’s current credit rating as of March 31, 2016.  In addition, facility fees of 0.30% are charged on the full $2.0 billion commitment.  At March 31, 2016, the company had borrowings of $925 million under this committed facility.  At March 31, 2016, the Company also had uncommitted credit lines that had an estimated total borrowing capacity of approximately $82 million of which $46 million was outstanding under these uncommitted credit lines.    The Company also had outstanding letters of credit of approximately $88 million issued under its revolving credit facility at quarter end 2016, which reduced the available borrowing capacity under the agreement.    If necessary, the Company believes it could borrow funds under all or certain of these uncommitted lines with various financial institutions in future periods.    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 $19.1 million and $206.7 million, respectively, associated with this lease at March 31, 2016.



Note E – Cash Flow Disclosures



Additional disclosures regarding cash flow activities are provided below.

















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 period ended March 31, 2015.







Curtailment expense for the three months ended March 31, 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, 2016, the Company made contributions of $3.5 million to its defined benefit pension and postretirement benefit plans.  Remaining required funding in 2016 for the Company’s defined benefit pension and postretirement plans is anticipated to be $10.3 million.

 

Note G – Incentive Plans



The costs resulting from all share-based payment transactions are recognized as an expense in the Consolidated Statements of Income 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 200,000 time-based RSU in February.  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 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 $17.57 per share.  Additionally, the Committee granted 708,200 SAR and 507,470 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 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.



For 2016 and 2015, stock options exercised  were non-cash transactions, thus there was no income tax benefit realized from option exercises during 2016 and 2015.

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Note G – Incentive Plans (Cont’d)



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













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, 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 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 2016 and 2015, 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, 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 effective tax rate for the three-month period ended March 31, 2015 was above the U.S. statutory tax rate primarily due to a deferred tax benefit associated with the sale of Malaysian assets.



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, 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.



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 March 31, 2016.  The impact from marking to market these commodity derivative contracts decreased the loss before income taxes by $56.8 million for the three-month period ended March 31, 2016.  There were no open derivative contracts at March 31, 2015.



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











Subsequent to March  31, 2016, the Company entered into an additional 5,000 barrels per day in WTI futures contracts for the second half of 2016 at an average price of $45.30 per barrel.







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



Foreign Currency Exchange Risks

The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S.  At March 31, 2016 and 2015 short-term derivative instrument were outstanding in Canada for approximately $11.3 million and $15.5 million, respectively, to manage the currency risks of certain U.S. dollar accounts receivable associated with sale of Canadian crude oil.   The worksheet impact from marking to market these foreign currency derivative contracts improved loss before income taxes by $0.3 million and $38 thousand for the three-month periods ended March 31, 2016 and 2015, respectively.



At March 31, 2016 and December 31, 2015, 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, 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 three-month periods ended March 31, 2016 and 2015, $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, 2016 was $18.1 million, which is recorded, net of income taxes of $6.3 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 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.

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









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 March 31, 2016 and December 31, 2015.



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, 2015 and March 31, 2016 and the changes during the three-month period ended March 31, 2016 are presented net of taxes in the following table.



1All amounts are presented net of income taxes.

2Reclassifications before taxes of $3,867 for the three-month period ended March 31, 2016 are included in the computation of net periodic benefit expense.  See Note G for additional information.  Related income taxes of $1,354 for the three-month period ended March 31, 2016 are included in Income tax expense.

3Reclassifications before taxes of $741 for the three-month period ended March 31, 2016 are included in Interest expense.  Related income taxes of $259 for the three month period ended March 31, 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

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Note L – Environmental and Other Contingencies (Contd.)



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 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.



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 $31.7 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 March 31, 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 natural gas sales volumes in Western Canada.  The natural gas sales contracts call for deliveries in 2016 of approximately 59 million cubic feet per day at Cdn $3.19 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 24.



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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.



Note P – Subsequent Events



In April 2016, a Canadian subsidiary of the Company signed a purchase and sale agreement for the sale of its interest in Syncrude Canada Ltd.  (“Syncrude”) asset to Suncor Energy Inc. (“Suncor”), for approximately C$937 million, subject to closing adjustments.  The company will divest its five percent, non-operated working interest in Syncrude subject to regulatory approval and normal closing conditions, and the sale is anticipated to close in mid-year 2016.



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 C$538 million.  The net book value of assets being divested totaling approximately $226.7 million has been classified as current assets held for sale as of March 31, 2016.  The resulting gain on sale will be deferred and recognized over the next 20 years as a reduction of lease operating expense in Canadian “conventional” operating segment consistent with the expected continuing involvement of the subsidiary.



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.  Under the terms of the joint venture the total consideration amounts to C$475 million, of which Murphy will pay approximately C$250 million in cash at closing, subject to normal closing adjustments, and

the remaining C$225 million in the form of a carried interest for a period of up to five years.  The transaction is expected to close in the second quarter of 2016.

 

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Overall Review



During the first quarter 2016, worldwide benchmark oil and natural gas prices continued to be significantly below average comparable benchmark prices during the first quarter 2015.  These lower oil and natural gas prices have led the Company to incur losses from operations in 2016.  Although the Company continues to aggressively attack its overall cost structure, a continuation of very low commodity prices would continue to lead to adverse effects on the Company’s income and cash flow.



Results of Operations



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





Murphy’s net loss in the first quarter of 2016 was $198.8 million ($1.16 per diluted share) compared to net loss of $14.4 million ($0.08 per diluted share) in the first quarter of 2015.  Income (loss) from continuing operations decreased from a profit of $3.5 million ($0.02 per diluted share) in the 2015 quarter to a loss of $199.5 million ($1.16 per diluted share) in 2016.  In the 2016 first quarter, the Company’s exploration and production continuing operations incurred a loss of $156.8 million compared to earnings of $18.7 million in the 2015 quarter.  The net loss in the 2016 quarter was unfavorably impacted by lower revenues due to significantly lower realized oil and natural gas sales prices and lower volume sold, and impairment charges, offset in part by lower lease operating expenses, lower depreciation expense and lower exploration costs.  The corporate function had after-tax costs of $42.7 million in the 2016 first quarter compared to after-tax costs of $15.2 million in the 2015 period with the unfavorable variance in the current period mostly due to lower benefits from foreign exchange effects offset in part by lower administrative costs.  The 2016 first quarter included income from discontinued operations of $0.7 million ($0.00 per diluted share) compared to a loss of $17.9 million ($0.10 per diluted share) in the 2015 period.  Discontinued operations in the prior period primarily consisted of costs relating to winding down of refining and marketing operations in the U.K., the final components of which were sold at the end of the second quarter 2015.







 

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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 2016 vs. 2015



United States exploration and production operations reported a loss of $65.6 million in the first quarter of 2016 compared to a loss of $93.9 million in the 2015 quarter.  Results improved $28.3 million in the 2016 quarter compared to the 2015 period as lower supply costs and lower exploration expenses more than offset declines in revenues.  Revenue in the U.S. fell $105.4 million in the period due to both lower oil and natural gas realized sales prices and lower volumes sold.  Lease operating expenses decreased by $46.3 million due to lower costs in Eagle Ford Shale and offshore Gulf of Mexico compared to same quarter in 2015 with most of the reduction due to the Company aggressively attacking its cost structure.  Severance and ad valorem taxes in the 2016 quarter were $7.9 million lower than the 2015 period primarily due to weaker average commodity prices and lower volume sold.  Depreciation expense decreased $36.0 million in 2016 compared to 2015 due to both lower unit rates in the 2016 period and lower volume sold.  Exploration expenses were down $56.3 million in the first quarter of 2016 primarily related to lower dry hole costs of $46.4 million compared to the 2015 quarter.



Operations in Canada had a  loss of $87.3 million in the first quarter 2016 compared to a  loss of $38.5 million in the 2015 quarter.  Canadian results of operations worsened by $48.8 million in the 2016 quarter and included losses for both conventional oil and natural gas operations and synthetic oil operations.  Results for conventional operations were $48.8 million lower in 2016 due to impairment expense, lower average realized sales prices for crude oil and natural gas and lower oil volume sold.  These were partially offset by higher natural gas volumes produced, lower supply costs and no repeat of prior year charges for an environmental provision at the Seal heavy oil area.    Natural gas sales volumes increased in 2016 due to higher production in the Tupper area of Western Canada as a result of no repeat of 2015 pipeline restriction by a third party and lower royalty.  Lease operating expenses associated with conventional operations were $8.0 million lower in the 2016 quarter due to both lower costs and a weaker Canadian dollar exchange rate.  Impairment expense was $95.1 million in 2016 due to a write down of heavy oil properties at Seal in Western Canada and the Terra Nova field offshore East Coast Canada.  Both impairments were the result of weakening in oil sales prices at March 31, 2016 compared to the end of 2015.  Synthetic operations results for 2016 were virtually the same as in the first quarter of 2015. Lower oil sales prices were offset by higher volume sold due to improved uptime at the processing facility and lower lease operating expense.  Lease operating expenses associated with synthetic operations were $5.8 million lower in the 2016 quarter due to lower maintenance costs, lower fuel costs and a weaker Canadian dollar exchange rate.



Malaysia operations reported earnings of $22.3 million in the 2016 quarter compared to earnings of $223.1 million during the same period in 2015.  Results were down $200.8 million in 2016 in Malaysia due to a $199.5 million after-tax gain on sale of a 10% interest in Malaysian assets in the 2015 period.  Lower commodity prices received and lower volumes sold in the 2016 period were virtually offset by lower lease operating expenses and lower depreciation expense. Crude oil and natural gas sales volumes in Malaysia were lower in the 2016 quarter, primarily due to natural field decline.  Lease operating expenses decreased in the 2016 period by $13.2 million due to lower costs and lower volume sold compared to 2015.  Depreciation expense was $144.5 million lower in 2016 compared to the 2015 quarter primarily due to lower unit rates following 2015 impairment charges at certain producing properties and lower oil and natural gas volumes sold.



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Results of Operations (Contd.)



Exploration and Production (Contd.)



First quarter 2016 vs. 2015 (Contd.)



Other international operations reported a loss of $26.2 million in the first quarter of 2016 compared to a loss of $72.0 million in the 2015 quarter.  The $45.8 million improvement in the 2016 period was primarily related to lower exploration expenses.  Dry hole costs decreased by $31.9 million in the current period and geological and geophysical costs were $10.8 million less than the 2015 period.



Total hydrocarbon production averaged 196,568 barrels of oil equivalent per day in the 2016 first quarter, which represented a 11.3% decrease from the 221,554 barrels of oil equivalents per day produced in the 2015 quarter.  Average crude oil and condensate production was 123,475 barrels per day in the first quarter of 2016 compared to 140,400 barrels per day in the first quarter of 2015.  Crude oil production decreased approximately 7,500 barrels in the Eagle Ford Shale area of South Texas in 2016 due to well decline associated with significantly less drilling in the last half of 2015 and early 2016 in response to lower prices.  Crude oil production in the Gulf of Mexico was higher in the 2016 quarter due to added production from the Medusa field’s subsea expansion project completed in June 2015.  Heavy oil production from the Seal area in Western Canada was lower in 2016 primarily due to volumes shut-in associated with uneconomic wells and natural decline.  Oil production offshore Eastern Canada was lower during 2016 primarily due to lower uptime at the Terra Nova field.  Lower oil production in 2016 in Malaysia was primarily attributable to less net oil volumes produced due to the sale of 10% of the Company’s total interest in early 2015 coupled with natural decline.  On a worldwide basis, the Company's crude oil and condensate prices averaged $34.19 per barrel in the first quarter 2016 compared to $47.12 per barrel in the 2015 period, a decline of 27% quarter to quarter.  Total production of natural gas liquids (NGL) was 9,235 barrels per day in the 2016 first quarter compared to 10,412 barrels per day in the same 2015 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 $8.36 per barrel in the 2016 quarter compared to $12.89 per barrel in 2015.  Natural gas sales volumes averaged 383 million cubic feet per day in the first quarter 2016 compared to 424 million cubic feet per day in 2015.  Natural gas sales volumes decreased in North America for 2016 due primarily to lower volumes produced offshore Gulf of Mexico but was partially offset by higher volumes in the Tupper area of Western Canada.  Natural gas production volumes in Malaysia decreased in the 2016 period due the sale of 10% of the Company’s total interests in early 2015 and natural decline.  North American natural gas sales prices averaged $1.57 per thousand cubic feet (MCF) in the 2016 quarter, 36% below the $2.46 per MCF average in the same quarter of 2015.  The average realized price for natural gas produced in the 2016 quarter at fields offshore Sarawak was $3.67 per MCF, compared to a price of $4.50 per MCF in the 2015 quarter.



Additional details about results of oil and gas operations are presented in the tables on page 24.

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Results of Operations (Contd.)



Exploration and Production (Contd.)



Selected operating statistics for the three-month periods ended March 31, 2016 and 2015 follow.







1 The Company sold a 10% interest in Malaysia properties on January 29, 2015.  Production in this table includes production for these sold interests through the date of disposition.

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  Prices are net of payments under 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, 2016 AND 2015

















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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 $42.7 million in the 2016 first quarter compared to a net cost of $15.2 million in the same 2015 quarter.  The $27.5 million increased cost in the 2016 period is primarily due to lower benefits from foreign currency exchange offset by lower administrative costs.  An after-tax gain of $1.7 million occurred in 2016 on transactions denominated in foreign currencies, while the 2015 quarter had an after-tax gain of $33.8 million.



Discontinued Operations



The Company has presented refining and marketing operations in the U.K. as discontinued operations in its consolidated financial statements.  In June 2015, the Company completed an agreement to sell the remaining U.K. downstream assets.



The after-tax results of these operations for the three-month period ended March 31, 2016 and 2015 are reflected in the following table.







Financial Condition



Net cash provided by continuing operating activities was $43.3 million for the first three months of 2016 compared to $533.8 million during the same period in 2015.  The decline in cash provided by continuing operations activities in 2016 was primarily attributable to significantly lower realized sales prices for the Company’s oil and gas production and lower volume sold during the current year, offset in part by lower lease operating expenses.  Changes in noncash operating working capital from continuing operations used cash of $104.3 million during the first three months of 2016, compared to generating cash of $258.8 million in 2015.  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 $33 thousand in 2016 compared to $417.2 million in 2015 with the prior year amount primarily relating to proceeds received upon sale of a 10% interest in Malaysian assets.  Other significant sources of cash included $87.0 million in the 2016 period and $301.5 million in 2015 from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition.  The Company had net borrowings of $371.0 million in the three-month period of 2016 compared to a net repayment of $295.0 million in the 2015 quarter.  The net borrowings were primarily related to day rate commitments associated with deepwater rig contract exits costs and 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 $210.0 million and $823.8 million in the three-month period ended March 31, 2016 and 2015, respectively.  Total cash dividends to shareholders amounted to $60.3 million in 2016 and $62.3 million in 2015.  Also, the purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $49.3 million in the 2016 period and $265.7 million in the 2015 period.



Total accrual basis capital expenditures were as follows:







The reduction in capital expenditures in the exploration and production business in 2016 compared to 2015 was primarily attributable to lower development drilling in the Eagle Ford Shale area in the United States and offshore Malaysia and lower spending on exploration drilling in the Gulf of Mexico and other international operations.



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, 2016 was $321.2 million, $547.4 million more than December 31, 2015, with the increase attributable to lower accounts payable for deepwater rig contract exit cost and other operating activities and an increase in current assets held for sale related to a Canadian subsidiary of the Company.



At March 31, 2016, long-term debt of $3,409.5 million had increased by $368.9 million compared to December 31, 2015.  A summary of capital employed at March 31, 2016 and December 31, 2015 follows.

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Financial Condition (Contd.)



Cash and invested cash are maintained in several operating locations outside the United States.  At March 31, 2016, cash, cash equivalents and cash temporarily invested in Canadian government securities held outside the U.S. included U.S. dollar equivalents of approximately $243.7 million in Canada and $288.6 million in Malaysia.  In addition $5.6 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, 2016.  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.



Accounting and Other Matters



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.



Outlook



Average worldwide crude oil prices in April 2016 have improved over the average prices during the first quarter of 2016 when, at one point, the West Texas Intermediate market reached 14 year lows.  Global crude oil balances are beginning to tighten as non-OPEC production slides, but massive inventory levels will be slow to clear.  North American natural gas prices weakened in the 2016 first quarter as seasonal demand slumped due to an abnormally mild winter heating season coupled with year on year production growth.    The Company expects its total oil and natural gas production to average 177,000 to 180,000 barrels of oil equivalent per day in the second quarter 2016.  The Company currently anticipates total capital expenditures for the full year 2016 to be approximately $580 million.



The Company will primarily fund its capital program in 2016 using operating cash flow, but supplements funding where necessary using borrowings under available credit facilities.  The Company’s 2016 budget calls for borrowings of long-term debt during the year to fund a portion of the capital program.  If oil and/or natural gas prices weaken,  actual cash flow generated from operations could be reduced such that higher than anticipated borrowings might be required during the year to maintain funding of the Company’s ongoing development projects.  The Company’s revolving credit facility matures in June 2017, and the Company currently expects to execute a new agreement prior to expiry of the existing facility.  A new credit facility may include different terms compared to the existing facility.



The significant reduction in the sales prices of crude oil has caused the Company to reduce capital expenditures, including development drilling and completion operations in North America.  The Company currently projects that its capital spending program in 2016 will be well below 2015 levels.  The reduced level of capital expenditures, if it continues, could lead to lower production levels in future periods.  A continuation of low oil and/or gas prices or further deterioration therein, could lead to negative future effects on the Company, which could include reductions in proved reserves, additional impairment charges, the necessity for further cost containment measures, higher debt levels, and a reconsideration of the level of dividends on its Common stock.

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Outlook (Contd.)



As of May 2,  2016 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 2015 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and page 29 of this Form 10-Q report.  Murphy undertakes no duty to publicly update or revise any forward-looking statements.



ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK



The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates.  As described in Note J to this Form 10-Q report, Murphy makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.



There were commodity transactions in place at March 31, 2016 covering certain future U.S. crude oil sales volumes in 2016.  A 10% increase in the respective benchmark price of these commodities would have decreased the recorded net asset associated with these derivative contracts by approximately $22.9 million, while a 10% decrease would have increased the recorded net asset by a similar amount.



There were derivative foreign exchange contracts in place at March 31, 2016 to hedge the value of the U.S. dollar against the Canadian dollar for certain U.S. dollar receivables to be collected in April 2016.  A 10% strengthening of the U.S. dollar against the Canadian dollar would have decreased the recorded net asset associated with these contracts by approximately $1.1 million, while a 10% weakening of the U.S. dollar would have increased the recorded net asset by approximately $1.2 million.  Changes in the fair value of these derivative contracts generally offset the financial statement impact of an equivalent volume of foreign currency exposures associated with other assets and/or liabilities.

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