UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

                                                                       

FORM 10-Q

                                                                       

                               (Mark one)

[X]  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended March 31, 2015

 

OR

 

[  ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR

15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from _______________ to _______________

 

Commission File Number 1-8590

                                                    

 

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)

                                                    

 

(870) 862-6411

(Registrant's telephone number, including area code)

                                                    

 

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.

☒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).

☒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  ☒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     ☒ No

 

Number of shares of Common Stock, $1.00 par value, outstanding at March 31, 2015 was 177,969,015.

 

                                                                                                                                                                                                                                                                                                                                 

                                                                                                                                                                                                                                                                                                                                 

 

 

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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)

 

 

*Reclassified to conform to current presentation.

 

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 (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)

 

 

 

*Investments 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, 2015 and December 31, 2014, and the results of operations,  cash flows and changes in stockholders’ equity for the interim periods ended March 31, 2015 and 2014, 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 2014 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, 2015 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, 2015, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $120.6 million.  The following table reflects the net changes in capitalized exploratory well costs during the three-month periods ended March 31, 2015 and 2014.

 

 

 

 

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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 $120.6 million of exploratory well costs capitalized more than one year at March 31, 2015, $54.7 million is in the U.S. and $65.9 million is in Brunei.  In both geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

 

During the first quarter 2015, the Company completed the second phase of the sale of 30% of its oil and gas assets in Malaysia and received net cash proceeds of $417.2 million.  The Company recorded an after-tax gain on this sale of $199.5 million.  Combined net cash proceeds received to date from the 30% sale, subject to final adjustments, totaled $1.88 billion.

 

See also Note E for discussion regarding a capital lease of production equipment at the Kakap field.

 

 

Note C – Inventories

 

Inventories are carried at the lower of cost or market.  For the Company’s U.K. refining and marketing operations reported as discontinued operations, the cost of crude oil and finished products is predominantly determined on the last-in, first-out (LIFO) method.  At March 31, 2015 and December 31, 2014, the carrying value of inventories under the LIFO method was $29.7 million and $44.9 million, respectively, less than such inventories would have been valued using the first-in, first-out (FIFO) method.  These inventories are included in current assets held for sale on the Consolidated Balance Sheet.

 

 

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Note D – Discontinued Operations

 

The Company has accounted for its U.K. refining and marketing operations as discontinued operations for all periods presented.  During the first quarter 2015, the Company signed an agreement to sell the remaining U.K. downstream assets with the transaction scheduled to close mid-year 2015.

 

The results of operations associated with these discontinued operations for the three-month period ended March 31, 2015 and 2014 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, 2015 and December 31, 2014.  

 

 

 

 

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Note E – Financing Arrangements and Debt

 

The Company has a $2.0 billion committed credit facility that expires in June 2017.  Borrowings under the facility bear interest at 1.25% above LIBOR based on the Company’s current credit rating as of March 31, 2015.  In addition, facility fees of 0.25% are charged on the full $2.0 billion commitment.  The Company also had unused uncommitted credit facilities that totaled approximately $290 million at March 31, 2015.  These uncommitted facilities may be withdrawn by the various banks at any time.  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 2015.

 

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 $21.8 million and $209.2 million, respectively, associated with this lease at March 31, 2015.

 

 

Note F – Cash Flow Disclosures

 

Additional disclosures regarding cash flow activities are provided below.

 

 

 

 

 

 

 

Note G – 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 G – 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, 2015 and 2014.

 

 

 

During the three-month period ended March 31, 2015, the Company made contributions of $26.3 million to its defined benefit pension and postretirement benefit plans.  Remaining required funding in 2015 for the Company’s defined benefit pension and postretirement plans is anticipated to be $9.9 million.

 

 

Note H – 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 2015, the Committee granted stock options for 991,000 shares at an exercise price of either $49.65 or $51.63 per share.    The Black-Scholes valuation for these awards was $10.97 per option.  The Committee also granted 455,000 performance-based RSU and 233,400 time-based RSU in February.  The fair value of the performance-based RSU, using a Monte Carlo valuation model, ranged from $44.03 to $48.12 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 $49.65 per share.    Additionally, the Committee granted 847,400 SAR and 616,790 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 48,665 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 ranged between $49.09 and $50.90 per unit on date of grant. 

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Note H – Incentive Plans (Contd.)

 

Beginning January 1, 2014, all stock option exercises are non-cash transactions for the Company.  The employee will receive net shares, after applicable statutory withholding taxes, upon each exercise.  The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $0.7 million for the three-month period ended March 31, 2014.  No income tax benefit was realized from option exercises for the three-month period ended March 31, 2015.

 

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

 

 

 

 

 

Note I – Earnings per Share

 

Net income (loss) was used as the numerator in computing both basic and diluted income per Common share for the three-month periods ended March 31, 2015 and 2014.  The following table reconciles the weighted-average shares outstanding used for these computations.

 

 

 

The following table reflects certain options to purchase shares of common stock that were outstanding during the 2015 and 2014 periods but were not included in the computation of diluted earnings per share because the incremental shares from assumed conversion were antidilutive.

 

 

 

 

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Note J – Income Taxes

 

The Company’s effective income tax rate generally exceeds the statutory U.S. tax rate of 35%.  The effective tax rate is calculated as the amount of income tax expense divided by income before income tax expense.  For the three-month periods in 2015 and 2014, the Company’s effective income tax rates were as follows:

 

 

The effective tax rates for most periods 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. 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 effective tax note rate for the three-month period ended March 31, 2014 was above the U.S. statutory tax rate, primarily due to other expenses in certain foreign jurisdictions for which no tax benefits were recognized.

 

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, 2015, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows:  United States – 2011; Canada – 2008; Malaysia – 2007; and United Kingdom – 2012.

 

 

Note K – 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 Income.  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 Income (Loss).  This deferred cost is being reclassified to Interest Expense in the Consolidated Statements of Income 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.  There were no open derivative contracts covering commodity price risk at March 31, 2015.  The Company had open derivative contracts at March 31, 2014.  The impact from marking the market these commodity derivative contracts decreased income before taxes by $18.8 million for the three-month period ended March 31, 2014.

 

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, 2014, short-term derivative instruments were outstanding to manage the risk of certain future income taxes that are payable in Malaysian ringgits.  The equivalent U.S. dollars of Malaysian ringgit derivative contracts open at March 31, 2014 were approximately $133.5 million. There were no open ringgit contracts at March 31, 2015.  Short-term derivative instrument contracts totaling $15.5 million and $23.0 million U.S. dollars were also outstanding at March 31, 2015 and 2014, respectively, to manage the risk of certain U.S. dollar accounts receivable associated with sale of crude oil production in Canada.  The impact from marking to market these

 

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

 

foreign currency derivative contracts increased income before taxes by $38 thousand and $3.4 million for the three-month periods ended March 31, 2015 and 2014, respectively.

 

At March 31, 2015 and December 31, 2014, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

 

 

 

For the three-month periods ended March 31, 2015 and 2014, the gains and losses recognized in the Consolidated Statements of Income 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, 2015 and 2014,  $0.7 million of the deferred cost on the interest rate swaps was charged to income as a component of Interest Expense.  The remaining cost deferred on these matured contracts at March 31, 2015 was $21.1 million, which is recorded, net of income taxes of $7.4 million, in Accumulated Other Comprehensive Loss in the Consolidated Balance Sheet.  The Company expects to charge approximately $2.2 million of this deferred cost to income in the form of interest expense during the remaining nine months of 2015.

 

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 K – Financial Instruments and Risk Management (Contd.)

 

The carrying value of assets and liabilities recorded at fair value on a recurring basis at March 31, 2015 and December 31, 2014 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 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 Income and 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 Income.

 

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, 2015 and December 31, 2014.

 

 

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Note L – Accumulated Other Comprehensive Loss

 

The components of Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets at December 31, 2014 and March 31, 2015 and the changes during the three-month period ended March 31, 2015 are presented net of taxes in the following table.

 

 

1All amounts are presented net of income taxes.

2Reclassifications before taxes of $4,260 for the three-month period ended March 31, 2015 are included in the computation of net periodic benefit expense.  See Note G for additional information.  Related income taxes of $1,478 for the three-month period ended March 31, 2015 are included in Income tax expense.

3Reclassifications before taxes of $741 for the three-month period ended March 31, 2015 are included in Interest expense.  Related income taxes of $259 for the three-month period ended March 31, 2015 are included in Income tax expense.

 

 

Note M – Environmental and Other Contingencies

 

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

 

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

 

The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws the

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Note M – Environmental and Other Contingencies (Contd.)

 

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 the first quarter 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 underway 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 the first quarter 2015 associated with the estimated costs of remediating the site.  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(s) will exceed the amount of expense recorded through March 31, 2015.

 

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 N – Commitments

 

The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2015 and 2016 natural gas sales volumes in Western Canada.  The natural gas sales contracts call for deliveries in 2015 and 2016 of approximately 65 million cubic feet per day and 9 million cubic feet per day, respectively, at prices that average Cdn $4.13 per MCF for both periods.  These natural gas contracts have been accounted for as normal sales for accounting purposes.

 

 

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Note O – New Accounting Principles

 

In April 2015, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) that simplifies the presentation of debt issuance costs.  The ASU requires that the cost of issuing debt be presented on the balance sheet as a direct reduction from the associated debt liability.  These costs have historically been recorded as an asset, rather than a direct reduction of debt.  This ASU does not affect the results of operations, as costs of debt issuance will continue to be amortized to interest expense.  The Company is required to adopt the ASU effective in the first quarter of 2016, but early adoption is permitted.  The Company has elected to adopt this ASU early, effective with the first quarter of 2015.  This change in accounting principle is preferable due to allowing debt issuance costs and debt issuance discounts to be presented similarly in the Balance Sheet as reductions to recorded debt balances.  A retrospective change to the December 31, 2014 Balance Sheet as previously presented is required due to the adoption.  The retrospective adjustment to the December 31, 2014 Balance Sheet is shown below:

 

 

 

 

 

 

Note P – Business Segments

 

 

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

 

 

 

 

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ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Overall Review

 

On January 29, 2015, the Company announced the closing of the second phase of the sale of 30% of its oil and gas assets in Malaysia.  The second phase covered the remaining one-third of the transaction or 10% of the Company’s Malaysian oil and gas assets.  The final post-closing adjustment period will end during the second quarter 2015 and actual results could differ from current estimates reported.  See Note B for further discussion of the sale. 

 

During the first quarter 2015, worldwide benchmark oil prices were significantly below average comparable benchmark prices during the first quarter 2014.  Should these lower benchmark oil prices remain, the Company would expect its net income and cash flow to continue to be adversely affected in 2015.

 

 

Results of Operations

 

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

 

 

Murphy’s net loss in the first quarter of 2015 was $14.4 million ($0.08 per diluted share) compared to net income of $155.3 million ($0.85 per diluted share) in the first quarter of 2014.  Income from continuing operations decreased from $169.3 million ($0.93 per diluted share) in the 2014 quarter to $3.5 million ($0.02 per diluted share) in 2015.  In the 2015 first quarter, the Company’s exploration and production continuing operations earned $18.7 million, down from $210.6 million in the 2014 quarter.  Exploration and production income in the 2015 quarter was unfavorably impacted compared to 2014 by lower realized oil and natural gas sales prices that were partially offset by increased sales volumes and a gain on the second phase of its sale of assets in Malaysia.  The corporate function had after-tax costs of $15.2 million in the 2015 first quarter compared to after-tax costs of $41.3 million in the 2014 period with the favorable variance in the current period due mostly to foreign currency exchange effects, partially offset by higher net interest expense and selling and general expenses.  The 2015 first quarter included a loss from discontinued operations of $17.9 million ($0.10 per diluted share) compared to a loss of $14.0 million ($0.08 per diluted share) in the first quarter 2014.  Discontinued operations primarily relate to refining and marketing operations in the U.K.

 

 

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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 2015 vs. 2014

 

United States exploration and production operations reported a loss of $93.9 million in the first quarter of 2015 compared to a profit of $103.1 million in the 2014 quarter.  Results were $197.0 million lower in the 2015 quarter compared to the same period in 2014 as lower realized oil and natural gas sales prices and higher depreciation, exploration and lease operating expenses were partially offset by increased sales volumes.  Revenue in the U.S. fell $205.4 million in the first quarter 2015 primarily due to lower oil and natural gas realized sales prices, however, produced and sold volumes for oil and natural gas was higher in 2015 at Eagle Ford Shale in South Texas and in the Gulf of Mexico.  Lease operating and depreciation expenses increased $25.3 million and $36.7 million, respectively, in 2015 compared to 2014 due to higher production in Eagle Ford Shale area and from the Dalmatian field in the Gulf of Mexico.  Exploration expense was up $37.3 million in 2015 primarily related to unsuccessful exploratory drilling at the Urca prospect in the Gulf of Mexico.

 

Operations in Canada had losses of $38.5 million in the first quarter 2015 compared to earnings of $67.6 million in the 2014 quarter.  Canadian results were $106.1 million lower in the 2015 quarter due to losses for both conventional oil and natural gas operations and synthetic oil operations.  Results for conventional operations were $75.6 million lower in 2015 mostly due to lower realized sales prices for crude oil and natural gas and less oil sales volumes compared to the 2014 period and the estimated costs of remediating a leak or leaks in the Seal field.  Oil production for conventional operations declined in Canada in the 2015 period compared to 2014 primarily due to lower volume at the Seal heavy oil area, partially offset by higher production offshore Canada due to less downtime for maintenance.  Natural gas sales volumes increased in 2015 due to higher production in the Tupper area of Western Canada as a result of second half 2014 drilling.  Other expense increased by $43.9 million due to an environmental remediation provision associated with the condensate leak(s) in the transfer pipeline at the Seal heavy oil area.  Synthetic operating results were lower by $30.5 million in the first quarter of 2015 due to weaker realized oil prices.  Lease operating expenses associated with synthetic operations were reduced by $19.7 million in the 2015 quarter due to lower maintenance costs, lower fuel costs, and a  weaker Canadian dollar exchange rate.

 

Operations in Malaysia reported earnings of $223.1 million in the 2015 quarter compared to earnings of $162.3 million during the same period in 2014.  Earnings were up $60.8 million in 2015 in Malaysia primarily due to a $199.5 million after-tax gain on sale of a 10% interest in Malaysian assets in the current quarter and lower lease operating expenses, partially offset by lower realized sales prices for oil and natural gas.  Crude oil sales volumes in Malaysia were higher in the 2015 quarter, primarily the Kakap and Siakap fields, offshore Sabah.  Natural gas sales volumes decreased in the 2015 quarter due to lower entitlement and impacts from the sale of 30% of the Company’s total interests.  Lease operating expense decreased in the 2015 period by $20.1 million primarily due to less maintenance cost compared to 2014.  Depreciation expense was $55.5 million higher in 2015 compared to the 2014 quarter primarily due to higher sales volumes and higher capital amortization rate for the Kakap field.  Tax expense decreased by $138.7 million compared to the 2014 quarter primarily due to lower earnings excluding the gain on sale and deferred tax benefits associated with the divestment of 10% of the Company’s Malaysia assets in 2015.

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Results of Operations (Contd.)

 

Exploration and Production (Contd.)

 

First quarter 2015 vs. 2014 (Contd.)

 

Other international operations reported a loss of $72.0 million in the first quarter of 2015 compared to a loss of $122.4 million in the 2014 quarter.  The $50.4 million improvement in the current quarter was primarily related to lower dry hole costs. 

 

Total hydrocarbon production averaged 221,554 barrels of oil equivalent per day in the 2015 first quarter, which represented an 8% increase from the 204,436 barrel equivalents per day produced in the 2014 quarter.  Average crude oil and condensate production was 140,400 barrels per day in the first quarter of 2015 compared to 131,573 barrels per day in the first quarter of 2014.  Crude oil production increased in the Eagle Ford Shale area of South Texas in 2015 where an ongoing development program continues.  Crude oil production in the Gulf of Mexico was higher in the 2015 quarter due to production at the Dalmatian field with wells that came onstream mid-year 2014.  Heavy oil production from the Seal area in Western Canada was lower in 2015 primarily due to volumes shut-in associated with a leak or leaks at an infield condensate transfer pipeline.  Oil production offshore Eastern Canada was higher during 2015 primarily due to less downtime for equipment repairs.  Oil production offshore Sarawak was lower in the 2015 quarter due to both lower entitlement percentages and sale of a combined 30% of its interests.  Oil production was higher in Block K in the 2015 quarter due to less downtime compared to the prior period where production was shut-in for 18 days in the 2014 quarter to tie-in the Siakap North Petai (SNP) field partially offset by impact of sale.  On a worldwide basis, the Company's crude oil and condensate prices averaged $47.12 per barrel in the first quarter 2015 compared to $96.43 per barrel in the 2014 period, a decline of 51% quarter to quarter.  Total production of natural gas liquids (NGL) was 10,412 barrels per day in the 2015 first quarter compared to 6,182 barrels per day in the same 2014 period.  The increase in NGL was primarily associated with the ongoing drilling program in the Eagle Ford Shale and the start-up of the Dalmatian field in the Gulf of Mexico mid-year 2014.  The average sales price for U.S. NGL was $12.89 per barrel in the 2015 quarter compared to $34.78 per barrel in 2014.  Natural gas sales volumes averaged 424 million cubic feet per day in the first quarter 2015, up from 400 million cubic feet per day in the 2014 quarter.  Natural gas sales volumes increased in North America for 2015 due to ongoing development drilling in the Eagle Ford Shale in South Texas, second half 2014 drilling in Tupper area of western Canada and production from the Dalmatian field in the Gulf of Mexico, which started in April 2014.  The increase in natural gas sales volumes in 2015 was somewhat offset by lower volumes in Malaysia due primarily to both lower entitlement percentages and sale of 30% of its interests.  North American natural gas sales prices averaged $2.46 per thousand cubic feet (MCF) in the 2015 quarter, 41% below the $4.15 per MCF average in the same quarter of 2014.  The average realized price for natural gas produced in the 2015 quarter at fields offshore Sarawak was $4.50 per MCF, compared to a price of $5.59 per MCF in the 2014 quarter.

 

Additional details about results of oil and gas operations are presented in the table 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, 2015 and 2014 follow.

 

 

 

*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, 2015 AND 2014

 

 

 

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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 a net cost of $15.2 million in the three months ended March 31, 2015 compared to a net cost of $41.3 million in the same 2014 quarter.  Net costs in the 2015 quarter were $26.1 million lower than the prior-year quarter due to favorable impacts from foreign currency exchange offset in part by higher net interest and administrative expenses.  Net after-tax gains of $33.8 million occurred in 2015 on transactions denominated in foreign currencies, while the 2014 quarter had net after-tax gains of $3.1 million.  The increase in net interest expense of $4.1 million was mostly associated with lower interest being capitalized. 

 

Discontinued Operations

The Company has presented refining and marketing operations in the U.K. as discontinued operations in its consolidated financial statements.  The refinery is currently in a period of shut-down and will be decommissioned and operated as a petroleum storage and distribution terminal.  In March 2015, the Company signed an agreement to sell the remaining assets with the transaction expected to close near mid-year.

 

The after-tax results of these operations for the three-month periods ended March 31, 2015 and 2014 are reflected in the following table.

 

 

 

Financial Condition

 

Net cash provided by operating activities was $533.8 million for the first three months of 2015 compared to $725.9 million during the same period in 2014.  Changes in operating working capital other than cash and cash equivalents from continuing operations generated cash of $258.8 million during the first three months of 2015, compared to $18.7 million in 2014.  In the 2015 quarter, proceeds from sales of property, plant and equipment generated cash of $417.2 million and were primarily due to the sale of a portion of the Company’s Malaysian assets.  Other significant sources of cash included $301.5 million in the 2015 period and $243.6 million in 2014 from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition.

 

The most significant use of cash in both years was for property additions and dry holes for continuing operations, which including amounts expensed, were $823.8 million and $996.2 million in the three-month periods ended March 31, 2015 and 2014, respectively.  Total cash dividends to shareholders amounted to $62.3 million in 2015 and $56.1 million in 2014.  The Company had net repayment of $295.0 million in debt in the 2015 first quarter with cash received in 2014 from the sale of a portion of its Malaysian assets.  In the 2014 quarter, the Company borrowed $479.0 million to fund capital development activities and repurchase Company stock.  The Company also paid $250.0 million to repurchase approximately 4,018,000 shares of its Common stock through an accelerated share repurchase (ASR) agreement with a major financial institution in the first quarter 2014.  The purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $265.7 million in the 2015 period and $240.8 million in the 2014 period.

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Financial Condition (Contd.)

 

Total accrual basis capital expenditures for continuing operations were as follows:

 

 

 

The reduction in capital expenditures in the exploration and production business in 2015 compared to 2014 was primarily attributable to lower development spending in the Eagle Ford Shale area in the United States and offshore Malaysia and lower spending on exploration drilling in 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, 2015 was $411.3 million, $280.0 million more than December 31, 2014, with the increase attributable to lower accounts payable for other operating activities and proceeds received from the sale of 10% interest in Malaysia in the first quarter 2015, partially offset by lower accounts receivable balances due to significant decline in realized sales prices and lower invested cash balances held by the Company’s Canadian operations.

 

At March 31, 2015, long-term debt of $2,591.7 million had increased by $74.0 million compared to December 31, 2014.  A summary of capital employed at March 31, 2015 and December 31, 2014 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, 2015, cash, cash equivalents and cash temporarily invested in Canadian government securities held outside the U.S. included U.S. dollar equivalents of approximately $441.7 million in Canada and $864.5 million in Malaysia.  In addition $135.8 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, 2015.  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 exist 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.

 

On August 6, 2014, the Company announced that its Board of Directors had approved a share buyback program of up to $500 million of the Company’s shares of Common stock over the next year.  As of the date of the filing of this Form 10-Q report, the Company has not repurchased any of its shares under this authorized share buyback program.

 

Accounting and Other Matters

 

In April 2015, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) that simplifies the presentation of debt issuance costs.  The ASU requires that the cost of issuing debt be presented on the balance sheet as a direct reduction from the associated debt liability.  These costs have historically been recorded as an asset, rather than a direct reduction of debt.  This ASU does not affect the results of operations, as costs of debt issuance will continue to be amortized to interest expense.  The Company is required to adopt the ASU effective in the first quarter of 2016, but early adoption is permitted.  The Company has elected to adopt this ASU early, effective with the first quarter of 2015.  This change in accounting principle is preferable due to allowing debt issuance costs and debt issuance discounts to be presented similarly in the Balance Sheet as reductions to recorded debt balances.  A retrospective change to the December 31, 2014 Balance Sheet as previously presented is required due to the adoption.  See Note O for further discussion of the retrospective adjustment.

 

During the first quarter 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.  Additional information associated with the leak or leaks is addressed in Note M to the Consolidated Financial Statements beginning on page 16 of this Form 10-Q.  Based on information currently available to the Company, the changes in the recognized estimated remediation costs at the site are not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.

 

Outlook

 

Average worldwide crude oil prices in April 2015 have been mixed compared to the average price during the first quarter of 2015.  North American natural gas prices in April 2015 have weakened slightly compared to those experienced in the first quarter due to warmer spring temperatures across much of the continent.  The Company expects its total oil and natural gas production to average 197,000 barrels of oil equivalent per day in the second quarter 2015.  The Company currently anticipates total capital expenditures for the full year 2015 to be approximately $2.3 billion.

 

The Company primarily funds its capital program using operating cash flow, but supplements funding where necessary using borrowings under available credit facilities.  Weaker oil and/or natural gas prices normally lead to lower cash flow generated from operations, which could lead to higher than anticipated borrowings in order to maintain funding of the Company’s ongoing development projects.  A period of low crude oil and/or gas prices could also cause the Company to reduce its capital spending program.  Additionally, weaker oil and/or natural gas prices could lead to impairment of certain investments in oil and natural gas properties in a future period.

 

The Company has continued to carry out its announced plan to exit the U.K. downstream business and signed an agreement to sell the remaining U.K. downstream assets with the transaction scheduled to close near mid-year.  The ultimate completion of the process to exit this U.K. business could lead to future financial accounting losses for the Company.

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Outlook (Contd.)

 

The Company has completed the sale of 30% of its working interest in most of its oil and gas properties in Malaysia as the final 10% sale was completed in January 2015.  The total sale price of $2.0 billion for the 30% interest is subject to normal closing costs and settlement adjustments, which are scheduled to be completed in the second quarter 2015.  The final settlement with purchaser could lead to adjustments to the recorded gain and net cash proceeds.

 

Through March 31, 2015, 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 2014 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 K 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 derivative foreign exchange contracts in place at March 31, 2015 to hedge the value of the U.S. dollar against the Canadian dollar for certain U.S. dollar receivables to be collected in April 2015.  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 $1.4 million, while a 10% weakening of the U.S. dollar would have increased the recorded net asset by approximately $1.7 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.