Form 10-Q
Table of Contents

 

 

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, 2009

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)

 

 

 

Delaware   71-0361522

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification Number)

 
200 Peach Street P.O. Box 7000, El Dorado, Arkansas   71731-7000
(Address of principal executive offices)   (Zip Code)

(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.    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).    ¨  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, 2009 was 190,787,349.

 

 

 


Table of Contents

MURPHY OIL CORPORATION

TABLE OF CONTENTS

 

     Page

Part I – Financial Information

  

Item 1. Financial Statements

  

Consolidated Balance Sheets

   2

Consolidated Statements of Income

   3

Consolidated Statements of Comprehensive Income

   4

Consolidated Statements of Cash Flows

   5

Consolidated Statements of Stockholders’ Equity

   6

Notes to Consolidated Financial Statements

   7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

   16

Item 3. Quantitative and Qualitative Disclosures About Market Risk

   23

Item 4. Controls and Procedures

   23

Part II – Other Information

  

Item 1. Legal Proceedings

   24

Item 1A. Risk Factors

   25

Item 6. Exhibits and Reports on Form 8-K

   25

Signature

   26

 

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Table of Contents

PART I – FINANCIAL INFORMATION

 

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)

 

     (Unaudited)
March 31,
2009
    December 31,
2008
 

ASSETS

    

Current assets

    

Cash and cash equivalents

   $ 327,403     666,110  

Canadian government securities with maturities greater than 90 days at the date of acquisition

     613,563     420,340  

Accounts receivable, less allowance for doubtful accounts of $7,513 in 2009 and $7,303 in 2008

     974,956     1,033,996  

Inventories, at lower of cost or market

    

Crude oil and blend stocks

     142,373     98,217  

Finished products

     348,936     315,340  

Materials and supplies

     184,668     190,616  

Prepaid expenses

     91,617     92,544  

Deferred income taxes

     33,852     29,801  
              

Total current assets

     2,717,368     2,846,964  

Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $3,693,987 in 2009 and $3,824,393 in 2008

     7,758,429     7,727,718  

Goodwill

     36,153     37,370  

Deferred charges and other assets

     552,926     537,046  
              

Total assets

   $ 11,064,876     11,149,098  
              

LIABILITIES AND STOCKHOLDERS’ EQUITY

    

Current liabilities

    

Current maturities of long-term debt

   $ —       2,572  

Accounts payable and accrued liabilities

     1,396,431     1,434,202  

Income taxes payable

     398,783     451,372  
              

Total current liabilities

     1,795,214     1,888,146  

Notes payable

     996,274     1,026,222  

Deferred income taxes

     845,348     878,131  

Asset retirement obligations

     429,011     435,589  

Deferred credits and other liabilities

     658,827     642,065  

Stockholders’ equity

    

Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued

     —       —    

Common Stock, par $1.00, authorized 450,000,000 shares, issued 191,508,641 shares in 2009 and 191,248,941 shares in 2008

     191,509     191,249  

Capital in excess of par value

     653,043     631,859  

Retained earnings

     5,680,948     5,557,483  

Accumulated other comprehensive loss

     (166,496 )   (87,697 )

Treasury stock, 721,292 shares of Common Stock in 2009 and 535,135 shares in 2008, at cost

     (18,802 )   (13,949 )
              

Total stockholders’ equity

     6,340,202     6,278,945  
              

Total liabilities and stockholders’ equity

   $ 11,064,876     11,149,098  
              

See Notes to Consolidated Financial Statements, page 7.

The Exhibit Index is on page 27.

 

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Table of Contents

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

(Thousands of dollars, except per share amounts)

 

     Three Months Ended
March 31,
 
     2009     2008*  

REVENUES

    

Sales and other operating revenues

   $ 3,416,427     6,466,668  

Gain on sale of assets

     15     42,386  

Interest and other income

     29,110     471  
              

Total revenues

     3,445,552     6,509,525  
              

COSTS AND EXPENSES

    

Crude oil and product purchases

     2,556,044     5,146,397  

Operating expenses

     362,361     401,178  

Exploration expenses, including undeveloped lease amortization

     111,105     66,496  

Selling and general expenses

     56,832     58,774  

Depreciation, depletion and amortization

     194,769     160,625  

Accretion of asset retirement obligations

     6,253     5,156  

Interest expense

     11,988     21,153  

Interest capitalized

     (10,323 )   (6,949 )
              

Total costs and expenses

     3,289,029     5,852,830  
              

Income from continuing operations before income taxes

     156,523     656,695  

Income tax expense

     85,283     248,489  
              

Income from continuing operations

     71,240     408,206  

Income from discontinued operations, net of income taxes

     99,864     786  
              

NET INCOME

   $ 171,104     408,992  
              

INCOME PER COMMON SHARE – Basic

    

Income from continuing operations

   $ 0.37     2.16  

Income from discontinued operations

     0.53     —    
              

Net Income – Basic

   $ 0.90     2.16  
              

INCOME PER COMMON SHARE – Diluted

    

Income from continuing operations

   $ 0.37     2.13  

Income from discontinued operations

     0.52     0.01  
              

Net income – Diluted

   $ 0.89     2.14  
              

Average Common shares outstanding – basic

     190,545,771     189,150,647  

Average Common shares outstanding – diluted

     192,281,803     191,550,683  

 

* Reclassified to conform to current presentation.

See Notes to Consolidated Financial Statements, page 7.

 

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Table of Contents

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

(Thousands of dollars)

 

     Three Months Ended
March 31,
 
     2009     2008  

Net income

   $ 171,104     408,992  

Other comprehensive income, net of income taxes

    

Net loss from foreign currency translation

     (80,987 )   (23,559 )

Retirement and postretirement benefit plan gains (losses)

     2,188     (1,489 )
              

COMPREHENSIVE INCOME

   $ 92,305     383,944  
              

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)

 

     Three Months Ended
March 31,
 
     2009     20081  

OPERATING ACTIVITIES

    

Net income

   $ 171,104     408,992  

Income from discontinued operations

     99,864     786  
              

Income from continuing operations

     71,240     408,206  

Adjustments to reconcile income from continuing operations to net cash provided by operating activities

    

Depreciation, depletion and amortization

     194,769     160,625  

Amortization of deferred major repair costs

     6,501     6,636  

Expenditures for asset retirements

     (2,098 )   (1,211 )

Dry hole costs

     67,471     241  

Amortization of undeveloped leases

     25,734     27,488  

Accretion of asset retirement obligations

     6,253     5,156  

Deferred and noncurrent income tax charges (benefits)

     (785 )   110,784  

Pretax gain from disposition of assets

     (15 )   (42,386 )

Net (increase) decrease in noncash operating working capital

     44,970     (245,215 )

Other operating activities, net

     (36,589 )   3,222  
              

Net cash provided by continuing operations

     377,451     433,546  

Net cash provided by discontinued operations

     2,576     12,983  
              

Net cash provided by operating activities

     380,027     446,529  
              

INVESTING ACTIVITIES

    

Property additions and dry hole costs

     (511,358 )   (506,657 )

Purchases of investment securities2

     (599,751 )   —    

Proceeds from maturity of investment securities2

     406,528     —    

Expenditures for major repairs

     (7,408 )   (7,676 )

Proceeds from sales of assets

     116     104,126  

Other – net

     (1,836 )   (5,749 )

Investing activities of discontinued operations

    

Sales proceeds

     78,908     —    

Other

     (845 )   (3,705 )
              

Net cash required by investing activities

     (635,646 )   (419,661 )
              

FINANCING ACTIVITIES

    

Increase (decrease) in notes payable

     (30,000 )   202,921  

Repayment of nonrecourse debt of a subsidiary

     (2,572 )   (5,235 )

Proceeds from exercise of stock options and employee stock purchase plans

     4,420     9,922  

Excess tax benefits related to exercise of stock options

     1,957     9,945  

Cash dividends paid

     (47,639 )   (35,564 )
              

Net cash provided (required) by financing activities

     (73,834 )   181,989  
              

Effect of exchange rate changes on cash and cash equivalents

     (9,254 )   (13,435 )
              

Net increase (decrease) in cash and cash equivalents

     (338,707 )   195,422  

Cash and cash equivalents at January 1

     666,110     673,707  
              

Cash and cash equivalents at March 31

   $ 327,403     869,129  
              

SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES

    

Cash income taxes paid

   $ 82,401     56,683  

Interest paid more than (less than) amounts capitalized

   $ (8,975 )   4,524  

 

1

Reclassified to conform to current presentation.

2

Represents cash invested in 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)

 

     Three Months Ended
March 31,
 
     2009     2008  

Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued

     —       —    
              

Common Stock – par $1.00, authorized 450,000,000 shares, issued 191,508,641 shares at March 31, 2009 and 190,499,101 shares at March 31, 2008

    

Balance at beginning of period

   $ 191,249     189,973  

Exercise of stock options

     260     526  
              

Balance at end of period

     191,509     190,499  
              

Capital in Excess of Par Value

    

Balance at beginning of period

     631,859     547,185  

Exercise of stock options, including income tax benefits

     7,440     20,261  

Restricted stock transactions and other

     5,439     6,962  

Amortization, forfeitures and other

     8,114     7,191  

Sale of stock under employee stock purchase plans

     191     —    
              

Balance at end of period

     653,043     581,599  
              

Retained Earnings

    

Balance at beginning of period

     5,557,483     3,983,998  

Net income for the period

     171,104     408,992  

Cash dividends

     (47,639 )   (35,564 )
              

Balance at end of period

     5,680,948     4,357,426  
              

Accumulated Other Comprehensive Income (Loss)

    

Balance at beginning of period

     (87,697 )   351,765  

Foreign currency translation losses, net of income taxes

     (80,987 )   (23,559 )

Retirement and postretirement benefit plan gains (losses), net of income taxes

     2,188     (1,489 )
              

Balance at end of period

     (166,496 )   326,717  
              

Treasury Stock

    

Balance at beginning of period

     (13,949 )   (6,747 )

Sale of stock under employee stock purchase plans

     587     164  

Awarded restricted stock, net of forfeitures

     —       637  

Cancellation of performance-based restricted stock and forfeitures

     (5,440 )   (7,598 )
              

Balance at end of period

     (18,802 )   (13,544 )
              

Total Stockholders’ Equity

   $ 6,340,202     5,442,697  
              

See notes to consolidated financial statements, page 7.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 – Interim Financial Statements

The consolidated financial statements of the Company presented herein have not been audited by independent auditors, except for the Consolidated Balance Sheet at December 31, 2008. 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, 2009, and the results of operations, cash flows and changes in stockholders’ equity for the three-month periods ended March 31, 2009 and 2008, in conformity with accounting principles generally accepted in the United States. In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the United States, 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 2008 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three months ended March 31, 2009 are not necessarily indicative of future results.

Note B – Discontinued Operations

On March 12, 2009, the Company sold its operations in Ecuador for net cash proceeds of $78.9 million, subject to post-closing adjustments. The acquirer also assumed certain tax and other liabilities associated with the Ecuador properties sold. The Ecuador properties sold included 20% interests in producing Block 16 and the nearby Tivacuno area. The Company recorded a gain of $104.0 million, net of income taxes of $14.0 million, from the sale of the Ecuador properties. The Company used the proceeds of the sale to pay down debt and to partially fund ongoing development projects in other areas. At the time of the sale, the Ecuador properties produced approximately 6,700 net barrels per day of heavy oil and had net oil reserves of approximately 4.6 million barrels. Ecuador operating results prior to the sale, and the resulting gain on disposal, have been reported as discontinued operations. The consolidated financial statements for 2008 have been reclassified to conform to this presentation. In past reports, the operating results for the Ecuador properties were primarily included in the Ecuador segment in the Oil and Gas Operating Results table; interest expense associated with the business was previously included in Corporate results. The major assets (liabilities) associated with the Ecuador properties were as follows:

 

(Thousands of dollars)   

Current assets

   $ 4,214

Property, plant and equipment, net of accumulated depreciation, depletion and amortization

     65,178

Other noncurrent assets

     683
      

Assets sold

   $ 70,075
      

Current liabilities

   $ 105,554

Other noncurrent liabilities

     35
      

Liabilities associated with assets sold

   $ 105,589
      

The following table reflects the results of operations from the sold properties including the gain on sale.

 

     Three Months Ended
March 31,
(Thousands of dollars)    2009    2008

Revenues, including a pretax gain on sale of $117,926 in 2009

   $ 126,023    23,206

Income before income tax expense

     113,825    1,241

Income tax expense

     13,961    455

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C– Property, Plant and Equipment

Financial Accounting Standards Board (FASB) Staff Position (FSP) 19-1 applies to companies that use the successful efforts method of accounting and it clarifies that 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, 2009, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $312.4 million. The following table reflects the net changes in capitalized exploratory well costs during the three-month periods ended March 31, 2009 and 2008.

 

(Thousands of dollars)    2009    2008

Beginning balance at January 1

   $ 310,118    272,155

Additions pending the determination of proved reserves

     2,326    15,051

Reclassifications to proved properties based on the determination of proved reserves

     —      —  
           

Balance at March 31

   $ 312,444    287,206
           

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.

 

     March 31
     2009    2008
(Thousands of dollars)    Amount    No. of
Wells
   No. of
Projects
   Amount    No. of
Wells
   No. of
Projects

Aging of capitalized well costs:

                 

Zero to one year

   $ 31,261    3    2    $ 17,672    2    2

One to two years

     18,046    2    2      71,145    14    3

Two to three years

     71,101    14    3      97,773    15    2

Three years or more

     192,036    25    5      100,616    10    4
                                 
   $ 312,444    44    12    $ 287,206    41    11
                                 

Of the $281.2 million of exploratory well costs capitalized more than one year at March 31, 2009, $177.7 million is in Malaysia, $60.3 million is in the Republic of Congo, $27.6 million is in the U.S., $9.6 million is in the U.K., and $6.0 million is in Canada. In Malaysia either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. In the Republic of Congo a development program is underway for the offshore Azurite field. In the U.S. drilling and development operations are planned, in Canada a continuing drilling and development program is underway, and in the U.K. further studies to evaluate the discovery are ongoing.

In January 2008, the Company sold its interest in Berkana Energy Corporation and recorded a pretax gain of $41.7 million ($39.9 million after-tax).

Note D – 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 retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note D – 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, 2009 and 2008.

 

     Three Months Ended March 31,  
     Pension Benefits     Other
Postretirement Benefits
 
(Thousands of dollars)    2009     2008     2009     2008  

Service cost

   $ 4,118     4,538     776     609  

Interest cost

     6,988     6,741     1,391     1,250  

Expected return on plan assets

     (5,346 )   (5,857 )   —       —    

Amortization of prior service cost

     398     344     (66 )   (65 )

Amortization of transitional asset

     (106 )   (132 )   —       —    

Recognized actuarial loss

     2,944     1,016     421     409  
                          

Net periodic benefit expense

   $ 8,996     6,650     2,522     2,203  
                          

Murphy previously disclosed in its financial statements for the year ended December 31, 2008, that it expected to contribute $50.2 million to its defined benefit pension plans and $4.9 million to its postretirement benefits plan during 2009. The anticipated defined benefit pension plan contributions included $30.0 million of voluntary contributions. During the three-month period ended March 31, 2009, the Company made contributions of $18.3 million (including $15.0 million of voluntary contributions to the defined benefit pension plan), and remaining funding in 2009 for the Company’s domestic and foreign defined benefit pension and postretirement plans is anticipated to be $36.8 million.

Note E – Incentive Plans

Statement of Financial Accounting Standards (SFAS) No. 123R, Share Based Payment, requires that the cost resulting from all share-based payment transactions be recognized as an expense in the financial statements using a fair value-based measurement method over the periods that the awards vest.

The 2007 Annual Incentive Plan (2007 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 2007 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 2007 Long-Term Incentive Plan (2007 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units, performance units, performance shares, dividend equivalents and other stock-based incentives. The 2007 Long-Term Plan expires in 2017. A total of 6,700,000 shares are issuable during the life of the 2007 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 June 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 2009, the Committee granted stock options for 1,057,000 shares at an exercise price of $43.95 per share. The Black-Scholes valuation for these awards was $15.15 per option. The Committee also granted 375,050 performance-based restricted stock units in February 2009 under the 2007 Long-Term Plan. The fair value of the performance-based restricted stock units, using a Monte Carlo valuation model, was $42.42 per unit. Also in February the Committee granted 47,790 shares of time-lapse restricted stock to the Company’s Directors under the 2008 Non-employee Director Plan. These shares vest on the third anniversary of the date of grant. The fair value of these awards was estimated based on the fair market value of the Company’s stock on the date of grant, which was $44.65 per share.

Cash received from options exercised under all share-based payment arrangements for the three-month periods ended March 31, 2009 and 2008 was $4.4 million and $9.9 million, respectively. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $2.5 million and $10.7 million for the three-month periods ended March 31, 2009 and 2008, respectively.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note E – Incentive Plans (Contd.)

 

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

 

     Three Months Ended
March 31
(Thousands of dollars)    2009    2008

Compensation charged against income before tax benefit

   $ 8,127    7,543

Related income tax benefit recognized in income

     2,707    2,638

Note F – Earnings per Share

Net income was used as the numerator in computing both basic and diluted income per Common share for the three months ended March 31, 2009 and 2008. The following table reconciles the weighted-average shares outstanding used for these computations.

 

     Three Months Ended
March 31
(Weighted-average shares)    2009    2008

Basic method

   190,545,771    189,150,647

Dilutive stock options

   1,736,032    2,400,036
         

Diluted method

   192,281,803    191,550,683
         

Certain options to purchase shares of common stock were outstanding during the 2009 and 2008 periods but were not included in the computation of diluted EPS because the incremental shares from assumed conversion were antidilutive. These included 3,354,875 shares at a weighted average share price of $55.71 in 2009 and 233,125 shares at a weighted average share price of $72.75 in 2008.

Note G – Financial Instruments and Risk Management

Murphy periodically utilizes 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. The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks.

 

 

Crude Oil Purchase Price Risks – The Company purchases crude oil as feedstock at its U.S. and U.K. refineries and is therefore subject to commodity price risk. Short-term derivative instruments were outstanding at March 31, 2009 and 2008 to manage the cost of about 0.5 million barrels and 1.5 million barrels, respectively, of crude oil at the Company’s Meraux, Louisiana and Superior, Wisconsin refineries. The total impact of marking these contracts to market increased income from continuing operations before income taxes by $0.2 million and $1.5 million in the three-month periods ended March 31, 2009 and 2008, respectively. The instruments outstanding at March 31, 2009 all mature by May 2009.

 

 

Foreign Currency Exchange Risks – The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. Short-term derivative instruments were outstanding at March 31, 2009 to manage the risk of certain income tax payments due in 2009 that are payable in Malaysian ringgits. The equivalent U.S. dollars of such Malaysian ringgit contracts outstanding at March 31, 2009 were approximately $140.3 million. Short-term derivative instruments were outstanding at March 31, 2009 and 2008 to manage the risk of certain U.S. dollar accounts receivable associated with sale of the Company’s Canadian crude oil. A total of $16.0 million U.S. dollar contracts were outstanding at March 31, 2009 related to these Canadian receivables. The effect of marking these contracts to market at March 31, 2009 and 2008 reduced first quarter 2009 and 2008 income from continuing operations before income taxes by $0.5 million and $0.6 million, respectively. The outstanding Malaysian instruments mature by July 2009 and the outstanding Canadian instruments mature in April 2009.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

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

 

At March 31, 2009, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

 

    

March 31, 2009

 
    

Asset (Liability) Derivatives

 
(Thousands of dollars)   

Balance Sheet Location

   Fair Value  

Commodity derivative contracts

  

Accounts payable and accrued liabilities

   $ (1,545 )

Foreign exchange derivative contracts

  

Accounts payable and accrued liabilities

     (483 )

For the three month period ended March 31, 2009, the gains and losses recognized in the consolidated statement of income for derivative instruments not designated as hedging instruments are presented in the following table.

 

   

Three Months Ended March 31, 2009

 
(Thousands of dollars)  

Location of Gain or

(Loss) Recognized in

Income on Derivative

   Amount of Gain
(Loss) Recognized in
Income on Derivative
 

Commodity derivative contracts

  Crude oil and product purchases    $ (4,684 )

Foreign exchange derivative contracts

  Interest and other income      (550 )
          
     $ (5,234 )
          

The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheet. The fair value measurements for these assets and liabilities at March 31, 2009 are presented in the following table.

 

           Fair Value Measurements at Reporting Date Using
(Thousands of dollars)    March 31,
2009
    Quoted Prices
in Active
Markets for
Identical

Assets (Liabilities)
(Level 1)
    Significant
Other Observable

Inputs
(Level 2)
    Significant
Unobservable

Inputs
(Level 3)

Assets – None

        

Liabilities

        

Derivative liabilities

   $ (2,028 )   —       (2,028 )   —  

Nonqualified employee savings plan

     (7,088 )   (7,088 )   —       —  
                        
   $ (9,116 )   (7,088 )   (2,028 )   —  
                        

Note H – Accumulated Other Comprehensive Loss

The components of Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets at March 31, 2009 and December 31, 2008 are presented in the following table.

 

(Thousands of dollars)    March 31,
2009
    Dec. 31,
2008
 

Foreign currency translation gains (losses), net of tax

   $ (35,470 )   45,517  

Retirement and postretirement benefit plan losses, net of tax

     (131,026 )   (133,214 )
              

Accumulated other comprehensive loss

   $ (166,496 )   (87,697 )
              

Note I – 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

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note I – Environmental and Other Contingencies (Contd.)

 

affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Because governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences, and may be taken in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.

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

The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. While some of these historical properties are in various stages of negotiation, investigation, and/or cleanup, the Company is investigating the extent of any such liability and the availability of applicable defenses and 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.

The Company’s liability for remedial obligations includes certain amounts that are based on anticipated regulatory approval for proposed remediation of former refinery waste sites. Although regulatory authorities may require more costly alternatives than the proposed processes, the cost of such potential alternative processes is not expected to exceed the accrued liability by a material amount. Certain environmental expenditures are likely to be recovered by the Company from other sources, primarily environmental funds maintained by certain states. Since no assurance can be given that future recoveries from other sources will occur, the Company has not recorded a benefit for likely recoveries.

The U.S. Environmental Protection Agency (EPA) currently considers the Company to be a Potentially Responsible Party (PRP) at two Superfund sites. The potential total cost to all parties to perform necessary remedial work at these sites may be substantial. However, based on current negotiations and available information, the Company believes that it is a de minimis party as to ultimate responsibility at these Superfund sites. The Company has not recorded a liability for remedial costs on Superfund sites. The Company could be required to bear a pro rata share of costs attributable to nonparticipating PRPs or could be assigned additional responsibility for remediation at the two sites or other Superfund sites. The Company believes that its share of the ultimate costs to clean-up the Superfund sites will be immaterial and will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

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.

On September 9, 2005, a class action lawsuit was filed in federal court in the Eastern District of Louisiana seeking unspecified damages to the class comprised of residents of St. Bernard Parish caused by a release of crude oil at Murphy Oil USA, Inc.’s (a wholly-owned subsidiary of Murphy Oil Corporation) Meraux, Louisiana, refinery as a result of flood damage to a crude oil storage tank following Hurricane Katrina. Additional class action lawsuits were consolidated with the first suit into a single action in the U.S. District Court for the Eastern District of Louisiana. In September 2006, the Company reached a settlement with class counsel and on October 10, 2006, the court granted preliminary approval of a class action Settlement Agreement. A Fairness Hearing was held January 4, 2007 and the

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note I – Environmental and Other Contingencies (Contd.)

 

court entered its ruling on January 30, 2007 approving the class settlement. The majority of the settlement of $330 million will be paid by insurance. The Company recorded an expense of $18 million in 2006 related to settlement costs not expected to be covered by insurance. As part of the settlement, all properties in the class area received a fair and equitable cash payment and have had residual oil cleaned. As part of the settlement, the Company offered to purchase all properties in an agreed area adjacent to the west side of the Meraux refinery; these property purchases and associated remediation have been paid by the Company at a cost of $55 million. The Company has fulfilled its obligations under the Class Action Settlement Agreement. Approximately 40 non-class action suits regarding the oil spill have been filed and remain pending. The Company believes that insurance coverage exists and it does not expect to incur significant costs associated with this litigation. On August 14, 2007, four of the Company’s high level excess insurers noticed the Company for arbitration as to whether and to what extent expenditures made by the Company in resolving the oil spill litigation have reached the attachment point for covered loss under their respective policies. The Company is of the position that full coverage should be afforded. In April 2009, two of the four insurers agreed to a settlement with the Company and withdrew from the arbitral proceedings, which are scheduled to take place in London in the third quarter. The Company believes neither the ultimate resolution of the remaining litigation nor the insurance arbitration will have a material adverse effect on its net income, financial condition or liquidity in a future period.

On June 10, 2003, a fire severely damaged the Residual Oil Supercritical Extraction (ROSE) unit at the Company’s Meraux, Louisiana refinery. The ROSE unit recovers feedstock from the heavy fuel oil stream for conversion into gasoline and diesel. Subsequent to the fire, numerous class action lawsuits have been filed seeking damages for area residents. All the lawsuits have been administratively consolidated into a single legal action in St. Bernard Parish, Louisiana, except for one such action which was filed in federal court. Additionally, individual residents of Orleans Parish, Louisiana, have filed an action in that venue. On May 5, 2004, plaintiffs in the consolidated action in St. Bernard Parish amended their petition to include a direct action against certain of the Company’s liability insurers. The St. Bernard Parish action has since been removed to federal court, which issued an order on July 25, 2008 denying plaintiff’s request to certify the case as a class action. In responding to this direct action, one of the Company’s insurers, AEGIS, has raised lack of coverage as a defense. The Company believes that this contention lacks merit and has been advised by counsel that the applicable policy does provide coverage for the underlying incident. Because the Company believes that insurance coverage exists for this matter, it does not expect to incur any significant costs associated with the lawsuits. Accordingly, the Company continues to believe that the ultimate resolution of the June 2003 ROSE fire litigation will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

The joint agreement between the owners of the Terra Nova field offshore eastern Canada requires a redetermination of working interests based on an analysis of reservoir quality among fault separated areas where varying ownership interests exist. Heretofore, the Company’s ownership interest has been 12%. The matter will be the subject of arbitration before final interests are established. This redetermination is expected to be finalized in 2010, and is retroactive to 2005. Upon completion of the redetermination process, a cash settlement is required among partners to balance cash flows retroactive to the effective date. The field’s operator has presented a preliminary indication that could reduce the Company’s interest at Terra Nova. The Company cannot predict at this time how its ownership interest will be affected by the redetermination process, and it is unable to determine whether settlement of this matter will have a material adverse effect on its net income in a future period.

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.

In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide financial guarantees or letters of credit that may be drawn upon if the Company fails to perform under those contracts. At March 31, 2009, the Company had contingent liabilities of $7.8 million under a financial guarantee and $104.3 million on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to these letters of credit because it is believed that the likelihood of having these drawn is remote.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note J – Accounting Matters

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51. This statement was adopted by the Company on January 1, 2009 and it is to be applied prospectively, except for presentation and disclosure requirements which are applied retrospectively. This statement requires noncontrolling interests to be reclassified as equity, and consolidated net income and comprehensive income shall include the respective results attributable to noncontrolling interests. The adoption of this statement did not have a significant effect on the Company’s consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations. This statement was adopted by the Company as of January 1, 2009 and it establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquired business. It also establishes how to recognize and measure goodwill acquired in the business combination or a gain from a bargain purchase, if applicable. Assets and liabilities that arise from business combinations that occurred prior to 2009 are not affected by this statement. The adoption of this statement had no effect on the Company’s financial statements for the three-month period ended March 31, 2009. This statement will impact the recognition and measurement of assets and liabilities in business combinations that occur beginning in 2009, and the Company is unable to predict at this time how the application of this statement will affect its financial statements in future periods.

In March 2008, the FASB issued SFAS No. 161, Disclosure about Derivative Instruments and Hedging Activities. This statement was adopted by the Company in January 2009, and it expands required disclosures regarding derivative instruments to include qualitative information about objectives and strategies for using derivatives, quantities disclosures about fair value amounts and gains and losses on derivative instruments, and disclosures about credit-risk related contingent features in derivative agreements. See Note G for further disclosures.

In June 2008, the FASB issued FASB Staff Position on EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities (FSP EITF 03-6-1). This statement, which was adopted by the Company in 2009, provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings per share (EPS) calculation under the two-class method. All prior-period EPS calculations must be adjusted retrospectively. The adoption of this statement did not have a significant impact on the Company’s prior-period EPS calculations.

In November 2008, the EITF published Issue No. 08-6, Equity Method Investment Accounting Considerations. This pronouncement was adopted by the Company in January 2009 and has been applied prospectively. The pronouncement gives guidance about how to initially measure contingent consideration for an equity method investment, how to recognize other-than-temporary impairments of an equity method investment, and how an equity method investor is to account for a share issuance by an investee. The adoption of this statement did not have a significant impact on the Company’s consolidated financial statements.

In December 2008, the FASB issued Staff Position No. FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets. This guidance will require additional disclosures about benefit plan assets, including how asset investment allocation decisions are made, the fair value of each major category of plan assets, and how fair value is determined for each major asset category. This guidance is effective for the Company as of December 31, 2009. Upon adoption, no comparative disclosures are required for earlier years presented. The Company does not expect the adoption of this standard to have a material impact on its consolidated financial statements in future periods.

In December 2008, the U.S. Securities and Exchange Commission adopted revisions to oil and natural gas reserve reporting requirements which are effective, as previously written, for the Company at year-end 2009. The primary changes to reserve reporting include:

 

 

A revised definition of proved reserves, including the use of unweighted average prices for a 12-month period to compute such reserves,

 

 

Expanding the definition of oil and gas producing activities to include non-traditional and unconventional resources, which includes the Company’s synthetic oil operations in Alberta,

 

 

Allowing companies to voluntarily disclose probable and possible reserves in SEC filings,

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note J – Accounting Matters (Contd.)

 

 

Amending required proved reserve disclosures to include separate amounts for synthetic oil and gas,

 

 

Expanding disclosures of proved undeveloped reserves, including discussion of such proved undeveloped reserves five years old or more, and

 

 

Disclosure of the qualifications of the chief technical person who oversees the Company’s overall reserve process.

The Company is currently evaluating these new rules and cannot predict how the new rules will affect its future reporting of oil and natural gas reserves.

Note K – Business Segments

 

      Total Assets    Three Mos. Ended March 31, 2009     Three Mos. Ended March 31, 2008  
(Millions of dollars)    at March 31,
2009
   External
Revenues
   Interseg.
Revenues
   Income
(Loss)
    External
Revenues
   Interseg.
Revenues
   Income
(Loss)
 

Exploration and production*

                   

United States

   $ 1,508.0    71.0    —      (7.3 )   143.1    —      47.1  

Canada

     1,989.3    113.4    21.1    .6     326.0    23.5    151.3  

United Kingdom

     200.2    11.7    —      3.4     86.1    —      32.1  

Malaysia

     2,766.0    337.4    —      117.5     464.6    —      204.7  

Other

     488.8    .5    —      (63.9 )   1.4    —      (8.0 )
                                       

Total

     6,952.3    534.0    21.1    50.3     1,021.2    23.5    427.2  
                                       

Refining and marketing

                   

North America

     2,322.5    2,396.6    —      14.6     4,530.2    —      1.0  

United Kingdom

     771.1    485.9    —      (3.8 )   957.6    —      9.2  
                                       

Total

     3,093.6    2,882.5    —      10.8     5,487.8    —      10.2  
                                       

Total operating segments

     10,045.9    3,416.5    21.1    61.1     6,509.0    23.5    437.4  

Corporate and other

     1,019.0    29.1    —      10.1     .5    —      (29.2 )
                                       

Revenue/income from continuing operations

     11,064.9    3,445.6    21.1    71.2     6,509.5    23.5    408.2  

Discontinued operations, net of tax

     —      —      —      99.9     —      —      .8  
                                       

Total

   $ 11,064.9    3,445.6    21.1    171.1     6,509.5    23.5    409.0  
                                       

 

* Additional details about results of oil and gas operations are presented in the tables on page 19.

 

15


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

Results of Operations

Murphy’s net income in the first quarter of 2009 was $171.1 million, $0.89 per diluted share, down significantly from net income of $409.0 million, $2.14 per diluted share, in the same quarter of 2008. Net income includes income from discontinued operations in 2009 of $99.9 million, $0.52 per diluted share, with this income mostly being generated from a gain on sale of the Company’s Ecuador operations in March 2009. Income from discontinued operations in the first quarter of 2008 was $0.8 million, $0.01 per diluted share. In 2009, substantially lower income from the Company’s exploration and production business was partially offset by favorable results from corporate activities. Murphy’s income from continuing operations by operating segment is presented below.

 

     Income (Loss)  
     Three Months Ended
March 31,
 
(Millions of dollars)    2009    2008  

Exploration and production

   $ 50.3    427.2  

Refining and marketing

     10.8    10.2  

Corporate

     10.1    (29.2 )
             

Income from continuing operations

   $ 71.2    408.2  
             

Murphy’s income from continuing exploration and production operations was $50.3 million in the first quarter of 2009 compared to $427.2 million in the same quarter of 2008. Lower realized sales prices for crude oil and natural gas and higher exploration expenses were the primary reasons for the lower 2009 earnings. In addition, earnings in the 2008 quarter included a $39.9 million after-tax gain from sale of Berkana Energy in Canada. Exploration expense in the 2009 period was $111.1 million, up from $66.5 million in 2008. Murphy’s refining and marketing operations generated earnings of $10.8 million in the 2009 quarter compared to earnings of $10.2 million in the 2008 quarter. Corporate functions reflected a net benefit of $10.1 million in the 2009 first quarter compared to net costs of $29.2 million in 2008.

Exploration and Production

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

 

     Income (Loss)  
     Three Months Ended
March 31,
 
(Millions of dollars)    2009     2008  

Exploration and production

    

United States

   $ (7.3 )   47.1  

Canada

     0.6     151.3  

United Kingdom

     3.4     32.1  

Malaysia

     117.5     204.7  

Other International

     (63.9 )   (8.0 )
              

Total

   $ 50.3     427.2  
              

In the United States, exploration and production operations had a loss of $7.3 million in the first quarter of 2009 compared to earnings of $47.1 million in the 2008 quarter. This unfavorable result was primarily due to lower oil and natural gas sales prices and higher exploration expenses. Production expense in the U.S. was less in the 2009 period due to lower operating costs compared to 2008. Depreciation expense rose in 2009 primarily due to higher per barrel equivalent amortization rates. Exploration expenses in the U.S. were $2.4 million higher in 2009 as more dry hole costs, primarily for an unsuccessful well in South Louisiana, were only partially offset by lower geophysical costs.

Earnings from operations in Canada were $0.6 million in the 2009 quarter versus $151.3 million in the 2008 quarter. The 2008 earnings included a $39.9 million after-tax gain on disposal of Berkana Energy. Canadian operations realized lower crude oil sales prices and had lower overall oil sales volumes in the current period. Natural gas sales volumes were higher in the 2009 quarter due to start-up of production in the Tupper area in British Columbia in December 2008, but natural gas sale prices were significantly lower in 2009. Production expenses in Canada were favorable in 2009 due to lower energy costs at Syncrude and the sale of the Lloydminster heavy oil field in the second quarter of 2008. Depreciation expense increased in the 2009 period compared to 2008 due mostly to the new Tupper natural gas sales volumes. Exploration expenses in Canada were $20.3 million in 2009 compared to $32.6 million in

 

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Table of Contents
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

 

Results of Operations (Contd.)

 

Exploration and Production (Contd.)

 

2008, and the reduction was due to higher seismic costs incurred in 2008 in the Tupper natural gas area. The effective tax rate was low in Canada in 2008 due to a capital gain tax effect attributable to the profit on sale of Berkana Energy.

U.K. operations earned $3.4 million in the 2009 period versus $32.1 million in the same quarter a year ago, with the reduction due to a combination of lower crude oil and natural gas sales prices and lower crude oil and natural gas sales volumes. Production and depreciation expenses decreased in 2009 compared to 2008 in the U.K. due to the lower oil and gas sales volumes.

Operations in Malaysia reported a profit of $117.5 million in the first quarter of 2009 compared to a profit of $204.7 million in the same period in 2008. The 2009 results were unfavorable to 2008 essentially due to lower crude oil sales prices. Production volumes for crude oil and natural gas increased during the 2009 period at the Kikeh field. Depreciation expense in Malaysia rose significantly in 2009 due to Kikeh field production increases. Dry hole costs were higher in the 2009 quarter than in 2008 due to unsuccessful drilling in Block P, offshore Sabah. Geological and geophysical expenses were lower in 2009 primarily due to 3-D seismic acquisition and processing costs in Block P in the first quarter a year ago. Certain exploration expenses in Malaysia do not receive income tax benefits at the present time.

Other international operations reported a loss of $63.9 million in the 2009 period versus a loss of $8.0 million in the same period a year ago. The higher loss in 2009 was primarily due to unsuccessful exploratory drilling costs for the Abalone Deep well, offshore Western Australia, and 3-D seismic expense for Block 37 offshore Suriname.

On a worldwide basis, the Company’s crude oil, condensate and natural gas liquids sales price averaged $43.15 per barrel for the 2009 first quarter compared to $89.51 per barrel in the first quarter of 2008. Crude oil and liquids production averaged a quarterly record 139,318 barrels per day in the 2009 quarter, up from 113,339 barrels per day in the 2008 period. Average oil sales volumes increased from 126,932 barrels per day in 2008 to 134,306 barrels per day in 2009. The higher crude oil production and sales volumes were mostly attributable to the Kikeh field in Block K, offshore Sabah Malaysia, where additional production wells were drilled and put onstream during 2008. Oil production in the United States was higher in 2009 than 2008 due to better production at the Front Runner field in the deepwater Gulf of Mexico. Heavy oil production in Western Canada was lower in the 2009 first quarter compared to the 2008 period primarily due to the sale of the Lloydminster heavy oil property in the second quarter 2008. Synthetic oil production at Syncrude in northern Alberta was higher in 2009 than 2008 primarily caused by a lower royalty rate attributable to lower oil prices. Production volumes offshore Eastern Canada were lower in 2009 versus 2008 due to a combination of field decline and a higher net royalty rate. Production in the U.K. was lower in 2009 due to lower volumes produced at the Schiehallion field due to equipment downtime. North American natural gas sales prices averaged $4.66 per thousand cubic feet (MCF) in the 2009 first quarter compared to $8.40 per MCF in the same quarter of 2008. Total natural gas sales volumes averaged 111 million cubic feet per day in 2009, up from 69 million cubic feet per day in the same period last year. The increase in 2009 was primarily attributable to gas production from the Kikeh field offshore Sabah Malaysia and gas production in the Tupper area in Western Canada, both of which started up in December 2008. Natural gas sales volumes in the U.K. were lower in 2009 than in 2008 due to equipment failure at the Amethyst field that shut down production for the entire 2009 quarter.

Additional details about results of oil and gas operations are presented in the tables on page 19.

 

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Table of Contents
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

 

Results of Operations (Contd.)

 

Exploration and Production (Contd.)

 

Selected operating statistics for the three-month periods ended March 31, 2009 and 2008 follow.

 

     Three Months Ended
March 31,
     2009    2008

Net crude oil, condensate and gas liquids produced – barrels per day

     139,318    113,339

Continuing operations

     133,977    105,458

United States

     13,268    12,112

Canada – light

     —      186

    – heavy

     7,436    9,907

    – offshore

     15,542    18,717

    – synthetic

     13,464    11,431

United Kingdom

     4,769    6,727

Malaysia

     79,498    46,378

Discontinued operations

     5,341    7,881

Net crude oil, condensate and gas liquids sold – barrels per day

     134,306    126,932

Continuing operations

     129,595    117,707

United States

     13,268    12,112

Canada – light

        186

    – heavy

     7,436    9,907

    – offshore

     13,459    17,153

    – synthetic

     13,464    11,431

United Kingdom

     2,464    8,772

Malaysia

     79,504    58,146

Discontinued operations

     4,711    9,225

Net natural gas sold – thousands of cubic feet per day

     111,309    68,983

United States

     53,307    56,884

Canada

     29,711    4,440

United Kingdom

     2,492    7,659

Malaysia

     25,799    —  

Total net hydrocarbons produced – equivalent barrels per day (1)

     157,870    124,836

Total net hydrocarbons sold – equivalent barrels per day (1)

     152,858    138,429

Weighted average sales prices

     

Crude oil, condensate and natural gas liquids – dollars per barrel (2)

     

United States

   $ 37.55    92.03

Canada (3) – light

        70.37

         – heavy

     22.30    53.57

         – offshore

     42.17    96.35

         – synthetic

     44.63    100.56

United Kingdom

     44.79    98.51

Malaysia (4)

     45.90    89.63

Natural gas – dollars per thousand cubic feet

     

United States (2)

   $ 5.12    8.52

Canada (3)

     3.84    6.80

United Kingdom (3)

     7.40    10.48

Malaysia

     0.23    —  

 

(1) Natural gas converted on an energy equivalent basis of 6:1
(2) Includes intracompany transfers at market prices.
(3) U.S. dollar equivalent.
(4) Prices are net of payments under the terms of production sharing contracts for Blocks SK 309 and K.

 

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

 

Results of Operations (Contd.)

 

OIL AND GAS OPERATING RESULTS (unaudited)

 

(Millions of dollars)

   United
States
    Canada     United
Kingdom
   Malaysia     Other     Synthetic
Oil –

Canada
    Total

Three Months Ended March 31, 2009

               

Oil and gas sales and other operating revenues

   $ 71.0     80.4     11.7    337.4     .5     54.1     555.1

Production expenses

     15.2     21.7     1.9    49.5     —       44.9     133.2

Depreciation, depletion and amortization

     43.3     34.5     2.1    73.7     .4     6.3     160.3

Accretion of asset retirement obligations

     1.7     1.0     .5    1.7     .1     1.0     6.0

Exploration expenses

               

Dry holes

     11.4     —       —      13.7     42.4     —       67.5

Geological and geophysical

     .8     1.0     —      (.2 )   12.2     —       13.8

Other

     1.6     .1     —      —       2.4     —       4.1
                                         
     13.8     1.1     —      13.5     57.0     —       85.4

Undeveloped lease amortization

     5.9     19.2     —      —       .6     —       25.7
                                         

Total exploration expenses

     19.7     20.3     —      13.5     57.6     —       111.1
                                         

Selling and general expenses

     5.4     3.5     .8    .1     6.3     .2     16.3
                                         

Results of operations before taxes

     (14.3 )   (.6 )   6.4    198.9     (63.9 )   1.7     128.2

Income tax provisions (benefits)

     (7.0 )   2.0     3.0    81.4     —       (1.5 )   77.9
                                         

Results of operations (excluding corporate overhead and interest)

   $ (7.3 )   (2.6 )   3.4    117.5     (63.9 )   3.2     50.3
                                         

Three Months Ended March 31, 2008

               

Oil and gas sales and other operating revenues

   $ 143.1     244.9     86.1    464.6     1.4     104.6     1,044.7

Production expenses

     16.9     24.2     10.0    53.4     —       48.1     152.6

Depreciation, depletion and amortization

     27.2     29.9     10.3    52.1     .2     6.7     126.4

Accretion of asset retirement obligations

     1.4     1.3     .5    1.3     .2     .2     4.9

Exploration expenses

               

Dry holes

     .5     —       —      (.3 )   —       —       .2

Geological and geophysical

     10.2     10.5     —      12.7     .6     —       34.0

Other

     1.5     .1     .1    —       3.1     —       4.8
                                         
     12.2     10.6     .1    12.4     3.7     —       39.0

Undeveloped lease amortization

     5.1     22.0     —      —       .4     —       27.5
                                         

Total exploration expenses

     17.3     32.6     .1    12.4     4.1     —       66.5
                                         

Selling and general expenses

     7.1     3.6     1.0    1.2     4.5     .2     17.6
                                         

Results of operations before taxes

     73.2     153.3     64.2    344.2     (7.6 )   49.4     676.7

Income tax provisions

     26.1     36.8     32.1    139.5     .4     14.6     249.5
                                         

Results of operations (excluding corporate overhead and interest)

   $ 47.1     116.5     32.1    204.7     (8.0 )   34.8     427.2
                                         

 

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Table of Contents
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

 

Results of Operations (Contd.)

 

Refining and Marketing

Refining and marketing operations in North America had earnings of $14.6 million in the 2009 first quarter compared to earnings of $1.0 million during the first quarter of 2008. The improved results in 2009 were primarily due to higher U.S. refining margins in the just completed quarter compared to one year ago. U.S. refining margins in 2009 benefited from lower prices for crude oil feedstocks. The economic downturn in the United States in 2009 has led to reduced demand for refined products such as gasoline and diesel, which in turn led to lower retail marketing margins in the U.S. in the 2009 quarter compared to 2008. Refining and marketing operations in the United Kingdom had a loss of $3.8 million in the first quarter of 2009 compared to a profit of $9.2 million in the same quarter of 2008. Results in the U.K. were hurt by both a decrease in demand for refined products and unplanned downtime of the fluid catalytic cracking unit at the Milford Haven, Wales, refinery.

Worldwide refinery inputs were 235,274 barrels per day in the first quarter of 2009 compared to 244,508 barrels per day in the 2008 quarter. Petroleum product sales were 503,878 barrels per day in the 2009 quarter, down from 524,061 barrels per day a year ago.

Selected operating statistics for the three-month periods ended March 31, 2009 and 2008 follow.

 

     Three Months Ended
March 31,
     2009    2008

Refinery inputs – barrels per day

   235,274    244,508

North America

   136,719    135,550

United Kingdom

   98,555    108,958

Petroleum products sold – barrels per day

   503,878    524,061

North America

   406,243    427,411

Gasoline

   300,470    307,784

Kerosine

   15,210    3,934

Diesel and home heating oils

   70,589    97,128

Residuals

   15,601    13,268

Asphalt, LPG and other

   4,373    5,297

United Kingdom

   97,635    96,650

Gasoline

   27,515    30,644

Kerosine

   10,767    10,262

Diesel and home heating oils

   34,876    27,570

Residuals

   7,575    12,380

LPG and other

   16,902    15,794

Corporate

Corporate activities, which include interest income and expense, foreign exchange effects, and corporate overhead not allocated to operating functions, reported a net benefit of $10.1 million in the 2009 first quarter compared to net costs of $29.2 million in the first quarter of 2008. The results from corporate activities improved in 2009 compared to 2008 primarily due to a combination of favorable foreign currency exchange effects and lower net interest expense. The foreign currency exchange benefits occurred mostly in Malaysia where a stronger U.S. dollar led to foreign currency exchange gains on Malaysian income tax liabilities. Total after-tax profit for foreign exchange was $26.1 million in the 2009 quarter compared to a $4.8 million loss in 2008. The lower net interest expense was attributable to a combination of lower interest rates, lower average debt levels, and higher amounts of interest capitalized to ongoing oil and gas development projects.

 

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

 

Financial Condition

Net cash provided by operating activities was $380.0 million for the first three months of 2009 compared to $446.5 million during the same period in 2008. Changes in operating working capital other than cash and cash equivalents generated cash of $45.0 million in the first quarter of 2009 and used cash of $245.2 million in the first quarter of 2008.

Other predominant uses of cash in both years were for dividends, which totaled $47.6 million in 2009 and $35.6 million in 2008, and for property additions and dry holes, which, including amounts expensed, were $511.4 million and $506.7 million in the three month periods ended March 31, 2009 and 2008, respectively. Cash of $193.2 million was used to purchase Canadian government securities with maturity dates greater than 90 days during the three months ended March 31, 2009. Total capital expenditures for continuing operations were as follows:

 

     Three Months Ended
March 31,
(Millions of dollars)    2009    2008

Capital expenditures – Continuing operations

     

Exploration and production

   $ 430.9    452.0

Refining and marketing

     48.6    119.8

Corporate and other

     1.2    1.0
           

Total capital expenditures – continuing operations

   $ 480.7    572.8
           

Working capital (total current assets less total current liabilities) at March 31, 2009 was 922.2 million, down $36.6 million from December 31, 2008. This level of working capital does not fully reflect the Company’s liquidity position, because the lower historical costs assigned to inventories under last-in first-out accounting were $283.6 million below fair value at March 31, 2009.

At March 31, 2009, long-term notes payable of $996.3 million had decreased by $29.9 million compared to December 31, 2008. A summary of capital employed at March 31, 2009 and December 31, 2008 follows.

 

     March 31, 2009    Dec. 31, 2008
(Millions of dollars)    Amount    %    Amount    %

Capital employed

           

Notes payable

   $ 996.3    13.6    $ 1,026.2    14.0

Stockholders' equity

     6,340.2    86.4      6,279.0    86.0
                       

Total capital employed

   $ 7,336.5    100.0    $ 7,305.2    100.0
                       

The Company’s ratio of earnings to fixed charges was 9.0 to 1 for the three-month period ended March 31, 2009. In May 2009, Standard & Poor’s maintained its “BBB” rating for the Company, but amended its outlook from negative to stable.

Accounting and Other Matters

Recent Accounting Pronouncements

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51. This statement was adopted by the Company on January 1, 2009 and it is to be applied prospectively, except for presentation and disclosure requirements which are applied retrospectively. This statement requires noncontrolling interests to be reclassified as equity, and consolidated net income and comprehensive income shall include the respective results attributable to noncontrolling interests. The adoption of this statement did not have a significant effect on the Company’s consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations. This statement was adopted by the Company as of January 1, 2009 and it establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquired business. It also establishes how to recognize and measure goodwill acquired in the business combination or a gain from a bargain purchase, if applicable. Assets and liabilities that arise from business combinations that occurred prior to 2009 are not affected by this statement. The adoption of this statement had no effect on the Company’s financial statements for the three-month period ended March 31, 2009. This statement will impact the recognition and measurement of assets and liabilities in business combinations that occur beginning in 2009, and the Company is unable to predict at this time how the application of this statement will affect its financial statements in 2009 and future periods.

 

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

 

Accounting and Other Matters (Contd.)

 

Recent Accounting Pronouncements (Contd.)

 

In March 2008, the FASB issued SFAS No. 161, Disclosure about Derivative Instruments and Hedging Activities. This statement was adopted by the Company in January 2009, and it expands required disclosures regarding derivative instruments to include qualitative information about objectives and strategies for using derivatives, quantities disclosures about fair value amounts and gains and losses on derivative instruments, and disclosures about credit-risk related contingent features in derivative agreements. See Note G to the consolidated financial statements.

In June 2008, the FASB issued FASB Staff Position on EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities (FSP EITF 03-6-1). This statement, which was adopted by the Company in 2009, provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings per share (EPS) calculation under the two-class method. All prior-period EPS calculations must be adjusted retrospectively. The adoption of this statement did not have a significant impact on the Company’s prior-period EPS calculations.

In November 2008, the EITF published Issue No. 08-6, Equity Method Investment Accounting Considerations. This pronouncement was adopted by the Company in January 2009 and has been applied prospectively. The pronouncement gives guidance about how to initially measure contingent consideration for an equity method investment, how to recognize other-than-temporary impairments of an equity method investment, and how an equity method investor is to account for a share issuance by an investee. The adoption of this statement did not have a significant impact on the Company’s consolidated financial statements.

In December 2008, the FASB issued Staff Position No. FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets. This guidance will require additional disclosures about benefit plan assets, including how asset investment allocation decisions are made, the fair value of each major category of plan assets, and how fair value is determined for each major asset category. This guidance is effective for the Company as of December 31, 2009. Upon adoption, no comparative disclosures are required for earlier years presented. The Company does not expect the adoption of this standard to have a material impact on its consolidated financial statements in future periods.

Outlook

Average crude oil prices in April 2009 have risen slightly compared to the average price during the first quarter 2009. The Company expects its oil and natural gas production to average about 144,000 barrels of oil equivalent per day in the second quarter, while sales volumes are expected to be approximately 140,000 barrels of oil equivalent per day during the quarter. Production volumes are projected to be lower in the second quarter than in the first quarter due to sale of the Company’s operations in Ecuador, downtime associated with oil and natural gas production and handling operations at the Kikeh field, spring breakup in the heavy oil area of Canada, a turnaround at Syncrude, and maintenance for the Hibernia and Schiehallion fields. U.S. downstream margins continued to be squeezed during April 2009 due to weak demand for refined products in the U.S. and U.K. The Company currently anticipates total capital expenditures for the full year 2009 to be approximately $2.0 billion.

Forward-Looking Statements

This Form 10-Q report contains statements of the Company’s expectations, intentions, plans and beliefs that are forward-looking and are dependent on certain events, risks and uncertainties that may be outside of the Company’s control. These forward-looking statements are made in reliance upon the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Actual results and developments could differ materially from those expressed or implied by such statements due to a number of factors including those described in the context of such forward-looking statements as well as those contained in the Company’s January 15, 1997 Form 8-K report on file with the U.S. Securities and Exchange Commission.

 

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Table of Contents
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 G to this Form 10-Q report, Murphy periodically makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions. There were short-term commodity derivative contracts in place at March 31, 2009 to hedge the cost of about 0.5 million barrels of crude oil at the Meraux and Superior refineries. A 10% increase in the price of West Texas Intermediate crude oil would have increased the recorded liability associated with these derivative contracts by approximately $2.6 million, while a 10% decrease would have reduced the recorded liability by a similar amount. Changes in the fair value of these derivative contracts generally offset the changes in value for an equivalent volume of crude oil feedstocks.

There were short-term derivative foreign exchange contracts in place at March 31, 2009 to hedge the value of the U.S. dollars against two foreign currencies. A 10% strengthening of the U.S. dollar against these foreign currencies would have increased the recorded liability associated with these contracts by approximately $14.1 million, while a 10% weakening of the U.S. dollar would have reduced the recorded liability by approximately $17.2 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.

 

ITEM 4. CONTROLS AND PROCEDURES

Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

There have been no changes in the Company’s internal control over financial reporting during the quarter ended March 31, 2009 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

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Table of Contents

PART II – OTHER INFORMATION

 

ITEM 1. LEGAL PROCEEDINGS

On September 9, 2005, a class action lawsuit was filed in federal court in the Eastern District of Louisiana seeking unspecified damages to the class comprised of residents of St. Bernard Parish caused by a release of crude oil at Murphy Oil USA, Inc.’s (a wholly-owned subsidiary of Murphy Oil Corporation) Meraux, Louisiana, refinery as a result of flood damage to a crude oil storage tank following Hurricane Katrina. Additional class action lawsuits were consolidated with the first suit into a single action in the U.S. District Court for the Eastern District of Louisiana. In September 2006, the Company reached a settlement with class counsel and on October 10, 2006, the court granted preliminary approval of a class action Settlement Agreement. A Fairness Hearing was held January 4, 2007 and the court entered its ruling on January 30, 2007 approving the class settlement. The majority of the settlement of $330 million will be paid by insurance. The Company recorded an expense of $18 million in 2006 related to settlement costs not expected to be covered by insurance. As part of the settlement, all properties in the class area received a fair and equitable cash payment and have had residual oil cleaned. As part of the settlement, the Company offered to purchase all properties in an agreed area adjacent to the west side of the Meraux refinery; these property purchases and associated remediation have been paid by the Company at a cost of $55 million. The Company has fulfilled its obligations under the Class Action Settlement Agreement. Approximately 40 non-class action suits regarding the oil spill have been filed and remain pending. The Company believes that insurance coverage exists and it does not expect to incur significant costs associated with this litigation. On August 14, 2007, four of the Company’s high level excess insurers noticed the Company for arbitration as to whether and to what extent expenditures made by the Company in resolving the oil spill litigation have reached the attachment point for covered loss under their respective policies. The Company is of the position that full coverage should be afforded. In April 2009, two of the four insurers agreed to a settlement with the Company and withdrew from the arbitral proceedings, which are scheduled to take place in London in the third quarter. The Company believes neither the ultimate resolution of the remaining litigation nor the insurance arbitration will have a material adverse effect on its net income, financial condition or liquidity in a future period.

On June 10, 2003, a fire severely damaged the Residual Oil Supercritical Extraction (ROSE) unit at the Company’s Meraux, Louisiana refinery. The ROSE unit recovers feedstock from the heavy fuel oil stream for conversion into gasoline and diesel. Subsequent to the fire, numerous class action lawsuits have been filed seeking damages for area residents. All the lawsuits have been administratively consolidated into a single legal action in St. Bernard Parish, Louisiana, except for one such action which was filed in federal court. Additionally, individual residents of Orleans Parish, Louisiana, have filed an action in that venue. On May 5, 2004, plaintiffs in the consolidated action in St. Bernard Parish amended their petition to include a direct action against certain of the Company’s liability insurers. The St. Bernard Parish action has since been removed to federal court, which issued an order on July 25, 2008 denying plaintiff’s request to certify the case as a class action. In responding to this direct action, one of the Company’s insurers, AEGIS, has raised lack of coverage as a defense. The Company believes that this contention lacks merit and has been advised by counsel that the applicable policy does provide coverage for the underlying incident. Because the Company believes that insurance coverage exists for this matter, it does not expect to incur any significant costs associated with the lawsuits. Accordingly, the Company continues to believe that the ultimate resolution of the June 2003 ROSE fire litigation will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

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

 

24


Table of Contents
ITEM 1A. RISK FACTORS

The Company has not identified any additional risk factors not previously disclosed in its Form 10-K filed on February 27, 2009.

 

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

 

(a) The Exhibit Index on page 27 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.

 

(b) A report on Form 8-K was filed on January 28, 2009 that included a News Release announcing the Company’s earnings and certain other financial information for the three-month and twelve-month periods ended December 31, 2008.

 

(c) A report on Form 8-K was filed on February 26, 2009 that included a News Release announcing an adjustment to 2008 results due to subsequent exploration expense.

 

25


Table of Contents

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

MURPHY OIL CORPORATION

(Registrant)

By  

/s/ JOHN W. ECKART

  John W. Eckart, Vice President and Controller (Chief Accounting Officer and Duly Authorized Officer)

May 7, 2009

    (Date)

 

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Table of Contents

EXHIBIT INDEX

 

Exhibit No.

    
12.1*    Computation of Ratio of Earnings to Fixed Charges
31.1*    Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*    Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32    Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 

* This exhibit is incorporated by reference within this Form 10-Q.

Exhibits other than those listed above have been omitted since they are either not required or not applicable.

 

27

Computation of Ratio of Earnings to Fixed Charges

Exhibit 12.1

Murphy Oil Corporation and Consolidated Subsidiaries

Computation of Ratio of Earnings to Fixed Charges (unaudited)

(Thousands of dollars)

 

     Three Months
Ended
March 31, 2009
   Years Ended December 31,1  
      2008    2007    2006     2005     2004  

Income from continuing operations before income taxes

   $ 156,523    2,821,455    1,208,747    1,000,043     1,347,028     804,262  

Distributions (less than) greater than equity in earnings of affiliates

     1,711    1,012    294    (4,065 )   (5,514 )   (4,225 )

Previously capitalized interest charged to earnings during period

     6,105    21,898    14,585    11,741     15,564     14,065  

Interest and expense on indebtedness, excluding capitalized interest

     1,665    42,153    25,612    9,476     8,765     34,064  

Interest portion of rentals2

     7,283    29,174    13,554    14,021     9,397     7,908  
                                   

Earnings before provision for taxes and fixed charges

   $ 173,287    2,915,692    1,262,792    1,031,216     1,375,240     856,074  
                                   

Interest and expense on indebtedness, excluding capitalized interest

     1,665    42,153    25,612    9,476     8,765     34,064  

Capitalized interest

     10,323    31,459    49,881    43,073     38,539     22,160  

Interest portion of rentals2

     7,283    29,174    13,554    14,021     9,397     7,908  
                                   

Total fixed charges

   $ 19,271    102,786    89,047    66,570     56,701     64,132  
                                   

Ratio of earnings to fixed charges

     9.0    28.4    14.2    15.5     24.3     13.3  

 

1

Prior years reclassified to conform to current presentation.

2

Calculated as one-third of rentals. Considered a reasonable approximation of interest factor.

 

Ex. 12-1

Section 302 PEO Certification

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, David M. Wood, certify that:

 

1. I have reviewed this quarterly report on Form 10-Q of Murphy Oil Corporation;

 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 

  a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

  b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

  c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

  d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal controls over financial reporting; and

 

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

  a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

  b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date: May 7, 2009

 

/s/ David M. Wood

David M. Wood
Principal Executive Officer

 

Ex. 31-1

Section 302 PFO Certification

Exhibit 31.2

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Kevin G. Fitzgerald, certify that:

 

1. I have reviewed this quarterly report on Form 10-Q of Murphy Oil Corporation;

 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 

  a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

  b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

  c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

  d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal controls over financial reporting; and

 

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

  a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

  b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date: May 7, 2009

 

/s/ Kevin G. Fitzgerald

Kevin G. Fitzgerald
Principal Financial Officer

 

Ex. 31-2

Section 906 PEO and PFO Certification

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Murphy Oil Corporation (the “Company”) on Form 10-Q for the period ended March 31, 2009 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we, David M. Wood and Kevin G. Fitzgerald, Principal Executive Officer and Principal Financial Officer, respectively, of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to our knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

May 7, 2009

 

/s/ David M. Wood

David M. Wood
Principal Executive Officer

/s/ Kevin G. Fitzgerald

Kevin G. Fitzgerald
Principal Financial Officer

 

Ex. 32