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, 2010

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.    þ  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).    þ  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  þ       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    þ  No

Number of shares of Common Stock, $1.00 par value, outstanding at March 31, 2010 was 191,482,649.

 

 

 


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

   17

Item 3. Quantitative and Qualitative Disclosures About Market Risk

   27

Item 4. Controls and Procedures

   27

Part II – Other Information

  

Item 1. Legal Proceedings

   28

Item 1A. Risk Factors

   28

Item 6. Exhibits and Reports on Form 8-K

   28

Signature

   29

 

1


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,
2010
    December 31,
2009
 

ASSETS

    

Current assets

    

Cash and cash equivalents

   $ 299,973      301,144   

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

     895,643      779,025   

Accounts receivable, less allowance for doubtful accounts of $7,872 in 2010 and $7,761 in 2009

     1,390,131      1,463,297   

Inventories, at lower of cost or market

    

Crude oil and blend stocks

     157,817      128,936   

Finished products

     377,659      384,250   

Materials and supplies

     218,733      220,796   

Prepaid expenses

     91,290      83,218   

Deferred income taxes

     54,713      15,029   
              

Total current assets

     3,485,959      3,375,695   

Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $5,057,057 in 2010 and $4,714,826 in 2009

     9,307,027      9,065,088   

Goodwill

     42,115      40,652   

Deferred charges and other assets

     334,741      274,924   
              

Total assets

   $ 13,169,842      12,756,359   
              

LIABILITIES AND STOCKHOLDERS’ EQUITY

    

Current liabilities

    

Current maturities of long-term debt

   $ 29      38   

Accounts payable and accrued liabilities

     2,003,515      1,794,406   

Income taxes payable

     447,836      387,164   
              

Total current liabilities

     2,451,380      2,181,608   

Long-term debt

     1,231,235      1,353,183   

Deferred income taxes

     1,052,274      1,018,767   

Asset retirement obligations

     502,331      476,938   

Deferred credits and other liabilities

     379,037      379,837   

Stockholders’ equity

    

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

     —        —     

Common Stock, par $1.00, authorized 450,000,000 shares, issued 191,988,394 shares in 2010 and 191,797,600 shares in 2009

     191,988      191,798   

Capital in excess of par value

     688,344      680,509   

Retained earnings

     6,305,396      6,204,316   

Accumulated other comprehensive income

     381,041      287,187   

Treasury stock, 505,745 shares of Common Stock in 2010 and 682,222 shares of Common Stock in 2009, at cost

     (13,184   (17,784
              

Total stockholders’ equity

     7,553,585      7,346,026   
              

Total liabilities and stockholders’ equity

   $   13,169,842      12,756,359   
              

See Notes to Consolidated Financial Statements, page 7.

The Exhibit Index is on page 30.

 

2


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,
 
     2010     2009  

REVENUES

    

Sales and other operating revenues

   $ 5,228,675      3,416,427   

Gain on sale of assets

     676      15   

Interest and other income (expense)

     (49,191   29,110   
              

Total revenues

     5,180,160      3,445,552   
              

COSTS AND EXPENSES

    

Crude oil and product purchases

     3,978,959      2,556,044   

Operating expenses

     465,607      362,361   

Exploration expenses, including undeveloped lease amortization

     66,364      111,105   

Selling and general expenses

     65,131      56,832   

Depreciation, depletion and amortization

     292,680      194,769   

Accretion of asset retirement obligations

     7,613      6,253   

Redetermination of Terra Nova working interest

     5,516      —     

Interest expense

     14,809      11,988   

Interest capitalized

     (2,665   (10,323
              

Total costs and expenses

     4,894,014      3,289,029   
              

Income from continuing operations before income taxes

     286,146      156,523   

Income tax expense

     137,255      85,283   
              

Income from continuing operations

     148,891      71,240   

Income from discontinued operations, net of income taxes

     —        99,864   
              

NET INCOME

   $ 148,891      171,104   
              

INCOME PER COMMON SHARE – BASIC

    

Income from continuing operations

   $ 0.78      0.37   

Income from discontinued operations

     —        0.53   
              

Net Income – Basic

   $ 0.78      0.90   
              

INCOME PER COMMON SHARE – DILUTED

    

Income from continuing operations

   $ 0.77      0.37   

Income from discontinued operations

     —        0.52   
              

Net income – Diluted

   $ 0.77      0.89   
              

Average Common shares outstanding – basic

     191,219,265      190,545,771   

Average Common shares outstanding – diluted

     192,929,735      192,281,803   

See Notes to Consolidated Financial Statements, page 7.

 

3


Table of Contents

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

(Thousands of dollars)

 

     Three Months Ended
March 31,
 
     2010    2009  

Net income

   $ 148,891    171,104   

Other comprehensive income, net of income taxes

     

Net gain (loss) from foreign currency translation

     91,660    (80,987

Retirement and postretirement benefit plan adjustments

     2,194    2,188   
             

COMPREHENSIVE INCOME

   $ 242,745    92,305   
             

See Notes to Consolidated Financial Statements, page 7.

 

4


Table of Contents

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)

 

     Three Months Ended
March 31,
 
     2010     2009  

OPERATING ACTIVITIES

    

Net income

   $ 148,891      171,104   

Income from discontinued operations

     —        99,864   
              

Income from continuing operations

     148,891      71,240   

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

    

Depreciation, depletion and amortization

     292,680      194,769   

Amortization of deferred major repair costs

     7,181      6,501   

Expenditures for asset retirements

     (7,521   (2,098

Dry hole costs

     22,274      67,471   

Amortization of undeveloped leases

     20,857      25,734   

Accretion of asset retirement obligations

     7,613      6,253   

Deferred and noncurrent income tax charges (benefits)

     18,272      (785

Pretax gain from disposition of assets

     (676   (15

Net decrease in noncash operating working capital

     244,327      44,970   

Other operating activities, net

     75,499      (36,589
              

Net cash provided by continuing operations

     829,397      377,451   

Net cash provided by discontinued operations

     —        2,576   
              

Net cash provided by operating activities

     829,397      380,027   
              

INVESTING ACTIVITIES

    

Property additions and dry hole costs

     (481,005   (511,358

Purchases of investment securities*

     (630,169   (599,751

Proceeds from maturity of investment securities*

     513,551      406,528   

Expenditures for major repairs

     (50,516   (7,408

Proceeds from sales of assets

     1,545      116   

Other – net

     (7,580   (1,836

Investing activities of discontinued operations

    

Sales proceeds

     —        78,908   

Other

     —        (845
              

Net cash required by investing activities

     (654,174   (635,646
              

FINANCING ACTIVITIES

    

Repayment of notes payable

     (122,000   (30,000

Repayment of nonrecourse debt of a subsidiary

     —        (2,572

Proceeds from exercise of stock options and employee stock purchase plans

     5,620      4,420   

Withholding tax on stock-based incentive awards

     (4,930   —     

Excess tax benefits related to exercise of stock options

     191      1,957   

Cash dividends paid

     (47,811   (47,639
              

Net cash required by financing activities

     (168,930   (73,834
              

Effect of exchange rate changes on cash and cash equivalents

     (7,464   (9,254
              

Net decrease in cash and cash equivalents

     (1,171   (338,707

Cash and cash equivalents at January 1

     301,144      666,110   
              

Cash and cash equivalents at March 31

   $ 299,973      327,403   
              

SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES

    

Cash income taxes paid

   $ 122,959      82,401   

Interest paid more than (less than) amounts capitalized

   $ 911      (8,975

 

* Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.

See Notes to Consolidated Financial Statements, page 7.

 

5


Table of Contents

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

(Thousands of dollars)

 

     Three Months Ended
March 31,
 
     2010     2009  

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

     —        —     
              

Common Stock – par $1.00, authorized 450,000,000 shares, issued 191,988,394 shares at March 31, 2010 and 191,508,641 shares at March 31, 2009

    

Balance at beginning of period

   $ 191,798      191,249   

Exercise of stock options

     190      260   
              

Balance at end of period

     191,988      191,509   
              

Capital in Excess of Par Value

    

Balance at beginning of period

     680,509      631,859   

Exercise of stock options, including income tax benefits

     5,300      7,440   

Restricted stock transactions and other

     (9,229   5,439   

Amortization, forfeitures and other

     11,502      8,114   

Sale of stock under employee stock purchase plans

     262      191   
              

Balance at end of period

     688,344      653,043   
              

Retained Earnings

    

Balance at beginning of period

     6,204,316      5,557,483   

Net income for the period

     148,891      171,104   

Cash dividends

     (47,811   (47,639
              

Balance at end of period

     6,305,396      5,680,948   
              

Accumulated Other Comprehensive Income (Loss)

    

Balance at beginning of period

     287,187      (87,697

Foreign currency translation gains (losses), net of income taxes

     91,660      (80,987

Retirement and postretirement benefit plan adjustments, net of income taxes

     2,194      2,188   
              

Balance at end of period

     381,041      (166,496
              

Treasury Stock

    

Balance at beginning of period

     (17,784   (13,949

Sale of stock under employee stock purchase plans

     301      587   

Awarded restricted stock, net of forfeitures

     4,299      —     

Cancellation of performance-based restricted stock and forfeitures

     —        (5,440
              

Balance at end of period

     (13,184   (18,802
              

Total Stockholders’ Equity

   $ 7,553,585      6,340,202   
              

See notes to consolidated financial statements, page 7.

 

6


Table of Contents

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, 2009. 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, 2010, and the results of operations, cash flows and changes in stockholders’ equity for the three-month periods ended March 31, 2010 and 2009, 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 2009 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, 2010 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 preliminary gain of $104.0 million, net of income taxes of $14.0 million, from the sale of the Ecuador properties. 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 4.3 million barrels. All Ecuador operating results prior to the sale, and the resulting gain on disposal, have been reported as discontinued operations. The major assets (liabilities) associated with the Ecuador properties at the date of sale 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

   $ 105,185

Other noncurrent liabilities

     35
      

Liabilities associated with assets sold

   $ 105,220
      

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

 

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

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

   $ 126,023

Income before income tax expense

     113,825

Income tax expense

     13,961

Note C – Property, Plant and Equipment

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

 

7


Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

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

 

At March 31, 2010, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $379.2 million. The following table reflects the net changes in capitalized exploratory well costs during the three-month periods ended March 31, 2010 and 2009.

 

(Thousands of dollars)    2010      2009

Beginning balance at January 1

   $ 369,862      310,118

Additions pending the determination of proved reserves

     9,310      2,326

Reclassifications to proved properties based on the determination of proved reserves

     —        —  
             

Balance at March 31

   $ 379,172      312,444
             

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
     2010    2009
(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

   $ 122,085    14    6    31,261    3    2

One to two years

     32,400    4    2    18,046    2    2

Two to three years

     17,946    2    2    71,101    14    3

Three years or more

     206,741    32    4    192,036    25    5
                               
   $ 379,172    52    14    312,444    44    12
                               

Of the $257.1 million of exploratory well costs capitalized more than one year at March 31, 2010, $177.7 million is in Malaysia, $59.8 million is in the U.S., $10.1 million is in Canada and $9.5 million is in the U.K. In Malaysia either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. 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.

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.

The table that follows provides the components of net periodic benefit expense for the three-month periods ended March 31, 2010 and 2009.

 

     Three Months Ended March 31,  
     Pension Benefits     Other
Postretirement Benefits
 
(Thousands of dollars)    2010     2009     2010     2009  

Service cost

   $ 5,259      4,118      888      776   

Interest cost

     7,448      6,988      1,431      1,391   

Expected return on plan assets

     (5,851   (5,346   —        —     

Amortization of prior service cost

     387      398      (64   (66

Amortization of transitional asset

     (127   (106   —        —     

Recognized actuarial loss

     2,965      2,944      578      421   
                          

Net periodic benefit expense

   $ 10,081      8,996      2,833      2,522   
                          

 

8


Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

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

 

During the three-month period ended March 31, 2010, the Company made contributions of $3.7 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2010 for the Company’s defined benefit pension and postretirement plans is anticipated to be $22.3 million.

In March 2010, the U.S. enacted a health care reform law. Along with other provisions, the law (a) eliminates the tax free status of federal subsidies to companies with qualified retiree prescription drug plans that are actuarially equivalent to Medicare Part D plans beginning in 2013; (b) imposes a 40% excise tax on high-cost health plans as defined in the law beginning in 2018; (c) eliminates lifetime or annual coverage limits and required coverage for preventative health services beginning in September 2010; and (d) imposes a fee of $2 (subsequently adjusted for inflation) for each person covered by a health insurance policy beginning in September 2010.

The Company provides a health care benefit plan to eligible U.S. employees and most U.S. retired employees. The new law did not significantly affect the Company’s consolidated financial statements as of March 31, 2010 and for the three-month period then ended. The Company is still evaluating the various components of the new law and cannot predict with certainly all the ways it may impact the Company. However, based on the evaluation performed to date, the Company currently believes that the health care reform law will not have a material effect on its financial condition, net income or cash flow in future periods.

Note E – Incentive Plans

The costs resulting from all share-based payment transactions are 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 2010, the Committee granted stock options for 1,605,628 shares at an exercise price of $52.845 per share. The Black-Scholes valuation for these awards was $18.75 per option. The Committee also granted 449,100 performance-based restricted stock units in February 2010 under the 2007 Long-Term Plan. The fair value of the performance-based restricted stock units, using a Monte Carlo valuation model, ranged from $42.38 to $50.95 per unit. Also in February the Committee granted 43,370 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 $52.49 per share.

Cash received from options exercised under all share-based payment arrangements for the three-month periods ended March 31, 2010 and 2009 was $5.6 million and $4.4 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 for each of the three-month periods ended March 31, 2010 and 2009.

 

9


Table of Contents

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)    2010    2009

Compensation charged against income before tax benefit

   $ 11,932    8,127

Related income tax benefit recognized in income

     3,181    2,707

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, 2010 and 2009. The following table reconciles the weighted-average shares outstanding used for these computations.

 

     Three Months Ended
March 31
(Weighted-average shares)    2010    2009

Basic method

   191,219,265    190,545,771

Dilutive stock options

   1,710,470    1,736,032
         

Diluted method

   192,929,735    192,281,803
         

Certain options to purchase shares of common stock were outstanding during the 2010 and 2009 periods but were not included in the computation of diluted EPS because the incremental shares from assumed conversion were antidilutive. These included 3,271,753 shares at a weighted average share price of $54.27 in 2010 and 3,354,875 shares at a weighted average share price of $55.71 in 2009.

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 to manage the cost of about 0.5 million barrels 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 in the three-month period ended March 31, 2009. There were no open crude oil purchase derivative contracts at March 31, 2010.

 

 

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, 2010 to manage the risk of certain income tax payments due in 2010 and later years that are payable in Malaysian ringgits. The equivalent U.S. dollars of such Malaysian ringgit contracts outstanding at March 31, 2010 and 2009 were approximately $361 million and $140 million, respectively. Short-term derivative instruments were outstanding at March 31, 2010 and 2009 to manage the risk of certain U.S. dollar accounts receivable associated with sale of the Company’s Canadian crude oil. A total of $45.0 million and $16.0 million U.S. dollar contracts were outstanding at March 31, 2010 and 2009, respectively, related to these Canadian receivables. The impact on consolidated income from continuing operations before income taxes from marking these derivative contracts to market was a gain of $14.3 million for first quarter 2010 and loss of $0.5 million for first quarter 2009. The outstanding Malaysian instruments mature by December 2010 and the outstanding Canadian instruments mature in April 2010.

 

10


Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

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

 

At March 31, 2010 and December 31, 2009, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

 

     March 31, 2010     December 31, 2009
     Asset (Liability) Derivatives     Asset (Liability) Derivatives
(Thousands of dollars)    Balance Sheet Location    Fair
Value
    Balance Sheet Location    Fair
Value

Commodity derivative contracts

   Accounts payable and
accrued liabilities
   $ (2,344   Accounts receivable    $ 2,296

Foreign exchange derivative contracts

   Accounts receivable      14,466      Accounts receivable      340

For the three-month periods ended March 31, 2010 and 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, 2010     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
    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
  $ (2,162   Crude oil and product
purchases
  $ (4,684

Foreign exchange derivative contracts

  Interest and other
income
    14,330      Interest and other
income
    (550
                   
    $ 12,168        $ (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, 2010 and December 31, 2009 are presented in the following table.

 

     March 31,
2010
    Fair Value Measurements at Reporting Date Using
(Thousands of dollars)      Quoted Prices
in Active
Markets for
Identical Assets
(Liabilities)
(Level 1)
    Significant Other
Observable
Inputs
(Level 2)
    Significant
Unobservable
Inputs
(Level 3)

Assets

        

Foreign exchange derivative assets

   $ 14,466      —        14,466      —  
                        

Liabilities

        

Commodity derivative liabilities

   $ (2,344   —        (2,344   —  

Nonqualified employee savings plan

     (5,723   (5,723   —        —  
                        
   $ (8,067   (5,723   (2,344   —  
                        

 

     Dec. 31,
2009
    Fair Value Measurements at Reporting Date Using
(Thousands of dollars)      Quoted Prices
in Active
Markets for
Identical Assets
(Liabilities)
(Level 1)
    Significant Other
Observable
Inputs
(Level 2)
   Significant
Unobservable
Inputs
(Level 3)

Assets

         

Derivative assets

   $ 2,636      —        2,636    —  
                       

Liabilities

         

Nonqualified employee savings plan

   $ (5,691   (5,691   —      —  
                       

 

11


Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

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

 

The nonqualified employee savings plan is an unfunded savings plan through which the participants seek a return via phantom investments in equity securities and/or mutual funds. Fair value of this liability was based on quoted prices for these equity securities and mutual funds. The fair value of commodity derivatives was determined based on market quotes for WTI crude and foreign currency exchange contracts at the balance sheet date. The income effect of the changes in the fair value of nonqualified employee savings plan is recorded in Selling and General Expense in the Consolidated Statement of Income. The change in fair value of commodity derivatives is recorded in Crude Oil and Product Purchases and the change in fair value of foreign currency exchange derivatives is recorded in Interest and Other Income (Loss).

The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.

Note H – Accumulated Other Comprehensive Income

The components of Accumulated Other Comprehensive Income on the Consolidated Balance Sheets at March 31, 2010 and December 31, 2009 are presented in the following table.

 

(Thousands of dollars)    March 31,
2010
    Dec. 31,
2009
 

Foreign currency translation gains, net of tax

   $ 513,128      421,468   

Retirement and postretirement benefit plan losses, net of tax

     (132,087   (134,281
              

Accumulated other comprehensive income

   $ 381,041      287,187   
              

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 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

 

12


Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note I – Environmental and Other Contingencies (Contd.)

 

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 one Superfund site. In early 2010, the Company’s involvement with another Superfund site was settled for a de minimis cash settlement. The potential total cost to all parties to perform necessary remedial work at the one remaining Superfund site 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 this Superfund site. 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 site or other Superfund sites. The Company believes that its share of the ultimate costs to clean-up the Superfund site 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.

Litigation arising out of a June 10, 2003 fire in the Residual Oil Supercritical Extraction (ROSE) unit at the Company’s Meraux, Louisiana refinery was settled in July 2009 and memorialized via a filing in the U.S. District Court for the Eastern District of Louisiana on July 24, 2009. An arbitral tribunal heard the Company’s claim for indemnity from one of its insurers, AEGIS, in September 2009 and a decision is pending. The Company believes that insurance coverage does apply for this matter. The Company continues to believe that the ultimate resolution of the June 2003 ROSE fire litigation, including associated insurance coverage issues, 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 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, 2010, the Company had contingent liabilities of $7.8 million under a financial guarantee and $59.4 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.

Note J – Commitments

The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2010 and 2011 natural gas sales volumes at the Tupper field in Western Canada. The contracts call for natural gas deliveries of approximately 33 million cubic feet per day during the remainder of 2010 at a price of Cdn$5.30 per thousand cubic feet and 34 million cubic feet per day in 2011 at a price of Cdn$6.26, with both contracts calling for delivery at the AECO “C” sales point. These contracts have been accounted for as a normal sale for accounting purposes.

 

13


Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note K – Terra Nova Working Interest Redetermination

 

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. The operator of Terra Nova completed the initial redetermination assessment in 2009 and the matter is the subject of arbitration before final interests are determined. The Company anticipates that its working interest at Terra Nova will be reduced from its current 12.0% to approximately 10.5%, subject to the results of the ongoing arbitration process between the operator and certain other owners. Upon completion of the arbitration process, which is anticipated to occur in late 2010, the Company will be required to make a cash settlement payment to the Terra Nova partnership for the value of oil sold since about December 2004 related to the ultimate working interest reduction below 12.0%. The Company has recorded cumulative expense of $89.0 million through March 2010 based on the anticipated working interest reduction. The expense has been reflected as Redetermination of Terra Nova Working Interest in the respective Consolidated Statement of Income. The Company cannot predict the final outcome of the redetermination process, which is expected to be completed by the end of 2010.

Note L – Accounting Matters

The Company adopted new guidance issued by the Financial Accounting Standards Board (FASB) regarding accounting for transfers of financial assets effective January 1, 2010. This guidance makes the concept of a qualifying special-purpose entity as defined previously no longer relevant for accounting purposes. Therefore, formerly qualifying special-purpose entities must be reevaluated for consolidation by reporting entities in accordance with the applicable consolidation guidance. This adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted, effective January 1, 2010, new guidance issued by the FASB that requires a company to perform an analysis to determine whether its variable interests give it a controlling financial interest in a variable interest entity. The primary beneficiary of a variable interest entity has both the power to direct the activities of the entity that most significantly impact the entity’s economic performance and the obligation to absorb potentially significant losses of the entity or the right to receive potentially significant benefits from the entity. A company is required to make ongoing reassessments of whether it is the primary beneficiary of a variable interest entity. This guidance also amends previous guidance for determining whether an entity is considered a variable interest entity. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted new accounting guidance issued by the FASB for noncontrolling interests in consolidated financial statements effective January 1, 2009. This guidance was applied prospectively, except for presentation and disclosure requirements which are applied retrospectively. This guidance required 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 guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted new accounting guidance covering business combinations effective January 1, 2009. The new guidance established 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 established how to recognize and measure goodwill acquired in the business combination or a gain from a bargain purchase, if applicable. This guidance impacts the recognition and measurement of assets and liabilities in business combinations that occur beginning in 2009. Assets and liabilities that arose from business combinations that occurred prior to 2009 are not affected by this guidance. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements. The Company is unable to predict how the application of this guidance will affect its financial statements in future periods.

The Company adopted new accounting guidance which addresses disclosures about derivative instruments and hedging activities in January 2009. This guidance 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.

 

14


Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note L – Accounting Matters (Contd.)

 

In 2009, the Company adopted new accounting guidance for determining whether instruments granted in share-based payment transactions are participating securities. This guidance specifies 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, and also requires that all prior-period EPS calculations be adjusted retrospectively. The adoption of this guidance did not have a significant impact on the Company’s prior-period EPS calculations.

The Company adopted new accounting guidance addressing certain equity method investment accounting considerations in January 2009, which has been applied prospectively. The guidance addresses 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 guidance did not have a significant impact on the Company’s consolidated financial statements.

The Company adopted new accounting guidance addressing subsequent events effective June 30, 2009. The guidance clarified the accounting for and disclosure of subsequent events that occur after the balance sheet date through the date of issuance of the applicable financial statements. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The FASB’s Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles guidance became effective for interim and annual periods ended after September 15, 2009 (the third calendar quarter for Murphy Oil) and it recognized the FASB Accounting Standards Codification as the single source of authoritative nongovernment U.S. generally accepted accounting principles. The codification superseded all existing accounting standards documents issued by the FASB, and established that all other accounting literature not included in the codification is considered nonauthoritative. Although the codification does not change U.S. generally accepted accounting principles, it does reorganize the principles into accounting topics using a consistent structure. The codification also includes relevant U.S. Securities and Exchange Commission guidance following the same topical structure. For periods ending after September 15, 2009, all references to U.S. generally accepted accounting principles will use the new topical guidelines established with the codification. Otherwise, this new standard is not expected to have a material impact on the Company’s consolidated financial statements in future periods.

The FASB has provided additional guidance regarding disclosures about postretirement 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 was effective for the Company as of December 31, 2009. Upon adoption, no comparative disclosures were required for earlier years presented.

In December 2008, the U.S. Securities and Exchange Commission adopted revisions to oil and natural gas reserves reporting requirements which became effective for the Company at year-end 2009. The primary changes to reserves reporting included:

 

 

A revised definition of proved reserves, including the use of unweighted average oil and natural gas prices in effect at the beginning of each month during the year 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,

 

 

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 utilized this new guidance at year-end 2009 to determine its proved reserves and to develop associated disclosures. The Company has thus far chosen not to provide voluntary disclosures of probable and possible reserves in its filings with the Securities and Exchange Commission.

 

15


Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

 

Note M – Business Segments

 

     Total
Assets at
March 31,
2010
                                 
        Three Mos. Ended March 31, 2010     Three Mos. Ended March 31,  20091  
(Millions of dollars)       External
Revenues
    Interseg.
Revenues
   Income
(Loss)
    External
Revenues
   Interseg.
Revenues
   Income
(Loss)
 

Exploration and production2

                  

United States

   $ 1,527.7    175.0      —      18.7      71.0    —      (7.3

Canada

     2,726.7    203.3      19.6    49.2      113.4    21.1    .6   

Malaysia

     3,228.6    503.9      —      173.5      337.4    —      117.5   

United Kingdom

     213.8    52.4      —      16.6      11.7    —      3.4   

Republic of the Congo

     571.9    28.3      —      2.5      —      —      .3   

Other

     41.8    2.3      —      (13.5   .5    —      (64.2
                                        

Total

     8,310.5    965.2      19.6    247.0      534.0    21.1    50.3   
                                        

Refining and marketing

                  

United States manufacturing

     1,261.6    116.2      640.2    (23.6   65.2    512.7    8.3   

United States marketing

     1,425.4    3,605.6      —      8.9      2,331.4    —      6.3   

United Kingdom

     914.4    542.4      —      (15.0   485.9    —      (3.8
                                        

Total

     3,601.4    4,264.2      640.2    (29.7   2,882.5    512.7    10.8   
                                        

Total operating segments

     11,911.9    5,229.4      659.8    217.3      3,416.5    533.8    61.1   

Corporate and other

     1,257.9    (49.2   —      (68.4   29.1    —      10.1   
                                        

Revenue/income from continuing operations

     13,169.8    5,180.2      659.8    148.9      3,445.6    533.8    71.2   

Discontinued operations, net of tax

     —      —        —      —        —      —      99.9   
                                        

Total

   $ 13,169.8    5,180.2      659.8    148.9      3,445.6    533.8    171.1   
                                        

 

1

Reclassified to conform to current presentation.

2

Additional details about results of oil and gas operations are presented in the tables on page 21.

Due to a recent realignment of management responsibilities within the Company’s domestic downstream business, U.S. refining and marketing operating results have now been presented as separate segments for U.S. manufacturing operations and U.S. marketing operations. The Company believes this presentation better reflects the core businesses of its U.S. downstream subsidiaries. United States Manufacturing operations include two refineries and an ethanol production facility. United States Marketing includes retail and wholesale fuel marketing operations. Prior year amounts have been reclassified to reflect the new segment presentation. Transactions between these two U.S. downstream segments are recorded at agreed transfer prices and eliminations have been made as necessary within the consolidated financial statements.

Note N – Subsequent Event

The Company has been informed by PETRONAS that following the execution of the Exchange of Letters between Malaysia and the Sultanate of Brunei on March 16, 2009, the offshore exploration areas designated as Block L and Block M are no longer a part of Malaysia. As a consequence, the production sharing contracts covering Blocks L and M, awarded in 2003 to PETRONAS Carigali Sdn Bhd and Murphy, were formally terminated by letter dated April 7, 2010. Murphy’s potential participation in replacement production sharing contracts covering these areas is under discussion. The Company’s remaining net investment in Block L of $12.2 million at March 31, 2010 is included in Property, Plant and Equipment in the consolidated balance sheet pending resolution of its potential participation in replacement production sharing contracts.

 

16


Table of Contents
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 2010 was $148.9 million ($0.77 per diluted share) down from net income of $171.1 million ($0.89 per diluted share) in the same quarter of 2009. The 2010 quarterly results included net after-tax losses of $41.3 million ($0.21 per diluted share) on transactions denominated in foreign currencies, while the 2009 results included after-tax gains of $26.1 million ($0.14 per diluted share) on these transactions. Net income in 2009 included income from discontinued operations 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 continuing operations for the three-month periods ended March 31, 2010 and 2009 was $148.9 million ($0.77 per diluted share) and $71.2 million ($0.37 per diluted share), respectively. The 109% improvement in income from continuing operations in 2010 was attributable to substantially higher income from the Company’s exploration and production business partially offset by unfavorable results from refining and marketing operations and corporate activities. Murphy’s income from continuing operations by type of business is presented below.

 

     Income (Loss)
     Three Months Ended
March 31,
(Millions of dollars)    2010     2009

Exploration and production

   $ 247.0      50.3

Refining and marketing

     (29.7   10.8

Corporate

     (68.4   10.1
            

Income from continuing operations

   $ 148.9      71.2
            

Murphy’s income from continuing exploration and production operations was $247.0 million in the first quarter of 2010 compared to $50.3 million in the same quarter of 2009. The almost four-fold increase in 2010 income compared to 2009 was primarily driven by a combination of higher realized sales prices for crude oil and natural gas, higher natural gas sales volumes and lower exploration expenses in the current period. Exploration expense in the 2010 period was $66.3 million, down from $111.1 million in 2009. Murphy’s refining and marketing operations incurred a loss of $29.7 million in the 2010 quarter compared to earnings of $10.8 million in the 2009 quarter. This unfavorable variance was principally attributable to much weaker refining margins and downtime for refinery turnarounds in the U.S. and U.K. Corporate functions reflected net costs of $68.4 million in the 2010 first quarter compared to a net benefit of $10.1 million in 2009. The increase in net corporate costs in 2010 mostly reflected significant after-tax losses on transactions denominated in foreign currencies in 2010 compared to after-tax gains in the 2009 quarter.

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)    2010     2009  

Exploration and production – continuing operations

    

United States

   $ 18.7      (7.3

Canada

     49.2      0.6   

Malaysia

     173.5      117.5   

United Kingdom

     16.6      3.4   

Republic of the Congo

     2.5      0.3   

Other International

     (13.5   (64.2
              

Total – continuing operations

   $ 247.0      50.3   
              

In the United States, exploration and production operations had income of $18.7 million in the first quarter of 2010 compared to a loss of $7.3 million in the 2009 quarter. This favorable result in 2010 compared to the prior year was primarily due to higher crude oil and natural gas sales prices and higher crude oil sales volumes. Partial offsets were lower natural gas sales volumes and higher expenses for production, exploration, depreciation and administration. Production expense in the U.S. was higher in the 2010 period due to more oil production compared to 2009, with the increase primarily due to production at the Thunder Hawk field in the Gulf of Mexico, which came onstream in the third quarter of 2009. Depreciation expense also rose in 2010 primarily due to higher production volumes at Thunder Hawk. Exploration expenses in the U.S. of $28.0 million were up $8.3 million in 2010 due to higher amortization expense for undeveloped leases held in the Eagle Ford shale area of South Texas and higher geophysical costs for seismic acquisition in the Gulf of Mexico. Dry hole expense was lower in 2010 than 2009 due to unsuccessful onshore Louisiana drilling in the prior year. Administrative costs increased in 2010 primarily due to higher employee costs and a lower percentage of overhead charged to partners.

 

17


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

 

Results of Operations (Contd.)

 

Exploration and Production (Contd.)

 

Earnings from operations in Canada were $49.2 million in the 2010 quarter compared to $0.6 million in the 2009 quarter. Canadian operations realized higher crude oil sales prices, higher sales volumes and sales prices for natural gas, and lower exploration expenses in the current period. The 2010 period had unfavorable variances for crude oil sales volumes, production and depreciation expenses, and costs associated with a redetermination of working interests at the Terra Nova field, offshore Newfoundland. Natural gas sales volumes were higher in the 2010 quarter due to continued ramp-up of production in the Tupper area in Western Canada. Production expenses in Canada were unfavorable in 2010 due to higher costs at Syncrude and higher natural gas production at Tupper. Depreciation expense increased in the 2010 period compared to 2009 due mostly to more Tupper natural gas sales volumes and higher unit rates at Syncrude. Exploration expenses in Canada were $7.4 million in 2010 compared to $20.3 million in 2009, and the reduction was due primarily to lower undeveloped leasehold amortization costs incurred in 2010 for the Tupper West natural gas area. The expense associated with Terra Nova redetermination relates to an anticipated cash settlement for revenues, net of expenses, that will be required upon final working interest redetermination, which is currently expected in late 2010. The Company’s original 12.0% working interest could be reduced to approximately 10.5% upon completion of the redetermination process. While the redetermination process continues, the Company continues to be allocated and sells 12% of crude oil production at Terra Nova.

Operations in Malaysia reported a profit of $173.5 million in the first quarter of 2010 compared to a profit of $117.5 million in the same period in 2009. The 2010 results were favorable to 2009 primarily due to higher crude oil sales prices. Production volumes for natural gas increased during the 2010 period related to a Sarawak gas field that started up in the third quarter of 2009 and higher demand for natural gas volumes at the Kikeh field, offshore Sabah. Although crude oil liquids production volumes declined slightly during the 2010 period, sales volumes rose due to the timing of scheduling sales of oil through periodic oil tanker loadings at the Kikeh field. Production and depreciation expenses in Malaysia rose in 2010 mostly due to higher overall natural gas sales volumes. Dry hole costs were higher in the 2010 quarter than in 2009 primarily due to more unsuccessful wildcat drilling costs in the current quarter in deepwater blocks offshore Sabah. Certain exploration expenses in Malaysia do not receive income tax benefits at the present time.

U.K. operations earned $16.6 million in the 2010 period versus $3.4 million in the same quarter a year ago, with the improvement due to a combination of higher crude oil sales prices, and higher crude oil and natural gas sales volumes. Crude oil sales volumes increased primarily at the Schiehallion field where a sale occurred in the 2010 period, whereas no sale occurred at this field during the 2009 quarter. Natural gas sales volumes were higher in 2010 than 2009 due to gas produced at the Amethyst field in the current period, while the field was off production for the entire first quarter of the prior year because of major equipment failure. Production and depreciation expenses increased in 2010 compared to 2009 in the U.K. due to the higher oil and natural gas sales volumes.

Operations in Republic of the Congo had income of $2.5 million in the first quarter of 2010 compared to income of $0.3 million in the comparable 2009 quarter. Income in the current period was associated with crude oil sales volumes following start-up of production in the third quarter 2009. Production and depreciation expenses increased in 2010 associated with the crude oil production activities.

Other international operations reported a loss of $13.5 million in the 2010 period versus a loss of $64.2 million in the same period for 2009. The smaller loss in 2010 was primarily due to unsuccessful exploratory drilling costs in 2009 offshore Western Australia and more 3-D seismic expense in 2009 for Block 37 offshore Suriname.

On a worldwide basis, the Company’s crude oil, condensate and natural gas liquids sales price averaged $64.89 per barrel for the 2010 first quarter compared to $43.15 per barrel in the first quarter of 2009. The 50% increase in average realized crude oil sales price was below the 82% increase between periods in the West Texas Intermediate (WTI) benchmark because of several factors. The benchmark price for crude oil in Malaysia did not increase as much as WTI and the Company is required under its production sharing contract to share a portion of higher sales prices with the government in Malaysia. Additionally, in the Republic of the Congo, oil sales prices were based on one January cargo sold at a time when oil prices were near the low during the first quarter. The Company’s production from continuing operations averaged 196,226 barrels of oil equivalent per day during the first quarter 2010, an increase of 29% compared to the 2009 first quarter. Crude oil and

 

18


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

 

Results of Operations (Contd.)

 

Exploration and Production (Contd.)

 

liquids production from continuing operations averaged 139,060 barrels per day in the 2010 quarter, 4% higher than the 133,977 barrels per day produced in the 2009 period. Oil production in the United States was higher in 2010 than 2009 due to production at the Thunder Hawk field in the deepwater Gulf of Mexico, following start-up of the field in the third quarter 2009. Heavy oil production in Western Canada was lower in the 2010 first quarter compared to the 2009 period primarily at the Seal area due to a higher overall royalty rate resulting from project payout and higher net profits. Production volumes offshore Eastern Canada were lower in 2010 versus 2009 due to higher net profits royalty rates at Hibernia and Terra Nova coupled with field decline at Terra Nova. Synthetic net oil production at Syncrude in northern Alberta decreased in 2010 compared to 2009 primarily due to a higher net profits royalty rate attributable to stronger oil prices. Oil production declined somewhat in Malaysia in 2010 due to a lower percentage of Kikeh field production allocated to the Company, partially offset by condensate produced at the Sarawak natural gas field that started up in the third quarter of 2009. Production in the U.K. was unfavorable in 2010 due to lower volumes produced at the Schiehallion field caused by equipment downtime. Oil production in Republic of the Congo in the first quarter 2010 was generated from the Azurite field, which commenced production in the third quarter 2009. Average oil sales volumes for continuing operations increased from 129,595 barrels per day in the 2009 first quarter to 145,783 barrels per day in 2010. The higher crude oil sales volumes were attributable to the Kikeh field in Block K, offshore Sabah Malaysia, where sales volumes are affected by the timing of periodic oil tanker loadings, and sales volumes at the Thunder Hawk and Azurite fields after start-up of oil production at both fields in the third quarter 2009. North American natural gas sales prices averaged $5.14 per thousand cubic feet (MCF) in the 2010 first quarter compared to $4.66 per MCF in the same quarter of 2009. Total natural gas sales volumes averaged 343 million cubic feet per day in 2010, an increase of more than 200% from the 111 million cubic feet per day sold in the same period of 2009. The increase in 2010 was attributable to natural gas production offshore Sarawak Malaysia and at the Thunder Hawk field in the Gulf of Mexico that both commenced in the third quarter 2009, higher natural gas volumes produced in 2010 attributable to ramp-up of production at the Tupper area in Western Canada, and higher natural gas sales volumes at the Kikeh field due to more uptime at the onshore processing plant owned by a third party. Natural gas sales volumes in the U.K. were higher in 2010 than in 2009 primarily due to the Amethyst field being shut-in for the entire 2009 quarter due to equipment failure.

Additional details about results of oil and gas operations are presented in the tables on page 21.

 

19


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, 2010 and 2009 follow.

 

     Three Months Ended
March 31,
     2010    2009

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

     139,060    139,318

Continuing operations

     139,060    133,977

United States

     21,648    13,268

Canada  – light

     51    —  

    – heavy

     6,483    7,436

    – offshore

     12,600    15,542

    – synthetic

     12,379    13,464

Malaysia

     78,098    79,498

United Kingdom

     4,087    4,769

Republic of the Congo

     3,714    —  

Discontinued operations

     —      5,341

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

     145,783    134,306

Continuing operations

     145,783    129,595

United States

     21,648    13,268

Canada  – light

     51    —  

    – heavy

     6,483    7,436

    – offshore

     12,181    13,459

    – synthetic

     12,379    13,464

Malaysia

     82,585    79,504

United Kingdom

     7,220    2,464

Republic of the Congo

     3,236    —  

Discontinued operations

     —      4,711

Net natural gas sold – thousands of cubic feet per day

     342,995    111,309

United States

     43,803    53,307

Canada

     79,783    29,711

Malaysia  – Sarawak

     158,576    —  

       – Kikeh

     55,119    25,799

United Kingdom

     5,714    2,492

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

     196,226    157,870

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

     202,949    152,858

Weighted average sales prices

     

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

     

United States

   $ 75.57    37.55

Canada (3)  – light

     78.06    —  

          – heavy

     54.97    22.30

          – offshore

     75.38    42.17

          – synthetic

     78.71    44.63

Malaysia (4)

     58.16    45.90

United Kingdom

     75.75    44.79

Republic of the Congo

     68.19    —  

Natural gas – dollars per thousand cubic feet

     

United States (2)

   $ 5.76    5.12

Canada (3)

     4.80    3.84

Malaysia  – Sarawak

     4.58    —  

       – Kikeh

     0.23    0.23

United Kingdom (3)

     5.78    7.40

 

(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.

 

20


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

 

Results of Operations (Contd.)

 

Exploration and Production (Contd.)

 

OIL AND GAS OPERATING RESULTS (unaudited)

 

(Millions of dollars)

   United
States
    Canada     Malaysia     United
Kingdom
   Republic
of the
Congo
    Other     Synthetic
Oil –
  Canada
    Total

Three Months Ended March 31, 2010

                 

Oil and gas sales and other operating revenues

   $ 175.0      135.2      503.9      52.4    28.3      2.3      87.7      984.8

Production expenses

     32.8      25.8      83.8      9.2    11.9      —        51.8      215.3

Depreciation, depletion and amortization

     75.4      46.1      105.9      8.3    9.4      .3      10.0      255.4

Accretion of assets retirement obligations

     1.7      1.2      2.3      .5    .1      .1      1.6      7.5

Exploration expenses

                 

Dry holes

     .1      —        22.6      —      (.4   —        —        22.3

Geological and geophysical

     12.4      .6      .2      .4    .3      2.1      —        16.0

Other

     2.6      .1      —        .1    .3      4.1      —        7.2
                                               
     15.1      .7      22.8      .5    .2      6.2      —        45.5

Undeveloped lease amortization

     12.9      6.7      —        —      —        1.2      —        20.8
                                               

Total exploration expenses

     28.0      7.4      22.8      .5    .2      7.4      —        66.3
                                               

Terra Nova working interest redetermination

     —        5.5      —        —      —        —        —        5.5

Selling and general expenses

     8.0      3.6      .1      .9    (.9   7.2      .2      19.1
                                               

Results of operations before taxes

     29.1      45.6      289.0      33.0    7.6      (12.7   24.1      415.7

Income tax provisions

     10.4      13.6      115.5      16.4    5.1      .8      6.9      168.7
                                               

Results of operations (excluding corporate overhead and interest)

   $ 18.7      32.0      173.5      16.6    2.5      (13.5   17.2      247.0
                                               

Three Months Ended March 31, 2009*

                 

Oil and gas sales and other operating revenues

   $ 71.0      80.4      337.4      11.7    —        .5      54.1      555.1

Production expenses

     15.2      21.7      49.5      1.9    —        —        44.9      133.2

Depreciation, depletion and amortization

     43.3      34.5      73.7      2.1    —        .4      6.3      160.3

Accretion of asset retirement obligations

     1.7      1.0      1.7      .5    —        .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      —        —      (.3   2.7      —        4.1
                                               
     13.8      1.1      13.5      —      (.3   57.3      —        85.4

Undeveloped lease amortization

     5.9      19.2      —        —      —        .6      —        25.7
                                               

Total exploration expenses

     19.7      20.3      13.5      —      (.3   57.9      —        111.1
                                               

Selling and general expenses

     5.4      3.5      .1      .8    —        6.3      .2      16.3
                                               

Results of operations before taxes

     (14.3   (.6   198.9      6.4    .3      (64.2   1.7      128.2

Income tax provisions (benefits)

     (7.0   2.0      81.4      3.0    —        —        (1.5   77.9
                                               

Results of operations (excluding corporate overhead and interest)

   $ (7.3   (2.6   117.5      3.4    .3      (64.2   3.2      50.3
                                               

 

* Reclassified to conform to current presentation.

 

21


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

 

Results of Operations (Contd.)

 

Refining and Marketing

Due to a recent realignment of management responsibilities within the Company’s domestic downstream business, U.S. refining and marketing operating results have now been presented as separate segments for U.S. manufacturing operations and U.S. marketing operations. The Company believes this presentation better reflects the core businesses of its U.S. downstream subsidiaries. United States Manufacturing operations include two refineries and an ethanol production facility. United States Marketing includes retail and wholesale fuel marketing operations. Prior year amounts have been reclassified to reflect the new segment presentation. Transactions between these two U.S. downstream segments are recorded at agreed transfer prices and eliminations have been made as necessary within the consolidated financial statements.

 

     Income (Loss)  
     Three Months Ended
March 31,
 
     2010     2009  

Refining and marketing

    

United States

    

Manufacturing

   (23.6   8.3   

Marketing

   8.9      6.3   
            

Total – United States

   (14.7   14.6   
            

United Kingdom

   (15.0   (3.8
            

Total

   (29.7   10.8   
            

United States manufacturing operations generated a loss of $23.6 million in the 2010 first quarter compared to earnings of $8.3 million during the first quarter of 2009. The unfavorable result in 2010 was primarily due to very weak U.S. refining margins and a six-week complete plant turnaround at the Meraux refinery in the just completed quarter. The WTI Gulf Coast 2-1-1 crack spread was about $3.00 per barrel lower in the first quarter of 2010 than in the same period in 2009. An ethanol production facility in Hankinson, North Dakota, that was acquired in October 2009, was profitable in the first quarter 2010.

United States marketing operations generated income of $8.9 million in the three months ended March 31, 2010, compared to income of $6.3 million in the 2009 period. The improved results in the 2010 quarter were mostly due to retail marketing margins in the U.S. which increased by about $0.03 per gallon compared to the same period in 2009. This improvement in retail margins in 2010 was somewhat tempered by tighter wholesale product margins in the current period. Although overall sales volumes at the U.S. retail stations in 2010 were about flat with 2009, sales volumes per store month were lower by about 2% compared to the prior year.

Refining and marketing operations in the United Kingdom had a loss of $15.0 million in the first quarter of 2010 compared to a loss of $3.8 million in the same quarter of 2009. Results in the U.K. in 2010 were hurt by a decrease in demand for refined products primarily related to severe winter storms early in the 2010 quarter, which led to very weak refining margins, especially early in the quarter. Additionally, the Milford Haven refinery was shut down for turnaround during March 2010 and is expected to restart in early May. A capital project being completed during the turnaround will expand the crude oil throughput capacity of the refinery from 108,000 to 130,000 barrels per day.

Worldwide refinery inputs were 169,600 barrels per day in the first quarter of 2010 compared to 235,274 barrels per day in the 2009 quarter. The decline in refinery inputs in 2010 was primarily due to turnarounds at the Meraux and Milford Haven plants during the quarter. Petroleum product sales were 478,692 barrels per day in the 2010 quarter, down from 503,878 barrels per day a year ago. This reduction was also mostly due to the aforementioned refinery turnarounds at Meraux and Milford Haven.

 

22


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

 

Results of Operations (Contd.)

 

Refining and Marketing (Contd.)

 

Selected operating statistics for the three-month periods ended March 31, 2010 and 2009 follow.

 

     Three Months Ended
March 31,
 
     2010     2009  

Refinery inputs – barrels per day

     169,600        235,274   

United States

     102,822        136,719   

Crude oil – Meraux, Louisiana

     66,777        99,799   

       – Superior, Wisconsin

     31,868        31,549   

Other feedstocks

     4,177        5,371   

United Kingdom

     66,778        98,555   

Crude oil – Milford Haven, Wales

     61,042        97,129   

Other feedstocks

     5,736        1,426   

Refinery yields – barrels per day

     169,600        235,274   

United States

     102,822        136,719   

Gasoline

     43,677        55,916   

Kerosine

     7,469        13,239   

Diesel and home heating oils

     25,282        37,501   

Residuals

     13,918        15,735   

Asphalt, LPG and other

     11,336        13,035   

Fuel and loss

     1,140        1,293   

United Kingdom

     66,778        98,555   

Gasoline

     18,281        22,838   

Kerosine

     9,819        12,313   

Diesel and home heating oils

     18,279        33,859   

Residuals

     7,180        8,149   

Asphalt, LPG and other

     10,735        17,009   

Fuel and loss

     2,484        4,387   

Petroleum products sold – barrels per day

     478,692        503,878   

Total United States

     410,674        406,243   

United States Manufacturing

     99,883        126,634   

Gasoline

     50,770        55,917   

Kerosine

     7,469        13,239   

Diesel and home heating oils

     25,282        37,501   

Residuals

     13,356        15,601   

Asphalt, LPG and other

     3,006        4,376   

United States Marketing

     394,310        386,263   

Gasoline

     316,588        312,412   

Kerosine

     7,183        15,207   

Diesel and other

     70,539        58,644   

United States Intercompany Elimination

     (83,519     (106,654

Gasoline

     (50,768     (55,913

Kerosine

     (7,469     (13,240

Diesel and other

     (25,282     (37,501

United Kingdom

     68,018        97,635   

Gasoline

     16,943        27,515   

Kerosine

     9,882        10,767   

Diesel and home heating oils

     21,697        34,876   

Residuals

     8,276        7,575   

LPG and other

     11,220        16,902   

Unit margins per barrel:

    

United States refining1

     (4.23     1.09   

United Kingdom refining and marketing

     (3.23     0.08   

United States retail marketing:

    

Fuel margin per gallon2

   $ 0.081      $ 0.050   

Gallons sold per store month

     292,122        299,192   

Merchandise sales revenue per store month

   $ 138,456      $ 116,869   

Merchandise margin as a percentage of merchandise sales

     12.3     13.9

Store count at end of period (Company operated)

     1,055        1,027   

 

1

Represents refinery sales realizations less cost of crude and other feedstocks and refinery operating and depreciation expenses.

2

Represents net sales prices for fuel less purchased cost of fuel.

 

23


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

 

Results of Operations (Contd.)

 

Corporate

Corporate activities, which include interest income and expense, foreign exchange effects, and corporate overhead not allocated to operating functions, had net costs of $68.4 million in the 2010 first quarter compared to a net benefit of $10.1 million in the first quarter of 2009. The results for corporate activities were unfavorable in 2010 compared to 2009 primarily due to after-tax losses of $41.3 million in the 2010 quarter on transactions denominated in foreign currencies compared to an after-tax profit of $26.1 million in the 2009 quarter. The foreign exchange loss in 2010 was primarily associated with a stronger U.S. dollar compared to the British sterling and a weaker dollar compared to the Malaysian ringgit. The weaker British sterling in 2010 led to foreign currency losses on dollar based liabilities in the sterling functional U.K. downstream operations, and the stronger Malaysian ringgit led to foreign currency losses on ringgit based income tax liabilities in the dollar functional Malaysian oil and gas operations. The foreign exchange benefit in 2009 mostly related to a stronger U.S. dollar versus the Malaysian ringgit, which led to currency gains for Malaysian income tax liabilities to be paid in the local currency. Higher net interest expense in the 2010 quarter compared to 2009 was attributable to a combination of higher average debt levels and lower amounts of interest capitalized to ongoing oil and gas development projects.

Financial Condition

Net cash provided by operating activities was $829.4 million for the first three months of 2010 compared to $380.0 million during the same period in 2009. Changes in operating working capital other than cash and cash equivalents generated cash of $244.3 million in the first quarter of 2010 and $45.0 million in the first quarter of 2009. The cash generated in the 2010 quarter from working capital changes essentially related to a $244.4 million recovery of U.S. federal royalties paid in prior years. Cash of $513.6 million and $406.5 million in the 2010 and 2009 quarters, respectively, was generated from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition.

Significant uses of cash in both years were for dividends, which totaled $47.8 million in 2010 and $47.6 million in 2009, and for property additions and dry holes, which, including amounts expensed, were $481.0 million and $511.4 million in the three month periods ended March 31, 2010 and 2009, respectively. Additionally, cash of $630.2 million and $599.8 million was used to purchase Canadian government securities with maturity dates greater than 90 days during the three months ended March 31, 2010 and 2009, respectively. The Company expended $50.5 million in the first three months of 2010 on major repairs, up from $7.4 million in the 2009 period, with the increase due to planned major turnarounds at the Meraux, Louisiana and Milford Haven, Wales refineries during the 2010 period. Total capital expenditures for continuing operations on an accrual basis were as follows:

 

     Three Months Ended
March 31,
(Millions of dollars)    2010    2009

Capital expenditures – continuing operations

     

Exploration and production

   $ 442.2    430.9

Refining and marketing

     80.8    48.6

Corporate and other

     1.7    1.2
           

Total capital expenditures – continuing operations

   $ 524.7    480.7
           

Working capital (total current assets less total current liabilities) at March 31, 2010 was $1,034.6 million, down $159.5 million from December 31, 2009. 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 $566.3 million below fair value at March 31, 2010.

At March 31, 2010, total long-term debt of $1,231.2 million had decreased by $122.0 million compared to December 31, 2009. A summary of capital employed at March 31, 2010 and December 31, 2009 follows.

 

     March 31, 2010    Dec. 31, 2009
(Millions of dollars)    Amount    %    Amount    %

Capital employed

           

Long-term debt

   $ 1,231.2    14.0      1,353.2    15.6

Stockholders’ equity

     7,553.6    86.0      7,346.0    84.4
                       

Total capital employed

   $ 8,784.8    100.0    $ 8,699.2    100.0
                       

The Company’s ratio of earnings to fixed charges was 14.0 to 1 for the three-month period ended March 31, 2010.

 

24


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

 

Accounting and Other Matters

The Company adopted new guidance issued by the Financial Accounting Standards Board (FASB) regarding accounting for transfers of financial assets effective January 1, 2010. This guidance makes the concept of a qualifying special-purpose entity as defined previously no longer relevant for accounting purposes. Therefore, formerly qualifying special-purpose entities must be reevaluated for consolidation by reporting entities in accordance with the applicable consolidation guidance. This adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted, effective January 1, 2010, new guidance issued by the FASB that requires a company to perform an analysis to determine whether its variable interests give it a controlling financial interest in a variable interest entity. The primary beneficiary of a variable interest entity has both the power to direct the activities of the entity that most significantly impact the entity’s economic performance and the obligation to absorb potentially significant losses of the entity or the right to receive potentially significant benefits from the entity. A company is required to make ongoing reassessments of whether it is the primary beneficiary of a variable interest entity. This guidance also amends previous guidance for determining whether an entity is considered a variable interest entity. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted new accounting guidance issued by the FASB for noncontrolling interests in consolidated financial statements effective January 1, 2009. This guidance was applied prospectively, except for presentation and disclosure requirements which are applied retrospectively. This guidance required 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 guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted new accounting guidance covering business combinations effective January 1, 2009. The new guidance established 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 established how to recognize and measure goodwill acquired in the business combination or a gain from a bargain purchase, if applicable. This guidance impacts the recognition and measurement of assets and liabilities in business combinations that occur beginning in 2009. Assets and liabilities that arose from business combinations that occurred prior to 2009 are not affected by this guidance. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements. The Company is unable to predict how the application of this guidance will affect its financial statements in future periods.

The Company adopted new accounting guidance which addresses disclosures about derivative instruments and hedging activities in January 2009. This guidance 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.

In 2009, the Company adopted new accounting guidance for determining whether instruments granted in share-based payment transactions are participating securities. This guidance specifies 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, and also requires that all prior-period EPS calculations be adjusted retrospectively. The adoption of this guidance did not have a significant impact on the Company’s prior-period EPS calculations.

The Company adopted new accounting guidance addressing certain equity method investment accounting considerations in January 2009, which has been applied prospectively. The guidance addresses 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 guidance did not have a significant impact on the Company’s consolidated financial statements.

The Company adopted new accounting guidance addressing subsequent events effective June 30, 2009. The guidance clarified the accounting for and disclosure of subsequent events that occur after the balance sheet date through the date of issuance of the applicable financial statements. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

 

25


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

 

Accounting and Other Matters (Contd.)

 

The FASB’s Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles guidance became effective for interim and annual periods ended after September 15, 2009 (the third calendar quarter for Murphy Oil) and it recognized the FASB Accounting Standards Codification as the single source of authoritative nongovernment U.S. generally accepted accounting principles. The codification superseded all existing accounting standards documents issued by the FASB, and established that all other accounting literature not included in the codification is considered nonauthoritative. Although the codification does not change U.S. generally accepted accounting principles, it does reorganize the principles into accounting topics using a consistent structure. The codification also includes relevant U.S. Securities and Exchange Commission guidance following the same topical structure. For periods ending after September 15, 2009, all references to U.S. generally accepted accounting principles will use the new topical guidelines established with the codification. Otherwise, this new standard is not expected to have a material impact on the Company’s consolidated financial statements in future periods.

The FASB has provided additional guidance regarding disclosures about postretirement 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 was effective for the Company as of December 31, 2009. Upon adoption, no comparative disclosures were required for earlier years presented.

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

 

 

A revised definition of proved reserves, including the use of unweighted average oil and natural gas prices in effect at the beginning of each month during the year 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,

 

 

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 utilized this new guidance at year-end 2009 to determine its proved reserves and to develop associated disclosures. The Company has thus far chosen not to provide voluntary disclosures of probable and possible reserves in its filings with the Securities and Exchange Commission.

Outlook

Average crude oil prices in April 2010 rose slightly compared to the average price during the first quarter 2009. The Company expects its oil and natural gas production to average about 188,000 barrels of oil equivalent per day in the second quarter 2010, while sales volumes are expected to be approximately 184,000 barrels of oil equivalent per day during the quarter. Production volumes are projected to be lower in the second quarter 2010 than in the first quarter primarily in Malaysia due to a mechanical issue at a third party operated LNG facility that will reduce Sarawak gas sales and due to well intervention work on a subsea oil producing well that will reduce oil production at the Kikeh field. The Company still anticipates total production volumes of 200,000 barrels of oil equivalent per day for the full year 2010. U.S. downstream margins in April 2010 have shown some improvement compared to the first quarter. The Milford Haven, Wales refinery will start back up in early May following an extensive turnaround. The Company currently anticipates total capital expenditures for the full year 2010 to be approximately $2.5 billion.

 

26


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

 

Forward-Looking Statements

This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements include, but are not limited to, the volatility and level of crude oil and natural gas prices, the level and success rate of our exploration programs, our ability to maintain production rates and replace reserves, political and regulatory instability, and uncontrollable natural hazards. For further discussion of risk factors, see Murphy’s 2009 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission. Murphy undertakes no duty to publicly update or revise any forward-looking statements.

 

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note 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 derivative foreign exchange contracts in place at March 31, 2010 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 $6.2 million, while a 10% weakening of the U.S. dollar would have reduced the recorded liability by approximately $5.0 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, 2010 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

 

27


Table of Contents

PART II – OTHER INFORMATION

 

ITEM 1. LEGAL PROCEEDINGS

Litigation arising out of a June 10, 2003 fire in the Residual Oil Supercritical Extraction (ROSE) unit at the Company’s Meraux, Louisiana refinery was settled in July 2009 and memorialized via a filing in the U.S. District Court for the Eastern District of Louisiana on July 24, 2009. An arbitral tribunal heard the Company’s claim for indemnity from one of its insurers, AEGIS, in September 2009 and a decision is pending. The Company believes that insurance coverage does apply for this matter. The Company continues to believe that the ultimate resolution of the June 2003 ROSE fire litigation, including associated insurance coverage issues, 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.

 

ITEM 1A. RISK FACTORS

In April 2010, a drilling accident and subsequent oil spill occurred in the Gulf or Mexico at a property owned by other companies. At the present time, the Company is uncertain how the accident and oil spill will affect its U.S. and worldwide operations. The impacts could include a disruption of operations at the Meraux, Louisiana, refinery and further regulations and/or restrictions covering offshore drilling operations.

See additional risk factors previously disclosed in the Company’s Form 10-K filed on February 26, 2010.

 

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

 

(a) The Exhibit Index on page 30 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 27, 2010 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, 2009.

 

(c) A report on Form 8-K was filed on February 4, 2010 that included amended By-Laws that changed the number of directors from eleven to ten effective May 12, 2010.

 

28


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, 2010

      (Date)

 

29


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
101    Interactive Data Files

 

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

Attached as Exhibit 101 to this report are documents formatted in XBRL (Extensible Business Reporting Language). Users of this data are advised pursuant to Rule 406T of Regulation S-T that the interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of section 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise not subject to liability under these sections. The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”

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

 

30