3rd Quarter 2011 (10-Q)

Source Quarterly 10-Q
Company Murphy Oil Corporation 
Tags Financial & Operating Data
Date November 04, 2011


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 September 30, 2011

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 September 30, 2011 was 193,521,911.

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 Results of Operations and Financial Condition       20   
   
Item 3. Quantitative and Qualitative Disclosures About Market Risk       34   
   
Item 4. Controls and Procedures       34   
   
Part II – Other Information       35   
   
Item 1. Legal Proceedings       35   
   
Item 1A. Risk Factors       35   
   
Item 6. Exhibits       35   
   
Signature       36   

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)
 Sept. 30,  
 2011 
     December 31,  
 2010 
 
ASSETS                 
 Current assets                 
 Cash and cash equivalents     $   1,278,981         535,825   
 Canadian government securities with maturities greater than 90 days at the date of acquisition       493,705         616,558   
 Accounts receivable, less allowance for doubtful accounts of $7,945 in 2011 and $7,954 in 2010       1,780,976         1,467,311   
 Inventories, at lower of cost or market                 
 Crude oil and blend stocks       237,999         147,256   
 Finished products       195,678         388,162   
 Materials and supplies       205,023         226,795   
 Prepaid expenses       113,841         88,241   
 Deferred income taxes       75,748         80,545   
 Assets held for sale       78,679         0   
                 
 Total current assets       4,460,630         3,550,693   
 Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $6,121,765 in 2011 and $6,040,996 in 2010       10,338,783         10,367,847   
 Goodwill       40,716         42,850   
 Deferred charges and other assets       184,606         271,853   
 Assets held for sale       466,347         0   
                 
 Total assets     $   15,491,082         14,233,243   
                 
LIABILITIES AND STOCKHOLDERS’ EQUITY                 
 Current liabilities                 
 Current maturities of long-term debt     $   349,975         41   
 Accounts payable and accrued liabilities       2,792,520         2,572,105   
 Income taxes payable       321,375         358,764   
                 
 Total current liabilities       3,463,870         2,930,910   
 Long-term debt       974,541         939,350   
 Deferred income taxes       1,230,237         1,212,213   
 Asset retirement obligations       566,597         555,248   
 Deferred credits and other liabilities       367,485         395,972   
 Stockholders’ equity                 
 Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued       0         0   
 Common Stock, par $1.00, authorized 450,000,000 shares, issued 193,719,102 shares in 2011 and 193,293,526 shares in 2010       193,719         193,294   
 Capital in excess of par value       799,565         767,762   
 Retained earnings       7,628,093         6,800,992   
 Accumulated other comprehensive income       272,115         449,428   
 Treasury stock, 197,191 shares of Common Stock in 2011 and 457,518 shares of Common Stock in 2010, at cost       (5,140   )         (11,926   )   
                 
 Total stockholders’ equity       8,888,352         8,199,550   
                 
 Total liabilities and stockholders’ equity     $   15,491,082         14,233,243   
                 

 See Notes to Consolidated Financial Statements, page 7.

 The Exhibit Index is on page 37.

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  
 September 30, 
     Nine Months Ended  
 September 30, 
 
     2011       2010*       2011       2010*   
REVENUES                                 
 Sales and other operating revenues     $   7,211,407         5,210,807         20,865,047         14,665,786   
 Gain on sale of assets       60         208         23,192         997   
 Interest and other income (expense)       28,976         (10,681   )         39,802         (61,140   )   
                                 
 Total revenues       7,240,443         5,200,334         20,928,041         14,605,643   
                                 
         
COSTS AND EXPENSES                                 
 Crude oil and product purchases       5,727,873         3,990,497         16,633,221         11,015,394   
 Operating expenses       521,864         437,926         1,471,901         1,218,625   
 Exploration expenses, including undeveloped lease amortization       85,688         62,046         304,500         181,503   
 Selling and general expenses       73,561         63,892         220,753         189,416   
 Depreciation, depletion and amortization       272,914         272,621         793,445         828,918   
 Accretion of asset retirement obligations       9,351         8,104         28,494         23,561   
 Redetermination of Terra Nova working interest       0         4,491         (5,351   )         15,353   
 Interest expense       17,329         12,751         41,648         41,453   
 Interest capitalized       (2,475   )         (4,708   )         (11,547   )         (11,069   )   
                                 
 Total costs and expenses       6,706,105         4,847,620         19,477,064         13,503,154   
                                 
 Income from continuing operations before income taxes       534,338         352,714         1,450,977         1,102,489   
 Income tax expense       198,597         155,277         596,778         472,411   
                                 
 Income from continuing operations       335,741         197,437         854,199         630,078   
 Income from discontinued operations, net of taxes       70,373         5,395         132,431         (6,066   )   
                                 
NET INCOME     $   406,114         202,832         986,630         624,012   
                                 
         
INCOME PER COMMON SHARE – BASIC                                 
 Income from continuing operations     $   1.74         1.03         4.42         3.29   
 Income from discontinued operations       0.36         0.03         0.68         (0.03   )   
                                 
 Net income     $   2.10         1.06         5.10         3.26   
                                 
         
INCOME PER COMMON SHARE – DILUTED                                 
 Income from continuing operations     $   1.73         1.02         4.39         3.27   
 Income from discontinued operations       0.36         0.03         0.68         (0.03   )   
                                 
 Net income     $   2.09         1.05         5.07         3.24   
                                 
 Average common shares outstanding                                 
 Basic       193,517,785         191,943,813         193,342,825         191,577,000   
 Diluted       194,411,116         193,437,992         194,548,846         192,866,485   
 *   Reclassified to conform to current presentation 

 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
 September 30, 
     Nine Months Ended
 September 30, 
 
     2011       2010       2011       2010   
 Net income     $   406,114         202,832         986,630         624,012   
         
 Other comprehensive income (loss), net of tax                                 
 Net gain (loss) from foreign currency translation       (300,506   )         115,670         (177,481   )         75,285   
 Retirement and postretirement benefit plan adjustments       9,264         2,199         13,637         6,726   
 Loss deferred on interest rate hedges       (13,469   )         0         (13,469   )         0   
                                 
         
COMPREHENSIVE INCOME     $   101,403         320,701         809,317         706,023   
                                 

 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)

                 
     Nine Months Ended
 September 30, 
 
     2011       20101   
OPERATING ACTIVITIES                 
 Net income     $   986,630         624,012   
 Adjustments to reconcile net income to net cash provided by operating activities:                 
 (Income) loss from discontinued operations       (132,431   )         6,066   
 Depreciation, depletion and amortization       793,445         828,918   
 Amortization of deferred major repair costs       17,357         10,047   
 Expenditures for asset retirements       (18,399   )         (34,376   )   
 Dry hole costs       118,585         35,045   
 Amortization of undeveloped leases       90,623         76,816   
 Accretion of asset retirement obligations       28,494         23,561   
 Deferred and noncurrent income tax charges       125,461         38,939   
 Pretax gain from disposition of assets       (23,192   )         (997   )   
 Net (increase) decrease in noncash operating working capital       (309,436   )         417,237   
 Other operating activities, net       36,121         123,663   
                 
 Net cash provided by continuing operations       1,713,258         2,148,931   
 Net cash provided by discontinued operations       163,489         51,950   
                 
 Net cash provided by operating activities       1,876,747         2,200,881   
                 
     
INVESTING ACTIVITIES                 
 Property additions and dry hole costs       (1,853,939   )         (1,532,446   )   
 Proceeds from sales of assets       27,629         2,195   
 Purchase of investment securities 2       (1,233,321   )         (1,862,609   )   
 Proceeds from maturity of investment securities 2       1,356,175         2,011,386   
 Expenditures for major repairs       (2,826   )         (58,453   )   
 Investing activities of discontinued operations, including proceeds from sale of Superior refinery and associated inventories       354,238         (116,757   )   
 Other – net       7,150         (31,225   )   
                 
 Net cash required by investing activities       (1,344,894   )         (1,587,909   )   
                 
     
FINANCING ACTIVITIES                 
 Borrowings (repayments) of notes payable       384,970         (247,028   )   
 Repayment of nonrecourse debt of a subsidiary       0         (82,000   )   
 Proceeds from exercise of stock options and employee stock purchase plans       8,245         26,100   
 Excess tax benefits related to exercise of stock options       4,119         9,585   
 Withholding tax on stock-based incentive awards       (8,014   )         (5,170   )   
 Issue cost of debt facility       (8,619   )         0   
 Cash dividends paid       (159,529   )         (148,439   )   
                 
 Net cash provided (required) by financing activities       221,172         (446,952   )   
                 
 Effect of exchange rate changes on cash and cash equivalents       (9,869   )         (4,772   )   
                 
 Net increase in cash and cash equivalents       743,156         161,248   
 Cash and cash equivalents at January 1       535,825         301,144   
                 
 Cash and cash equivalents at September 30     $   1,278,981         462,392   
                 
 1     Reclassified to conform to current presentation. 
 2     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)

                 
     Nine Months Ended
 September 30, 
 
     2011       2010   
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued       0         0   
                 
     
Common Stock – par $1.00, authorized 450,000,000 shares, issued 193,719,102 at September 30, 2011 and 192,835,791 shares at September 30, 2010                 
 Balance at beginning of period     $   193,294         191,798   
 Exercise of stock options       425         1,038   
                 
 Balance at end of period       193,719         192,836   
                 
     
Capital in Excess of Par Value                 
 Balance at beginning of period       767,762         680,509   
 Exercise of stock options, including income tax benefits       13,755         34,973   
 Restricted stock transactions and other       (15,119   )         (9,688   )   
 Stock-based compensation       32,255         30,712   
 Sale of stock under employee stock purchase plans       912         717   
                 
 Balance at end of period       799,565         737,223   
                 
     
Retained Earnings                 
 Balance at beginning of period       6,800,992         6,204,316   
 Net income for the period       986,630         624,012   
 Cash dividends       (159,529   )         (148,439   )   
                 
 Balance at end of period       7,628,093         6,679,889   
                 
     
Accumulated Other Comprehensive Income                 
 Balance at beginning of period       449,428         287,187   
 Foreign currency translation gains (losses), net of income taxes       (177,481   )         75,285   
 Retirement and postretirement benefit plan adjustments, net of income taxes       13,637         6,726   
 Loss deferred on interest rate hedges, net of income taxes       (13,469   )         0   
                 
 Balance at end of period       272,115         369,198   
                 
     
Treasury Stock                 
 Balance at beginning of period       (11,926   )         (17,784   )   
 Sale of stock under employee stock purchase plans       578         994   
 Awarded restricted stock, net of forfeitures       6,208         4,305   
 Cancellation of performance-based restricted stock and forfeitures       0         258   
                 
 Balance at end of period       (5,140   )         (12,227   )   
                 
     
Total Stockholders’ Equity     $   8,888,352         7,966,919   
                 

 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, 2010. 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 September 30, 2011, and the results of operations, cash flows and changes in stockholders’ equity for the three-month and nine-month periods ended September 30, 2011 and 2010, 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 2010 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and nine-month periods ended September 30, 2011 are not necessarily indicative of future results. All periods presented have been adjusted to present discontinued operations as discussed in Note D.

Note B – Property, Plant and Equipment

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

 At September 30, 2011, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $529.2 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2011 and 2010.

                 
 (Thousands of dollars)     2011       2010   
 Beginning balance at January 1     $   497,765         369,862   
 Additions pending the determination of proved reserves       31,481         89,797   
 Reclassifications to proved properties based on the determination of proved reserves       0         0   
                 
 Balance at September 30     $   529,246         459,659   
                 

 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.

                                                 
     September 30,   
     2011       2010   
 (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     $   92,752         15         5       $   83,642         13         5   
 One to two years       69,591         9         1         118,776         12         3   
 Two to three years       115,924         8         3         50,604         4         4   
 Three years or more       250,979         37         7         206,637         32         3   
                                                 
     $   529,246         69         16       $   459,659         61         15   
                                                 

 Of the $436.5 million of exploratory well costs capitalized more than one year at September 30, 2011, $273.1 million is in Malaysia, $137.5 million is in the U.S., $15.3 million is in Republic of the Congo, and $10.6 million is in Canada. In Malaysia either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. In the U.S. drilling and development operations are planned. In Republic of the Congo further appraisal drilling is planned. In Canada a drilling and development program continues.

7

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C – Inventories

 Inventories are carried at the lower of cost or market. The cost of crude oil and finished products is predominantly determined on the last-in, first-out (LIFO) method. At September 30, 2011 and December 31, 2010, the carrying value of inventories under the LIFO method was $824.5 million and $735.1 million, respectively, less than such inventories would have been valued using the first-in, first-out (FIFO) method.

Note D – Discontinued Operations

 In July 2010, the Company announced that its Board of Directors had approved plans to exit the U.S. refining and U.K. refining and marketing businesses. Following the 2010 announcement the Company actively marketed its Meraux, Louisiana and Superior, Wisconsin refineries and certain associated product terminals to interested parties. The Company has also offered for sale its U.K. refinery at Milford Haven, Wales, and all U.K. product terminals and motor fuel stations. On July 25, 2011, the Company announced that it had entered into an agreement to sell the Superior, Wisconsin refinery and related assets for $214 million, plus certain capital expenditures between July 25 and the date of closing and the fair value of all associated hydrocarbon inventories at these locations. The sale of the Superior refinery assets was completed on September 30, 2011. On September 1, 2011, the Company announced that it had entered into an agreement to sell its Meraux, Louisiana refinery and related assets for $325 million, plus the fair value of associated hydrocarbon inventories. The sale of the Meraux assets was completed on October 1, 2011. The Company began to account for the Superior, Wisconsin and Meraux, Louisiana refineries and associated marketing assets as discontinued operations beginning in the third quarter 2011. All prior periods presented have been reclassified to conform to this presentation of the Superior and Meraux operating results as discontinued operations. The after-tax gain from disposal of the two refineries netted to $16.9 million, made up of a gain on the Superior refinery (including associated inventories) of $91.1 million and a loss on the Meraux refinery (including associated inventories) estimated at $74.2 million. The gain on disposal was based on refinery selling prices, plus the sales of all associated inventories at fair value, which was significantly above the last-in, first-out carrying value of the inventories sold. A loss on the sale of Meraux has been recorded in the third quarter 2011 because the Meraux business unit qualified for accounting purposes as an asset held for sale, which requires losses to be recorded when they can be estimated based on net realizable sales proceeds. Assets and liabilities associated with the Meraux refinery are presented as held for sale in the Company’s Consolidated Balance Sheet as of September 30, 2011. The sale process for the U.K. refining and marketing assets continues. Based on current market conditions, it is possible that the Company could incur a loss on future sales of the U.K. downstream assets.

 Assets and liabilities presented in the September 30, 2011 Consolidated Balance Sheet as held for sale related to the Meraux refinery and associated assets were as follows:

         
 (Thousands of dollars)       
 Current Assets:         
 Accounts receivable     $   1,243   
 Liquid inventories       51,268   
 Materials and supplies inventories       23,076   
 Other       3,092   
         
       78,679   
         
 Noncurrent Assets:         
 Property, plant and equipment – net, at realizable value     $   428,804   
 Other       37,543   
         
       466,347   
         

 The results of operations associated with these discontinued operations were as follows:

                                 
     Three Months Ended
 September 30 
     Nine Months Ended
 September 30 
 
 (Thousands of dollars)     2011       2010       2011       2010   
 Revenues     $   1,315,229         863,449         3,700,789         2,230,231   
 Income (loss) before income taxes, including gain on sale of $15,959 in the three-month and nine-month periods in 2011       107,215         7,285         203,601         (11,366   )   
       
 Income tax expense (benefit)       36,842         1,890         71,170         (5,301   )   

8

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note E – Financing Arrangements

 In June 2011, the Company replaced its $1.9 billion committed credit facility that was scheduled to expire in July 2012 with a new five-year $1.5 billion credit facility. Borrowings under the new facility bear interest at 1.5% above LIBOR based on the Company’s current credit rating as of September 30, 2011. The new committed facility did not alter the ability of the Company to borrow under other existing credit facilities, nor did it impact its shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through September 2012.

 Ten year notes totaling $350 million, which mature in May 2012, have been classified as Current maturities of long-term debt as of September 30, 2011. Early in the fourth quarter 2011, the Company used cash proceeds from a sale of two U.S. refineries to pay down outstanding loans under existing revolving credit facilities. The balance of revolving debt outstanding at September 30, 2011 was $725.0 million.

Note F – Cash Flow Disclosures

 Additional disclosures regarding cash flow activities are provided below.

                 
     Nine Months Ended
 September 30, 
 
 (Thousands of dollars)     2011       2010   
 Net (increase) decrease in operating working capital other than cash and cash equivalents:                 
 (Increase) decrease in accounts receivable     $   (314,908   )         99,628   
 (Increase) decrease in inventories       (31,865   )         (104,464   )   
 (Increase) decrease in prepaid expenses       (28,693   )         (2,045   )   
 (Increase) decrease in deferred income tax assets       4,797         (59,254   )   
 Increase (decrease) in accounts payable and accrued liabilities       185,618         412,015   
 Increase (decrease) in current income tax liabilities       (124,385   )         71,357   
                 
 Total     $   (309,436   )         417,237   
                 
     
 Supplementary disclosures:                 
 Cash income taxes paid     $   608,065         419,313   
 Interest paid, net of amounts capitalized       18,124         17,162   

Note G – Employee and Retiree Benefit Plans

 The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors’ plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory. In conjunction with the sale of the Superior, Wisconsin refinery in September 2011, the purchaser assumed the obligations associated with the defined pension and other postretirement plans covering the refinery’s union employees. In conjunction with the sale of the Meraux refinery in October 2011, all benefits associated with the defined pension and other postretirement benefit plans were frozen.

9

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

 The table that follows provides the components of net periodic benefit expense for the three-month and nine-month periods ended September 30, 2011 and 2010.

                                 
     Three Months Ended September 30,   
     Pension Benefits       Other
 Postretirement Benefits 
 
 (Thousands of dollars)     2011       2010       2011       2010   
 Service cost     $   5,915         5,282         1,289         921   
 Interest cost       7,919         7,480         1,719         1,474   
 Expected return on plan assets       (6,840   )         (5,933   )         0         0   
 Amortization of prior service cost       337         387         (66   )         (67   )   
 Amortization of transitional asset       (51   )         (127   )         3         0   
 Recognized actuarial loss       2,543         2,995         786         596   
                                 
       9,823         10,084         3,731         2,924   
 Termination benefits expense       700         0         0         0   
 Curtailment expense (gain)       1,105         0         (605   )         0   
                                 
 Net periodic benefit expense     $   11,628         10,084         3,126         2,924   
                                 
                                 
     Nine Months Ended September 30,   
     Pension Benefits       Other
 Postretirement Benefits 
 
 (Thousands of dollars)     2011       2010       2011       2010   
 Service cost     $   17,763         15,738         3,803         2,729   
 Interest cost       23,855         22,361         5,084         4,379   
 Expected return on plan assets       (20,634   )         (17,675   )         0         0   
 Amortization of prior service cost       1,020         1,158         (196   )         (197   )   
 Amortization of transitional asset       (155   )         (383   )         7         0   
 Recognized actuarial loss       7,661         8,948         2,326         1,770   
                                 
       29,510         30,147         11,024         8,681   
 Termination benefits expense       700         0         0         0   
 Curtailment expense (gain)       1,105         0         (605   )         0   
                                 
 Net periodic benefit expense     $   31,315         30,147         10,419         8,681   
                                 

 Termination benefits and curtailments in the 2011 periods related to the sales of U.S. refineries in 2011.

 During the nine-month period ended September 30, 2011, the Company made contributions of $36.6 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2011 for the Company’s defined benefit pension and postretirement plans is anticipated to be $8.8 million.

 In March 2010, the United States Congress 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) imposed 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. active and retired employees. The new law did not significantly affect the Company’s consolidated financial statements as of September 30, 2011 and 2010 and for the three-month and nine-month periods then ended. The Company continues to evaluate the various components of the law as further guidance is issued and cannot predict with certainty 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.

10

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note H – 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 September 30, 2017. The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock and stock options or a combination thereof to the Company’s Directors.

 In February 2011, the Committee granted stock options for 1,397,312 shares at an exercise price of $67.635 per share. The Black-Scholes valuation for these awards was $20.34 per option. The Committee also granted 521,423 performance-based restricted stock units in February 2011 under the 2007 Long-Term Plan. The fair value of the performance-based restricted stock units, using a Monte Carlo valuation model, ranged from $38.94 to $64.89 per unit. Also in February and August 2011, the Committee granted 29,115 shares and 3,596 shares, respectively, of time-based restricted stock to the Company’s Directors under the 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 $67.64 per share in February and $60.41 per share in August.

 Cash received from options exercised under all share-based payment arrangements for the nine-month periods ended September 30, 2011 and 2010 was $8.2 million and $26.1 million, respectively. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $7.4 million and $11.7 million for the nine-month periods ended September 30, 2011 and 2010, respectively.

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

                 
     Nine Months Ended
 September 30, 
 
(Thousands of dollars)     2011       2010   
 Compensation charged against income before tax benefit     $   32,885         31,594   
 Related income tax benefit recognized in income       9,883         9,144   

Note I – Earnings per Share

 Net income was used as the numerator in computing both basic and diluted income per Common share for the three-month and nine-month periods ended September 30, 2011 and 2010. The following table reconciles the weighted-average shares outstanding used for these computations.

                                 
     Three Months Ended  
 September 30, 
     Nine Months Ended
 September 30, 
 
 (Weighted-average shares)     2011       2010       2011       2010   
 Basic method       193,517,785         191,943,813         193,342,825         191,577,000   
 Dilutive stock options and restricted stock units       893,331         1,494,179         1,206,021         1,289,485   
                                 
 Diluted method       194,411,116         193,437,992         194,548,846         192,866,485   
                                 

 Certain options to purchase shares of common stock were outstanding during the 2011 and 2010 periods but were not included in the computation of diluted EPS because the incremental shares from assumed conversion were antidilutive. These included 1,764,565 shares at a weighted average share price of $69.53 in each 2011 period and 2,237,753 shares at a weighted average share price of $58.79 in each 2010 period.

11

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Income Taxes

 The Company’s effective income tax rate generally exceeds the statutory U.S. tax rate of 35%. The effective tax rate is calculated as the amount of income tax expense divided by income before income tax expense. For the three-month and nine-month periods in 2011 and 2010, the Company’s effective income tax rates were as follows:

                 
    2011      2010   
 Three months ended September 30       37.2   %         44.0   %   
 Nine months ended September 30       41.1   %         42.8   %   

 The effective tax rates for the periods presented exceeded the U.S. statutory tax rate of 35% due to several factors, including: the effects of income generated in foreign tax jurisdictions; U.S. state tax expense; a tax rate increase in 2011 on oil and gas profits in the U.K.; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are available or are not presently being recorded due to a lack of reasonable certainty of adequate future revenue against which to utilize these expenses as deductions. A one-time tax benefit in Malaysia reduced income tax expense in 2011.

 In July 2011, the United Kingdom enacted a supplemental tax rate increase for oil and gas companies effective retroactive to March 2011. The total U.K. tax rate increased from 50% to 62% for oil and gas companies. The Company recorded the effect of this tax increase in its consolidated financial statements in the third quarter 2011. The supplemental tax increased income tax expense by $14.5 million for the three-month and nine-month periods ended September 30, 2011. The majority of this impact relates to a third quarter adjustment to increase the carrying value of net deferred tax liabilities associated with U.K. upstream operations. The tax rates for the three-month and nine-month periods in 2010 benefited 0.5% and 0.2%, respectively, for an income tax adjustment in the U.K.

 In the third quarter 2011, it was determined that Block P expenditures are deductible against Block K income. The Company recorded a $25.6 million income tax benefit in the three-month and nine-month periods ended September 30, 2011 associated with prior-year expenditures in Block P. The Company had previously recognized no tax benefits associated with Block P expenditures.

 The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. During the third quarter of 2011, $6.5 million of uncertain tax positions were settled in the U.S. and recorded as a benefit due to a lapse of time related to the statute of limitation. As of September 30, 2011, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2008; Canada – 2006; United Kingdom – 2009; and Malaysia – 2006.

Note K – 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. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Income. As described below, certain interest rate derivative contracts are accounted for as hedges and the gain or loss associated with recording the fair value of these contracts has been deferred in Accumulated Other Comprehensive Income until the anticipated transactions occur.

12

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Commodity Purchase Price Risks

 The Company is subject to commodity price risks related to crude oil feedstocks previously held in inventory at U.S. refineries. The Company had no open crude oil derivative contracts at September 30, 2011. Short-term derivative instruments were outstanding at September 30, 2010 to manage the cost of about  0.9 million barrels of crude oil and other feedstocks at the Company’s U.S. refineries. Also, at September 30, 2010, the Company had open derivative contracts covering 0.4 million barrels of intermediate feedstock inventories which were to be processed at the Company’s refineries. The total impact of marking to market these contracts decreased income before taxes by $3.8 million in the nine-month period ended September 30, 2010. There was an accounts receivable of $7.3 million related to matured but unsettled crude oil derivative contracts at September 30, 2011.

 The Company is also subject to commodity price risk related to corn that it will purchase in the future for feedstock and to wet and dried distillers grain that it will sell in the future at its ethanol production facilities in the United States. At September 30, 2011 and 2010, the Company had open physical delivery fixed-price commitment contracts for purchase of approximately 7.9 million and 5.4 million bushels of corn, respectively, for processing at its ethanol plants. The Company also had outstanding derivative contracts to sell a similar volume of these fixed-price quantities and buy them back at future prices in effect on the expected date of delivery under the purchase commitment contracts. Also, at September 30, 2011, the Company had open physical delivery fixed-price commitment contracts for sale of approximately 1.6 million equivalent bushels of wet and dried distillers grain with outstanding derivative contracts to purchase a similar volume of these fixed-price quantities and sell them back at future prices in effect on the expected date of delivery under the sale commitment contracts. Additionally, at September 30, 2011, the Company had outstanding derivative contracts to sell 2.3 million bushels of corn and buy them back when certain corn inventories are expected to be processed at the Hereford, Texas facility. The impact of marking to market these commodity derivative contracts increased income before taxes by $1.9 million in the nine-month period ended September 30, 2011 and was insignificant for the nine-month period ended September 30, 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 September 30, 2011 and 2010 to manage the risk of certain future income taxes that are payable in Malaysian ringgits. The equivalent U.S. dollars of Malaysian ringgit derivative contracts open at September 30, 2011 and 2010 were approximately $123.3 million and $194.0 million, respectively. Short-term derivative instrument contracts totaling $38.0 million and $107.0 million U.S. dollars were also outstanding at September 30, 2011 and 2010, respectively, to manage the risk of certain U.S. dollar accounts receivable associated with sale of crude oil production in Canada. The impact from marking to market these foreign currency derivative contracts increased income before taxes by $4.6 million and $29.7 million for the nine-month periods ended September 30, 2011 and 2010, respectively.

 At September 30, 2011 and December 31, 2010, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

                             
     September 30, 2011       December 31, 2010   
 (Thousands of dollars)     Asset (Liability) Derivatives       Asset (Liability) Derivatives   
 Type of Derivative Contract     Balance Sheet Location       Fair Value       Balance Sheet Location     Fair Value   
 Commodity       Accounts receivable       $   9,228       Accounts receivable     $   750   
 Commodity       —            —          Accounts payable       (626   )   
 Foreign exchange       Accounts payable         (2,609   )       Accounts receivable       7,261   

 For the three-month and nine-month periods ended September 30, 2011 and 2010, the gains and losses recognized in the Consolidated Statements of Income for derivative instruments not designated as hedging instruments are presented in the following table.

                                     
         Gain (Loss)   
         Three Months Ended
 September 30, 
     Nine Months Ended
 September 30, 
 
 (Thousands of dollars)     Statement of Income  
 Location 
   2011       2010       2011       2010   
 Type of Derivative Contract           
 Commodity     Crude oil and
 product purchases 
   $   7,381         (1,695   )         5,900         (1,085   )   
 Foreign exchange     Interest and other  
 income 
     (7,376   )         13,954         4,614         29,681   
                                     
         $   5         12,259         10,514         28,596   
                                     

13

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Interest Rate Risks

 The Company has ten-year notes totaling $350 million that mature on May 1, 2012. The Company currently anticipates replacing these notes at maturity with new ten-year notes, and it therefore has risk associated with the interest rate associated with the anticipated sale of these notes in 2012. To manage this risk, in the third quarter 2011 the Company entered into a series of derivative contracts known as forward starting interest rate swaps that mature in May 2012. The Company utilizes hedge accounting to defer any gain or loss on these contracts until the payment of interest on these anticipated notes occurs. There was no impact in the 2011 Consolidated Statements of Income associated with accounting for these interest rate derivative contracts.

 At September 30, 2011, the fair value of these interest rate derivative contracts, which have been designated as hedging instruments for accounting purposes, are presented in the following table.

                 
    September 30, 2011   
(Thousands of dollars)    Asset (Liability) Derivatives   
Type of Derivative Contract    Balance Sheet Location      Fair Value   
 Interest rate       Accounts Payable       $   (20,722   )   

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

 The carrying value of assets and liabilities recorded at fair value on a recurring basis at September 30, 2011 and December 31, 2010 are presented in the following table.

                                                                 
    September 30, 2011      December 31, 2010   
(Thousands of dollars)     Level 1       Level 2       Level 3       Total       Level 1       Level 2       Level 3       Total   
 Assets                                                                 
 Foreign exchange derivative contracts     $   0         0         0         0         0         7,261         0         7,261   
 Commodity derivative contracts       0         9,228         0         9,228         0         750         0         750   
                                                                 
     $   0         9,228         0         9,228         0         8,011         0         8,011   
                                                                 
 Liabilities                                                                 
 Nonqualified employee savings plans     $   (6,980   )         0         0         (6,980   )         (7,672   )         0         0         (7,672   )   
 Foreign exchange derivative contracts       0         (2,609   )         0         (2,609   )         0         0         0         0   
 Commodity derivative contracts       0         0         0         0         0         (626   )         0         (626   )   
 Interest rate derivative contracts       0         (20,722   )         0         (20,722   )         0         0         0         0   
                                                                 
     $   (6,980   )         (23,331   )         0         (30,311   )         (7,672   )         (626   )         0         (8,298   )   
                                                                 

 The fair value of commodity derivative contracts was determined based on market quotes for West Texas Intermediate crude oil and for No. 2 yellow corn. The fair value of foreign exchange and interest rate derivative contracts was based on market quotes for similar contracts at the balance sheet date. The income effect of changes in fair value of commodity derivative contracts is recorded in Crude Oil and Product Purchases in the Consolidated Statements of Income and changes in fair value of foreign exchange derivative contracts is recorded in Interest and Other Income. There was no income effect for the change in fair value of interest rate derivative contracts. 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. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. The income effect of changes in the fair value of nonqualified employee savings plan is recorded in Selling and General Expenses.

14

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note L – Accumulated Other Comprehensive Income

 The components of Accumulated Other Comprehensive Income on the Consolidated Balance Sheets at September 30, 2011 and December 31, 2010 are presented in the following table.

                 
    Sept. 30,
 2011 
    Dec. 31,
 2010 
 
 (Thousands of dollars)             
 Foreign currency translation gains, net of tax     $   409,927         587,408   
 Retirement and postretirement benefit plan losses, net of tax       (124,343   )         (137,980   )   
 Loss deferred for fair value of interest rate derivative contracts, net of tax       (13,469   )         0   
                 
 Accumulated other comprehensive income     $   272,115         449,428   
                 

Note M – Environmental and Other Contingencies

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

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

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

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

15

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note M – Environmental and Other Contingencies  (Contd.)

 The U.S. Environmental Protection Agency (EPA) currently considers the Company to be a Potentially Responsible Party (PRP) at one Superfund site. The potential total cost to all parties to perform necessary remedial work at the 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 the Superfund site. 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.

 Murphy is 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 September 30, 2011, the Company had contingent liabilities of $7.8 million under a financial guarantee and $251.5 million on outstanding letters of credit. The Company has not accrued a liability in its Consolidated Balance Sheets related to these letters of credit because it is believed that the likelihood of having these drawn is remote.

Note N – Commitments

 The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2011 and 2012 natural gas sales volumes in the Tupper and Tupper West areas in Western Canada. The contracts call for natural gas deliveries of approximately 99 million cubic feet per day in the last three months of 2011 at an average price of Cdn$4.90 per MCF, with the contracts calling for delivery at the AECO “C” sales point. In 2012, contracts call for delivery at AECO “C” of approximately 50 million cubic feet per day at an average price of Cdn$4.43 per MCF. These contracts have been accounted for as a normal sale for accounting purposes.

Note O – Terra Nova Working Interest Redetermination

 The joint agreement between the owners of the Terra Nova field, offshore Eastern Canada, required a redetermination of working interests based on an analysis of reservoir quality among fault separated areas where varying ownership interests exist. The Terra Nova redetermination process was essentially completed in 2010, and the Company’s working interest at Terra Nova was reduced from its original 12.0% to approximately 10.475%. The Company made a cash settlement payment in the first quarter 2011 to certain Terra Nova partners for the value of oil sold since February 2005 related to the working interest reduction. The Company had recorded cumulative expense of $102.1 million through 2010 based on the working interest reduction. Based on the final settlement paid in 2011, the Company recorded a benefit of $5.4 million in the nine-month period ended September 30, 2011 due to the ultimate cost of the redetermination settlement being less than originally estimated. The 2010 expense and 2011 benefit have been reflected as Redetermination of Terra Nova Working Interest in the Consolidated Statements of Income.

16

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note P – Accounting Matters

 In September 2011, the Financial Accounting Standards Board (FASB) issued an update that is intended to simplify the annual goodwill impairment assessment process by permitting a company to assess whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount before applying the two-step goodwill impairment test. If a company concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the company would be required to conduct the current two-step goodwill impairment test. This change is effective for annual and interim goodwill impairment tests performed in fiscal years beginning after December 15, 2011, but early adoption is permitted. The Company is still evaluating the standard and may choose to early adopt this update for the annual goodwill impairment test due to be performed as of year-end 2011.

 The Company adopted new guidance issued by the 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 amended 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.

 In July 2010, the FASB issued new accounting guidance that expanded the disclosure requirements about financing receivables and the related allowance for credit losses. This guidance became effective for the Company at December 31, 2010. Because the Company has no significant financing receivables that extend beyond one year, the impact of this guidance did not have a significant effect on its consolidated financial statement disclosures.

 The United States Congress passed the Dodd-Frank Act in 2010. Among other requirements, the law requires companies in the oil and gas industry to disclose payments made to the U.S. Federal and all foreign governments. The SEC was directed to develop the reporting requirements in accordance with the law. The SEC has issued preliminary guidance and has sought feedback thereon from all interested parties. The preliminary rules indicated that payment disclosures would be required at a project level within the annual Form 10-K report beginning with the year ending December 31, 2012. The Company cannot predict the final disclosure requirements that will be required by the Dodd-Frank Act.

17

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note Q – Business Segments

                                                         
           Three Mos. Ended Sept. 30, 2011       Three Mos. Ended Sept. 30, 20101   
 (Millions of dollars)     Total Assets
 at Sept. 30,
 2011 
     External
 Revenues 
     Inter-segment  
 Revenues 
     Income
 (Loss) 
     External
 Revenues 
     Inter-segment
 Revenues 
     Income
 (Loss) 
 
 Exploration and production 2                                                         
 United States     $   1,752.7         173.2         0         38.2         155.2         0         14.6   
 Canada       3,467.6         307.4         42.7         102.3         170.5         33.5         39.1   
 Malaysia       3,487.0         484.8         0         197.7         453.4         0         167.6   
 United Kingdom       205.4         20.2         0         (11.5   )         28.0         0         4.9   
 Republic of the Congo       706.0         43.7         0         (.7   )         46.6         0         (20.2   )   
 Other       68.9         0         0         (64.1   )         .4         0         (19.3   )   
                                                         
 Total       9,687.6         1,029.3         42.7         261.9         854.1         33.5         186.7   
                                                         
 Refining and marketing                                                         
 United States       2,241.8         4,629.2         0         88.0         3,424.6         0         59.0   
 United Kingdom       1,157.4         1,552.1         0         (19.1   )         930.5         0         (13.8   )   
                                                         
 Total       3,399.2         6,181.3         0         68.9         4,355.1         0         45.2   
                                                         
 Total operating segments       13,086.8         7,210.6         42.7         330.8         5,209.2         33.5         231.9   
 Corporate       1,859.3         29.8         0         4.9         (8.9   )         0         (34.5   )   
                                                         
 Assets/revenue/income from continuing operations       14,946.1         7,240.4         42.7         335.7         5,200.3         33.5         197.4   
 Discontinued operations, net of tax       545.0         0         0         70.4         0         0         5.4   
                                                         
 Total     $   15,491.1         7,240.4         42.7         406.1         5,200.3         33.5         202.8   
                                                         
                                                 
     Nine Months Ended Sept. 30, 2011       Nine Months Ended Sept. 30, 20101   
 (Millions of dollars)     External
 Revenues 
     Inter-segment  
 Revenues 
     Income
 (Loss) 
     External
 Revenues 
     Inter-segment
 Revenues 
     Income
 (Loss) 
 
 Exploration and production 2                                                 
 United States     $   539.7         0         106.8         497.8         0         47.8   
 Canada       827.7         137.4         284.5         593.9         73.9         150.6   
 Malaysia       1,442.1         0         559.5         1,386.7         0         499.3   
 United Kingdom       83.9         0         6.8         109.5         0         29.9   
 Republic of the Congo       111.4         0         (.4   )         100.3         0         (26.6   )   
 Other       24.4         0         (191.6   )         3.0         0         (48.2   )   
                                                 
 Total       3,029.2         137.4         765.6         2,691.2         73.9         652.8   
                                                 
 Refining and marketing                                                 
 United States       13,356.1         0         172.9         10,083.5         0         135.2   
 United Kingdom       4,499.0         0         (43.6   )         1,889.5         0         (24.4   )   
                                                 
 Total       17,855.1         0         129.3         11,973.0         0         110.8   
                                                 
 Total operating segments       20,884.3         137.4         894.9         14,664.2         73.9         763.6   
 Corporate       43.7         0         (40.7   )         (58.6   )         0         (133.5   )   
                                                 
 Revenue/income from continuing operations       20,928.0         137.4         854.2         14,605.6         73.9         630.1   
 Discontinued operations, net of tax       0         0         132.4         0         0         (6.1   )   
                                                 
 Total     $   20,928.0         137.4         986.6         14,605.6         73.9         624.0   
                                                 
 1     Reclassified to conform to current presentation. 
 2     Additional details about results of oil and gas operations are presented in the tables on pages 26 and 27. 

18

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note Q – Business Segments  (Contd.)

 In 2010, the Company announced its intention to sell its two U.S. refineries and its U.K. downstream operations during 2011. On September 30, 2011, the Company completed the sale of the Superior, Wisconsin refinery and associated marketing assets. On October 1, 2011, the Company completed the sale of the Meraux, Louisiana refinery and associated marketing assets. Beginning in the third quarter 2011, results of operations for the Superior and Meraux refineries and associated marketing assets have been reported as discontinued operations net of taxes for all periods presented in the Consolidated Statement of Income and in the following segment table. Due to the sale of the two U.S. refineries, Company management has reevaluated the reportable segments for the downstream business. Based on this reevaluation, the U.S. downstream is now being presented as one reportable segment while the two refineries that formerly comprised the majority of the former U.S. manufacturing segment are presented in the segment table as discontinued operations. The Company continues to actively market for sale the U.K. downstream assets and expects that the results of these operations to be sold will be presented as discontinued operations in future periods when the criteria for held for sale under U.S. generally accepted accounting principles have been met.

19

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 third quarter of 2011 was $406.1 million ($2.09 per diluted share) compared to net income of $202.8 million ($1.05 per diluted share) in the third quarter of 2010. The income improvement in 2011 primarily related to higher sales prices for the Company’s crude oil production and higher margins on U.S. refining and marketing operations. The 2011 quarter also included net tax benefits of $11.1 million related to oil and gas operations. These factors were partially offset by lower crude oil sales volumes, higher exploration expenses and significantly weaker results in U.K. downstream operations. The Company sold its two U.S. refineries near the end of the third quarter 2011 and has reported results of operations and the 2011 net gain on sale as discontinued operations. The 2011 quarterly net income included income from discontinued operations of $70.4 million ($0.36 per diluted share) compared to income of $5.4 million ($0.03 per diluted share) in the 2010 quarter. The improvement in the 2011 quarter was due to stronger U.S. refinery margins in the current period, coupled with an after-tax gain of $16.9 million upon sale of the two refineries. Income from continuing operations was $335.7 million ($1.73 per diluted share) in the 2011 quarter and $197.4 million ($1.02 per diluted share) in the comparable 2010 quarter.

 For the first nine months of 2011, net income totaled $986.6 million ($5.07 per diluted share) compared to net income of $624.0 million ($3.24 per diluted share) for the same period in 2010. The increase in net income in 2011 compared to 2010 was also primarily attributable to higher crude oil sales prices and improved U.S. refining and marketing results. Operating results were unfavorably affected in 2011 by lower crude oil sales volumes, higher exploration expenses and a larger operating loss in U.K. downstream operations. Income from discontinued operations totaled $132.4 million ($0.68 per diluted share) in the nine-month period of 2011, while these results were a loss of $6.1 million ($0.03 loss per diluted share) in 2010. The current year included much stronger U.S. refining margins and a $16.9 million after-tax gain on sale of the refineries. Income from continuing operations in the 2011 and 2010 nine months was $854.2 million ($4.39 per diluted share) and $630.1 million ($3.24 per diluted share), respectively.

 Murphy’s income from continuing operations by operating business is presented below.

                                 
     Income (Loss)   
     Three Months Ended
 September 30, 
     Nine Months Ended
 September 30, 
 
 (Millions of dollars)     2011       2010       2011       2010   
 Exploration and production     $   261.9         186.7         765.6         652.8   
 Refining and marketing       68.9         45.2         129.3         110.8   
 Corporate       4.9         (34.5   )         (40.7   )         (133.5   )   
                                 
 Income from continuing operations     $   335.7         197.4         854.2         630.1   
                                 

 In the 2011 third quarter, the Company’s exploration and production operations earned $261.9 million compared to $186.7 million in the 2010 quarter. Income in the 2011 quarter was favorably impacted compared to 2010 by higher crude oil sales prices, higher natural gas sales volumes, and an $11.1 million net income tax benefit. Exploration expenses were $85.7 million in the third quarter of 2011 compared to $62.0 million in the same period of 2010. The Company’s refining and marketing operations generated income from continuing operations of $68.9 million in the 2011 third quarter compared to $45.2 million in the same quarter of 2010. U.S. retail marketing margins improved in the 2011 quarter, compared to the 2010 quarter, but refining and marketing results in the U.K. were unfavorable to the prior year. The Company sold its two U.S. refineries near the end of third quarter 2011 and has reported all periods presented for these U.S. refining assets as discontinued operations. The corporate function had after-tax benefits of $4.9 million in the 2011 third quarter compared to after-tax costs of $34.5 million in the 2010 period with the favorable variance in 2011 mostly due to gains on transactions denominated in foreign currencies in 2011 compared to losses on such transactions in the 2010 quarter.

 In the first nine months of 2011, the Company’s exploration and production operations earned $765.6 million compared to $652.8 million in the same period of 2010. Earnings in 2011 compared favorably to the 2010 period primarily due to higher realized crude oil sales prices and higher natural gas sales volumes. Exploration expenses increased from $181.5 million in the first nine months of 2010 to $304.5 million in the 2011 period, with the higher costs in 2011 primarily from unsuccessful wildcat drilling offshore Indonesia, Suriname and Brunei. The Company’s refining and marketing continuing operations had earnings of $129.3 million in the first nine months of 2011 compared to earnings of $110.8 million in the same 2010 period. The 2011 period included stronger results in the U.S. retail marketing business compared to a year ago based on better operating margins. However, losses from U.K. refining and marketing operations were significantly higher in 2011 compared to 2010 due to more sales volumes at very

20

Table of Contents

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

Results of Operations  (Contd.)

 weak operating margins. Corporate after-tax costs were $40.7 million in the 2011 period compared to after-tax costs of $133.5 million in the 2010 period. The current period had a favorable impact from gains on transactions denominated in foreign currencies, while the prior year included significant losses from these transactions.

Exploration and Production

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

                                 
     Income (Loss)   
     Three Months Ended
 September 30, 
     Nine Months Ended
 September 30, 
 
 (Millions of dollars)     2011       2010       2011       2010   
 Exploration and production                                 
 United States     $   38.2         14.6         106.8         47.8   
 Canada       102.3         39.1         284.5         150.6   
 Malaysia       197.7         167.6         559.5         499.3   
 United Kingdom       (11.5   )         4.9         6.8         29.9   
 Republic of the Congo       (0.7   )         (20.2   )         (0.4   )         (26.6   )   
 Other International       (64.1   )         (19.3   )         (191.6   )         (48.2   )   
                                 
 Total     $   261.9         186.7         765.6         652.8   
                                 

Third quarter 2011 vs. 2010

 United States exploration and production operations had earnings of $38.2 million in the third quarter of 2011 compared to earnings of $14.6 million in the 2010 quarter. Earnings improved in the 2011 period primarily due to higher realized oil sales prices. Oil and natural gas production volumes were lower in 2011 due to decline at Thunder Hawk and other fields in the Gulf of Mexico. A significant portion of this production decline was attributable to an inability to obtain drilling permits in the Gulf of Mexico following the Macondo incident in April 2010. Also, production in the Gulf of Mexico was unfavorably affected by about six days of downtime at several fields due to a tropical storm in September 2011. Production expenses increased $6.9 million in 2011 compared to 2010 mostly due to higher production in the Eagle Ford Shale area of South Texas. Depreciation expense was $25.7 million less in 2011 due to lower oil and natural gas production volumes and lower per-barrel capital amortization rates in the Gulf of Mexico in the current quarter. Exploration expenses in the 2011 quarter were $2.4 million lower due to less leasehold amortization for oil fields now being developed in the Eagle Ford Shale area, partially offset by higher seismic costs in the Eagle Ford Shale. Selling and general expenses in the 2011 period increased $1.1 million from the prior year primarily due to higher costs for employee compensation and other professional services.

 Operations in Canada had earnings of $102.3 million in the third quarter 2011 compared to earnings of $39.1 million in the 2010 quarter. Canadian earnings increased in the 2011 quarter mostly due to higher crude oil and natural gas sales prices and higher oil and natural gas sales volumes. Oil production increased in the 2011 period compared to 2010 primarily due to a combination of higher volumes at  Syncrude due to less downtime for maintenance during the current quarter and higher heavy oil production at Seal due to expanded drilling activities. Natural gas volumes increased in 2011 due to start-up of Tupper West area production in February 2011 and higher volumes produced at the nearby Tupper Main area. Production and depreciation expenses for conventional oil operations in Canada were unfavorable in 2011 by $20.7 million and $33.4 million, respectively, due primarily to higher gas volumes produced at Tupper West and Tupper Main. Production expenses at  Syncrude increased $6.3 million in 2011 due to higher fuel and maintenance costs. Depreciation expense increased by $2.7 million at  Syncrude in 2011 due to higher oil production volumes. The 2010 quarter included expense of $4.5 million related to a required working redetermination at the Terra Nova field, offshore Newfoundland. Selling and general expenses increased $1.5 million in 2011 due to higher employee compensation and office costs.

 Operations in Malaysia reported earnings of $197.7 million in the 2011 quarter compared to earnings of $167.6 million during the same period in 2010. Earnings rose in 2011 in Malaysia from a combination of higher crude oil sales prices, higher natural gas sales prices and sales volumes from fields offshore Sarawak, and favorable income tax benefits. The 2011 quarter was unfavorably affected by lower crude oil sales volumes, primarily at the Kikeh field where certain wells were shut-in or curtailed for rig workovers. An active workover program is ongoing at Kikeh and early results have been successful. Production expenses were higher in the 2011 period by $29.5 million primarily

21

Table of Contents

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

Results of Operations  (Contd.)

Exploration and Production (Contd.)

Third quarter 2011 vs. 2010 (Contd.)

 due to the workover costs at the Kikeh field. Depreciation expense was $11.2 million less in the 2011 quarter due to lower crude oil sales volumes, somewhat offset by higher natural gas sales volumes. Exploration expense was $2.8 million higher in 2011 due to the cost of 3D seismic acquired in Block H, offshore Sabah. An income tax benefit of $25.6 million was recorded in the third quarter 2011 associated with costs incurred in prior years in Block P, offshore Sabah, after it was determined that Block P costs are deductible against taxable earnings of Block K. The Company had previously not recognized income tax benefits of Block P costs.

 United Kingdom operations had a net loss of $11.5 million in the 2011 quarter compared to earnings of $4.9 million in the 2010 quarter. The lower operating results were primarily due to unfavorable income tax adjustments in the 2011 quarter, coupled with lower sales volumes for crude oil and natural gas. These variances were partially offset by higher crude oil and natural gas sales prices and lower exploration expenses in the current quarter. The lower crude oil and natural gas sales volumes were mostly caused by maintenance undertaken at North Sea fields during the summer months of 2011. Production expense was $2.9 million more in 2011 than 2010 due to higher maintenance costs in the current quarter at the Schiehallion and Mungo/Monan fields. Depreciation expense declined by $3.4 million in 2011 compared to 2010 primarily due to lower oil and gas sales volumes. Exploration expenses were $5.6 million less in the 2011 quarter compared to 2010, principally due to an unsuccessful exploratory well drilled in the prior year. An income tax charge of $14.5 million was recognized in the 2011 third quarter associated with a 12% tax rate increase on oil and gas company profits, which was enacted by the U.K. government during the quarter retroactive to April 2011. The tax charge was primarily associated with an increase of recorded deferred tax liabilities. Henceforth, the statutory tax rate is 62% for U.K. exploration and production operations.

 Operations in Republic of the Congo incurred a loss of $0.7 million in the third quarter of 2011 compared to a loss of $20.2 million in the 2010 quarter. Results improved in the current period primarily due to lower exploration expenses and higher crude oil sales prices. Production expense declined by $9.8 million in 2011 versus 2010 due to less well maintenance costs at the Azurite field. Depreciation expense increased by $0.9 million in 2011 associated with a higher unit rate for capital amortization. Exploration expenses were $13.8 million less in the 2011 third quarter compared to 2010 as the prior year included costs for 3D seismic acquired over a portion of the offshore MPN and MPS blocks.

 Other international operations reported a loss of $64.1 million in the third quarter of 2011 compared to a loss of $19.3 million in the 2010 period. The unfavorable variance in the current quarter included higher unsuccessful exploratory drilling costs in Brunei, higher seismic costs covering licenses offshore Brunei, and higher geophysical and lease amortization costs associated with exploration licenses in the Kurdistan Region of Iraq.

 On a worldwide basis, the Company’s crude oil, condensate and gas liquids prices averaged $95.95 per barrel in the third quarter 2011 compared to $65.45 in the 2010 period. Total hydrocarbon production averaged 174,801 barrels of oil equivalent per day in the 2011 third quarter, down from the 181,733 barrels equivalent per day produced in the 2010 quarter. Average crude oil and liquids production was 96,437 barrels per day in the third quarter of 2011 compared to 119,899 barrels per day in the third quarter of 2010, with the reduction primarily attributable to lower gross oil production at the Kikeh field caused by wells shut-in or curtailed for rig workovers. U.S. crude oil production in the 2011 third quarter was down from 2010 mostly at the Thunder Hawk field, where development drilling has been delayed by the protracted process required to obtain drilling permits in the Gulf of Mexico following the Macondo incident in 2010. Canadian offshore crude oil production at Terra Nova was lower in the 2011 quarter due to curtailed production associated with equipment constraints on the production facility. Canadian crude oil production in the heavy oil area was higher in 2011 mostly due to more drilling activity in the Seal area in the current year. Synthetic crude oil production was higher in 2011 due to less downtime for maintenance in the current quarter. Oil production in the U.K. was lower in 2011 due to more downtime for maintenance at North Sea fields during the summer, and oil production in the Republic of Congo was lower in 2011 due to Azurite field well decline. North American natural gas sales prices averaged $4.20 per thousand cubic feet (MCF) in the 2011 quarter compared to $4.24 per MCF in the same quarter of 2010. Natural gas produced in 2011 at fields offshore Sarawak was sold at $7.54 per MCF, compared to a sale price of $5.71 per MCF in the 2010 quarter. Natural gas sales volumes averaged 470 million cubic feet per day in the third quarter 2011, up from 371 million cubic feet per day in the 2010 quarter. The increase

22

Table of Contents

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

Results of Operations  (Contd.)

Exploration and Production (Contd.)

Third quarter 2011 vs. 2010 (Contd.)

 in natural gas sales volumes in 2011 was primarily due to start-up of Tupper West area production in British Columbia in February 2011. The Company also had higher natural gas production at nearby Tupper Main as development drilling operations continued in 2011, and also had higher gas production from fields offshore Sarawak due to higher customer demand and more consistent operations.

Nine months 2011 vs. 2010

 U.S. E&P operations had income of $106.8 million for the nine months ended September 30, 2011 compared to income of $47.8 million in the 2010 period. The 2011 period benefited from higher crude oil sales prices, but natural gas sales prices were lower in the 2011 period compared to the prior year. Crude oil and natural gas production volumes were lower in 2011 primarily due to declines at fields in the Gulf of Mexico, which were mostly caused by delays in obtaining drilling permits following the Macondo incident. Production expense was $17.9 million more in 2011 than 2010 mostly due to higher production in the Eagle Ford Shale area of South Texas. Depreciation expense was $89.9 million less in 2011 than 2010 due to the lower overall production volumes and a lower per-barrel capital amortization rate. Exploration expense in the 2011 period was $10.3 million above 2010 levels primarily due to higher Eagle Ford Shale area geophysical expense and undeveloped lease amortization. Selling and general expenses rose by $8.1 million in 2011 compared to 2010 essentially due to higher costs for employee compensation and other professional services.

 Canadian operations had income of $284.5 million in the first nine months of 2011 compared to income of $150.6 million a year ago. Higher sales prices for crude oil and higher volumes of natural gas sold were the primary drivers to the improvement in 2011 earnings. Production and depreciation expenses increased $60.3 million and $71.6 million, respectively, in 2011 mostly related to higher volumes of natural gas produced at the Tupper West area following start-up in February 2011 and higher maintenance costs and production volumes at  Syncrude oil operations. A required redetermination of working interest at the Terra Nova field, offshore Newfoundland, led to net costs of $15.4 million in the 2010 period, but the 2011 period included a benefit of $5.4 million associated with the early 2011 final settlement being less costly than previously projected. Selling and general expenses increased by $1.6 million in 2011 due to higher compensation and other office costs.

 Malaysia operations earned $559.5 million in the first nine months of 2011 compared to earnings of $499.3 million in the 2010 period. Earnings were stronger in 2011 primarily due to higher crude oil sales prices, a $25.6 million income tax benefit, and higher sales volumes and sales prices for natural gas produced offshore Sarawak. Crude oil sales volumes at the Kikeh field were lower in 2011 than 2010 due to less gross oil production caused by certain wells shut-in or curtailed for rig workovers. Production expense in 2011 exceeded the 2010 cost by $63.2 million primarily due to higher Kikeh field maintenance. Depreciation expense in 2011 was $36.3 million below the 2010 period due to lower oil sales volumes at the Kikeh field. Exploration expense was $22.9 million lower in 2011 mostly due to no repeat of unsuccessful exploration drilling costs incurred in Block H in 2010, but 2011 included higher geophysical costs for 3D seismic acquisition and processing in Block H. The aforementioned income tax benefit arose because it was determined that Block P costs are deductible against taxable earnings from Block K.

 Income in the U.K. for the nine-month period in 2011 was $6.8 million compared to $29.9 million a year ago. The earnings reduction in 2011 was primarily due to lower crude oil and natural gas sales volumes and an income tax charge associated with a tax rate increase. The 2011 period benefited from higher crude oil and natural gas sales prices and lower exploration expense compared to 2010. Production expense in 2011 exceeded 2010 levels by $3.2 million primarily due to higher maintenance costs at offshore fields in the current period. Depreciation expense for 2011 was $9.2 million less than in 2010 due to the lower crude oil and natural gas sales volumes. Exploration expense in 2011 was $5.8 million below 2010 due to an unsuccessful exploration well in the prior year. The U.K. government enacted a 12% tax rate increase for oil and gas profits during the third quarter 2011. The rate increase was retroactive to April 2011. The $14.5 million tax charge primarily related to an increase in recorded deferred tax liabilities. The statutory income tax rate for the U.K. oil and gas operations is now 62%.

23

Table of Contents

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

Results of Operations ( Contd.)

Exploration and Production (Contd.)

Nine months 2011 vs. 2010 (Contd.)

 Operations in Republic of the Congo had a loss of $0.4 million for the nine-month 2011 period, compared to a loss of $26.6 million in the 2010 period. The improvement in 2011 was primarily due to higher sales prices for oil produced at the offshore Azurite field and lower exploration expenses. The 2011 period benefited from lower production expenses by $19.5 million due to less well maintenance costs and lower sales volumes in the current period. Depreciation expense increased $16.6 million due to a higher capital amortization rate and higher sales volumes at the Azurite oil field. Exploration expense was $12.3 million lower in 2011 than 2010. The prior year included higher costs for a 3D seismic acquisition covering a portion of the offshore MPN and MPS blocks. Selling and general expense in 2011 was $1.9 million above 2010 levels due to lower overhead amounts chargeable to drilling operations in the current period.

 Other international operations reported a loss of $191.6 million in the first nine months of 2011 compared to a loss of $48.2 million in the 2010 period. The higher 2011 loss primarily related to higher costs of $115.5 million associated with unsuccessful offshore wildcat drilling in Indonesia, Suriname and Brunei in the current year. Higher geophysical expense of $20.3 million in 2011 was primarily related to 3D seismic acquired offshore Brunei and studies on exploration licenses in the Central Dohuk and Baranan areas in the Kurdistan Region of Iraq. Higher undeveloped leasehold amortization of $13.2 million in 2011 compared to 2010 was attributable to the new exploration licenses in the Kurdistan Region of Iraq. Other exploration expenses increased $3.3 million in 2011 due to higher costs at various exploration field offices. Selling and general expenses were $4.4 million higher in 2011 primarily due to higher office costs supporting international E&P operations. The 2011 period included an after-tax gain of $13.1 million attributable to sale of the Company’s gas storage assets in Spain.

 For the first nine months of 2011, the Company’s sales price for crude oil, condensate and gas liquids averaged $94.36 per barrel, up from $65.06 per barrel in 2010. Total worldwide production averaged 175,776 barrels of oil equivalent per day during the nine months ended September 30, 2011, down from 189,250 barrels of oil equivalent produced in the same period in 2010. Crude oil, condensate and gas liquids production in the first nine months of 2011 averaged 101,269 barrels per day compared to 130,244 barrels per day a year ago. The reduction was mostly attributable to lower gross oil production at the Kikeh field offshore Sabah Malaysia, where wells were shut-in or curtailed for rig workovers. Crude oil production in the U.S. was lower in 2011 than 2010, primarily at the Thunder Hawk field where development drilling operations have been delayed by the inability to obtain timely drilling permits at the Gulf of Mexico field following the Macondo incident in 2010. Crude oil production offshore eastern Canada was lower in 2011 due to curtailment associated with equipment constraints on the Terra Nova production facility. Crude oil production in the U.K. was lower in 2011 than 2010 due to field decline at Mungo/Monan and more downtime for equipment repairs at Schiehallion. Synthetic oil production at  Syncrude increased in 2011 compared to 2010 due to higher gross production. Crude oil produced in Republic of the Congo increased in 2011 due to a new well coming onstream. Heavy Canadian crude oil production in 2011 increased due to ongoing development drilling operations in the Seal area of Alberta. The average sales price for North American natural gas in the first nine months of 2011 was $4.26 per MCF, down from $4.48 per MCF realized in 2010. Natural gas production at fields offshore Sarawak was sold at an average price of $6.76 per MCF in 2011 compared to $5.20 per MCF in 2010. Natural gas sales volumes increased from 354 million cubic feet per day in 2010 to 447 million cubic feet per day in 2011, with the increase mostly due to start-up of natural gas production volumes at the Tupper West area in British Columbia, which came onstream in February 2011, coupled with higher production at nearby Tupper Main and higher volumes produced at offshore Sarawak, Malaysia fields. Natural gas sales volumes from the Kikeh field were lower in 2011 than 2010 due to a combination of wells shut-in or curtailed for workovers and lower customer demand for gas production volumes.

 Additional details about results of oil and gas operations are presented in the tables on pages 26 and 27.

24

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 and nine-month periods ended September 30, 2011 and 2010 follow.

                                 
     Three Months  
 Ended September 30, 
     Nine Months  
 Ended September 30, 
 
 Exploration and Production     2011       2010       2011       2010   
 Net crude oil, condensate and gas liquids produced – barrels per day       96,437         119,899         101,269         130,244   
 United States       16,388         19,404         16,750         20,594   
 Canada – light       107         47         74         43   
              – heavy       7,097         5,749         6,875         6,048   
              – offshore       9,758         10,534         9,284         11,774   
              – synthetic       14,022         12,044         13,878         12,973   
 Malaysia       42,976         63,794         46,684         70,444   
 United Kingdom       1,502         2,831         2,313         3,669   
 Republic of Congo       4,587         5,496         5,411         4,699   
         
 Net crude oil, condensate and gas liquids sold – barrels per day       93,394         122,574         98,663         133,304   
 United States       16,388         19,404         16,750         20,594   
 Canada – light       107         47         74         43   
              – heavy       7,097         5,749         6,875         6,048   
              – offshore       10,262         10,055         9,381         11,682   
              – synthetic       14,022         12,044         13,878         12,973   
 Malaysia       39,329         64,547         45,374         72,428   
 United Kingdom       1,643         3,394         2,371         4,742   
 Republic of Congo       4,546         7,334         3,960         4,794   
         
 Net natural gas sold – thousands of cubic feet per day       470,183         371,005         447,044         354,038   
 United States       38,790         56,159         47,789         52,582   
 Canada       210,735         81,869         174,635         83,179   
 Malaysia – Sarawak       181,265         167,773         176,067         150,973   
                 – Kikeh       36,291         59,538         44,147         61,559   
 United Kingdom       3,102         5,666         4,406         5,745   
         
 Total net hydrocarbons produced – equivalent barrels per day (1)       174,801         181,733         175,776         189,250   
 Total net hydrocarbons sold – equivalent barrels per day (1)       171,758         184,408         173,170         192,310   
         
 Weighted average sales prices – Crude oil, condensate and natural gas liquids – dollars per barrel (2)                                 
 United States     $   102.05         73.10         102.33         74.53   
 Canada (3) – light       90.24         68.33         93.85         73.75   
                    – heavy       49.78         46.09         55.08         49.29   
                    – offshore       112.47         75.52         110.08         75.29   
                    – synthetic       101.18         74.80         103.08         76.04   
 Malaysia (4)       93.85         60.35         89.86         58.90   
 United Kingdom       113.82         77.22         110.51         76.53   
 Republic of the Congo       104.43         70.73         103.05         71.09   
 Natural gas – dollars per thousand cubic feet                                 
 United States (2)     $   4.36         4.51         4.32         4.75   
 Canada (3)       4.17         4.05         4.24         4.31   
 Malaysia – Sarawak       7.54         5.71         6.76         5.20   
                 – Kikeh       0.23         0.23         0.24         0.23   
 United Kingdom (3)       10.06         7.24         10.00         6.33   
 (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 the production sharing contracts for Blocks SK 309 and K. 

25

Table of Contents

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

Results of Operations  (Contd.)

OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED SEPTEMBER 30, 2011 AND 2010

                                                                 
     United
 States 
     Canada       Malaysia       United
 King-  
 dom 
     Republic
 of the
 Congo 
     Other       Total   
 (Millions of dollars)       Conven-
 tional 
     Syn-  
 thetic 
           
Three Months Ended September 30, 2011                                                                 
 Oil and gas sales and other operating revenues     $   173.2         219.6         130.5         484.8         20.2         43.7         —            1,072.0   
 Production expenses       41.4         43.7         59.2         116.5         9.3         11.4         —            281.5   
 Depreciation, depletion and amortization       40.8         75.1         13.5         83.0         1.6         26.7         .5         241.2   
 Accretion of asset retirement obligations       2.5         1.2         1.8         2.7         .7         .1         .1         9.1   
 Exploration expenses                                                                 
 Dry holes       —            —            —            —            —            —            13.3         13.3   
 Geological and geophysical       3.8         .9         —            3.7         .1         .9         24.5         33.9   
 Other       .8         .3         —            —            .1         —            7.2         8.4   
                                                                 
       4.6         1.2         —            3.7         .2         .9         45.0         55.6   
 Undeveloped lease amortization       14.0         7.4         —            —            —            —            8.7         30.1   
                                                                 
 Total exploration expenses       18.6         8.6         —            3.7         .2         .9         53.7         85.7   
                                                                 
 Selling and general expenses       10.4         3.9         .3         (1.1   )         .7         .5         9.9         24.6   
                                                                 
 Results of operations before taxes       59.5         87.1         55.7         280.0         7.7         4.1         (64.2   )         429.9   
 Income tax provisions (benefits)       21.3         26.9         13.6         82.3         19.2         4.8         (.1   )         168.0   
                                                                 
 Results of operations (excluding corporate overhead and interest)     $   38.2         60.2         42.1         197.7         (11.5   )         (.7   )         (64.1   )         261.9   
                                                                 
Three Months Ended September 30, 2010                                                                 
 Oil and gas sales and other operating revenues     $   155.2         121.0         83.0         453.4         28.0         46.6         .4         887.6   
 Production expenses       34.5         23.0         52.9         87.0         6.4         21.2         —            225.0   
 Depreciation, depletion and amortization       66.5         41.7         10.8         94.2         5.0         25.8         .4         244.4   
 Accretion of asset retirement obligations       1.8         1.2         1.5         2.5         .6         .1         .2         7.9   
 Exploration expenses                                                                 
 Dry holes       (.2   )         —            —            —            5.7         (.3   )         —            5.2   
 Geological and geophysical       2.1         .1         —            .9         .1         15.0         3.3         21.5   
 Other       .6         .1         —            —            —            —            6.2         6.9   
                                                                 
       2.5         .2         —            .9         5.8         14.7         9.5         33.6   
 Undeveloped lease amortization       18.5         8.7         —            —            —            —            1.2         28.4   
                                                                 
 Total exploration expenses       21.0         8.9         —            .9         5.8         14.7         10.7         62.0   
                                                                 
 Terra Nova working interest redetermination       —            4.5         —            —            —            —            —            4.5   
 Selling and general expenses       9.3         2.4         .3         .3         .7         (.5   )         8.4         20.9   
                                                                 
 Results of operations before taxes       22.1         39.3         17.5         268.5         9.5         (14.7   )         (19.3   )         322.9   
 Income tax provisions       7.5         12.7         5.0         100.9         4.6         5.5         —            136.2   
                                                                 
 Results of operations (excluding corporate overhead and interest)     $   14.6         26.6         12.5         167.6         4.9         (20.2   )         (19.3   )         186.7   
                                                                 

26

Table of Contents

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

Results of Operations  (Contd.)

OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2011 AND 2010

                                                                 
     United
 States 
     Canada       Malaysia       United
 King-  
 dom 
     Republic
 of the
 Congo 
     Other       Total   
 (Millions of dollars)       Conven-
 tional 
     Syn-  
 thetic 
           
Nine Months Ended September 30, 2011                                                                 
 Oil and gas sales and other operating revenues     $   539.7         574.8         390.3         1,442.1         83.9         111.4         24.4         3,166.6   
 Production expenses       118.9         112.0         176.0         304.3         23.8         28.2         —            763.2   
 Depreciation, depletion and amortization       132.1         199.3         40.1         254.7         9.9         64.5         1.3         701.9   
 Accretion of asset retirement obligations       7.4         3.7         5.7         8.0         2.3         .4         .3         27.8   
 Exploration expenses                                                                 
 Dry holes       .6         —            —            —            —            2.9         115.1         118.6   
 Geological and geophysical       24.4         3.4         —            9.5         .4         2.5         27.0         67.2   
 Other       8.1         .9         —            —            .3         .1         18.7         28.1   
                                                                 
       33.1         4.3         —            9.5         .7         5.5         160.8         213.9   
 Undeveloped lease amortization       52.3         21.4         —            —            —            —            16.9         90.6   
                                                                 
 Total exploration expenses       85.4         25.7         —            9.5         .7         5.5         177.7         304.5   
                                                                 
 Terra Nova working interest redetermination       —            (5.4   )         —            —            —            —            —            (5.4   )   
 Selling and general expenses       30.8         10.5         .7         (1.1   )         2.4         .8         28.0         72.1   
                                                                 
 Results of operations before taxes       165.1         229.0         167.8         866.7         44.8         12.0         (182.9   )         1,302.5   
 Income tax provisions       58.3         68.6         43.7         307.2         38.0         12.4         8.7         536.9   
                                                                 
 Results of operations (excluding corporate overhead and interest)     $   106.8         160.4         124.1         559.5         6.8         (.4   )         (191.6   )         765.6   
                                                                 
Nine Months Ended September 30, 2010                                                                 
 Oil and gas sales and other operating revenues     $   497.8         397.1         270.7         1,386.7         109.5         100.3         3.0         2,765.1   
 Production expenses       101.0         75.3         152.4         241.1         20.6         47.7         —            638.1   
 Depreciation, depletion and amortization       222.0         134.8         33.0         291.0         19.1         47.9         1.0         748.8   
 Accretion of asset retirement obligations       5.2         3.6         4.7         7.2         1.7         .2         .4         23.0   
 Exploration expenses                                                                 
 Dry holes       (.1   )         —            —            30.5         5.7         (.6   )         (.5   )         35.0   
 Geological and geophysical       19.2         .6         —            1.9         .6         18.4         6.7         47.4   
 Other       6.3         .3         —            —            .2         —            15.5         22.3   
                                                                 
       25.4         .9         —            32.4         6.5         17.8         21.7         104.7   
 Undeveloped lease amortization       49.7         23.4         —            —            —            —            3.7         76.8   
                                                                 
 Total exploration expenses       75.1         24.3         —            32.4         6.5         17.8         25.4         181.5   
                                                                 
 Terra Nova working interest redetermination       —            15.4         —            —            —            —            —            15.4   
 Selling and general expenses       22.7         8.9         .7         .6         2.3         (1.1   )         23.6         57.7   
                                                                 
 Results of operations before taxes       71.8         134.8         79.9         814.4         59.3         (12.2   )         (47.4   )         1,100.6   
 Income tax provisions       24.0         41.3         22.8         315.1         29.4         14.4         .8         447.8   
                                                                 
 Results of operations (excluding corporate overhead and interest)     $   47.8         93.5         57.1         499.3         29.9         (26.6   )         (48.2   )         652.8   
                                                                 

27

Table of Contents

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

Results of Operations ( Contd.)

Refining and Marketing

Third Quarter 2011 vs. 2010

 In 2010, the Company announced its intention to sell its three refineries and U.K. marketing operations during 2011. The Company completed the sale of the Superior, Wisconsin refinery and associated marketing assets on September 30, 2011. Also, the Company sold the Meraux, Louisiana refinery and associated marketing assets on October 1, 2011. The assets and liabilities of the Meraux refinery sold in the fourth quarter are reported as held for sale in the Consolidated Balance Sheet as of September 30, 2011. The revenues and expenses for both refineries for all periods presented have been reclassified to discontinued operations, net of tax, in the Consolidated Statements of Income. The sale process for the U.K. downstream operations continues to progress. See Note D in the consolidated financial statements for further discussion.

 United States refining and marketing includes two ethanol production facilities along with retail and wholesale fuel marketing operations. The United Kingdom refining and marketing segment includes the Milford Haven, Wales, refinery and U.K. retail and other refined products marketing operations.

 Murphy’s downstream income from continuing operations is presented below by segment.

                                 
     Income (Loss)   
     Three Months Ended
 September 30, 
     Nine Months Ended
 September 30, 
 
     2011       2010       2011       2010   
 (Millions of dollars)                         
 Refining and marketing – continuing operations                                 
 United States     $   88.0         59.0         172.9         135.2   
 United Kingdom       (19.1   )         (13.8   )         (43.6   )         (24.4   )   
                                 
 Total     $   68.9         45.2         129.3         110.8   
                                 

 United States downstream earnings from continuing operations increased from $59.0 million in the 2010 third quarter to $88.0 million in 2011. The U.S. retail marketing business generated virtually all of the increased income for U.S. operations in the current quarter. The favorable 2011 result was primarily due to an improvement in U.S. retail marketing margins, which totaled $0.200 per gallon in 2011 and $0.137 per gallon in 2010. In addition, these U.S. retail operations generated higher profits from merchandise sales in the 2011 quarter. However, overall per-store retail fuel sales volumes in the current period were below 2010 levels by about 11%. Earnings from ethanol production operations were flat between periods, primarily due to decreased margins at the Hankinson, North Dakota plant essentially offset by a full quarter of operations at the Hereford, Texas plant in the current year. The ramp-up of production at the Hereford plant after start-up has met Company expectations.

 Refining and marketing operations in the United Kingdom had a net loss of $19.1 million in the third quarter of 2011 compared to a net loss of $13.8 million in the same quarter of 2010. The U.K. results in 2011 were unfavorably affected compared to 2010 by higher administrative expenses in the current quarter and a nonrecurring income tax benefit in 2010 for a 1% reduction in corporate tax rates. Crude oil throughput volumes at the Milford Haven refinery were 135,053 barrels per day during the 2011 quarter, significantly ahead of throughputs of 105,522 barrels per day in the 2010 quarter. A capital project completed during a 2010 turnaround expanded the crude oil throughput capacity of the Milford Haven refinery from 108,000 to 135,000 barrels per day.

 Worldwide petroleum product sales (including discontinued operations) were 594,619 barrels per day in the 2011 quarter, up from 584,306 barrels per day a year ago. This increase was mostly due to the aforementioned higher crude oil throughputs in 2011 at the Milford Haven refinery.

28

Table of Contents

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

Results of Operations  (Contd.)

Refining and Marketing (Contd.)

Nine months 2011 vs. 2010

 The United States downstream continuing operations generated income of $172.9 million in the first nine months of 2011 compared to $135.2 million in the 2010 period. U.S. marketing operations generated essentially all of the increase in income in 2011. The favorable result in 2011 was primarily due to U.S. retail marketing margins which improved to $0.165 per gallon in 2011 following a margin of $0.128 per gallon in 2010. In addition, these U.S. retail operations generated higher profits from merchandise sales in 2011 due to capturing slightly more margin on these sales. However, overall per-store fuel sales volumes for the retail operations in the 2011 period were below 2010 levels by about 9%. Ethanol production operations generated lower income in the first nine months of 2011 compared to the same period in 2010. The reduction in 2011 was primarily attributable to unprofitable operations during start-up of the Hereford, Texas plant during the 2011 second quarter in conjunction with decreased margins at the Hankinson, North Dakota plant in the current year as ethanol sales prices did not keep pace with higher corn costs.

 Refining and marketing operations in the United Kingdom had a net loss of $43.6 million in the 2011 nine months compared to a net loss of $24.4 million in the same 2010 period. The U.K. results in 2011 were hurt by continued weak refining margins. Although refining margins were somewhat better in 2011 than 2010, higher crude oil throughputs at the Milford Haven, Wales, refinery led to larger volumes of products sold into the weak pricing market, generating a larger overall loss in the current year. Crude oil throughput volumes at Milford Haven were 130,986 barrels per day in 2011, up from 70,729 barrels per day in 2010, as the plant was shut down for turnaround for several months in 2010.

 Total petroleum product sales (including discontinued operations) were 586,928 barrels per day in the 2011 period, up from 524,092 barrels per day a year ago. This increase was also mostly due to the aforementioned refinery turnaround at Milford Haven during the prior year.

29

Table of Contents

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

Results of Operations  (Contd.)

 Selected operating statistics for the three-month and nine-month periods ended September 30, 2011 and 2010 follow.

                                 
     Three Months Ended
 September 30, 
     Nine Months Ended
 September 30, 
 
     2011       2010       2011       2010   
 Refinery inputs – barrels per day       314,348         267,988         307,714         215,285   
 United States – discontinued operations       176,307         158,002         173,368         140,022   
 Crude oil – Meraux, Louisiana       135,991         111,543         133,918         99,333   
                 – Superior, Wisconsin       36,426         36,568         35,407         34,050   
 Other feedstocks       3,890         9,891         4,043         6,639   
 United Kingdom       138,041         109,986         134,346         75,263   
 Crude oil –Milford Haven, Wales       135,053         105,552         130,986         70,729   
 Other feedstocks       2,988         4,434         3,360         4,534   
         
 Refinery yields – barrels per day       314,348         267,988         307,714         215,285   
 United States – discontinued operations       176,307         158,002         173,368         140,022   
 Gasoline       67,596         62,873         69,457         57,616   
 Kerosine       14,244         8,950         14,937         9,973   
 Diesel and home heating oils       50,382         46,542         50,435         38,519   
 Residuals       18,871         19,105         17,028         18,420   
 Asphalt       22,203         18,684         19,844         14,352   
 Fuel and loss       3,011         1,848         1,667         1,142   
 United Kingdom       138,041         109,986         134,346         75,263   
 Gasoline       34,496         29,697         32,670         18,831   
 Kerosine       17,459         15,326         17,183         10,683   
 Diesel and home heating oils       46,714         34,503         46,360         22,179   
 Residuals       15,048         10,447         13,862         7,207   
 Asphalt       21,049         16,354         21,183         13,471   
 Fuel and loss       3,275         3,659         3,088         2,892   
         
 Petroleum products sold – barrels per day       594,619         584,306         586,928         524,092   
 Total United States       457,729         467,119         451,644         445,897   
 United States Manufacturing – discontinued operations       183,997         160,902         174,618         141,523   
 Gasoline       80,983         70,328         80,479         65,018   
 Kerosine       14,245         8,952         14,937         9,973   
 Diesel and home heating oils       51,161         46,542         50,433         38,519   
 Residuals       18,424         18,516         16,870         18,151   
 Asphalt, LPG and other       19,184         16,564         11,899         9,862   
 United States Marketing       419,375         432,039         422,531         417,884   
 Gasoline       320,520         339,956         323,812         330,194   
 Kerosine       15,014         10,968         14,929         9,986   
 Diesel and other       83,841         81,115         83,790         77,704   
 United States Intercompany Elimination       (145,643   )         (125,822   )         (145,505   )