10-Q 1 d237676d10q.htm FORM 10-Q Form 10-Q
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark one)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended 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.

 

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Table of Contents

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

(Thousands of dollars, except per share amounts)

 

     Three Months Ended
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.

 

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Table of Contents

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

(Thousands of dollars)

 

     Three Months Ended
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.

 

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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 securities2

     (1,233,321     (1,862,609

Proceeds from maturity of investment securities2

     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.

 

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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

 

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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.

 

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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.

 

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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


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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 production2

                  

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 production2

               

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   
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

 

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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.

 

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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.

 

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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     (113,510

Gasoline

     (80,983     (70,328     (80,479     (65,018

Kerosine

     (14,244     (8,952     (14,937     (9,973

Diesel and other

     (50,416     (46,542     (50,089     (38,519

United Kingdom

     136,890        117,187        135,284        78,195   

Gasoline

     36,643        30,389        34,459        21,005   

Kerosine

     18,625        15,587        16,961        10,765   

Diesel and home heating oils

     47,614        38,572        47,409        26,496   

Residuals

     14,493        11,786        14,526        7,414   

LPG and other

     19,515        20,853        21,929        12,515   

Unit margins per barrel:

        

United States refining 1 – discontinued operations

   $ 4.82        0.23        3.45        (0.68

United Kingdom refining and marketing

     (1.66     (1.84     (1.37     (1.75

United States retail marketing:

        

Fuel margin per gallon 2

   $ 0.200        0.137        0.165        0.128   

Gallons sold per store month

     279,997        313,140        278,442        307,276   

Merchandise sales revenue per store month

   $ 164,953        161,352        158,385        152,875   

Merchandise margin as a percentage of merchandise sales

     13.1     13.5     13.2     13.0

Store count at end of period (Company operated)

     1,120        1,083        1,120        1,083   

 

1 

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

2 

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

 

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

 

Results of Operations (Contd.)

Corporate

Corporate activities, which include interest income and expense, foreign exchange effects, and corporate overhead not allocated to operating functions, had after-tax benefits of $4.9 million in the 2011 third quarter compared to after-tax costs of $34.5 million in the third quarter of 2010. The 2011 results of corporate activities were favorable to 2010 primarily due to net after-tax benefits of $28.3 million on transactions denominated in foreign currencies in the current quarter compared to net after-tax costs of $15.8 million in the comparable 2010 period. The current period foreign currency benefit was primarily attributable to a weakening of the Malaysian ringgit against the U.S. dollar, which led to a reduction of income tax liabilities that are to be paid in the local currency. Partially offsetting the favorable effects of foreign currencies, Corporate activities included higher administrative costs, mostly attributable to employee compensation, and higher net interest expense, associated with both higher average borrowings and lower amounts of interest capitalized to oil and natural gas development projects.

For the first nine months of 2011, corporate activities reflected net costs of $40.7 million compared to net costs of $133.5 million a year ago. Nine-month corporate costs in 2011 were significantly favorable to 2010 mostly related to the effects of transactions denominated in foreign currencies. Total after-tax benefits for foreign currency transactions were $32.2 million in the 2011 period compared to net after-tax costs of $58.8 million in the first nine months of 2010. Administrative expense was higher in 2011, primarily associated with increased employee compensation costs.

Discontinued Operations

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.

Income from discontinued operations was $70.4 million in the third quarter 2011, including operating profits of $53.5 million and a net gain on sale of the two U.S. refineries of $16.9 million. The after-tax gain from disposal of the two refineries included 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. Operating profits in 2011 of $53.5 million bested the 2010 profits of $5.4 million due to much stronger refining margins in the 2011 quarter.

Income from discontinued operations associated with the two U.S. refineries sold near the end of the third quarter 2011 was a profit of $132.4 million in the nine months of 2011 compared to a loss of $6.1 million in the 2010 period. The 2011 profit included a $16.9 million net gain on sale of the U.S. refineries, including associated marketing assets and inventories. The improvement in 2011 results was primarily due to significantly improved refining margins, higher crude oil throughputs at the refineries in the 2011 period, and the aforementioned gain on disposal.

 

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

 

Financial Condition

Net cash provided by operating activities was $1,876.7 million for the first nine months of 2011 compared to $2,200.9 million during the same period in 2010. Cash provided by operating activities of discontinued operations amounted to $163.5 million and $52.0 million, respectively, in the 2011 and 2010 periods. Changes in operating working capital other than cash and cash equivalents used cash of $309.4 million in the first nine months of 2011, but provided cash of $417.2 million in the first nine months of 2010. Cash was used for working capital in 2011 primarily due to an increase in accounts receivable caused by higher sales prices and cash paid for income taxes, which were only partially offset by an increase in accounts payable balances. Cash generated from working capital changes in the 2010 period included a $244.4 million recovery of U.S. federal royalties paid in prior years on oil and natural gas production in the Gulf of Mexico. Cash of $1,356.2 million in the 2011 period and $2,011.4 million in 2010 was generated from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition. The sale of gas storage assets in Spain in the 2011 nine-month period generated cash proceeds of $27.4 million. The sale of the Superior, Wisconsin refinery on September 30, 2011 provided cash proceeds of $403.8 million, including inventory sales. Cash associated with the sale of the Meraux, Louisiana refinery on October 1, 2011 was collected in the fourth quarter.

Significant uses of cash in both years were for dividends, which totaled $159.5 million in 2011 and $148.4 million in 2010, and for property additions and dry holes, which including amounts expensed, were $1,853.9 million and $1,532.5 million in the nine-month periods ended September 30, 2011 and 2010, respectively. Cash used for property additions related to discontinued operations totaled $48.1 million and $79.2 million, respectively in 2011 and 2010. Also, the purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $1,233.3 million in the 2011 period and $1,862.6 million in the 2010 period. Total accrual basis capital expenditures were as follows:

 

     Nine Months Ended
September 30,
 

(Millions of dollars)

   2011      2010  

Capital Expenditures

     

Exploration and production

   $ 1,899.3         1,460.7   

Refining and marketing, including discontinued operations

     132.1         294.9   

Corporate and other

     4.4        4.5   
  

 

 

    

 

 

 

Total capital expenditures, including discontinued operations

     2,035.8         1,760.1   
  

 

 

    

 

 

 

A reconciliation of property additions and dry hole costs in the consolidated statements of cash flows to total capital expenditures follows.

 

     Nine Months Ended
September 30,
 

(Millions of dollars)

   2011      2010  

Property additions and dry hole costs per cash flow statements, including discontinued operations

   $ 1,902.0         1,611.7   

Geophysical and other exploration expenses

     95.4         69.7   

Capital expenditure accrual changes, including discontinued operations

     38.4         78.7   
  

 

 

    

 

 

 

Total capital expenditures, including discontinued operations

     2,035.8         1,760.1   
  

 

 

    

 

 

 

Working capital (total current assets less total current liabilities) at September 30, 2011 was $996.8 million, an increase of $377.0 million from December 31, 2010. This level of working capital does not fully reflect the Company’s liquidity position because the lower historical costs assigned to inventories under last-in first-out accounting were $824.5 million below fair value at September 30, 2011.

At September 30, 2011, long-term notes payable of $974.5 million had increased by $35.1 million compared to December 31, 2010. During 2011, the Company’s $350 million notes maturing in May 2012 were reclassified to a current liability. In October 2011, the Company repaid $725 million of long-term debt outstanding at September 30, 2011, primarily with proceeds from sale of the Meraux, Louisiana and Superior, Wisconsin refineries. A summary of capital employed at September 30, 2011 and December 31, 2010 follows.

 

     Sept. 30, 2011      Dec. 31, 2010  

(Millions of dollars)

   Amount      %      Amount