e10vq
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 2006
OR
     
o   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 1-5153
Marathon Oil Corporation
(Exact name of registrant as specified in its charter)
     
Delaware   25-0996816
(State of Incorporation)   (I.R.S. Employer Identification No.)
5555 San Felipe Road, Houston, TX 77056-2723
(Address of principal executive offices)
(713) 629-6600
(Registrant’s telephone number)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ  No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ       Accelerated filer o       Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o  No þ
There were 358,165,724 shares of Marathon Oil Corporation common stock outstanding as of July 31, 2006.
 
 

 


 

MARATHON OIL CORPORATION
Form 10-Q
Quarter Ended June 30, 2006
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Supplemental Statistics
    34  
 
       
       
 
       
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 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
 Computation of Ratio of Earnings to Fixed Charges
 Certification Pursuant to Rule 13(a)-14 and 15(d)-14
 Certification Pursuant to Rule 13(a)-14 and 15d-14
 Certification Pursuant to 18 U.S.C. Section 1350
 Certification Pursuant to 18 U.S.C. Section 1350
Unless the context otherwise indicates, references in this Form 10-Q to “Marathon,” “we,” “our,” or “us” are references to Marathon Oil Corporation, including its wholly-owned and majority-owned subsidiaries, and its ownership interests in equity method investees (corporate entities, partnerships, limited liability companies and other ventures over which Marathon exerts significant influence by virtue of its ownership interest, typically between 20 and 50 percent). Effective September 1, 2005, Marathon Ashland Petroleum LLC changed its name to Marathon Petroleum Company LLC. In this Form 10-Q, references to Marathon Petroleum Company LLC (“MPC”) are references to the entity formerly known as Marathon Ashland Petroleum LLC.

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Part I — Financial Information
Item 1. Financial Statements
MARATHON OIL CORPORATION
Consolidated Statements of Income (Unaudited)
                                 
    Second Quarter Ended     Six Months Ended  
    June 30,     June 30,  
(Dollars in millions, except per share data)   2006     2005     2006     2005  
Revenues and other income:
                               
 
                               
Sales and other operating revenues (including consumer excise taxes)
  $ 15,962     $ 12,009     $ 28,862     $ 21,796  
Revenues from matching buy/sell transactions
    1,806       3,565       5,012       6,374  
Sales to related parties
    411       368       723       651  
Income from equity method investments
    97       45       189       84  
Net gains on disposal of assets
    5       23       16       34  
Other income
    9       14       27       40  
 
                       
Total revenues and other income
    18,290       16,024       34,829       28,979  
Costs and expenses:
                               
 
                               
Cost of revenues (excludes items below)
    11,628       9,255       21,387       16,936  
Purchases related to matching buy/sell transactions
    1,750       3,442       4,983       6,274  
Purchases from related parties
    47       63       98       119  
Consumer excise taxes
    1,277       1,210       2,442       2,294  
Depreciation, depletion and amortization
    369       321       769       631  
Selling, general and administrative expenses
    308       268       595       527  
Other taxes
    91       78       188       157  
Exploration expenses
    66       36       137       66  
 
                       
Total costs and expenses
    15,536       14,673       30,599       27,004  
Income from operations
    2,754       1,351       4,230       1,975  
 
                               
Net interest and other financing costs (income)
    (9 )     35       14       68  
Minority interests in income (loss) of:
                               
Marathon Petroleum Company LLC
          314             384  
Equatorial Guinea LNG Holdings Limited
    (2 )           (5 )     (1 )
 
                       
Income from continuing operations before income taxes
    2,765       1,002       4,221       1,524  
 
                               
Provision for income taxes
    1,281       334       1,966       533  
 
                       
 
                               
Income from continuing operations
    1,484       668       2,255       991  
 
Discontinued operations
    264       5       277       6  
 
                       
 
Net income
  $ 1,748     $ 673     $ 2,532     $ 997  
 
                       
 
Per Share Data
                               
 
                               
Basic:
                               
Income from continuing operations
  $ 4.11     $ 1.93     $ 6.21     $ 2.86  
Discontinued operations
  $ 0.73     $ 0.01     $ 0.76     $ 0.02  
Net income
  $ 4.84     $ 1.94     $ 6.97     $ 2.88  
Diluted:
                               
Income from continuing operations
  $ 4.07     $ 1.91     $ 6.16     $ 2.84  
Discontinued operations
  $ 0.73     $ 0.01     $ 0.75     $ 0.02  
Net income
  $ 4.80     $ 1.92     $ 6.91     $ 2.86  
Dividends paid
  $ 0.40     $ 0.28     $ 0.73     $ 0.56  
 
                       
The accompanying notes are an integral part of these consolidated financial statements.

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MARATHON OIL CORPORATION
Consolidated Balance Sheets (Unaudited)
                 
    June 30,     December 31,  
(Dollars in millions, except per share data)   2006     2005  
Assets
               
 
               
Current assets:
               
Cash and cash equivalents
  $ 3,026     $ 2,617  
Receivables, less allowance for doubtful accounts of $3 and $3
    4,210       3,476  
Receivables from United States Steel
    21       20  
Receivables from related parties
    58       38  
Inventories
    3,817       3,041  
Other current assets
    173       191  
 
           
Total current assets
    11,305       9,383  
 
               
Investments and long-term receivables, less allowance for doubtful accounts of $9 and $10
    1,882       1,864  
Receivables from United States Steel
    510       532  
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $12,902 and $12,384
    15,110       15,011  
Goodwill
    1,286       1,307  
Intangible assets, less accumulated amortization of $65 and $58
    192       200  
Other noncurrent assets
    165       201  
 
           
Total assets
  $ 30,450     $ 28,498  
 
           
Liabilities
               
 
Current liabilities:
               
Accounts payable
  $ 6,140     $ 5,353  
Consideration payable under Libya re-entry agreement
    212       732  
Payables to related parties
    166       82  
Payroll and benefits payable
    263       344  
Accrued taxes
    1,012       782  
Deferred income taxes
    438       450  
Accrued interest
    89       96  
Long-term debt due within one year
    456       315  
 
           
Total current liabilities
    8,776       8,154  
 
               
Long-term debt
    3,224       3,698  
Deferred income taxes
    2,114       2,030  
Employee benefits obligations
    1,263       1,321  
Asset retirement obligations
    754       711  
Payable to United States Steel
    5       6  
Deferred credits and other liabilities
    346       438  
 
           
Total liabilities
    16,482       16,358  
 
               
Minority interests in Equatorial Guinea LNG Holdings Limited
    479       435  
Commitments and contingencies
               
 
Stockholders’ Equity
               
 
Common stock issued — 367,677,611 and 366,925,852 shares (par value $1 per share, 550,000,000 shares authorized)
    368       367  
Common stock held in treasury, at cost — 7,600,887 and 179,977 shares
    (569 )     (8 )
Additional paid-in capital
    5,150       5,111  
Retained earnings
    8,672       6,406  
Accumulated other comprehensive loss
    (132 )     (151 )
Unearned compensation
          (20 )
 
           
Total stockholders’ equity
    13,489       11,705  
 
           
Total liabilities and stockholders’ equity
  $ 30,450     $ 28,498  
 
           
The accompanying notes are an integral part of these consolidated financial statements.

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MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows (Unaudited)
                 
    Six Months Ended June 30,  
(Dollars in millions)   2006     2005  
Increase (decrease) in cash and cash equivalents
               
 
               
Operating activities:
               
 
               
Net income
  $ 2,532     $ 997  
 
               
Adjustments to reconcile to net cash provided from operating activities:
               
Income from discontinued operations
    (277 )     (6 )
Deferred income taxes
    134       (33 )
Minority interests in income (loss) of subsidiaries
    (5 )     383  
Depreciation, depletion and amortization
    769       631  
Pension and other postretirement benefits, net
    (41 )     33  
Exploratory dry well costs and unproved property impairments
    69       25  
Net gains on disposal of assets
    (16 )     (34 )
Equity method investments, net
    (141 )     (25 )
Changes in the fair value of long-term U.K. natural gas contracts
    (61 )     224  
Changes in:
               
Current receivables
    (833 )     (357 )
Inventories
    (777 )     (643 )
Current accounts payable and accrued expenses
    916       269  
All other, net
    (39 )     5  
 
           
Net cash provided from continuing operations
    2,230       1,469  
Net cash provided from discontinued operations
    69       51  
 
           
Net cash provided from operating activities
    2,299       1,520  
 
           
Investing activities:
               
 
               
Capital expenditures
    (1,308 )     (1,179 )
Acquisitions
    (543 )     (497 )
Disposal of assets
    49       63  
Disposal of discontinued operations
    832        
Investments - loans and advances
    (2 )     (36 )
- repayments of loans and advances
    146       5  
Investing activities of discontinued operations
    (45 )     (47 )
All other, net
    14       (16 )
 
           
Net cash used in investing activities
    (857 )     (1,707 )
Financing activities:
               
 
               
Commercial paper issued
          590  
Debt repayments
    (303 )     (4 )
Issuance of common stock
    19       61  
Purchases of common stock
    (554 )      
Excess tax benefits from stock-based compensation arrangements
    14        
Dividends paid
    (265 )     (194 )
Distributions to minority shareholder of Marathon Petroleum Company LLC
          (272 )
Contributions from minority shareholders of Equatorial Guinea LNG Holdings Limited
    41       112  
 
           
Net cash provided from (used in) financing activities
    (1,048 )     293  
 
           
Effect of exchange rate changes on cash:
               
 
               
Continuing operations
    14       (13 )
Discontinued operations
    1        
 
           
 
Net increase in cash and cash equivalents
    409       93  
 
Cash and cash equivalents at beginning of period
    2,617       3,369  
 
           
 
Cash and cash equivalents at end of period
  $ 3,026     $ 3,462  
 
           
The accompanying notes are an integral part of these consolidated financial statements.

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MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
1.   Basis of Presentation
 
    These consolidated financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary for a fair presentation of the results for the periods reported. All such adjustments are of a normal recurring nature unless disclosed otherwise. These consolidated financial statements, including selected notes, have been prepared in accordance with the applicable rules of the Securities and Exchange Commission and do not include all of the information and disclosures required by accounting principles generally accepted in the United States of America for complete financial statements. Certain reclassifications of prior year data have been made to conform to 2006 classifications. These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the 2005 Annual Report on Form 10-K of Marathon Oil Corporation (“Marathon” or the “Company”).
 
2.   New Accounting Standards
 
    EITF Issue No. 04-13
 
    In September 2005, the Financial Accounting Standards Board (“FASB”) ratified the consensus reached by the Emerging Issues Task Force (“EITF”) on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The consensus establishes the circumstances under which two or more inventory purchase and sale transactions with the same counterparty should be recognized at fair value or viewed as a single exchange transaction subject to Accounting Principles Board (“APB”) Opinion No. 29, “Accounting for Nonmonetary Transactions.” In general, two or more transactions with the same counterparty must be combined for purposes of applying APB Opinion No. 29 if they are entered into in contemplation of each other. The purchase and sale transactions may be pursuant to a single contractual arrangement or separate contractual arrangements and the inventory purchased or sold may be in the form of raw materials, work-in-process or finished goods.
 
    Effective April 1, 2006, Marathon adopted the provisions of EITF Issue No. 04-13 prospectively. EITF Issue No. 04-13 changes the accounting for matching buy/sell arrangements that are entered into or modified on or after April 1, 2006 (except for those accounted for as derivative instruments, which are discussed below). In a typical matching buy/sell transaction, Marathon enters into a contract to sell a particular quantity and quality of crude oil or refined petroleum products at a specified location and date to a particular counterparty and simultaneously agrees to buy a particular quantity and quality of the same commodity at a specified location on the same or another specified date from the same counterparty. Prior to adoption of EITF Issue No. 04-13, Marathon recorded such matching buy/sell transactions in both revenues and cost of revenues as separate sale and purchase transactions. Upon adoption, these transactions are accounted for as exchanges of inventory.
 
    The scope of EITF Issue No. 04-13 excludes matching buy/sell arrangements that are accounted for as derivative instruments. A portion of Marathon’s matching buy/sell transactions are “nontraditional derivative instruments,” which are contracts involving the purchase or sale of commodities that either do not qualify or have not been designated as normal purchases or normal sales and therefore are required to be accounted for as derivative instruments. Although the accounting for nontraditional derivative instruments is outside the scope of EITF Issue No. 04-13, the conclusions reached in that consensus caused Marathon to reconsider the guidance in EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as Defined in Issue No. 02-3.” As a result, effective for contracts entered into or modified on or after April 1, 2006, the income effects of matching buy/sell arrangements accounted for as nontraditional derivative instruments are recognized on a net basis as cost of revenues. Prior to this change, Marathon recorded these transactions in both revenues and cost of revenues as separate sale and purchase transactions. This change in accounting principle is being applied on a prospective basis because it is impracticable to apply the change on a retrospective basis.
 
    Transactions arising from all matching buy/sell arrangements entered into before April 1, 2006 will continue to be reported as separate sale and purchase transactions.
 
    The adoption of EITF Issue No. 04-13 and the change in the accounting for nontraditional derivative instruments had no effect on net income. The amounts of revenues and cost of revenues recognized in the second quarter of 2006 and subsequent periods will be less than the amounts that would have been recognized under previous accounting practices.

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    SFAS No. 123 (Revised 2004)
 
    In December 2004, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 123 (Revised 2004), “Share-Based Payment,” (“SFAS No. 123(R)”) as a revision of SFAS No. 123, “Accounting for Stock-Based Compensation.” This statement requires entities to measure the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the grant date. That cost is recognized over the period during which an employee is required to provide service in exchange for the award, usually the vesting period. In addition, awards classified as liabilities are remeasured at fair value each reporting period. Marathon had previously adopted the fair value method under SFAS No. 123 for grants made, modified or settled on or after January 1, 2003.
 
    Marathon adopted SFAS No. 123(R) as of January 1, 2006, for all awards granted, modified or cancelled after adoption, and for the unvested portion of awards outstanding at January 1, 2006. At the date of adoption, SFAS No. 123(R) requires that an assumed forfeiture rate be applied to any unvested awards and that awards classified as liabilities be measured at fair value. Prior to adopting SFAS No. 123(R), Marathon recognized forfeitures as they occurred and applied the intrinsic value method to awards classified as liabilities. The adoption did not have a significant effect on Marathon’s consolidated results of operations, financial position or cash flows.
 
    SFAS No. 123(R) also requires a company to calculate the pool of excess tax benefits available to absorb tax deficiencies recognized subsequent to adopting the statement. In November 2005, the FASB issued FASB Staff Position No. 123R-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards,” to provide an alternative transition election (the “short-cut method”) to account for the tax effects of share-based payment awards to employees. Marathon elected the long-form method to determine its pool of excess tax benefits as of January 1, 2006.
 
    See Note 3 to the consolidated financial statements for the disclosures regarding share-based payments required by SFAS No. 123(R).
 
    SFAS No. 151
 
    Effective January 1, 2006, Marathon adopted SFAS No. 151, “Inventory Costs — an amendment of ARB No. 43, Chapter 4.” This statement requires that items such as idle facility expense, excessive spoilage, double freight and re-handling costs be recognized as a current-period charge. The adoption did not have a significant effect on Marathon’s consolidated results of operations, financial position or cash flows.
 
    SFAS No. 154
 
    Effective January 1, 2006, Marathon adopted SFAS No. 154, “Accounting Changes and Error Corrections — A Replacement of APB Opinion No. 20 and FASB Statement No. 3.” SFAS No. 154 requires companies to recognize (1) voluntary changes in accounting principle and (2) changes required by a new accounting pronouncement, when the pronouncement does not include specific transition provisions, retrospectively to prior periods’ financial statements, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change.
 
3.   Stock-Based Compensation Arrangements
 
    Description of the Plans
 
    The Marathon Oil Corporation 2003 Incentive Compensation Plan (the “Plan”) authorizes the Compensation Committee of the Board of Directors to grant stock options, stock appreciation rights, stock awards, cash awards and performance awards to employees. The Plan also allows Marathon to provide equity compensation to its non-employee directors. No more than 20,000,000 shares of common stock may be issued under the Plan, and no more than 8,500,000 of those shares may be used for awards other than stock options or stock appreciation rights. Shares subject to awards that are forfeited, terminated, settled in cash, exchanged for other awards, tendered to satisfy the purchase price of an award or withheld to satisfy tax obligations or that expire unexercised or otherwise lapse become available for future grants. Shares issued as a result of awards granted under the Plan are generally funded out of common stock held in treasury, except to the extent there are insufficient treasury shares, in which case new common shares are issued.
 
    The Plan replaced the 1990 Stock Plan, the Non-Officer Restricted Stock Plan, the Non-Employee Director Stock Plan, the deferred stock benefit provision of the Deferred Compensation Plan for Non-Employee Directors, the Senior Executive Officer Annual Incentive Compensation Plan and the Annual Incentive Compensation Plan (collectively, the “Prior Plans”). No new grants will be made from the Prior Plans. Any awards previously granted under the Prior Plans shall continue to vest and/or be exercisable in accordance with their original terms and conditions.

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    Stock-Based Awards Under the Plan
 
    Stock options — Marathon grants stock options under the Plan. Marathon’s stock options represent the right to purchase shares of common stock at the fair market value of the common stock on the date of grant. Through 2004, certain options were granted with a tandem stock appreciation right, which allows the recipient to instead elect to receive cash and/or common stock equal to the excess of the fair market value of shares of common stock, as determined in accordance with the Plan, over the option price of the shares. Most stock options granted under the Plan vest ratably over a three-year period and have a maximum term of ten years from the date they are granted.
 
    Stock appreciation rights (“SARs”) — Prior to 2005, Marathon granted SARs under the Plan. Similar to stock options, stock appreciation rights represent the right to receive a payment equal to the excess of the fair market value of shares of common stock on the date the right is exercised over the grant price. Certain SARs were granted as stock-settled SARs and others were granted in tandem with stock options. In general, SARs that have been granted under the Plan vest ratably over a three-year period and have a maximum term of ten years from the date they are granted.
 
    Stock-based performance awards — In 2003 and 2004, the Compensation Committee granted stock-based performance awards to certain officers of Marathon and its consolidated subsidiaries under the Plan. Since that time, stock-based performance awards are no longer issued; however cash-settled performance units have been granted to the officers. The stock-based performance awards represent shares of common stock that are subject to forfeiture provisions and restrictions on transfer. Those restrictions may be removed if certain pre-established performance measures are met. The stock-based performance awards granted under the Plan will generally vest at the end of a 36-month performance period to the extent that the performance targets are achieved and the recipient is employed by Marathon on that date. Additional shares could be granted at the end of this performance period should performance exceed the targets. Prior to vesting, the recipients have the right to vote and receive dividends on the target number of shares awarded. However, the shares are not transferable until after they vest.
 
    Restricted stock — Marathon grants restricted stock and restricted stock units under the Plan. Beginning in 2005, the Compensation Committee granted time-based restricted stock to officers. The restricted stock awards to officers vest three years from the date of grant, contingent on the recipient’s continued employment. Marathon also grants restricted stock to certain non-officer employees and restricted stock units to certain international non-officer employees (together with the restricted stock granted to officers above, “restricted stock awards”) based on their performance within certain guidelines and for retention purposes. The restricted stock awards to non-officers generally vest in one-third increments over a three-year period, contingent on the recipient’s continued employment. Prior to vesting, all restricted stock recipients have the right to vote such stock and receive dividends thereon. The nonvested shares are not transferable and are held by the Company’s transfer agent.
 
    Common stock units — Marathon maintains an equity compensation program for its non-employee directors under the Plan. All non-employee directors other than the Chairman receive annual grants of common stock units under the Plan and they are required to hold those units until they leave the Board of Directors. When dividends are paid on Marathon’s common stock, directors receive dividend equivalents in the form of additional common stock units. Prior to January 1, 2006, non-employee directors had the opportunity to receive a matching grant of up to 1,000 shares of common stock if they purchased an equivalent number of shares within 60 days of joining the Board.
 
    Stock-Based Compensation Expense
 
    The fair values of stock options, stock options with tandem SARs and stock-settled SARs (“stock option awards”) are estimated on the date of grant using the Black-Scholes option pricing model. The model employs various assumptions, based on management’s best estimates at the time of grant, which impact the fair value calculated and ultimately, the expense that is recognized over the life of the stock option award. Of the required assumptions, the expected life of the stock option award and the expected volatility of Marathon’s stock price have the most significant impact on the fair value calculation. Marathon has utilized historical data and analyzed current information which reasonably support these assumptions.
 
    The fair values of Marathon’s restricted stock awards and common stock units are determined based on the fair market value of the Company’s common stock on the date of grant. Prior to adoption of SFAS No. 123(R) on January 1, 2006, the fair values of Marathon’s stock-based performance awards were determined in the same manner as restricted stock awards. Under SFAS No. 123(R), on a prospective basis, these awards are required to be valued utilizing an option pricing model. No stock-based performance awards have been granted since May 2004.
 
    Effective January 1, 2006, Marathon’s stock-based compensation expense is recognized based on management’s best estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based

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    awards with a graded vesting feature. If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods. Unearned stock-based compensation is charged to stockholders’ equity when restricted stock awards and stock-based performance awards are granted. Compensation expense is recognized over the balance of the vesting period and is adjusted if conditions of the restricted stock award or stock-based performance award are not met. Options with tandem SARs are classified as a liability and are remeasured at fair value each reporting period until settlement.
 
    Prior to January 1, 2006, Marathon recorded stock-based compensation expense over the stated vesting period for stock option awards that are subject to specific vesting conditions and specify (1) that an employee vests in the award upon becoming “retirement eligible” or (2) that the employee will continue to vest in the award after retirement without providing any additional service. Under SFAS No. 123(R), from the January 1, 2006 date of adoption, such compensation cost is recognized immediately for awards granted to retirement-eligible employees or over the period from the grant date to the retirement eligibility date if retirement eligibility will be reached during the stated vesting period. Stock compensation expense for the first half of 2006 included $3 million for such option awards.
 
    During the quarters ended June 30, 2006 and 2005, total employee stock-based compensation expense was $27 million and $20 million. The total related income tax benefits were $10 million and $7 million. During the second quarter of 2006, cash received upon exercise of stock option awards was $11 million. Tax benefits realized for deductions during the second quarter of 2006 that were in excess of the stock-based compensation expense recorded for options exercised and other stock-based awards vested during the quarter totaled $4 million.
 
    During the six months ended June 30, 2006 and 2005, total employee stock-based compensation expense was $50 million and $63 million. The total related income tax benefits were $19 million and $22 million. In the first six months of 2006, cash received upon exercise of stock option awards was $19 million. Tax benefits realized for deductions during the six months ended June 30, 2006 that were in excess of the stock-based compensation expense recorded for options exercised and other stock-based awards vested during the first six months of 2006 totaled $14 million. Cash settlements of stock option awards totaled less than $1 million during the quarter and six months ended June 30, 2006.
 
    Stock Option Awards Granted
 
    During the six months ended June 30, 2006 and 2005, Marathon granted stock option awards to both officer and non-officer employees. The weighted average grant date fair values of these awards were based on the following Black-Scholes assumptions:
                 
    Six Months Ended June 30,
    2006   2005
 
Weighted average exercise price per share
  $ 75.68     $ 50.28  
Expected annual dividends per share
  $ 1.60     $ 1.32  
Expected life in years
    5.0       5.5  
Expected volatility
    28 %     28 %
Risk-free interest rate
    5.0 %     3.8 %
Weighted average grant date fair value of stock option awards granted
  $ 20.37     $ 12.30  
    Outstanding Stock-Based Awards
 
    The following is a summary of stock option award activity for the six months ended June 30, 2006:
                 
            Weighted-
    Number   Average
    of Shares   Exercise Price
 
Outstanding at December 31, 2005
    6,007,954     $ 36.51  
Granted
    1,601,800     $ 75.68  
Exercised
    (733,295 )   $ 24.70  
Canceled
    (47,909 )   $ 45.57  
 
               
Outstanding at June 30, 2006 (a)
    6,828,550     $ 46.12  
 
               
 
(a)   Of the stock option awards outstanding as of June 30, 2006, 6,004,739 and 823,811 were outstanding under the 2003 Incentive Compensation Plan and 1990 Stock Plan, including 841,502 stock options with tandem SARs.
    The intrinsic value of stock option awards exercised during the six months ended June 30, 2006 and 2005 was $34 million and $51 million. Of those amounts, $10 million in the six months ended June 30, 2006, and $27 million in the six months ended June 30, 2005, was related to stock options with tandem SARs.

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    The following table presents information on stock option awards at June 30, 2006:
                                         
    Outstanding   Exercisable
            Weighted-            
    Number   Average   Weighted-   Number   Weighted-
Range of Exercise   of Shares   Remaining   Average   of Shares   Average
        Prices   Under Option   Contractual Life   Exercise Price   Under Option   Exercise Price
 
$25.50 - 26.91
    1,039,680       7     $ 25.52       1,033,014     $ 25.51  
$28.12 - 30.88
    480,134       5     $ 28.37       475,134     $ 28.35  
$32.52 - 34.00
    1,947,952       7     $ 33.49       1,295,408     $ 33.43  
$47.65 - 51.67
    1,758,984       9     $ 50.22       548,196     $ 50.08  
$75.64 - 81.02
    1,601,800       10     $ 75.68              
 
                                       
Total
    6,828,550       8     $ 46.12       3,351,752     $ 32.99  
 
                                       
    As of June 30, 2006, the aggregate intrinsic value of stock option awards outstanding was $254 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option awards currently exercisable were $169 million and 7 years. As of June 30, 2006, the number of fully-vested stock option awards and stock option awards expected to vest was 6,388,997. The weighted average exercise price and weighted average remaining contractual life of these stock option awards were $45.16 and 8 years and the aggregate intrinsic value was $244 million. As of June 30, 2006, unrecognized compensation cost related to stock option awards was $40 million, which is expected to be recognized over a weighted average period of 2 years.
 
    The following is a summary of stock-based performance award and restricted stock award activity for the six months ended June 30, 2006:
                                 
    Stock-Based   Weighted           Weighted
    Performance   Average Grant   Restricted   Average Grant
    Awards   Date Fair Value   Stock Awards   Date Fair Value
 
Unvested at December 31, 2005
    448,600     $ 29.93       985,556     $ 47.94  
Granted (a)
    67,848     $ 76.82       123,160     $ 77.31  
Vested
    (273,448 )   $ 38.30       (178,176 )   $ 39.49  
Forfeited
    (6,000 )   $ 33.61       (25,656 )   $ 51.58  
 
                               
Unvested at June 30, 2006
    237,000     $ 33.61       904,884     $ 53.54  
 
                               
 
(a)   Additional shares were issued in 2006 because the performance targets were exceeded for the performance period related to the 2003 grant.
    During the six months ended June 30, 2006 and 2005, the weighted average grant date fair value of restricted stock awards was $77.31 and $47.25. The vesting date fair value of stock-based performance awards which vested during the six months ended June 30, 2006 and 2005 was $21 million and $5 million. The vesting date fair value of restricted stock awards which vested during the six months ended June 30, 2006 and 2005 was $14 million and $8 million.
 
    As of June 30, 2006, there was $33 million of unrecognized compensation cost related to restricted stock awards which is expected to be recognized over a weighted average period of 2 years.
 
4.   Discontinued Operations
 
    On June 2, 2006, Marathon sold its Russian oil exploration and production businesses in the Khanty-Mansiysk region of western Siberia. Under the terms of the agreement, Marathon received $787 million for these businesses, plus preliminary working capital and other closing adjustments of $56 million, for a total transaction value of $843 million. Proceeds net of transaction costs and cash held by the Russian businesses at the transaction date totaled $832 million. A gain on the sale of $243 million ($342 million before income taxes) is reported in discontinued operations for the quarter and six months ended June 30, 2006. Income taxes on this gain were reduced by the utilization of a capital loss carryforward as discussed in Note 8 to the consolidated financial statements. Exploration and Production segment goodwill of $21 million was allocated to the Russian assets and reduced the reported gain. The final adjustment to the purchase price is expected to be made before December 31, 2006 and could affect the reported gain. The activities of the Russian businesses have been reported as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for all periods presented. Revenues applicable to discontinued operations totaled $74 million and $77 million for the second quarters of 2006 and 2005, and $173 million and $130 million for the six months ended June 30, 2006 and 2005. Pretax income from discontinued operations totaled $24 million and $6 million for the second quarters of 2006 and 2005, and $45 million and $7 million for the six months ended June 30, 2006 and 2005.

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5.   Computation of Income per Share
 
    Basic income per share is based on the weighted average number of common shares outstanding. Diluted income per share assumes exercise of stock options, provided the effect is not antidilutive.
                                 
    Second Quarter Ended June 30,  
    2006     2005  
(Dollars in millions, except per share data)   Basic     Diluted     Basic     Diluted  
Income from continuing operations
  $ 1,484     $ 1,484     $ 668     $ 668  
Discontinued operations
    264       264       5       5  
 
                       
Net income
  $ 1,748     $ 1,748     $ 673     $ 673  
 
                       
Shares of common stock outstanding (thousands):
                               
Average number of common shares outstanding
    360,860       360,860       347,075       347,075  
Effect of dilutive securities
          3,300             2,843  
 
                       
Average common shares including dilutive effect
    360,860       364,160       347,075       349,918  
 
                       
Per share:
                               
Income from continuing operations
  $ 4.11     $ 4.07     $ 1.93     $ 1.91  
Discontinued operations
  $ 0.73     $ 0.73     $ 0.01     $ 0.01  
Net income
  $ 4.84     $ 4.80     $ 1.94     $ 1.92  
 
                       
                                 
    Six Months Ended June 30,  
    2006     2005  
(Dollars in millions, except per share data)   Basic     Diluted     Basic     Diluted  
Income from continuing operations
  $ 2,255     $ 2,255     $ 991     $ 991  
Discontinued operations
    277       277       6       6  
 
                       
Net income
  $ 2,532     $ 2,532     $ 997     $ 997  
 
                       
Shares of common stock outstanding (thousands):
                               
Average number of common shares outstanding
    362,973       362,973       346,541       346,541  
Effect of dilutive securities
          3,325             2,687  
 
                       
Average common shares including dilutive effect
    362,973       366,298       346,541       349,228  
 
                       
Per share:
                               
Income from continuing operations
  $ 6.21     $ 6.16     $ 2.86     $ 2.84  
Discontinued operations
  $ 0.76     $ 0.75     $ 0.02     $ 0.02  
Net income
  $ 6.97     $ 6.91     $ 2.88     $ 2.86  
 
                       
    The per share calculations above exclude 1.6 million stock options for the second quarter and six months ended June 30, 2006, and 1.9 million stock options for the second quarter and six months ended June 30, 2005, as they were antidilutive.
6.   Segment Information
    Marathon’s operations consist of three reportable operating segments:
  1)   Exploration and Production (“E&P”) — explores for, produces and markets crude oil and natural gas on a worldwide basis;
 
  2)   Refining, Marketing and Transportation (“RM&T”) — refines, markets and transports crude oil and petroleum products, primarily in the Midwest, the upper Great Plains and southeastern United States; and
 
  3)   Integrated Gas (“IG”) — markets and transports products manufactured from natural gas, such as liquefied natural gas (“LNG”) and methanol, on a worldwide basis, and is developing other projects to link stranded natural gas resources with key demand areas.
    Effective January 1, 2006, Marathon revised its measure of segment income to include the effects of minority interests and income taxes related to the segments to facilitate comparison of segment results with Marathon’s peers. Income taxes were allocated to the segments using estimated effective rates for each segment. In addition, the results of activities primarily associated with the marketing of the Company’s equity natural gas production,

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    which had been presented as part of the Integrated Gas segment prior to 2006, are now included in the Exploration and Production segment as those activities are aligned with E&P operations. Segment information for all periods presented reflects these changes.
    As discussed in Note 4, the Russian businesses that were sold in June 2006 have been accounted for as discontinued operations. Segment information for all presented periods excludes the amounts for these Russian operations.
                                 
                            Total  
(Dollars in millions)   E&P     RM&T     IG     Segments  
Second Quarter Ended June 30, 2006
                               
Revenues:
                               
Customer
  $ 2,325     $ 15,390     $ 70     $ 17,785  
Intersegment (a)
    187       2             189  
Related parties
    3       408             411  
 
                       
Segment revenues
    2,515       15,800       70       18,385  
Elimination of intersegment revenues
    (187 )     (2 )           (189 )
Loss on long-term U.K. natural gas contracts
    (17 )                 (17 )
 
                       
Total revenues
  $ 2,311     $ 15,798     $ 70     $ 18,179  
 
                       
Segment income
  $ 659     $ 917     $ 17     $ 1,593  
Income from equity method investments
    53       32       12       97  
Depreciation, depletion and amortization (b)
    221       137       2       360  
Minority interests in income (loss) of subsidiaries (b)
                (2 )     (2 )
Provision for income taxes (b)
    716       564       (1 )     1,279  
Capital expenditures (c)
    463       200       70       733  
 
                       
                                 
                            Total  
(Dollars in millions)   E&P     RM&T     IG     Segments  
Second Quarter Ended June 30, 2005
                               
Revenues:
                               
Customer
  $ 1,820     $ 13,877     $ 44     $ 15,741  
Intersegment (a)
    131       41             172  
Related parties
    3       365             368  
 
                       
Segment revenues
    1,954       14,283       44       16,281  
Elimination of intersegment revenues
    (131 )     (41 )           (172 )
Loss on long-term U.K. natural gas contracts
    (167 )                 (167 )
 
                       
Total revenues
  $ 1,656     $ 14,242     $ 44     $ 15,942  
 
                       
Segment income
  $ 504     $ 316     $     $ 820  
Income from equity method investments
    17       16       12       45  
Depreciation, depletion and amortization (b)
    206       105       2       313  
Minority interests in income of subsidiaries (b)
          309             309  
Provision for income taxes (b)
    272       198       4       474  
Capital expenditures (c)
    296       166       183       645  
 
                       

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                            Total  
(Dollars in millions)   E&P     RM&T     IG     Segments  
Six Months Ended June 30, 2006
                               
Revenues:
                               
Customer
  $ 4,433     $ 29,280     $ 100     $ 33,813  
Intersegment (a)
    377       15             392  
Related parties
    6       717             723  
 
                       
Segment revenues
    4,816       30,012       100       34,928  
Elimination of intersegment revenues
    (377 )     (15 )           (392 )
Gain on long-term U.K. natural gas contracts
    61                   61  
 
                       
Total revenues
  $ 4,500     $ 29,997     $ 100     $ 34,597  
 
                       
Segment income
  $ 1,124     $ 1,236     $ 25     $ 2,385  
Income from equity method investments
    106       58       25       189  
Depreciation, depletion and amortization (b)
    477       270       4       751  
Minority interests in income (loss) of subsidiaries (b)
                (5 )     (5 )
Provision for income taxes (b)
    1,196       768       4       1,968  
Capital expenditures (c)
    821       304       164       1,289  
 
                       
                                 
                            Total  
(Dollars in millions)   E&P     RM&T     IG     Segments  
Six Months Ended June 30, 2005
                               
Revenues:
                               
Customer
  $ 3,339     $ 24,950     $ 105     $ 28,394  
Intersegment (a)
    275       83             358  
Related parties
    5       646             651  
 
                       
Segment revenues
    3,619       25,679       105       29,403  
Elimination of intersegment revenues
    (275 )     (83 )           (358 )
Loss on long-term U.K. natural gas contracts
    (224 )                 (224 )
 
                       
Total revenues
  $ 3,120     $ 25,596     $ 105     $ 28,821  
 
                       
Segment income
  $ 838     $ 390     $ 22     $ 1,250  
Income from equity method investments
    22       33       29       84  
Depreciation, depletion and amortization (b)
    403       209       4       616  
Minority interests in income (loss) of subsidiaries (b)
          376       (1 )     375  
Provision for income taxes (b)
    484       266       (1 )     749  
Capital expenditures (c)
    566       302       308       1,176  
 
                       
 
(a)   Management believes intersegment transactions were conducted under terms comparable to those with unrelated parties.
 
(b)   Differences between segment totals and Marathon totals represent amounts related to corporate administrative activities and other unallocated items and are included in “Items not allocated to segments, net of income taxes” in the reconciliation below.
 
(c)   Differences between segment totals and Marathon totals represent amounts related to corporate administrative activities.
The following reconciles segment income to net income as reported in Marathon’s consolidated statements of income:
                                 
    Second Quarter Ended     Six Months Ended  
    June 30,     June 30,  
(Dollars in millions)   2006     2005     2006     2005  
Segment income
  $ 1,593     $ 820     $ 2,385     $ 1,250  
Items not allocated to segments, net of income taxes:
                               
Gain (loss) on long-term U.K. natural gas contracts
    (10 )     (97 )     35       (130 )
Corporate and other unallocated items
    (99 )     (70 )     (165 )     (144 )
Ohio tax legislation
          15             15  
Discontinued operations
    264       5       277       6  
 
                       
Net income
  $ 1,748     $ 673     $ 2,532     $ 997  
 
                       

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7.   Pensions and Other Postretirement Benefits
 
    The following summarizes the components of net periodic benefit cost:
                                 
    Second Quarter Ended June 30,  
    Pension Benefits     Other Benefits  
(Dollars in millions)   2006     2005     2006     2005  
Service cost
  $ 32     $ 26     $ 6     $ 4  
Interest cost
    31       30       11       9  
Expected return on plan assets
    (29 )     (23 )            
Amortization:
                               
— net transition gain
          (1 )            
— prior service costs (credits)
    1       1       (3 )     (3 )
— actuarial loss
    11       15       2       3  
Multi-employer and other plans
    1       1       2       1  
 
                       
Net periodic benefit cost
  $ 47     $ 49     $ 18     $ 14  
 
                       
                                 
    Six Months Ended June 30,  
    Pension Benefits     Other Benefits  
(Dollars in millions)   2006     2005     2006     2005  
Service cost
  $ 66     $ 57     $ 12     $ 9  
Interest cost
    63       58       21       19  
Expected return on plan assets
    (55 )     (46 )            
Amortization:
                               
— net transition gain
          (2 )            
— prior service costs (credits)
    2       2       (6 )     (6 )
— actuarial loss
    24       30       4       5  
Multi-employer and other plans
    1       1       2       1  
 
                       
Net periodic benefit cost
  $ 101     $ 100     $ 33     $ 28  
 
                       
    During the six months ended June 30, 2006, Marathon made contributions of $156 million to its funded pension plans. Of this amount, $14 million related to foreign pension plans. On July 21, 2006, Marathon made a contribution of $111 million to its U.S. funded pension plans and currently estimates additional contributions of up to $130 million, over the remainder of 2006. However, this contribution estimate may be revised pending analysis of the Pension Protection Act of 2006, which is expected to be signed into law in the third quarter of 2006. Contributions made from the general assets of Marathon to cover current benefit payments related to unfunded pension and other postretirement benefit plans were $3 million and $15 million for the first six months of 2006.
8.   Income Taxes
 
    The provision for income taxes for interim periods is based on management’s best estimate of the effective income tax rate expected to be applicable for the current year plus any adjustments arising from a change in the estimated amount of taxes related to prior periods. The following is an analysis of the effective income tax rates for continuing operations for the periods presented:
                                 
    Second Quarter Ended     Six Months Ended  
    June 30,     June 30,  
    2006     2005     2006     2005  
Statutory U.S. income tax rate
    35.0 %     35.0 %     35.0 %     35.0 %
Effects of foreign operations
    9.9       (1.1 )     10.4       (0.6 )
State and local income taxes after federal income tax effects
    2.0       (0.4 )     2.0       1.3  
Other tax effects
    (0.6 )     (0.2 )     (0.8 )     (0.7 )
 
                       
Effective income tax rate for continuing operations
    46.3 %     33.3 %     46.6 %     35.0 %
 
                       
    Capital loss carryforwards were utilized in conjunction with the sale of Marathon’s Russian oil exploration and production businesses in June 2006, as discussed in Note 4 to the consolidated financial statements. The reversal of

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    the valuation allowance related to these capital loss carryforwards reduced income taxes attributable to discontinued operations by $79 million. The sale of the Russian businesses fully utilized the Company’s capital loss carryforward deferred tax asset.
    Marathon is continuously undergoing examination of its federal income tax returns by the Internal Revenue Service (“IRS”). Audits of the Company’s 1998 through 2003 income tax returns have been agreed between Marathon and the IRS and sent to the Joint Committee on Taxation for approval. If accepted by the Joint Committee, the Company does not anticipate the conclusion of these audits would have a material impact on its consolidated results of operations or financial position. The Company anticipates that a refund of income taxes will be received by the end of 2006. This refund will include periods up to 2001; therefore, a portion of the refund in the form of tax sharing payments may be attributable to United States Steel. These payments will be handled in accordance with the tax sharing agreement between Marathon and United States Steel. See Note 3 to the consolidated financial statements, “Information about United States Steel,” in Marathon’s 2005 Annual Report on Form 10-K for additional discussion of this tax sharing agreement. Audits for tax years 2004 and 2005 are commencing in 2006. Marathon believes it has made adequate provision for federal income taxes and interest which may become payable for years not yet settled.
9.   Comprehensive Income
 
    The following sets forth Marathon’s comprehensive income for the periods indicated:
                                 
    Second Quarter Ended     Six Months Ended  
    June 30,     June 30,  
(Dollars in millions)   2006     2005     2006     2005  
Net income
  $ 1,748     $ 673     $ 2,532     $ 997  
Other comprehensive income (loss), net of taxes:
                               
Minimum pension liability adjustments
    5       24       15       24  
Change in fair value of derivative instruments
    4       (9 )     4       (15 )
 
                       
Total comprehensive income
  $ 1,757     $ 688     $ 2,551     $ 1,006  
 
                       
10.   Inventories
 
    Inventories are carried at the lower of cost or market. The cost of inventories of crude oil, refined products and merchandise is determined primarily under the last-in, first-out (“LIFO”) method.
                 
    June 30,     December 31,  
(Dollars in millions)   2006     2005  
Liquid hydrocarbons and natural gas
  $ 1,918     $ 1,093  
Refined products and merchandise
    1,725       1,763  
Supplies and sundry items
    174       185  
 
           
Total, at cost
  $ 3,817     $ 3,041  
 
           
11.   Property, Plant and Equipment
 
    Exploratory well costs capitalized greater than one year after completion of drilling as of June 30, 2006 were $99 million, including $40 million added to this category during the first quarter of 2006 for wells in Equatorial Guinea (Corona, Bococo and Gardenia), where Marathon is evaluating various development scenarios for the discoveries around the Alba Field, including plans that would integrate the resources into the Company’s long-term LNG supply.
 
12.   Long-term Debt
 
    Effective May 4, 2006, Marathon entered into an amendment to its $1.5 billion five-year revolving credit agreement, expanding the size of the facility to $2.0 billion and extending the termination date from May 2009 to May 2011. Interest on this facility is based on defined short-term market rates. During the term of the agreement, Marathon is obligated to pay a variable facility fee on the total commitment, which at June 30, 2006 was 0.08 percent. At June 30, 2006, there were no borrowings against this facility. Concurrent with this amendment, the $500 million MPC revolving credit agreement was terminated.

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13.   Commitments and Contingencies
 
    Marathon is the subject of, or party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. Certain of these commitments are discussed below. The ultimate resolution of these contingencies could, individually or in the aggregate, be material to Marathon’s consolidated financial statements. However, management believes that Marathon will remain a viable and competitive enterprise even though it is possible that these contingencies could be resolved unfavorably.
 
    Contract commitments — At June 30, 2006 and December 31, 2005, Marathon’s contract commitments to acquire property, plant and equipment totaled $709 million and $668 million, respectively. During the first half of 2006, the significant changes to Marathon’s contract commitments were increases of approximately $90 million related to the potential expansion of the Garyville, Louisiana refinery, and other increases related to development in North America and Libya. Commitments related to the Equatorial Guinea LNG plant, the Neptune development in the Gulf of Mexico and the Alvheim project in Norway declined as construction progress continued on those projects.
 
    Guarantees — In conjunction with the sale of its Russian businesses as discussed in Note 4 to the consolidated financial statements, Marathon guaranteed the purchaser with regard to unknown obligations and inaccuracies in representations, warranties, covenants and agreements by Marathon. These indemnifications are part of the normal course of selling assets. Under the agreement, the maximum potential amount of future payments associated with these guarantees is equivalent to the proceeds from the sale.
 
14.   Stock Repurchase Program
 
    On January 29, 2006, Marathon’s Board of Directors authorized the repurchase of up to $2 billion of common stock over a period of two years. Such purchases are to be made during this period as Marathon’s financial condition and market conditions warrant. Any purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions. The repurchase program does not include specific price targets and is subject to termination prior to completion. Marathon will use cash on hand, cash generated from operations or cash from available borrowings to acquire shares. During the first six months of 2006, Marathon acquired 7.3 million common shares at an acquisition cost of $554 million, which were recorded as common stock held in treasury in the consolidated balance sheet.
 
15.   Supplemental Cash Flow Information
                 
    Six Months Ended June 30,  
(Dollars in millions)   2006     2005  
Noncash investing and financing activities:
               
Asset retirement costs capitalized
  $ 20     $ 8  
Payments of debt assumed by United States Steel
    21       8  
Disposal of assets:
               
Asset retirement obligations assumed by buyer
    9       3  
Acquisition:
               
Debt and other liabilities assumed
    14       5,105  
Common stock issued to seller
          955  
Receivables transferred to seller
          913  
 
               
Commercial paper and revolving credit arrangements, net:
               
Borrowings
  $ 1,321     $ 590  
Repayments
    (1,321 )      
 
               
Net cash provided from operating activities included:
               
Interest paid (net of amounts capitalized)
  $ 56     $ 88  
Income taxes paid to taxing authorities
    1,728       643  
 
           

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16.   MPC Receivables Purchase and Sale Facility
 
    On July 1, 2005, MPC entered into a $200 million, three-year Receivables Purchase and Sale Agreement with certain purchasers. The program was structured to allow MPC to periodically sell a participating interest in pools of eligible accounts receivable. During the term of the agreement MPC was obligated to pay a facility fee of 0.12%. In the first quarter of 2006, the facility was terminated. No receivables were sold under the agreement during its term.
 
17.   Accounting Standards Not Yet Adopted
 
    In July 2006, the FASB issued FASB Interpretation (“FIN”) No. 48, “Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109.” FIN No. 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN No. 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods and disclosure. The provisions of FIN No. 48 are effective for fiscal years beginning after December 15, 2006. Marathon is currently evaluating the provisions of FIN No. 48 to determine the impact on its consolidated financial statements.
 
    In June 2006, the FASB ratified the consensus reached by the EITF regarding Issue No. 06-03, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement (That Is, Gross versus Net Presentation).” Included in the scope of this issue are any taxes assessed by a governmental authority that are imposed concurrent with or subsequent to a revenue-producing transaction between a seller and a customer. The EITF concluded that the presentation of such taxes on a gross basis (included in revenues and costs) or a net basis (excluded from revenues) is an accounting policy decision that should be disclosed pursuant to APB Opinion No. 22. In addition, the amounts of such taxes reported on a gross basis must be disclosed if those tax amounts are significant. The disclosure prescribed by this consensus is required in financial statements for interim and annual reporting periods beginning after December 15, 2006, but early application is permitted.
 
    In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets — An Amendment of FASB Statement No. 140.” This statement amends SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” with respect to the accounting for separately recognized servicing assets and servicing liabilities. Adoption of SFAS No. 156 is required as of the beginning of an entity’s first fiscal year that begins after September 15, 2006. Marathon does not expect adoption of this statement to have a significant effect on its consolidated results of operations, financial position or cash flows.
 
    In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments — An Amendment of FASB Statements No. 133 and 140.” SFAS No. 155 simplifies the accounting for certain hybrid financial instruments, eliminates the interim FASB guidance which provides that beneficial interests in securitized financial assets are not subject to the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and eliminates the restriction on the passive derivative instruments that a qualifying special-purpose entity may hold. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Marathon is currently evaluating the provisions of this Statement to determine the impact on its consolidated financial statements.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
     Marathon Oil Corporation is engaged in worldwide exploration, production and marketing of crude oil and natural gas; domestic refining, marketing and transportation of crude oil and petroleum products primarily in the Midwest, the upper Great Plains and southeastern United States; and worldwide marketing and transportation of products manufactured from natural gas, such as LNG and methanol, and development of other projects to link stranded natural gas resources with key demand areas. Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Consolidated Financial Statements and Selected Notes to Consolidated Financial Statements and the Supplemental Statistics.
     Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements typically contain words such as “anticipates,” “believes,” “estimates,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. For additional risk factors affecting our business, see Item 1A. Risk Factors in our 2005 Annual Report on Form 10-K.
     We acquired the 38 percent interest in MPC previously held by Ashland Inc. on June 30, 2005. Unless specifically noted as being after minority interests, amounts for the Refining, Marketing and Transportation segment include amounts related to the 38 percent interest held by Ashland prior to June 30, 2005.
     Marathon holds a 60 percent interest in Equatorial Guinea LNG Holdings Limited. The remaining interests are held by a company controlled by the government of Equatorial Guinea (25 percent interest), Mitsui & Co., Ltd. (8.5 percent interest) and a subsidiary of Marubeni Corporation (6.5 percent interest). Unless specifically noted as being after minority interests, amounts for the Integrated Gas segment include amounts related to the minority interests.
Overview and Outlook
Exploration and Production (“E&P”)
     Production available for sale during the second quarter of 2006 averaged 353,000 barrels of oil equivalent per day (“boepd”). Reported liquid hydrocarbon and natural gas sales during the quarter averaged 392,000 boepd. The difference between production available for sale and actual sales volumes is primarily attributable to the timing of liquid hydrocarbon liftings from our operations in Libya, Equatorial Guinea and the U.K.
     In Libya, our production available for sale for the first six months of 2006 was consistent with our expectations when we re-entered these operations at the end of 2005, and we are working with our partners to define growth plans for this business. In 2006, the United States restored full diplomatic ties with Libya. A United States embassy has been reopened and Libya has been removed from the list of state sponsors of terrorism.
     We continue to advance our major E&P projects. In Norway, the Alvheim project is 64 percent complete as of June 30, 2006, and is on target to deliver first production in the first quarter of 2007. As part of this project, development drilling commenced in the second quarter of 2006. Installation of pipelines and umbilicals (power and control lines) has been completed and additional subsea structures are being installed. The first phase of equipment placement onto the Alvheim floating production, storage and offloading (“FPSO”) vessel has been completed.and integration of all FPSO components is proceeding. Also, the Neptune development in the Gulf of Mexico is 28 percent complete as of June 30, 2006, and remains on target to deliver first production by early 2008. Development drilling began in the second quarter of 2006.
     In the first half of 2006, we completed leasehold acquisitions totaling approximately 200,000 acres in the Bakken Shale resource play. The majority of the acreage is located in North Dakota with the remainder in eastern Montana. We now own a substantial position in the Bakken Shale with approximately 300 locations to be drilled over the next four to five years.
     In the second quarter of 2006, we were awarded a 70 percent interest and will be the operator in the Pasangkayu Block offshore Indonesia. The 1.2 million acre block is located mostly in deep water, predominantly offshore of the island of Sulawesi in the Makassar Strait, directly east of the Kutei Basin oil and natural gas production region. A production sharing contract with the Indonesian government is being negotiated, with execution expected during the third quarter of 2006. We expect to begin collecting geophysical data in 2007, followed by exploratory drilling in 2008 and 2009.

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     Also in the second quarter of 2006, we sold our Russian oil exploration and production businesses. Under the terms of the agreement, we received $787 million for these businesses, plus preliminary working capital and other closing adjustments of $56 million, for a total transaction value of $843 million. A gain on the sale of $243 million ($342 million before tax) is reported in discontinued operations for the quarter and six months ended June 30, 2006. The final adjustment to the purchase price is expected to be made before December 31, 2006 and could affect the reported gain. For all periods presented, the activities of the Russian businesses have been reported as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows.
     We participated in two deepwater discoveries in the second quarter of 2006 in Block 31 offshore Angola, where we own a 10 percent interest. These two discoveries were the Urano prospect and a yet to be announced exploration well in the southeast portion of the block. Additional drilling/seismic analysis will be required to determine the commerciality of these two discoveries. Two exploratory dry holes were drilled during the second quarter of 2006: a well offshore Angola and the Abbott well in the Gulf of Mexico. Two other discoveries were announced in the first quarter of 2006: the Mostarda well on Block 32 offshore Angola, where we have a 30 percent interest, and the Gudrun well offshore Norway, in which we have a 28.2 percent interest. We expect to participate in another seven or eight exploration wells in 2006. Three to four exploration wells originally expected to be drilled in 2006 are now expected to be carried over to 2007. We are currently participating in an appraisal well at the Stones discovery in the Gulf of Mexico and three deepwater wells in Angola.
     We estimate our 2006 production available for sale will average between 350,000 and 370,000 boepd. This estimate reflects the impact of the sale of our Russian oil exploration and production businesses, but excludes the effect of any future acquisitions or dispositions. Reported volumes are based on sales volumes which may vary from production available for sale primarily due to the timing of liftings from certain of our international locations.
     In July 2006, we completed a leasehold acquisition of a long-life natural gas asset in the Piceance Basin of Colorado, located in Garfield County in the Greater Grand Valley Field Complex for cash of $354 million. The acreage is flanked by, and on-trend with, adjacent production. Our plans include drilling approximately 700 wells over the next ten years with first production expected in late 2007.
     We own an 18.5 percent interest in the outside-operated Corrib natural gas development project, located off Ireland’s west coast. Onshore development activities started in late 2004 but were suspended in 2005 pending resolution of issues raised by opponents of the project. The partners in this project recently accepted the findings of a government-commissioned independent safety review and an independent mediator’s report regarding the onshore pipeline associated with the proposed development. The partners now intend to proceed with this project.
     We discovered the Ash Shaer and Cherrife gas fields in Syria in the 1980s. We submitted four plans of development to the Syrian Petroleum Company in the 1990s, but none were approved. The Syrian government subsequently claimed that the production sharing contract for these fields had expired. We have been involved in an ongoing dispute with the Syrian Petroleum Company and government of Syria over our interest in these fields. On July 26, 2006, the president of Syria signed into law a new production sharing contract between us and the Syrian Petroleum Company. This new production sharing contract gives us the right to sell all or a significant portion of our interest in the Ash Shaer and Cherrife gas fields to a third party, subject to the consent of the Syrian government, and resolves the disputes between us and the Syrian Petroleum Company and the government of Syria over our interest in these fields. We have and will continue to comply with all U.S. sanctions related to Syria.
     The above discussion includes forward-looking statements with respect to the timing and levels of our worldwide liquid hydrocarbon, natural gas and condensate production, the development of the Alvheim field, the Neptune development, execution of the Indonesian production sharing contract, development of the Corrib field and anticipated future exploratory and development drilling activity. Some factors that could potentially affect these forward-looking statements include pricing, supply and demand for petroleum products, amount of capital available for exploration and development, acquisitions or dispositions of oil and natural gas properties, regulatory constraints, timing of commencing production from new wells, drilling rig availability, inability or delay in obtaining necessary government and third-party approvals and permits, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response and other geological, operating and economic considerations. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.
Refining, Marketing and Transportation (“RM&T”)
     We completed our ultra-low sulfur diesel fuel modifications on time and under budget during the second quarter of 2006 and began producing ultra-low sulfur diesel fuel prior to the June 1, 2006 deadline set by U.S. Environmental Protection Agency regulations. Also during the quarter, our RM&T operations benefited from refining margins (crack spreads) in the Midwest (Chicago) and Gulf Coast that were stronger than the comparable period of 2005. Primarily as a result of these improved margins, our refining and wholesale marketing gross margin averaged 29.78 cents per gallon in

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the second quarter of 2006 versus 15.92 cents per gallon in the second quarter of 2005. In addition, during the second quarter of 2006, our total refinery throughput was 5 percent higher than the same quarter in 2005. We continue to expect that our 2006 average crude oil throughput will exceed our record throughput for 2005. Also during the second quarter of 2006, we blended approximately 35 thousand barrels per day (“mbpd”) of ethanol into gasoline, 7 percent more than we blended in the second quarter of 2005. The expansion or contraction of our ethanol blending program will be driven by the economics of the ethanol supply.
     During the second quarter of 2006, Speedway SuperAmerica LLC realized increased same store merchandise sales of 8.7 percent over the second quarter of 2005, while same store gasoline sales volume decreased 1.8 percent when compared to the second quarter of 2005.
     The International Brotherhood of Teamsters’ labor agreement covering our St. Paul Park, Minnesota refinery expired on May 31, 2006. We agreed with the union to an extension that could be cancelled with 24 hours notice and have been negotiating a new collective bargaining agreement since early May. The union rejected our last proposal submitted on July 12, 2006, cancelled the extension and elected to strike on July 19, 2006. We continue to operate the St. Paul Park refinery at normal capacity.
     We are approximately 40 percent complete with the front-end engineering and design (“FEED”) of the proposed 180,000 barrel per day expansion of the Garyville, Louisiana refinery, with process design scope complete. The FEED estimate is expected to be completed in the fourth quarter of 2006. The applications for the necessary environmental permits have been submitted and approval is expected by year end. Our expenditure commitments for the Garyville expansion project in 2006 will total approximately $170 million, including both FEED costs and the procurement of certain long-lead time process unit components. The estimated cost of the expansion has been revised to approximately $3.0 billion from the previous estimate of $2.2 billion primarily due to an increase in the processing unit capacities and tankage to help optimize the overall economics of the project, Additional tanks have been added to the scope of the project to provide increased crude supply options, along with added gasoline and diesel grade segregation, to better serve water-bound cargoes, to support on-going product quality and to better position the refinery for market opportunities. Engineering and construction costs account for the majority of the remaining increase as both labor and material costs have continued to increase significantly over the last year. If this project is approved by our Board and if the environmental permits are received by year end, construction could commence in mid-2007.
     Recently we announced the signing of a letter of intent which could lead to the formation of a joint venture that would construct and operate a number of ethanol plants. The formation of the joint venture and other related activities are subject to the negotiation and execution of definitive agreements.
     The above discussion includes forward-looking statements with respect to projections of crude oil throughput, the Garyville expansion project under evaluation and a proposed joint venture that would construct and operate ethanol plants. Some factors that could potentially affect these forward-looking statements include planned and unplanned refinery maintenance projects, the levels of refining margins and other operating considerations, transportation logistics, availability of materials and labor, necessary government and third-party approvals, results of the FEED work, board approval, unforeseen hazards such as weather conditions, and other risks customarily associated with construction projects. These factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.
Integrated Gas (“IG”)
     Our integrated gas activities during the second quarter of 2006 were marked by continued progress in constructing the LNG plant in Equatorial Guinea. The project is approximately 87 percent complete on an engineering, procurement and construction basis as of June 30, 2006 and has moved ahead of schedule with the first shipments of LNG projected for mid-2007.
     The above discussion contains forward-looking statements with respect to the estimated construction and startup dates of a LNG project which could be affected by unforeseen problems arising from construction, inability or delay in obtaining necessary government and third-party approvals, unanticipated changes in market demand or supply, environmental issues, availability or construction of sufficient LNG vessels, and unforeseen hazards such as weather conditions. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.
Change in Accounting for Matching Buy/Sell Transactions
     Matching buy/sell transactions arise from arrangements in which we agree to buy a specified quantity and quality of crude oil or refined petroleum product to be delivered to a specified location while simultaneously agreeing to sell a specified quantity and quality of the same commodity at a specified location to the same counterparty. Prior to April 1, 2006, all matching buy/sell transactions were recorded as separate sale and purchase transactions, or on a “gross” basis.

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Effective for contracts entered into or modified on or after April 1, 2006, the income effects of matching buy/sell transactions are reported in cost of revenues, or on a “net” basis. Transactions under contracts entered into before April 1, 2006 will continue to be reported on a “gross” basis.
     Each purchase and sale transaction has the characteristics of a separate legal transaction, including separate invoicing and cash settlement. Accordingly, we believed that we were required to account for these transactions separately. A recent accounting interpretation clarified the circumstances under which a matching buy/sell transaction should be viewed as a single transaction for the exchange of inventory. For a further description of the accounting requirements and how they apply to matching buy/sell transactions, see Note 2 to the consolidated financial statements, “New Accounting Standards.”
     This accounting change had no effect on net income. The amounts of revenues and cost of revenues recognized in the second quarter of 2006 and subsequent periods will be less than the amounts that would have been recognized under previous accounting practices.
     Additionally, this accounting change will affect the comparability of certain operating statistics, most notably “refining and wholesale marketing gross margin per gallon.” While this change will not have a significant effect on the refining and wholesale marketing gross margin (the numerator for calculating this statistic), sales volumes (the denominator for calculating this statistic) recognized in the second quarter of 2006 and subsequent periods will be less than the amount that would have been recognized under previous accounting practices because volumes related to matching buy/sell transactions under contracts entered into or modified on or after April 1, 2006 have been excluded. Accordingly, the resulting refining and wholesale marketing gross margin per gallon statistic will be higher than that same statistic calculated from amounts determined under previous accounting practices. The effect of this change on the refining and wholesale marketing gross margin per gallon for the second quarter of 2006 was not significant.
Corporate
     In July 2006, the United Kingdom passed legislation to increase the supplementary corporation tax rate from 10 percent to 20 percent. In the third quarter of 2006, we will record the earnings impact of this change retroactive to January 1, 2006 and a one-time adjustment to income taxes for the impact of the rate change on our related deferred tax balances, neither of which will have a significant effect on our consolidated results of operations for the third quarter of 2006.
     Historically, we have maintained insurance coverage for physical damage and resulting business interruption to our major onshore and offshore facilities. Higher margins and commodity prices have increased our exposure to business interruptions. Due to hurricane activity in recent years, the availability of insurance coverage for our offshore facilities for windstorms in the Gulf of Mexico region has been reduced or, in many instances, it is prohibitively expensive. As a result, our exposure to losses from future windstorm activity in the Gulf of Mexico region has increased.
Critical Accounting Estimates
     The preparation of financial statements in accordance with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from the estimates and assumptions used.
     Certain accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change; and (2) the impact of the estimates and assumptions on financial condition or operating performance is material.
     There have been no significant changes to our critical accounting estimates subsequent to December 31, 2005.

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Results of Operations
Consolidated Results
     Total revenues for the second quarters and first six months of 2006 and 2005 are summarized by segment in the following table:
                                 
    Second Quarter Ended     Six Months Ended  
    June 30,     June 30,  
(Dollars in millions)   2006     2005     2006     2005  
E&P
  $ 2,515     $ 1,954     $ 4,816     $ 3,619  
RM&T
    15,800       14,283       30,012       25,679  
IG
    70       44       100       105  
 
                       
Segment revenues
    18,385       16,281       34,928       29,403  
 
                       
Elimination of intersegment revenues
    (189 )     (172 )     (392 )     (358 )
Gain (loss) on long-term U.K. natural gas contracts
    (17 )     (167 )     61       (224 )
 
                       
Total revenues
  $ 18,179     $ 15,942     $ 34,597     $ 28,821  
 
                       
Items included in both revenues and costs and expenses:
                               
Consumer excise taxes on petroleum products and merchandise
  $ 1,277     $ 1,210     $ 2,442     $ 2,294  
Matching crude oil and refined product buy/sell transactions:
                               
E&P
    5       34       16       70  
RM&T
    1,801       3,531       4,996       6,304  
 
                       
Total buy/sell transactions included in revenues
  $ 1,806     $ 3,565     $ 5,012     $ 6,374  
 
                       
     E&P segment revenues increased by $561 million in the second quarter of 2006 from the comparable prior-year period. For the first six months of 2006, revenues increased by $1.197 billion from the prior-year period. The increases were primarily due to higher hydrocarbon sales prices and net liquid hydrocarbon sales volumes, particularly in Africa where the first crude oil liftings in Libya occurred in the first quarter of 2006. At the end of the first quarter of 2006, we were underlifted from our international operations by approximately 4.0 million barrels of liquid hydrocarbons. During the second quarter of 2006, we were overlifted by 3.5 million barrels, of which 1.8 million barrels were attributed to Libya. As a result, at the end of the second quarter of 2006 we were in a relatively balanced position on liftings versus production on a worldwide basis.
     Excluded from E&P segment revenues are losses of $17 million for the second quarter of 2006 and $167 million for the second quarter of 2005 on long-term natural gas contracts in the United Kingdom that are accounted for as derivative instruments. For the first six months of 2006 and 2005, a gain of $61 million and a loss of $224 million are excluded from E&P segment revenues.
     RM&T segment revenues increased by $1.517 billion in the second quarter of 2006 and $4.333 billion in the first six months of 2006 from the comparable prior-year periods, although revenues reported for RM&T matching buy/sell transactions decreased $1.730 billion and $1.308 billion in the same periods as a result of the change in accounting for these transactions effective April 1, 2006, discussed above. The increases in revenues excluding matching buy/sell transactions in both periods primarily reflected higher refined product prices and sales volumes.
     For additional information on segment results, see Segment Income.
     Income from equity method investments for the second quarter and first six months of 2006 increased $52 million and $105 million from the comparable prior-year periods primarily due to the liquefied petroleum gas expansion in Equatorial Guinea which ramped up to full production in the third quarter of 2005.
     Cost of revenues for the second quarter and first six months of 2006 increased by $2.373 billion and $4.451 billion from the comparable prior-year periods. The increases are primarily in the RM&T segment and resulted mainly from higher acquisition costs for crude oil and other refinery charge and blend stocks. Additionally in the first six months of 2006, we experienced higher acquisition costs for refined products and higher RM&T manufacturing costs, primarily a result of higher purchased energy and maintenance costs.

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     Depreciation, depletion and amortization for the second quarter and first six months of 2006 increased $48 million and $138 million from the comparable periods of 2005. RM&T segment depreciation expense increased in both periods primarily as a result of the asset value increase recorded for our acquisition of Ashland Inc.’s 38 percent interest in MPC on June 30, 2005 and the Detroit refinery expansion completed in the fourth quarter of 2005. E&P segment depreciation expense for the first six months of 2006 included a $20 million impairment of capitalized costs related to the Camden Hills field in the Gulf of Mexico and the associated Canyon Express pipeline. Natural gas production from the Camden Hills field ended during the first quarter of 2006 as a result of increased water production from the well.
     Selling, general and administrative expenses increased $40 million in the second quarter of 2006 and $68 million in the first six months of 2006 over the same periods of 2005. Personnel and staffing costs, such as employee salaries and outside consultant fees, have increased as a result of variable compensation arrangements and increased business activity. Additionally, the increase reflects costs related to disaster preparedness programs.
     Exploration expenses were $66 million in the second quarter of 2006 compared to $36 million in the second quarter of 2005. Exploration expenses related to dry wells in the second quarter of 2006 totaled $28 million, primarily related to a well offshore Angola and the Abbott well in the Gulf of Mexico. Exploration expenses related to dry wells in the first quarter of 2006 totaled $30 million and primarily included costs related to the Davan well in the U.K. and the Soulandaka well in Gabon.
     Net interest and other financing costs (income) reflected a net $9 million of income in the second quarter of 2006 compared to a net $35 million expense for the second quarter of 2005. This favorable change primarily resulted from increased interest income due to higher interest rates and average cash balances, foreign currency exchange gains and lower interest expense.
     Minority interest in the income of MPC decreased $314 million and $384 million in the second quarter and first six months of 2006 from the comparable 2005 periods due to the completion of our acquisition of Ashland Inc.’s 38 percent interest in MPC on June 30, 2005.
     Provision for income taxes increased $947 million and $1.433 billion in the second quarter and first six months of 2006 from the comparable periods of 2005 primarily due to increased income from continuing operations before income taxes as discussed above. Our effective income tax rates for the second quarter and first six months of 2006 were 46 percent and 47 percent compared to 33 percent and 35 percent for the same periods of 2005. The increases are primarily a result of the income taxes related to our Libyan operations, where the statutory income tax rate is in excess of 90 percent. The following is an analysis of the effective tax rates for continuing operations for the second quarters and first six months of 2006 and 2005:
                                 
    Second Quarter Ended   Six Months Ended
    June 30,   June 30,
    2006   2005   2006   2005
Statutory U.S. income tax rate
    35.0 %     35.0 %     35.0 %     35.0 %
Effects of foreign operations
    9.9       (1.1 )     10.4       (0.6 )
State and local income taxes after federal income tax effects
    2.0       (0.4 )     2.0       1.3  
Other tax effects
    (0.6 )     (0.2 )     (0.8 )     (0.7 )
 
                               
Effective income tax rate for continuing operations
    46.3 %     33.3 %     46.6 %     35.0 %
 
                               
     Discontinued operations reflects the operations of our Russian oil exploration and production businesses which were sold in June 2006. An after-tax gain on the disposal of $243 million is included in discontinued operations for the second quarter of 2006. See Note 4 to the consolidated financial statements, “Discontinued Operations,” for additional information.
Segment Results
     Effective January 1, 2006, we revised our measure of segment income to include the effects of minority interests and income taxes related to the segments. In addition, the results of activities primarily associated with the marketing of our equity natural gas production, which had been presented as part of the Integrated Gas segment prior to 2006, are now included in the Exploration and Production segment. Segment results for all periods presented reflect these changes.
     As discussed previously, we sold our Russian oil exploration and production businesses during the second quarter of 2006. The activities of these operations have been reported as discontinued operations and therefore are excluded from segment results for all periods presented.

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     Segment income for the second quarters and first six months of 2006 and 2005 is summarized in the following table.
                                 
    Second Quarter Ended     Six Months Ended  
    June 30,     June 30,  
(Dollars in millions)   2006     2005     2006     2005  
E&P
                               
United States
  $ 243     $ 258     $ 488     $ 435  
International
    416       246       636       403  
 
                       
E&P segment
    659       504       1,124       838  
RM&T
    917       316       1,236       390  
IG
    17             25       22  
 
                       
Segment income
    1,593       820       2,385       1,250  
Items not allocated to segments, net of income taxes:
                               
Gain (loss) on long-term U.K. natural gas contracts
    (10 )     (97 )     35       (130 )
Corporate and other unallocated items
    (99 )     (70 )     (165 )     (144 )
Ohio tax legislation
          15             15  
Discontinued operations
    264       5       277       6  
 
                       
Net income
  $ 1,748     $ 673     $ 2,532     $ 997  
 
                       
     United States E&P income in the second quarter of 2006 was $15 million lower than the same period of 2005, while income in the first six months of 2006 was $53 million higher than the same period of 2005. Pretax income in the second quarter of 2006 decreased $14 million and the effective income tax rate increased to 37 percent from 36 percent in the second quarter of 2005. Pretax income in the first six months of 2006 increased $81 million and the effective income tax rate was 37 percent in 2006 and 2005.
     Revenues for the second quarter of 2006 were down when compared to the same quarter of 2005 primarily as a result of lower net natural gas sales volumes and prices. Net natural gas sales volumes of 523 million cubic feet per day (“mmcfd”) were down nearly 10 percent from the second quarter of 2005. The average realized natural gas price of $5.35 per thousand cubic feet (“mcf”) for the second quarter of 2006 was 41 cents lower than the $5.76 per mcf realized in the second quarter of 2005. In addition, domestic net liquid hydrocarbon sales volumes were 79 thousand barrels per day (“mbpd”), a decrease of 7 percent, from the second quarter of 2005 levels as a result of normal production declines. These revenue declines were partially offset by higher liquid hydrocarbon prices which increased to an average of $59.80 per barrel (“bbl”) for the second quarter of 2006 from $42.22 per bbl in the comparable period of 2005.
     Revenues increased in the first six months of 2006 primarily as a result of higher hydrocarbon prices. Our domestic average realized liquid hydrocarbon price was $54.52 per bbl for the first six months of 2006 compared to $40.52 per bbl in the comparable prior-year period. The average realized natural gas price of $6.02 per mcf was also higher than the $5.36 realized in the corresponding 2005 period. Net natural gas sales volume declines, primarily due to the cessation of production from the Camden Hills field in the first quarter of 2006, offset much of the impact of these price increases in the first six months of 2006.
     Both periods were impacted by higher variable costs, including depreciation, depletion and amortization expense, and by higher exploration expenses. Additionally, the second quarter and first six months of 2005 included business interruption insurance proceeds associated with damage from hurricane Ivan.
     International E&P income increased $170 million and $233 million in the second quarter and first six months of 2006. Pretax income increased $613 million and $917 million in the same periods, while the effective income tax rate increased from 34 percent to 58 percent in the second quarter of 2006 and from 36 percent to 59 percent in the first six-months of 2006 compared to the 2005 periods. These increases in the effective income tax rates are primarily a result of the income taxes related to our Libyan operations, where the statutory income tax rate is in excess of 90 percent.
     The increases in pretax income were primarily the result of increases in revenues from higher liquid hydrocarbon and natural gas prices and higher net liquid hydrocarbon sales volumes in the second quarter and first six months of 2006. Our international average realized liquid hydrocarbon prices were $65.76 and $61.74 per bbl in the second quarter and first six months of 2006 compared to $47.98 and $46.55 per bbl in the same prior-year periods. Our average realized natural gas prices of $5.19 and $5.78 per mcf in the second quarter and first six months of 2006 were higher than the $3.22 and $3.78 per mcf in the corresponding periods of 2005. International net liquid hydrocarbon sales volumes were 180 mbpd and 141 mbpd in the second quarter and first six months of 2006 as compared to 110 mbpd and 88 mbpd in the comparable periods of 2005 primarily due to our resumption of production in Libya. The increase in net

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sales volumes also reflects the effect of the Equatorial Guinea condensate expansion project which reached full production levels in the third quarter of 2005. Net natural gas sales volumes averaged 278 mmcfd in the second quarter of 2006, down 11 percent from the comparable period of 2005. The lower net natural gas sales volumes were primarily related to lower gas sales in Equatorial Guinea as a result of reduced demand associated with planned maintenance at the AMPCO methanol plant.
     These increases in revenues were partially offset by higher variable costs and dry hole costs in both periods of 2006.
     RM&T segment income increased by $601 million and $846 million from the second quarter and first six months of 2005. Pretax income increased $967 million and $1.348 billion in the same periods, while the effective income tax rate decreased from 39 percent to 38 percent in the second quarter of 2006 and from 41 percent to 38 percent in the first six months of 2006 compared to the 2005 periods. Segment income in both periods of 2006 benefited from the 38 percent minority interest in MPC that we acquired on June 30, 2005. In the second quarter and first six months of 2005, the pretax earnings reduction related to the minority interest was $309 million and $376 million. The decreases in the effective income tax rates for both periods are the result of lower state tax rates in 2006, particularly the effect of the Kentucky income tax increase on deferred tax balances at the beginning of 2005.
     A key driver of the increase in RM&T pretax income in both periods was our refining and wholesale marketing gross margin, which averaged 29.78 cents per gallon in the second quarter of 2006 and 20.77 cents per gallon in the first six months of 2006, compared to 15.92 and 11.58 cents per gallon in the comparable periods of 2005. This margin improvement was consistent with the relevant indicators (crack spreads) in the Midwest (Chicago) and Gulf Coast markets. Crude oil refined during the second quarter 2006 averaged 1,038,000 bpd, 26,100 bpd higher than during the second quarter 2005. In addition, total refinery throughputs totaled 1,244,800 bpd for the second quarter 2006, approximately 5 percent higher than the 1,186,500 bpd during the second quarter 2005. We were able to achieve both of these increases primarily as a result of the expansion of our Detroit refinery from 74,000 to 100,000 bpd that was completed during the fourth quarter 2005.
     IG segment income increased $17 million and $3 million in the second quarter and first six months of 2006 compared to the same periods of 2005. Income from domestic LNG activities increased in 2006 largely due to revenues associated with our re-gasification facility at Elba Island.
Cash Flows and Liquidity
Cash Flows
     Net cash provided from operating activities totaled $2.299 billion in the first six months of 2006, compared with $1.520 billion in the first six months of 2005. The $779 million increase primarily reflects the impact of higher liquid hydrocarbon prices and our increased refining and wholesale marketing gross margin.
     Net cash used in investing activities totaled $857 million in the first six months of 2006, down $850 million from the same period of 2005 primarily as a result of the $832 million net cash proceeds from the sale of our Russian oil exploration and production businesses in June 2006. Capital expenditures were $1.308 billion compared with $1.179 billion for the comparable prior-year period. E&P spending increased $255 million, partially offset by decreased IG spending as a result of major projects such as the LNG plant nearing completion. E&P spending in the first six months of 2006 reflected higher expenditures related to the Alvheim development offshore Norway and the Neptune development in the Gulf of Mexico. For information regarding capital expenditures by segment, refer to Supplemental Statistics. Cash paid for acquisitions during the first six months of 2006 totaled $543 million, primarily related to the initial $520 million payment associated with our re-entry into Libya.
     Net cash used in financing activities was $1.048 billion in the first six months of 2006, compared to net cash provided from financing activities of $293 million in the first six months of 2005. Significant uses of cash in financing activities during the 2006 period included the repayment of our $300 million 6.65% notes that matured during the first quarter, stock repurchases of $554 million under a previously announced plan discussed under Liquidity and Capital Resources below and dividend payments of $265 million.
Dividends to Stockholders
     On July 26, 2006, our Board of Directors declared a dividend of 40 cents per share, payable September 11, 2006, to stockholders of record at the close of business on August 16, 2006.

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Derivative Instruments
     See Quantitative and Qualitative Disclosures About Market Risk for a discussion of derivative instruments and associated market risk.
Liquidity and Capital Resources
     Our main sources of liquidity and capital resources are internally generated cash flow from operations, committed credit facilities, and access to both the debt and equity capital markets. Our ability to access the debt capital market is supported by our investment grade credit ratings. Our senior unsecured debt is currently rated investment grade by Standard and Poor’s Corporation, Moody’s Investor Services, Inc. and Fitch Ratings with ratings of BBB+, Baa1 and BBB+, respectively. Because of the liquidity and capital resource alternatives available to us, including internally generated cash flow, we believe that our short-term and long-term liquidity is adequate to fund operations, including our capital spending programs, stock repurchase program, repayment of debt maturities for the years 2006, 2007 and 2008, and any amounts that may ultimately be paid in connection with contingencies.
     Effective May 4, 2006, we entered into an amendment to our $1.5 billion five-year revolving credit agreement, expanding the size of the facility to $2.0 billion and extending the termination date from May 2009 to May 2011. Concurrent with this amendment, the $500 million MPC revolving credit facility was terminated. At June 30, 2006, there were no borrowings against our facility.
     As a condition of the closing agreements for our acquisition of Ashland’s minority interest in MPC, we are required to maintain MPC on a stand-alone basis financially for a two-year period. During this period of time, capital contributions into MPC are prohibited and MPC is prohibited from incurring additional debt, except for borrowings under an existing intercompany loan facility to fund the expansion project at our Detroit refinery and in the event of limited extraordinary circumstances. MPC was permitted to use its revolving credit facility only for short-term working capital requirements in a manner consistent with past practices. There are no restrictions against MPC making intercompany loans or declaring dividends to its parent. We believe that the existing cash balances of MPC and cash provided from its operations will be adequate to meet its liquidity requirements.
     As of June 30, 2006, $1.7 billion aggregate amount of common stock, preferred stock and other equity securities, debt securities, trust preferred securities or other securities, including securities convertible into or exchangeable for other equity or debt securities were available to be issued under our $2.7 billion universal shelf registration statement filed in 2002.
     Our cash-adjusted debt-to-capital ratio (total debt-minus-cash to total debt-plus-equity-minus-cash) was 5 percent at June 30, 2006, compared to 11 percent at year-end 2005 as shown below. This includes $522 million of debt that is serviced by United States Steel Corporation (“United States Steel”). We continually monitor our spending levels, market conditions and related interest rates to maintain what we perceive to be reasonable debt levels.
                 
    June 30,     December 31,  
(Dollars in millions)   2006     2005  
Long-term debt due within one year
  $ 456     $ 315  
Long-term debt
    3,224       3,698  
 
           
Total debt
  $ 3,680     $ 4,013  
 
           
 
               
Cash
  $ 3,026     $ 2,617  
Equity
  $ 13,489     $ 11,705  
 
           
 
               
Calculation:
               
Total debt
  $ 3,680     $ 4,013  
Minus cash
    3,026       2,617  
 
           
Total debt minus cash
    654       1,396  
 
           
 
               
Total debt
    3,680       4,013  
Plus equity
    13,489       11,705  
Minus cash
    3,026       2,617  
 
           
Total debt plus equity minus cash
  $ 14,143     $ 13,101  
 
           
 
               
Cash-adjusted debt-to-capital ratio
    5 %     11 %
 
           
     Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance (as measured by various factors including cash provided from operating activities), the state of

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worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies.
Stock Repurchase Program
     On January 29, 2006, our Board of Directors authorized the repurchase of up to $2 billion of common stock over a period of two years. Such purchases will be made during this period as our financial condition and market conditions warrant. Any purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions. We will use cash on hand, cash generated from operations or cash from available borrowings to acquire shares. During the first six months of 2006, Marathon acquired 7.3 million common shares, at an acquisition cost of $554 million. On July 26, 2006, we announced that purchases under the program were being accelerated. We currently anticipate repurchasing $1.5 billion of our common stock by December 31, 2006, with the balance of the shares being repurchased in 2007. This program does not include specific price targets and may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion.
     The forward-looking statements about our common stock repurchase program are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially are changes in prices of and demand for crude oil, natural gas and refined products, actions of competitors, disruptions or interruptions of our production or refining operations due to unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto, and other operating and economic considerations.
Contractual Cash Obligations
     As of June 30, 2006, our contractual cash obligations have increased by $1.9 billion from December 31, 2005. Purchase obligations under crude oil, refinery feedstocks and refined product contracts increased $2.5 billion primarily as a result of increased contract volumes and prices. Partially offsetting this increase were decreases in long-term debt obligations from the repayment of $300 million of notes that matured during the first quarter of 2006, and in future operating lease obligations related to the Russian businesses that were sold during the second quarter of 2006. There have been no other significant changes to our obligations to make future payments under existing contracts subsequent to December 31, 2005. The portion of our obligations to make future payments under existing contracts that have been assumed by United States Steel has not changed significantly subsequent to December 31, 2005.
Other Obligations
     An additional payment, estimated to be $212 million, is payable by us during 2006 under our agreement with the National Oil Corporation of Libya to return to our operations in the Waha concessions in Libya.
Off-Balance Sheet Arrangements
     Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under generally accepted accounting principles. Although off-balance sheet arrangements serve a variety of our business purposes, we are not dependent on these arrangements to maintain our liquidity and capital resources; and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on liquidity and capital resources. There have been no significant changes to our off-balance sheet arrangements subsequent to December 31, 2005.
Nonrecourse Indebtedness of Investees
     Certain of our investees have incurred indebtedness that we do not support through guarantees or otherwise. If we were obligated to share in this debt on a pro rata ownership basis, our share would have been $294 million as of June 30, 2006. Of this amount, $171 million relates to Pilot Travel Centers LLC (“PTC”). If any of these investees default, we have no obligation to support the debt. Our partner in PTC has guaranteed $125 million of the total PTC debt.
Obligations Associated with the Separation of United States Steel
     We remain obligated (primarily or contingently) for certain debt and other financial arrangements for which United States Steel has assumed responsibility for repayment under the terms of the Separation. (See the discussion of the Separation in our 2005 Annual Report on Form 10-K.) United States Steel’s obligations to Marathon are general

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unsecured obligations that rank equal to United States Steel’s accounts payable and other general unsecured obligations. If United States Steel fails to satisfy these obligations, we would become responsible for repayment. Under the Financial Matters Agreement, United States Steel has all of the existing contractual rights under the leases assumed from Marathon, including all rights related to purchase options, prepayments or the grant or release of security interests. However, United States Steel has no right to increase amounts due under or lengthen the term of any of the assumed leases, other than extensions set forth in the terms of the assumed leases.
     As of June 30, 2006, we have obligations totaling $570 million that have been assumed by United States Steel. Of the total $570 million, obligations of $531 million and corresponding receivables from United States Steel were recorded on our consolidated balance sheet (current portion — $21 million; long-term portion — $510 million). The remaining $39 million was related to off-balance sheet arrangements and contingent liabilities of United States Steel.
Environmental Matters
     We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately recovered in the prices of our products and services, operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas, production processes and whether it is also engaged in the petrochemical business or the marine transportation of crude oil, refined products, and refinery feedstocks.
     Of particular significance to our refining operations are U.S. Environmental Protection Agency (“EPA”) regulations that require reduced sulfur levels starting in 2004 for gasoline and 2006 for diesel fuel. We have achieved compliance with these regulations and began the production of ultra low sulfur diesel fuel prior to the June 1, 2006 deadline. The cost of achieving compliance is estimated to be approximately $875 million.
     During 2001, MPC entered into a New Source Review consent decree and settlement of alleged Clean Air Act (“CAA”) and other violations with the EPA covering all of its refineries. The settlement committed MPC to specific control technologies and implementation schedules for environmental expenditures and improvements to its refineries over approximately an eight-year period. The consent decree was amended twice in 2005. The total one-time expenditures for these environmental projects are expected to be $410 million over the eight-year period, with approximately $305 million incurred through June 30, 2006. The impact of the settlement on ongoing operating expenses is not expected to be significant. In addition, MPC has nearly completed certain agreed upon supplemental environmental projects as part of this settlement of an enforcement action for alleged CAA violations, at a cost of $9 million. We believe this settlement will provide MPC with increased permitting and operating flexibility while achieving emission reductions.
     The oil industry across the U.K. continental shelf is making reductions in the amount of oil in its produced water discharges pursuant to the Department of Trade and Industry initiative under the Oil Pollution Prevention and Control Regulations (“OSPAR”) of 2005. In compliance with these regulations, we expect to spend an estimated $12 million in capital costs on the OSPAR project for Brae field to make the required reductions of oil in its produced water discharges.
     In June 2006, Marathon and another operator filed a Complaint for Declaratory Judgment in Montana State District Court against the Montana Board of Environmental Review (“MBER”), and the Montana Department of Environmental Quality (“MDEQ”), seeking to set aside and declare invalid certain 2006 regulations (and underlying 2003 regulations) of the MBER that single out the coal bed natural gas industry and a few streams in eastern Montana for excessively severe and unjustified restrictions for surface water discharges of produced water from coal bed methane operations. None of the streams affected by the regulations suffers impairment from coal bed natural gas discharges. The complaint alleges that MBER violated Montana State law in that it adopted regulations without sound scientific justification, proposed water quality standards more stringent than federal law without required justification, and neglected to prepare an environmental impact statement to address resultant harm to jobs and communities from the regulations.
     There have been no other significant changes to our environmental matters subsequent to December 31, 2005.
Other Contingencies
     We are the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. The ultimate resolution of these contingencies could, individually or in the aggregate, be material to us. However, we believe that we will remain a viable and competitive enterprise even though it is possible that these contingencies could be resolved

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unfavorably to us. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.
Accounting Standards Not Yet Adopted
     In July 2006, the FASB issued FASB Interpretation (“FIN”) No. 48, “Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109.” FIN No. 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN No. 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods and disclosure. The provisions of FIN No. 48 are effective for fiscal years beginning after December 15, 2006. Marathon is currently evaluating the provisions of FIN No. 48 to determine the impact on its consolidated financial statements.
     In June 2006, the FASB ratified the consensus reached by the EITF regarding Issue No. 06-03, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement (That Is, Gross versus Net Presentation).” Included in the scope of this issue are any taxes assessed by a governmental authority that are imposed concurrent with or subsequent to a revenue-producing transaction between a seller and a customer. The EITF concluded that the presentation of such taxes on a gross basis (included in revenues and costs) or a net basis (excluded from revenues) is an accounting policy decision that should be disclosed pursuant to APB Opinion No. 22. In addition, the amounts of such taxes reported on a gross basis must be disclosed if those tax amounts are significant. The disclosure prescribed by this consensus is required in financial statements for interim and annual reporting periods beginning after December 15, 2006, but early application is permitted.
     In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets – An Amendment of FASB Statement No. 140.” This statement amends SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” with respect to the accounting for separately recognized servicing assets and servicing liabilities. Adoption of SFAS No. 156 is required as of the beginning of an entity’s first fiscal year that begins after September 15, 2006. Marathon does not expect adoption of this statement to have a significant effect on its consolidated results of operations, financial position or cash flows.
     In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments – An Amendment of FASB Statements No. 133 and 140.” SFAS No. 155 simplifies the accounting for certain hybrid financial instruments, eliminates the interim FASB guidance which provides that beneficial interests in securitized financial assets are not subject to the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and eliminates the restriction on the passive derivative instruments that a qualifying special-purpose entity may hold. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Marathon is currently evaluating the provisions of this Statement to determine the impact on its consolidated financial statements.

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ITEM 3. Quantitative and Qualitative Disclosures About Market Risk
Management Opinion Concerning Derivative Instruments
     Management has authorized the use of futures, forwards, swaps and options to manage exposure to market fluctuations in commodity prices, interest rates and foreign currency exchange rates.
     We use commodity-based derivatives to manage price risk related to the purchase, production or sale of crude oil, natural gas and refined products. To a lesser extent, we are exposed to the risk of price fluctuations on natural gas liquids and petroleum feedstocks used as raw materials, and purchases of ethanol.
     Our strategy has generally been to obtain competitive prices for our products and allow operating results to reflect market price movements dictated by supply and demand. We use a variety of derivative instruments, including option combinations, as part of the overall risk management program to manage commodity price risk in our different businesses. As market conditions change, we evaluate our risk management program and could enter into strategies that assume market risk whereby cash settlement of commodity-based derivatives will be based on market prices.
     Our E&P segment primarily uses commodity derivative instruments selectively to protect against price decreases on portions of our future production when deemed advantageous to do so. We also use derivatives to protect the value of natural gas purchased and injected into storage in support of production operations. We use commodity derivative instruments to mitigate the price risk associated with the purchase and subsequent resale of natural gas on purchased volumes and anticipated sales volumes.
Our RM&T segment uses commodity derivative instruments:
    to mitigate the price risk:
     o   between the time foreign and domestic crude oil and other feedstock purchases for refinery supply are priced and when they are actually refined into salable petroleum products,
 
     o   associated with anticipated natural gas purchases for refinery use,
 
     o   associated with freight on crude oil, feedstocks and refined product deliveries, and
 
     o   on fixed price contracts for ethanol purchases;
    to protect the value of excess refined product, crude oil and liquefied petroleum gas inventories;
 
    to protect margins associated with future fixed price sales of refined products to non-retail customers;
 
    to protect against decreases in future crack spreads;
 
    to take advantage of trading opportunities identified in the commodity markets.
     We use financial derivative instruments in each of our segments to manage foreign currency exchange rate exposure on foreign currency denominated capital expenditures, operating expenses and foreign tax payments.
     We use financial derivative instruments to manage interest rate risk exposures. As we enter into these derivatives, assessments are made as to the qualification of each transaction for hedge accounting.
     We believe that our use of derivative instruments, along with risk assessment procedures and internal controls, does not expose us to material risk. However, the use of derivative instruments could materially affect our results of operations in particular quarterly or annual periods. We believe that the use of these instruments will not have a material adverse effect on our financial position or liquidity.

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Commodity Price Risk
     Sensitivity analyses of the incremental effects on income from operations (“IFO”) of hypothetical 10 percent and 25 percent changes in commodity prices for open derivative commodity instruments as of June 30, 2006 are provided in the following table:
                 
    Incremental Decrease in IFO Assuming a
    Hypothetical Price Change of (a):
(Dollars in millions)   10%   25%
Commodity Derivative Instruments: (b)(c)
               
Crude oil (d)
  $ 29   (e)   $ 65   (e)
Natural gas (d)
    76   (e)     190   (e)
Refined products (d)
    42   (e)     115   (e)
 
               
 
(a)   We remain at risk for possible changes in the market value of derivative instruments; however, such risk should be mitigated by price changes in the underlying hedged item. Effects of these offsets are not reflected in the sensitivity analyses. Amounts reflect hypothetical 10 percent and 25 percent changes in closing commodity prices, excluding basis swaps, for each open contract position at June 30, 2006. Included in the natural gas impacts shown above are $85 million and $211 million related to the long-term U.K. natural gas contracts for hypothetical price changes of 10 percent and 25 percent, respectively. We evaluate our portfolio of derivative commodity instruments on an ongoing basis and add or revise strategies in anticipation of changes in market conditions and in risk profiles. We are also exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is reviewed continuously and master netting agreements are used when practical. Changes to the portfolio after June 30, 2006, would cause future IFO effects to differ from those presented in the table.
 
(b)   The number of net open contracts for the E&P segment varied throughout the second quarter of 2006, from a low of 316 contracts on June 27, 2006 to a high of 1,165 contracts on April 20, 2006, and averaged 794 for the quarter. The number of net open contracts for the RM&T segment varied throughout the second quarter of 2006, from a low of 8,802 contracts on April 2, 2006 to a high of 19,748 contracts on May 4, 2006, and averaged 14,700 for the quarter. The derivative commodity instruments used and hedging positions taken will vary and, because of these variations in the composition of the portfolio over time, the number of open contracts by itself cannot be used to predict future income effects.
 
(c)   The calculation of sensitivity amounts for basis swaps assumes that the physical and paper indices are perfectly correlated. Gains and losses on options are based on changes in intrinsic value only.
 
(d)   The direction of the price change used in calculating the sensitivity amount for each commodity reflects that which would result in the largest incremental decrease in IFO when applied to the commodity derivative instruments used to hedge that commodity.
 
(e)   Price increase.
E&P Segment
     Derivative gains of $24 million and $2 million were included in the E&P segment for the first six months of 2006 and 2005. The results of activities primarily associated with the marketing of our equity natural gas production, which had been presented as part of the Integrated Gas segment prior to 2006, are now included in the E&P segment.
     Excluded from the E&P segment results were gains of $61 million and losses of $224 million for the first six months of 2006 and 2005 related to long-term natural gas contracts in the United Kingdom that are accounted for as derivative instruments.
     At June 30, 2006, we had no open derivative commodity contracts related to our oil and natural gas production, and therefore we remain exposed to market prices of commodities. We continue to evaluate the commodity price risks related to our production and may enter into derivative commodity instruments when it is deemed advantageous. As a particular but not exclusive example, we may elect to use derivative commodity instruments to achieve minimum price levels on some portion of our production to support capital or acquisition funding requirements.

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RM&T Segment
     We do not attempt to qualify commodity derivative instruments used in our RM&T operations for hedge accounting. As a result, we recognize in income all changes in the fair value of derivatives used in our RM&T operations. Pre-tax derivative gains and losses included in RM&T segment income for the first six months of 2006 and 2005 are summarized in the following table:
                 
    Six Months Ended June 30,  
(Dollars in millions)   2006     2005  
Strategy:
               
Mitigate price risk
  $ (105 )   $ (19 )
Protect carrying values of excess inventories
    (78 )     (67 )
Protect margin on fixed price sales
    10       15  
Protect crack spread values
    (5 )     (68 )
 
           
Subtotal, non-trading activities
    (178 )     (139 )
Trading activities
    (2 )     (34 )
 
           
Total net derivative losses
  $ (180 )   $ (173 )
 
           
     Derivatives used in non-trading activities have an underlying physical commodity transaction. Derivative losses occur when market prices increase, and generally are offset by gains on the underlying physical commodity transactions. Conversely, derivative gains occur when market prices decrease, which are offset by losses on the underlying physical commodity transactions.
Other Commodity Related Risks
     We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. Natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets. For example, New York Mercantile Exchange (“NYMEX”) contracts for natural gas are priced at Louisiana’s Henry Hub, while the underlying quantities of natural gas may be produced and sold in the western United States at prices that do not move in strict correlation with NYMEX prices. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased exposure to basis risk. These regional price differences could yield favorable or unfavorable results. Over-the-counter transactions are being used to manage exposure to a portion of basis risk.
     We are impacted by liquidity risk, caused by timing delays in liquidating contract positions due to a potential inability to identify a counterparty willing to accept an offsetting position. Due to the large number of active participants, liquidity risk exposure is relatively low for exchange-traded transactions.
Interest Rate Risk
     We are impacted by interest rate fluctuations which affect the fair value of certain financial instruments. A sensitivity analysis of the projected incremental effect of a hypothetical 10 percent decrease in interest rates as of June 30, 2006 is provided in the following table:
                 
            Incremental Increase in
(Dollars in millions)   Fair Value (b)   Fair Value (c )
Financial assets (liabilities) (a)
               
 
               
Interest rate swap agreements
  $ (38 )   $ 12  
Long-term debt, including that due within one year (d)
    (3,806 )     (150 )
 
(a)   Fair values of cash and cash equivalents, receivables, notes payable, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.
 
(b)   Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.
 
(c)   Assumes a 10 percent decrease in the June 30, 2006 effective swap rate or a 10 percent decrease in the weighted average yield to maturity of our long-term debt at June 30, 2006, as appropriate.
 
(d)   See below for sensitivity analysis.
     At June 30, 2006, our portfolio of long-term debt was substantially comprised of fixed rate instruments. Therefore, the fair value of the portfolio is relatively sensitive to effects of interest rate fluctuations. This sensitivity is illustrated by the $150 million increase in the fair value of long-term debt assuming a hypothetical 10 percent decrease in interest rates. However, our sensitivity to interest rate declines and corresponding increases in the fair value of our debt

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portfolio would unfavorably affect our results of operations and cash flows only if we would elect to repurchase or otherwise retire all or a portion of our fixed-rate debt portfolio at prices above carrying value.
     We manage our exposure to interest rate movements by utilizing financial derivative instruments. The primary objective of this program is to reduce our overall cost of borrowing by managing the fixed and floating interest rate mix of the debt portfolio. We have entered into several interest rate swap agreements, designated as fair value hedges, which effectively resulted in an exchange of existing obligations to pay fixed interest rates for obligations to pay floating rates. There have been no unexpected changes to the positions subsequent to December 31, 2005.
Foreign Currency Exchange Rate Risk
     We manage our exposure to foreign currency exchange rates by utilizing forward and option contracts. The primary objective of this program is to reduce our exposure to movements in the foreign currency markets by locking in foreign currency rates. The aggregate effect on foreign exchange contracts of a hypothetical 10 percent change to quarter-end forward exchange rates would be approximately $35 million. There have been no significant changes to our exposure to foreign exchange rates subsequent to December 31, 2005.
Credit Risk
     We are exposed to significant credit risk from United States Steel arising from the Separation. That exposure is discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations — Obligations Associated with the Separation of United States Steel.
Safe Harbor
     These quantitative and qualitative disclosures about market risk include forward-looking statements with respect to management’s opinion about risks associated with the use of derivative instruments. These statements are based on certain assumptions with respect to market prices and industry supply of and demand for crude oil, natural gas, refined products and other feedstocks. If these assumptions prove to be inaccurate, future outcomes with respect to our hedging programs may differ materially from those discussed in the forward-looking statements.
Item 4. Controls and Procedures
     An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-14 and 15d-14 under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of Marathon’s management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this report based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective. During the quarter ended June 30, 2006, there were no changes in our internal controls over financial reporting that have materially affected, or were reasonably likely to materially affect, our internal controls over financial reporting.
     Marathon reviews and modifies its financial and operational controls on an ongoing basis to ensure that those controls are adequate to address changes in its business as it evolves. Marathon believes that its existing financial and operational controls and procedures are adequate.

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MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)
                                 
    Second Quarter     Six Months  
    Ended June 30,     Ended June 30,  
(Dollars in millions, except as noted)   2006     2005     2006     2005  
SEGMENT INCOME:
                               
 
                               
Exploration and Production
                               
United States
  $ 243     $ 258     $ 488     $ 435  
International
    416       246       636       403  
 
                       
E&P Segment
    659       504       1,124       838  
Refining, Marketing and Transportation(a)
    917       316       1,236       390  
Integrated Gas
    17             25       22  
 
                       
Segment Income
    1,593       820       2,385       1,250  
Items not allocated to segments, net of income taxes:
                               
Long-term U.K. natural gas contracts
    (10 )     (97 )     35       (130 )
Corporate and other unallocated items
    (99 )     (70 )     (165 )     (144 )
Ohio tax legislation
          15             15  
Discontinued operations
    264       5       277       6  
 
                       
Net income
  $ 1,748     $ 673     $ 2,532     $ 997  
 
                       
 
                               
CAPITAL EXPENDITURES:
                               
Exploration and Production
  $ 463     $ 296     $ 821     $ 566  
Refining, Marketing and Transportation(a)
    200       166       304       302  
Integrated Gas(b)
    70       183       164       308  
Discontinued Operations
    19       23       45       47  
Corporate
    2       2       19       3  
 
                       
Total
  $ 754     $ 670     $ 1,353     $ 1,226  
 
                               
EXPLORATION EXPENSE:
                               
United States
  $ 41     $ 24     $ 69     $ 41  
International
    25       12       68       25  
 
                       
Total
  $ 66     $ 36     $ 137     $ 66  
 
                               
E&P OPERATING STATISTICS
                               
 
                               
Net Liquid Hydrocarbon Sales (mbpd)(c)
                               
United States
    79       85       79       79  
 
                               
Europe
    47       49       38       40  
Africa
    133       61       103       48  
 
                       
Total International
    180       110       141       88  
 
                       
Worldwide Continuing Operations
    259       195       220       167  
Discontinued Operations
    20       24       25       24  
 
                       
Worldwide
    279       219       245       191  
 
                               
Net Natural Gas Sales (mmcfd)(c)(d)
                               
United States
    523       579       542       575  
 
Europe
    226       205       286       288  
Africa
    52       108       70       96  
 
                       
Total International
    278       313       356       384  
 
                       
Worldwide
    801       892       898       959  
 
                               
Total Worldwide Sales (mboepd)
    412       368       395       351  
Discontinued operations (mboepd)
    20       24       25       24  
Continuing operations (mboepd)
    392       344       370       327  
 
                       
 
(a)   RM&T segment income for the second quarter and first six months of 2005 is net of $309 million and $376 million pretax minority interest in MPC. RM&T capital expenditures include MPC at 100 percent.
 
(b)   Includes Equatorial Guinea LNG Holdings at 100 percent.
 
(c)   Amounts reflect sales after royalties, except for Ireland where amounts are before royalties.
 
(d)   Includes natural gas acquired for injection and subsequent resale of 60 mmcfd and 22 mmcfd in the second quarters of 2006 and 2005, and 50 mmcfd and 21 mmcfd for the first six months of 2006 and 2005. Effective July 1, 2005, the methodology for allocating sales volumes between natural gas produced from the Brae complex and third-party natural gas production was modified, resulting in an increase in volumes representing natural gas acquired for injection and subsequent resale.

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MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)
                                 
    Second Quarter     Six Months  
    Ended June 30,     Ended June 30,  
    2006     2005     2006     2005  
E&P OPERATING STATISTICS (continued)
                               
 
                               
Average Realizations (e)
                               
Liquid Hydrocarbons ($  per bbl)
                               
United States
  $ 59.80     $ 42.22     $ 54.52     $ 40.52  
 
                               
Europe
    67.52       49.77       65.43       48.06  
Africa
    65.14       46.53       60.36       45.31  
Total International
    65.76       47.98       61.74       46.55  
Worldwide Continuing Operations
    63.95       45.45       59.14       43.71  
Discontinued Operations
    39.80       34.50       38.38       29.69  
Worldwide
  $ 62.19     $ 44.23     $ 57.04     $ 41.94  
 
                               
Natural Gas ($  per mcf)
                               
United States
  $ 5.35     $ 5.76     $ 6.02     $ 5.36  
 
                               
Europe
    6.32       4.78       7.13       4.95  
Africa
    0.25       0.26       0.25       0.25  
Total International
    5.19       3.22       5.78       3.78  
Worldwide
  $ 5.29     $ 4.87     $ 5.93     $ 4.73  
 
                       
 
                               
RM&T OPERATING STATISTICS
                               
 
                               
Refinery Runs (mbpd):
                               
Crude oil refined
    1,038       1,012       968       967  
Other charge and blend stocks
    207       175       228       173  
 
                       
Total
    1,245       1,187       1,196       1,140  
 
                               
Refined Product Yields (mbpd):
                               
Gasoline
    663       636       654       606  
Distillates
    321       327       306       310  
Propane
    24       23       22       21  
Feedstocks and special products
    125       98       116       107  
Heavy fuel oil
    25       20       24       26  
Asphalt
    102       97       89       85  
 
                       
Total
    1,260       1,201       1,211       1,155  
 
                               
Refined Products Sales Volumes (mbpd)(f)(g)
    1,461       1,477       1,439       1,424  
Matching buy/sell volumes included in refined product sales volumes (mbpd) (g)
    11       87       47       84  
 
                               
Refining and Wholesale Marketing Gross Margin ($/gallon)(h)
  $ 0.2978     $ 0.1592     $ 0.2077     $ 0.1158  
 
                               
Number of SSA Retail Outlets
    1,637       1,647                  
 
                               
SSA Gasoline and Distillate Sales(i)
    816       822       1,592       1,567  
SSA Gasoline and Distillate Gross Margin ($/gallon)
  $ 0.1019     $ 0.1211     $ 0.1037     $ 0.1138  
 
                               
SSA Merchandise Sales
  $ 690     $ 645     $ 1,300     $ 1,205  
SSA Merchandise Gross Margin
  $ 171     $ 163     $ 319     $ 306  
 
                       
 
(e)   Excludes all derivative gains and losses, including the effects of long-term U.K. natural gas contracts that are accounted for as derivatives.
 
(f)   Total average daily volumes of all refined product sales to wholesale, branded and retail (SSA) customers.
 
(g)   As a result of the change in accounting for matching buy/sell arrangements on April 1, 2006, the reported sales volumes will be lower than the volumes determined under the previous accounting practices. See Note 2 to the consolidated financial statements, “New Accounting Standards.”
 
(h)   Sales revenue less cost of refinery inputs, purchased products and manufacturing expenses, including depreciation. As a result of the change in accounting for matching buy/sell transactions on April 1, 2006, the resulting per gallon statistic will be higher than the statistic that would have been calculated from amounts determined under previous accounting practices. See Note 2 to the consolidated financial statements, “New Accounting Standards.”
 
(i)   Millions of gallons.

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Part II — OTHER INFORMATION
Item 1. Legal Proceedings
Montana Litigation
     In June 2006, Marathon and another operator filed a complaint for declaratory judgment in Montana State District Court against the Montana Board of Environmental Review (“MBER”), and the Montana Department of Environmental Quality (“MDEQ”), seeking to set aside and declare invalid certain 2006 regulations (and underlying 2003 regulations) of the MBER that single out the coal bed natural gas industry and a few streams in eastern Montana for excessively severe and unjustified restrictions for surface water discharges of produced water from coal bed methane operations. None of the streams affected by the regulations suffers impairment from coal bed natural gas discharges. The complaint alleges that MBER violated Montana State law in that it adopted regulations without sound scientific justification, proposed water quality standards more stringent than federal law without required justification, and neglected to prepare an environmental impact statement to address resultant harm to jobs and communities from the regulations.
Item 1A. Risk Factors
     Marathon is subject to various risks and uncertainties in the course of its business. See the discussion of such risks and uncertainties under Item 1A. Risk Factors in Marathon’s 2005 Annual Report on Form 10-K. There have been no material changes from the risk factors previously disclosed in that Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
ISSUER PURCHASES OF EQUITY SECURITIES
                                 
    (a)   (b)   (c)   (d)
                    Total Number of   Approximate Dollar
                    Shares Purchased   Value of Shares that
                as Part of Publicly   May Yet Be
    Total Number of   Average Price Paid   Announced Plans   Purchased Under the
Period   Shares Purchased (a)(b)   per Share   or Programs (d)   Plans or Programs (d)
04/01/06 — 04/30/06
    1,505,468     $ 79.80       1,498,100     $ 1,651,291,662  
05/01/06 — 05/31/06
    1,333,472     $ 77.98       1,332,400     $ 1,547,393,011  
06/01/06 — 06/30/06
    1,383,061 (c)   $ 74.60       1,361,100     $ 1,445,827,171  
Total
    4,222,001     $ 77.52       4,191,600          
 
(a)   9,552 shares of restricted stock were delivered by employees to Marathon, upon vesting, to satisfy tax withholding requirements.
 
(b)   Under the terms of the transaction whereby Marathon acquired the minority interest in MPC and other businesses from Ashland Inc., Marathon paid Ashland Inc. shareholders cash in lieu of issuing fractional shares of Marathon’s common stock to which such holders would otherwise be entitled. Marathon acquired 3 shares due to acquisition share exchanges and Ashland Inc. share transfers pending at the closing of the transaction.
 
(c)   20,846 shares were repurchased in open-market transactions to satisfy the requirements for dividend reinvestment under the Marathon Oil Corporation Dividend Reinvestment and Direct Stock Purchase Plan (the “Dividend Reinvestment Plan”) by the administrator of the Dividend Reinvestment Plan. Stock needed to meet the requirements of the Dividend Reinvestment Plan are either purchased in the open market or issued directly by Marathon.
 
(d)   On January 29, 2006, our Board of Directors authorized the repurchase of up to $2 billion of common stock over a period of two years. On July 26, 2006 we announced that purchases under the program were being accelerated. We currently anticipate repurchasing $1.5 billion of our common stock by December 31, 2006, with the balance of the shares being repurchased in 2007. This program does not include specific price targets and may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion.

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Item 4. Submission of Matters to a Vote of Security Holders
     The annual meeting of stockholders was held on April 26, 2006. In connection with the meeting, proxies were solicited pursuant to the Securities Exchange Act of 1934. The following are the voting results on proposals considered and voted upon at the meeting, all of which were described in Marathon’s 2006 Proxy Statement.
1.   Votes regarding the persons elected to serve as Class I directors for a term expiring in 2009 were as follows:
                 
       NOMINEE   VOTES FOR   VOTES WITHHELD
Clarence P. Cazalot, Jr.
    306,764,458       15,827,069  
David A. Daberko
    303,433,496       19,158,031  
William L. Davis
    310,566,832       12,024,695  
    Continuing as Class II directors for a term expiring in 2007 are Charles F. Bolden, Jr., Charles R. Lee, Dennis H. Reilley and Thomas J. Usher. Continuing as Class III directors for a term expiring in 2008 are Shirley Ann Jackson, Philip Lader, Seth E. Schofield and Douglas C. Yearley.
 
2.   PricewaterhouseCoopers LLP was ratified as the independent auditors for 2006. The voting results were as follows:
         
VOTES FOR   VOTES AGAINST   VOTES ABSTAINED
315,237,067
  4,911,915   2,416,550
3.   The Board of Directors proposal to amend the Restated Certificate of Incorporation to declassify the Board of Directors was approved. The voting results were as follows:
         
VOTES FOR   VOTES AGAINST   VOTES ABSTAINED
316,615,678   3,100,505   2,838,147
4.   The Board of Directors proposal to amend the Restated Certificate of Incorporation to revise the purpose clause, eliminate the Series A Junior Preferred Stock and make other technical changes was approved. The voting results were as follows:
         
VOTES FOR   VOTES AGAINST   VOTES ABSTAINED
318,561,637   1,089,662   2,903,498
5.   The stockholder proposal to elect directors by a majority vote was approved. The proposal requested that the Board of Directors initiate the appropriate process to amend the Company’s governance documents (certificate of incorporation or bylaws) to provide that a director nominee shall be elected by the affirmative vote of the majority of votes cast at an annual meeting of shareholders. The voting results were as follows:
             
VOTES   VOTES   VOTES   BROKER
FOR   AGAINST   ABSTAINED   NON-VOTES
191,576,749   91,294,280   3,975,143   35,745,355
6.   The stockholder proposal for a simple majority vote of shareholders was approved. The proposal recommended that the Board of Directors take each step necessary for a simple majority vote to apply on each issue that can be subject to shareholder vote to the greatest extent possible. The voting results were as follows:
             
VOTES   VOTES   VOTES   BROKER
FOR   AGAINST   ABSTAINED   NON-VOTES
236,460,419   47,119,626   3,265,194   35,746,288

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Item 6. Exhibits
12.1   Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
 
12.2   Computation of Ratio of Earnings to Fixed Charges
 
31.1   Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
 
31.2   Certification of Senior Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
 
32.1   Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350
 
32.2   Certification of Senior Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350

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SIGNATURES
     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
             
 
           
    MARATHON OIL CORPORATION    
 
           
 
  By:   Michael K. Stewart    
 
           
 
      Michael K. Stewart    
 
      Vice President, Accounting and Controller    
August 7, 2006

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Index to Exhibit
     
12.1
  Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
 
   
12.2
  Computation of Ratio of Earnings to Fixed Charges
 
   
31.1
  Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
 
   
31.2
  Certification of Senior Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
 
   
32.1
  Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350
 
   
32.2
  Certification of Senior Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350

40