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Cautionary Note to U.S. Investors - The information contained in this website is provided solely for convenience. The documents contained herein are historical in nature. Therefore, events following the date of publication or subsequently available information may have rendered obsolete the estimates, assertions or other information contained in these documents. All information is provided without warranty of any kind. Marathon Oil assumes no duty to update the information contained in any of the documents and further assumes no responsibility for the accuracy of the information. Marathon Oil further reserves the right to change the content of the site at any time without notice.

Any person who uses, or makes decisions upon, information contained in this website does so at their own risk and agrees to hold Marathon Oil Corporation and its subsidiaries and affiliates harmless. Marathon Oil Corporation and its employees and representatives further expressly disclaim all liability for any costs, expenses, damages or consequences of any type that may result from reliance on the information obtained from this website or any website linked hereto.

The United States Securities and Exchange Commission (the "SEC") permits oil and gas companies, in their filings with the SEC, to disclose only proved probable and possible reserves. From time to time, we may use certain terms on this website or the documents contained herein, such as net unrisked mean resource potential, net unrisked resource potential, net resource, 2P resource, 2P net resource, net 2P resource, gross unrisked potential resource, gross resources, gross discovered resources, gross resource potential, gross block resource potential, resources, resource potential, potential resource, and other similar terms or variations of the foregoing terms. The SEC guidelines strictly prohibit us from including these terms in filings with the SEC. U.S. Investors are urged to consider closely the disclosures in our Forms 10-K, 10-Qs and 8-Ks, Commission File No. 1-5153, available from us at Marathon Oil Corporation, Attn. Investor Relations, 5555 San Felipe Street, Houston, TX 77056-2723. Our Form 10-K and other filings with the SEC can also be electronically accessed from our website or the SEC's website at http://www.sec.gov/.

form10q2010q1.htm



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549


FORM 10-Q


(Mark One)
 
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the Quarterly Period Ended March 31, 2010

OR

[   ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from _____ to _____

Commission file number 1-5153

Marathon Oil Corporation
(Exact name of registrant as specified in its charter)

Delaware
25-0996816
(State or other jurisdiction of incorporation or organization)
(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, including area code)

 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.        Yes    x    No           

 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.) Yes    x   No           
 
 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer       x   
Accelerated filer            
Non-accelerated filer               (Do not check if a smaller reporting company) 
Smaller reporting company           
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).        Yes            No    x     

 
There were 709,502,223 shares of Marathon Oil Corporation common stock outstanding as of April 30, 2010.
 
 


 

 
 
 


MARATHON OIL CORPORATION
 
Form 10-Q
 
Quarter Ended March 31, 2010


   
 
Page
PART I - FINANCIAL INFORMATION
Item 1.
Financial Statements:
 
 
 
 
 
 
Item 2.
Item 3.
Item 4.
 
PART II - OTHER INFORMATION
Item 1.
Item 1A.
Item 2.
Item 6.
 

 
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).

1
 
 
 
Part I - Financial Information
 
Item 1. Financial Statements

MARATHON OIL CORPORATION
 
Consolidated Statements of Income (Unaudited)
 

             
   
Three Months Ended March 31,
 
(In millions, except per share data)
 
2010
   
2009
 
Revenues and other income:
           
             
   Sales and other operating revenues (including consumer excise taxes)
  $ 15,849     $ 10,156  
   Sales to related parties
    20       20  
   Income from equity method investments
    105       47  
   Net gain on disposal of assets
    813       4  
   Other income
    33       52  
                 
             Total revenues and other income
    16,820       10,279  
                 
Costs and expenses:
               
   Cost of revenues (excludes items below)
    12,881       7,357  
   Purchases from related parties
    133       95  
   Consumer excise taxes
    1,212       1,174  
   Depreciation, depletion and amortization
    649       660  
   Long-lived asset impairments
    434       -  
   Selling, general and administrative expenses
    298       291  
   Other taxes
    115       102  
   Exploration expenses
    98       62  
                 
            Total costs and expenses
    15,820       9,741  
                 
Income from operations
    1,000       538  
   Net interest and other financing costs
    (30 )     (16 )
                 
Income from continuing operations before income taxes
    970       522  
   Provision for income taxes
    513       257  
                 
Income from continuing operations
    457       265  
                 
Discontinued operations
    -       17  
                 
Net income
  $ 457     $ 282  
                 
Per Share Data
               
                 
Basic:
               
     Income from continuing operations
  $ 0.64     $ 0.37  
     Discontinued operations
  $ -     $ 0.03  
     Net income
  $ 0.64     $ 0.40  
                 
Diluted:
               
     Income from continuing operations
  $ 0.64     $ 0.37  
     Discontinued operations
  $ -     $ 0.03  
     Net income
  $ 0.64     $ 0.40  
                 
Dividends paid
  $ 0.24     $ 0.24  
 
 
The accompanying notes are an integral part of these consolidated financial statements.

2
 
 

MARATHON OIL CORPORATION
 
Consolidated Balance Sheets (Unaudited)
 
 
 
 
   
 
 
 
 
March 31,
   
December 31,
 
(In millions, except per share data)
 
2010
   
2009
 
Assets
 
 
   
 
 
Current assets:
 
 
   
 
 
    Cash and cash equivalents
  $ 2,718     $ 2,057  
    Receivables, less allowance for doubtful accounts of $14 and $14
    4,860       4,677  
    Receivables from United States Steel
    22       22  
    Receivables from related parties
    70       60  
    Inventories
    3,848       3,622  
    Other current assets
    221       199  
 
               
            Total current assets
    11,739       10,637  
 
               
Equity method investments
    2,004       1,970  
Receivables from United States Steel
    320       324  
Property, plant and equipment, less accumulated depreciation,
               
   depletion and amortization of $18,217 and $17,185
    31,674       32,121  
Goodwill
    1,414       1,422  
Other noncurrent assets
    574       578  
 
               
            Total assets
  $ 47,725     $ 47,052  
Liabilities
               
Current liabilities:
               
    Accounts payable
  $ 7,143     $ 6,982  
    Payables to related parties
    59       64  
    Payroll and benefits payable
    360       399  
    Accrued taxes
    679       547  
    Deferred income taxes
    408       403  
    Other current liabilities
    638       566  
    Long-term debt due within one year
    98       96  
 
               
            Total current liabilities
    9,385       9,057  
 
               
Long-term debt
    8,440       8,436  
Deferred income taxes
    4,099       4,104  
Defined benefit postretirement plan obligations
    2,078       2,056  
Asset retirement obligations
    1,121       1,099  
Payable to United States Steel
    5       5  
Deferred credits and other liabilities
    370       385  
 
               
            Total liabilities
    25,498       25,142  
 
               
Commitments and contingencies
               
 
               
Stockholders’ Equity
               
Preferred stock – 5 million shares issued,  1 million shares
               
          outstanding (no par value, 6 million shares authorized)
    -       -  
Common stock:
               
     Issued – 769 million and 769 million shares (par value $1 per share,
               
          1.1 billion shares authorized)
    769       769  
     Securities exchangeable into common stock – 5 million shares issued,
               
          1 million shares outstanding (no par value, unlimited
               
          shares authorized)
    -       -  
     Held in treasury, at cost –  61 million shares
    (2,696 )     (2,706 )
Additional paid-in capital
    6,751       6,738  
Retained earnings
    18,328       18,043  
Accumulated other comprehensive loss
    (925 )     (934 )
 
 
               
            Total stockholders' equity
    22,227       21,910  
 
               
            Total liabilities and stockholders' equity
  $ 47,725     $ 47,052  
 
 
The accompanying notes are an integral part of these consolidated financial statements.

3
 
 

MARATHON OIL CORPORATION
 
Consolidated Statements of Cash Flows (Unaudited)
 

 
 
Three Months Ended March 31,
 
(In millions)
 
2010
   
2009
 
Increase (decrease) in cash and cash equivalents
 
 
   
 
 
Operating activities:
 
 
   
 
 
Net income
  $ 457     $ 282  
Adjustments to reconcile net income to net cash provided by operating activities:
               
    Discontinued operations
    -       (17 )
    Deferred income taxes
    (25 )     50  
    Depreciation, depletion and amortization
    649       660  
    Long-lived asset impairments
    434       -  
    Pension and other postretirement benefits, net
    50       38  
    Exploratory dry well costs and unproved property impairments
    52       16  
    Net gain on disposal of assets
    (813 )     (4 )
    Equity method investments, net
    (42 )     11  
    Changes in:
               
          Current receivables
    (193 )     200  
          Inventories
    (235 )     18  
          Current accounts payable and accrued liabilities
    448       (473 )
    All other operating, net
    67       29  
               Net cash provided by continuing operations
    849       810  
               Net cash provided by discontinued operations
    -       29  
               Net cash provided by operating activities
    849       839  
Investing activities:
               
    Additions to property, plant and equipment
    (1,348 )     (1,586 )
    Disposal of assets
    1,342       20  
    Trusteed funds - withdrawals
    -       13  
    Investments - loans and advances
    (7 )     (3 )
    Investments - repayments of loans and return of capital
    14       26  
    Investing activities of discontinued operations
    -       (34 )
    All other investing, net
    (11 )     6  
               Net cash used in investing activities
    (10 )     (1,558 )
Financing activities:
               
    Borrowings
    -       1,491  
    Debt issuance costs
    -       (11 )
    Debt repayments
    (2 )     (3 )
    Dividends paid
    (172 )     (170 )
    All other financing, net
    2       -  
               Net cash provided by (used in) financing activities
    (172 )     1,307  
Effect of exchange rate changes on cash:
               
    Continuing operations
    (6 )     (2 )
    Discontinued operations
    -       (2 )
               Total effect of exchange rate changes on cash
    (6 )     (4 )
Net increase in cash and cash equivalents
    661       584  
Cash and cash equivalents at beginning of period
    2,057       1,285  
Cash and cash equivalents at end of period
  $ 2,718     $ 1,869  
 
 
The accompanying notes are an integral part of these consolidated financial statements.

4
 
 

MARATHON OIL CORPORATION
 
Consolidated Statements of Comprehensive Income (Unaudited)
 

 
 
Three Months Ended March 31,
 
(In millions)
 
2010
   
2009
 
Net income
  $ 457     $ 282  
    Other comprehensive income (loss)
               
 
               
         Post-retirement and post-employment plans
               
            Change in actuarial gain
    30       8  
            Income tax provision on post-retirement and post-employment plans
    (24 )     (9 )
                Post-retirement and post-employment plans, net of tax
    6       (1 )
 
               
     Derivative hedges
               
           Net unrecognized gain (loss)
    2       (27 )
           Income tax benefit (provision) on derivatives
    1       (3 )
                Derivative hedges, net of tax
    3       (30 )
 
               
      Foreign currency translation and other
               
          Unrealized gain
    -       2  
           Income tax provision on foreign currency translation and other
    -       (1 )
               Foreign currency translation and other, net of tax
    -       1  
 
               
Other comprehensive income (loss)
    9       (30 )
 
               
Comprehensive income
  $ 466     $ 252  
 
 
The accompanying notes are an integral part of these consolidated financial statements.

5
 

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
 


1.      Basis of Presentation
 
These consolidated financial statements are unaudited; however, in the opinion of management these statements 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 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.
 
 
These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Marathon Oil Corporation (“Marathon”) 2009 Annual Report on Form 10-K.  The results of operations for the quarter ended March 31, 2010, are not necessarily indicative of the results to be expected for the full year.
 
 
Reclassifications – We have revised 2009 amounts of capital expenditures in the consolidated statement of cash flows.  The presentation within the consolidated statement of cash flows for additions to property, plant and equipment reflects capital expenditures on a cash basis.  The following reflects the reclassifications made:
 

 
Three Months Ended
 
Six Months Ended
 
Nine Months Ended
 
(in millions)
March 31, 2009
 
June 30, 2009
 
September 30, 2009
 
Capital expenditures from continuing operations,
                 
     previously reported
  $ (1,336 )   $ (2,939 )   $ (4,350 )
Discontinued operations, previously reported
    -       (47 )     (66 )
Reclassification of capital accruals
    (284 )     (287 )     (402 )
Additions to property, plant and equipment,
                       
     including discontinued operations
  $ (1,620 )   $ (3,273 )   $ (4,818 )
                         
    The corresponding offsets to the amounts above have been reflected within cash provided by operating activities through change in current accounts payable and accrued liabilities.
 
                 
                         
 
Three Months Ended
 
Six Months Ended
 
Nine Months Ended
 
(in millions)
March 31, 2009
 
June 30, 2009
 
September 30, 2009
 
Cash flow from operations, previously reported
  $ 555     $ 1,750     $ 2,906  
Reclassification of capital accruals
    284       287       402  
Cash flow from operations
  $ 839     $ 2,037     $ 3,308  

2.      Accounting Standards

Recently Adopted
 
Variable interest accounting standards were amended by the Financial Accounting Standards Board (“FASB”) in June 2009.  The new accounting standards replace the existing quantitative-based risks and rewards calculation for determining which enterprise has a controlling financial interest in a variable interest entity with an approach focused on identifying which enterprise has the power to direct the activities of a variable interest entity.  In addition, the concept of qualifying special-purpose entities has been eliminated.  Ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity are also required.  The amended variable interest accounting standard requires reconsideration for determining whether an entity is a variable interest entity when changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lack the power from voting rights or similar rights to direct the activities of the entity.  Enhanced disclosures are required for any enterprise that holds a variable interest in a variable interest entity. Prospective application of this standard in the first quarter of 2010 did not have significant impact on our consolidated results of operations, financial position or cash flows.  The required disclosures are presented in Note 3.
 
 
A standard to improve disclosures about fair value measurements was issued by the FASB in January 2010.  The additional disclosures required include: (1) the different classes of assets and liabilities measured at fair value, (2) the significant inputs and techniques used to measure Level 2 and Level 3 assets and liabilities for both recurring and nonrecurring fair value measurements, (3) the gross presentation of purchases, sales, issuances and settlements for the
 

6
 

 
Notes to Consolidated Financial Statements (Unaudited)
 

 
rollforward of Level 3 activity, and (4) the transfers in and out of Levels 1 and 2.  We adopted all aspects of this standard in the first quarter of 2010, including the gross presentation of the Level 3 activity rollforward, which could have been deferred until next year.  This adoption did not have a significant impact on our consolidated results of operations, financial position or cash flows.  The required disclosures are presented in Note 11.
 
Oil and Gas Reserve Estimation and Disclosure standards were issued by the FASB in January 2010, which align the FASB’s reporting requirements with the Securities and Exchange Commission (“SEC”) requirements.  Similar to the SEC requirements, the FASB requirements were effective for periods ending on or after December 31, 2009.  The SEC introduced a new definition of oil and gas producing activities which allows companies to include volumes in their reserve base from unconventional resources.  The FASB also addresses the impact of changes in the SEC’s rules and definitions on accounting for oil and gas producing activities.  Initial adoption did not have an impact on our consolidated results of operations, financial position or cash flows; however, there will be an impact on the amount of depreciation, depletion and amortization expense recognized in future periods.  The effect on depreciation, depletion and amortization expense in the first quarter of 2010, as compared to prior periods, was not significant.

 
3.      Variable Interest Entities
 
 
The Athabasca Oil Sands Project (“AOSP”), in which we hold a 20 percent undivided interest, contracted with a wholly-owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River mine, the Scotford upgrader and markets in Edmonton.  The contract, originally signed in 1999 by a company we acquired, allows each holder of an undivided interest in the AOSP to ship materials in accordance with its undivided interest.  Costs under this contract are accrued and recorded on a monthly basis, with a $1 million current liability recorded at March 31, 2010.  Under this agreement, the AOSP absorbs all of the operating and capital costs of the pipeline.  Currently, no third-party shippers use the pipeline.  Should shipments be suspended, by choice or due to force majeure, we are responsible for the portion of the payment related to our undivided interest for all remaining periods.  The contract expires in 2029; however, the shippers can extend its term perpetually.  This contract qualifies as a variable interest contractual arrangement and the Corridor Pipeline qualifies as a VIE.  We hold a significant variable interest but are not the primary beneficiary because our shipments are only 20 percent of the total; therefore, the Corridor Pipeline is not consolidated by Marathon.  Our maximum exposure to loss as a result of our involvement with this VIE is the amount we will be required to pay over the contract term, which was $1.0 billion as of March 31, 2010.  The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term.  We have not provided financial assistance to Corridor Pipeline and we do not have any guarantees of such assistance in the future.
 

4.      Income per Common Share
 
Basic income per share is based on the weighted average number of common shares outstanding, including securities exchangeable into common shares.  Diluted income per share assumes exercise of stock options and stock appreciation rights, provided the effect is not antidilutive.
 
 
Three Months Ended March 31,
 
 
2010
   
2009
 
(In millions, except per share data)
Basic
 
Diluted
   
Basic
 
Diluted
 
           
Income from continuing operations
  $ 457     $ 457     $ 265     $ 265  
Discontinued operations
    -       -       17       17  
Net income
  $ 457     $ 457     $ 282     $ 282  
                     
Weighted average common shares outstanding
    709       709       709       709  
Effect of dilutive securities
    -       2       -       3  
 Weighted average common shares, including dilutive effect
    709       711       709       712  
                     
Per share:
                               
    Income from continuing operations
  $ 0.64     $ 0.64     $ 0.37     $ 0.37  
    Discontinued operations
  $ -     $ -     $ 0.03     $ 0.03  
    Net income
  $ 0.64     $ 0.64     $ 0.40     $ 0.40  
 
The per share calculations above exclude 12 million and 9 million stock options and stock appreciation rights for the first three months of 2010 and 2009, that were antidilutive.
 

7
 

 
Notes to Consolidated Financial Statements (Unaudited)
 

5.      Dispositions
 
During the first quarter 2010, we closed the sale of a 20 percent outside-operated interest in our E&P segment’s Production Sharing Contract and Joint Operating Agreement in Block 32 offshore Angola.  We received net proceeds of $1.3 billion and recorded a pretax gain on the sale in the amount of $811 million.  We retained a 10 percent outside-operated interest in Block 32.
 

6.      Segment Information
 
We have four reportable operating segments.  Each of these segments is organized and managed based upon the nature of the products and services they offer.
 
 
 
1)
Exploration and Production (“E&P”) – explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis;
 
 
 
2)
Oil Sands Mining (“OSM”) – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil;
 
 
 
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
 
 
 
4)
Refining, Marketing and Transportation (“RM&T”) – refines, markets and transports crude oil and petroleum products, primarily in the Midwest, upper Great Plains, Gulf Coast and southeastern regions of the U.S.
 
 
Our Irish and Gabonese businesses were sold in 2009 and were accounted for as discontinued operations.  Segment information for the first three months of 2009 excludes any amounts for these operations.
 
           
   
Three Months Ended March 31, 2010
 
(In millions)
 
E&P
   
OSM
   
IG
   
RM&T
   
Total
 
                               
Revenues:
                             
    Customer
  $ 2,337     $ 147     $ 27     $ 13,338     $ 15,849  
    Intersegment (a)
    172       18       -       16       206  
    Related parties
    12       -       -       8       20  
        Segment revenues
    2,521       165       27       13,362       16,075  
    Elimination of intersegment revenues
    (172 )     (18 )     -       (16 )     (206 )
        Total revenues
  $ 2,349     $ 147     $ 27     $ 13,346     $ 15,869  
Segment income (loss)
  $ 502     $ (17 )   $ 44     $ (237 )   $ 292  
Income from equity method investments
    37       -       48       20       105  
Depreciation, depletion and amortization (c)
    397       23       1       220       641  
Income tax provision (benefit)(b)
    538       (7 )     23       (153 )     401  
Capital expenditures (c)(d)
    603       265       1       310       1,179  
 
Management believes intersegment transactions were conducted under terms comparable to those with unrelated parties.
 
(b)
Differences between segment totals and our 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 reconciliation below.
 
(c)
Differences between segment totals and our totals represent amounts related to corporate administrative activities.
 
(d)
Includes accruals.

8
 

 
Notes to Consolidated Financial Statements (Unaudited)
 

 

   
Three Months Ended March 31, 2009
 
(In millions)
 
E&P
   
OSM
   
IG
   
RM&T
   
Total
 
                               
Revenues:
                             
    Customer
  $ 1,306     $ 97     $ 11     $ 8,660     $ 10,074  
    Intersegment (a)
    119       25       -       9       153  
    Related parties
    15       -       -       5       20  
        Segment revenues
    1,440       122       11       8,674       10,247  
    Elimination of intersegment revenues
    (119 )     (25 )     -       (9 )     (153 )
    Gain on U.K. natural gas contracts(e)
    82       -       -       -       82  
        Total revenues
  $ 1,403     $ 97     $ 11     $ 8,665     $ 10,176  
Segment income (loss)
  $ 83     $ (24 )   $ 27     $ 159     $ 245  
Income (loss) from equity method investments
    11       -       42       (6 )     47  
Depreciation, depletion and amortization (c)
    465       37       1       152       655  
Income tax provision (benefit)(b)
    178       (8 )     13       106       289  
Capital expenditures (c)(d)
    365       286       -       660       1,311  
 
Management believes intersegment transactions were conducted under terms comparable to those with unrelated parties.
 
(b)
Differences between segment totals and our 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 reconciliation below.
 
(c)
Differences between segment totals and our totals represent amounts related to corporate administrative activities.
 
(d)
Includes accruals.
 
(e)
The U.K. natural gas contracts expired in September 2009.

    The following reconciles segment income to net income as reported in the consolidated statements of income:
 
             
   
Three Months Ended March 31,
 
(In millions)
 
2010
   
2009
 
Segment income
  $ 292     $ 245  
Items not allocated to segments, net of income taxes:
               
     Corporate and other unallocated items
    (10 )     (50 )
     Foreign currency remeasurement of taxes
    33       28  
     Gain on disposition(a)
    449       -  
     Long-lived asset impairment(b)
    (262 )     -  
     Deferred income taxes - tax legislation changes(c)
    (45 )     -  
     Gain on U.K. natural gas contracts
    -       42  
     Discontinued operations
    -       17  
          Net income
  $ 457     $ 282  
 
Additional information on this gain can be found in Note 5.
 
(b)
The impairment is further discussed in Note 11.
 
(c)
A discussion of the tax legislation changes can be found in Note 8.

    The following reconciles total revenues to sales and other operating revenues (including consumer excise taxes) as reported in the consolidated statements of income:
 
             
 
Three Months Ended March 31,
 
(In millions)
2010
   
2009
 
Total revenues
  $ 15,869     $ 10,176  
Less:  Sales to related parties
    20       20  
     Sales and other operating revenues (including consumer excise taxes)
  $ 15,849     $ 10,156  


9
 

 
Notes to Consolidated Financial Statements (Unaudited)
 

7.      Defined Benefit Postretirement Plans
 
The following summarizes the components of net periodic benefit cost:
 
   
Three Months Ended March 31,
 
   
Pension Benefits
   
Other Benefits
 
(In millions)
 
2010
   
2009
   
2010
   
2009
 
Service cost
  $ 29     $ 35     $ 5     $ 5  
Interest cost
    45       42       10       11  
Expected return on plan assets
    (40 )     (40 )     -       -  
Amortization:
                               
    – prior service cost (credit)
    3       3       (1 )     (1 )
    – actuarial loss
    25       6       (1 )     -  
Net periodic benefit cost
  $ 62     $ 46     $ 13     $ 15  
 
During the first three months of 2010, we made contributions of $9 million to our funded international pension plans.  We expect to make additional contributions up to an estimated $8 million to our funded international pension plans over the remainder of 2010 and do not anticipate making any contributions to our domestic plans.  Current benefit payments related to unfunded pension and other postretirement benefit plans were $8 million and $8 million during the first three months of 2010.
 

8.      Income Taxes
 
The following is an analysis of the effective income tax rates for the periods presented:
 
   
Three Months Ended March 31,
 
   
2010
   
2009
 
Statutory U.S. income tax rate
    35 %     35 %
Effects of foreign operations, including foreign tax credits
    14       13  
State and local income taxes, net of federal income tax effects
    (1 )     1  
Legislation change
    5       -  
        Effective income tax rate for continuing operations
    53 %     49 %
 
The Patient Protection and Affordable Care Act (“PPACA”) and the Health Care and Education Reconciliation Act of 2010 (“HCERA”), (together, the “Acts”) were signed in to law in March 2010.  The “Acts” effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D.  The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “MPDIMA”).  Under the MPDIMA, the federal subsidy does not reduce our income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually.  Beginning in 2013, under the Acts, our income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy.  Such a change in the tax law must be recognized in earnings in the period enacted regardless of the effective date.  As a result, we have recorded a charge of $45 million in the first quarter of 2010 for the write-off of deferred tax assets to reflect the change in the tax treatment of the federal subsidy.
 
 
The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income, the relative magnitude of these sources of income, and foreign currency remeasurement effects.  The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments.  The difference between the total provision and the sum of the amounts allocated to segments and to individual items not allocated to segments is reported in “Corporate and other unallocated items” shown in Note 6.
 
 
We are continuously undergoing examination of our U.S. federal income tax returns by the Internal Revenue Service.  Such audits have been completed through the 2005 tax year.  We believe adequate provision has been made for federal income taxes and interest which may become payable for years not yet settled.  Further, we are routinely involved in U.S. state income tax audits and foreign jurisdiction tax audits.  We believe all other audits will be resolved within the amounts paid and/or provided for these liabilities.
 

10
 

 
Notes to Consolidated Financial Statements (Unaudited)
 

 
 
As of March 31, 2010, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated.
 
United States (a)
2001 - 2008
Canada(b)
2004 - 2008
Equatorial Guinea
2006 - 2008
Libya
2006 - 2008
Norway
2008 
United Kingdom
2007 - 2009
 
(a)      Includes federal and state jurisdictions.
 
(b)      Tax years through 2003 have been audited, but remain subject to reexamination due to the existence of net operating losses.


9.      Inventories
 
Inventories are carried at the lower of cost or market value.  The cost of inventories of crude oil, refined products and merchandise is determined primarily under the last-in, first-out (“LIFO”) method.
 

   
March 31,
   
December 31,
 
(In millions)
 
2010
   
2009
 
Liquid hydrocarbons, natural gas and bitumen
  $ 1,560     $ 1,393  
Refined products and merchandise
    1,933       1,790  
Supplies and sundry items
    355       439  
        Total, at cost
  $ 3,848     $ 3,622  


10.    Property, Plant and Equipment

   
March 31,
   
December 31,
 
(In millions)
 
2010
   
2009
 
Exploration and Production
           
     United States
  $ 5,839     $ 6,005  
     International
    4,912       5,522  
          Total E&P
    10,751       11,527  
Oil Sands Mining
    8,776       8,531  
Integrated Gas
    35       34  
Refining, Marketing & Transportation
    11,979       11,887  
Corporate
    133       142  
     Total
  $ 31,674     $ 32,121  
 
Exploratory well costs capitalized greater than one year after completion of drilling were $173 million as of March 31, 2010, an increase of $23 million from December 31, 2009.   The offshore Gulf of Mexico Shenandoah appraisal well was added to this category in the first quarter of 2010 at a cost of $28 million.  The Shenandoah costs were incurred primarily during 2009.  Appraisal drilling for the Shenandoah prospect is expected to commence in 2011.  The results of the appraisal well program will be used to evaluate the commercial viability of the project.
 
 
A new, detailed study of the commerciality of the Gardenia well in Equatorial Guinea concluded that development of this area is now uncertain and therefore $20 million in costs associated with this well were written off in the first quarter of 2010.  The remaining $10 million of exploration well costs in Equatorial Guinea are associated with the Corona well which were incurred in 2004.  Efforts to develop these reserves continue and we are evaluating both a unitization with existing production facilities and stand-alone development.
 
 
The coal bed methane project in the United Kingdom was added to this category in the first quarter of 2010 at a cost of $15 million.  Most of the project costs were incurred in 2008. Technical work is ongoing to develop well design programs along with sourcing a suitable drilling rig.
 

11
 

 
Notes to Consolidated Financial Statements (Unaudited)
 

    In December 2009, we began drilling the Flying Dutchman prospect, located on Green Canyon Block 511 in the Gulf of Mexico.  The Flying Dutchman reached its targeted total depth in early May 2010. The well encountered hydrocarbon-bearing sands in an Upper Miocene that will require further technical evaluation.  During the second quarter of 2010, we anticipate expensing approximately $45 million for drilling costs incurred below the depth of the hydrocarbon-bearing sands.  The results of the Flying Dutchman well will be evaluated along with additional potential drilling on Green Canyon Block 511 to determine overall commerciality.  As a result, approximately $90 million of exploratory well costs will be suspended while we evaluate the results.  We are the operator and will have a 63 percent working interest in this prospect.
 

11.           Fair Value Measurements
 
Fair Values –Recurring
 
 
The following tables present assets and liabilities accounted for at fair value on a recurring basis, as of March 31, 2010 and December 31, 2009 by fair value hierarchy level.
 
   
March 31, 2010
 
(In millions)
 
Level 1
   
Level 2
   
Level 3
   
Collateral
   
Total
 
Derivative instruments, assets
                             
     Commodity
  $ 153     $ 49     $ 2     $ 46       250  
     Interest rate
    -       -       11       -       11  
     Foreign currency
    -       -       5       -       5  
          Derivative instruments, assets
    153       49       18       46       266  
Derivative instruments, liabilities
                                       
     Commodity
  $ (146 )   $ (39 )   $ (10 )   $ -       (195 )
          Derivative instruments, liabilities
    (146 )     (39 )     (10 )     -       (195 )
          Net derivative assets
  $ 7       10       8       46       71  


   
December 31, 2009
 
(In millions)
 
Level 1
   
Level 2
   
Level 3
   
Collateral
   
Total
 
Derivative instruments, assets
                             
     Commodity
  $ 133     $ 11     $ 12     $ 63     $ 219  
     Interest rate
    -       -       7       -       7  
     Foreign currency
    -       1       2       -       3  
          Derivative instruments, assets
    133       12       21       63       229  
Derivative instruments, liabilities
                                       
     Commodity
  $ (125 )   $ (12 )   $ (10 )   $ -     $ (147 )
     Interest rate
    -       -       (2 )     -       (2 )
          Derivative instruments, liabilities
    (125 )     (12 )     (12 )     -       (149 )
          Net derivative assets
  $ 8     $ -     $ 9     $ 63     $ 80  

 
Commodity derivatives in Level 1 are exchange-traded contracts for crude oil, natural gas, refined products and ethanol measured at fair value with a market approach using the close-of-day settlement price for the market.  Commodity derivatives and foreign currency forwards in Level 2 are measured at fair value with a market approach using broker price quotes or prices obtained from third-party services such as Bloomberg L.P. or Platt’s, a Division of McGraw-Hill Corporation (“Platt’s”), which have been corroborated with data from active markets for similar assets and liabilities.  Collateral deposits related to both Level 1 and Level 2 commodity derivatives are in broker accounts covered by master netting agreements.
 
 
Commodity and interest rate derivatives in Level 3 are measured at fair value with a market approach using prices obtained from various third-party services such as Platt’s and price assessments from other independent brokers.  The fair value of foreign currency options is measured using an option pricing model for which the inputs are obtained from a reporting service.  Since we are unable to independently verify information from the third-party service providers to active markets, these measures are considered Level 3.
 

12
 

 
Notes to Consolidated Financial Statements (Unaudited)
 

 
The following is a reconciliation of the net beginning and ending balances recorded for derivative instruments classified as Level 3 in the fair value hierarchy.
 
   
Three Months Ended March 31,
 
(In millions)
 
2010
   
2009
 
Beginning balance
  $ 9     $ (26 )
     Total realized and unrealized gains (losses):
               
          Included in net income
    (1 )     77  
          Included in other comprehensive income
    2       -  
    Purchases
    2       -  
    Sales
    -       (22 )
    Settlements
    (4 )     (20 )
Ending balance
  $ 8     $ 9  
 
Net income for the quarters ended March 31, 2010, and 2009 included unrealized losses of $1 million and gains of $76 million related to instruments held on those dates.  See Note 12 for the impacts of our derivative instruments on our consolidated statements of income.  There were no transfers of fair value estimates among hierarchy levels in the first quarter of 2010.
 
 
Fair Values – Nonrecurring
 
 
The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.
 
   
Three Months Ended March 31,
 
   
2010
   
2009
 
(In millions)
 
Fair Value
   
Impairment
   
Fair Value
   
Impairment
 
                         
Long-lived assets held for use
  $ 144     $ 434     $ -     $ -  
                                 
 
In the first quarter of 2010, we recorded property impairments of $434 million.  In March 2010, we completed a reservoir study which resulted in a portion of our Powder River Basin field being removed from plans for future development.  The field’s fair value was measured at $144 million, using an estimate of future cash flows with Level 3 inputs.  This resulted in an impairment of $423 million.  The remaining E&P segment impairments of $11 million were primarily a result of reduced drilling expectations.  The fair value of the assets impaired was measured using an income approach based upon internal estimates of future production levels, prices and discount rate, which are Level 3 inputs.
 
 
Fair Values – Reported
 
 
The following table summarizes financial instruments, excluding the derivative financial instruments reported above, by individual balance sheet line item at March 31, 2010, and December 31, 2009.
 
                         
   
March 31, 2010
   
December 31, 2009
 
   
Fair
   
Carrying
   
Fair
   
Carrying
 
(In millions)
 
Value
   
Amount
   
Value
   
Amount
 
Financial assets
                       
     Receivables from United States Steel, including current portion
  $ 356     $ 342     $ 360     $ 346  
     Other noncurrent assets
    339       181       334       175  
                                 
          Total financial assets  
    695       523       694       521  
                                 
Financial liabilities
                               
     Long-term debt, including current portion(a)
    8,755       8,188       8,754       8,190  
     Deferred credits and other liabilities
    76       78       71       73  
                                 
          Total financial liabilities  
  $ 8,831     $ 8,266     $ 8,825     $ 8,263  
(a)      Excludes capital leases.

13
 

 
Notes to Consolidated Financial Statements (Unaudited)
 


 
Our current assets and liabilities accounts contain financial instruments, the most significant of which are trade accounts receivables and payables.  We believe the carrying values of our current assets and liabilities approximate fair value, with the exception of the current portion of receivables from United States Steel and the current portion of our long-term debt which is reported above.  Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments (e.g., less than 1 percent of our trade receivables and payables are outstanding for greater than 90 days), (2) our investment-grade credit rating, and (3) our historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk.
 
 
The fair value of the receivables from United States Steel is measured using an income approach that discounts the future expected payments over the remaining term of the obligations.  Because this asset is not publicly-traded and not easily transferable, a hypothetical market based upon United States Steel’s borrowing rate curve is assumed and the majority of inputs to the calculation are Level 3.  The industrial revenue bonds are to be redeemed on or before January 1, 2012, the tenth anniversary of the USX Separation.
 
 
Restricted cash is included in our other noncurrent assets line.  The majority of our restricted cash represent cash accounts that earn interest; therefore, the balance approximates fair value.  Fair values of our other financial assets included in our other noncurrent assets line and of our financial liabilities included in our deferred credits and other liabilities line are measured using an income approach and mostly are internally generated inputs, which results in a Level 3 classification.  Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value.
 
 
Over 90 percent of our long-term debt instruments are publicly-traded.  A market approach, based upon quotes   from major financial institutions is used to measure the fair value of such debt.  Because these quotes cannot be independently verified to the market they are considered Level 3 inputs.   The fair value of our debt that is not publicly-traded is measured using an income approach.  The future debt service payments are discounted using the rate at which we currently expect to borrow.  All inputs to this calculation are Level 3.
 

 
12.           Derivatives
 
For information regarding the fair value measurement of derivative instruments see Note 11.  The following table presents the gross fair values of derivative instruments, excluding cash collateral, and where they appear on the consolidated balance sheets as of March 31, 2010 and December 31, 2009.
 

 
March 31, 2010
   
(In millions)
Asset
 
Liability
 
Net Asset
 
Balance Sheet Location
Cash Flow Hedges
                   
     Foreign currency
  $ 5     $ -     $ 5  
Other current assets
Fair Value Hedges
                         
     Interest rate
    11       -       11  
Other noncurrent assets
Total Designated Hedges
    16       -       16    
                           
Not Designated as Hedges
                         
     Commodity
    202       (162 )     40  
Other current assets
Total Not Designated as Hedges
    202       (162 )     40    
                           
     Total
  $ 218     $ (162 )   $ 56    
                           
                           
 
March 31, 2010
   
(In millions)
 
Asset
   
Liability
   
Net Liability
 
Balance Sheet Location
Not Designated as Hedges
                         
     Commodity
  $ 2     $ (33 )   $ (31 )
Other current liabilities
Total Not Designated as Hedges
    2       (33 )     (31 )  
                           
     Total
  $ 2     $ (33 )   $ (31 )  

14
 


 
Notes to Consolidated Financial Statements (Unaudited)
 


 
December 31, 2009
   
(In millions)
 
Asset
   
Liability
   
Net Asset
 
Balance Sheet Location
Cash Flow Hedges
                   
     Foreign currency
$
 
$
 
$
 
Other current assets
Fair Value Hedges
                   
     Interest rate
 
   
(3)
   
 
Other noncurrent assets
Total Designated Hedges
 
10 
   
(3)
   
   
                     
Not Designated as Hedges
                   
      Foreign Currency
 
   
   
 
Other current assets
     Commodity
 
116 
   
(104)
   
12 
 
Other current assets
Total Not Designated as Hedges
 
117 
   
(104)
   
13 
   
                     
     Total
$
127 
 
$
(107)
 
$
20 
   
                     
 
December 31, 2009
   
(In millions)
 
Asset
   
Liability
   
Net Liability
 
Balance Sheet Location
Fair Value Hedges
                   
     Commodity
$
 
$
(1)
 
$
(1)
 
Other current liabilities
Total Designated Hedges
 
   
(1)
   
(1)
   
                     
Not Designated as Hedges
                   
                     
     Commodity
 
13 
   
(15)
   
(2)
 
Other current liabilities
Total Not Designated as Hedges
 
13 
   
(15)
   
(2)
   
                     
     Total
$
13 
 
$
(16)
 
$
(3)
   

 
Derivatives Designated as Cash Flow Hedges
 
 
As of March 31, 2010, the following foreign currency options were designated as cash flow hedges.
 
(In millions)
Period
Notional Amount
Weighted Average Forward Rate
Foreign Currency Options:
       
    Dollar (Canada)
April 2010 - December 2010
$
144 
1.040 (a)
 
U.S. dollar to Foreign currency
 
The following table summarizes the pretax effect of derivative instruments designated as hedges of cash flows in other comprehensive income for the first quarters of 2010 and 2009.
 
   
Gain (Loss) in OCI
 
   
Three Months Ended March 31,
 
(In millions)
 
2010
   
2009
 
             
Foreign currency
  $ 2     $ (12 )
Interest rate
  $ -     $ (15 )

 
Derivatives Designated as Fair Value Hedges
 
 
As of March 31, 2010, we had multiple interest rate swap agreements with a total notional amount of $1,450 million at a weighted average, LIBOR-based, floating rate of 4.4 percent.  The offsetting impacts on both the derivative and the hedged item were $5 million in the first quarter of 2010.
 

15
 

 
Notes to Consolidated Financial Statements (Unaudited)
 

 
Derivatives not Designated as Hedges
 
 
At March 31, 2010, Euro forwards not designated as hedges with a notional value of $2 million remain open to June 2010 at a weighted average forward rate of 1.290.
 
 
The largest portion of our March 31, 2010 open commodity derivative contracts not designated as hedges in our E&P and OSM segments are related to 2010 forecasted sales, as shown in the table below.
 
 
Term
Bbls per Day
Weighted Average Swap Price
Benchmark
Crude Oil
       
U.S.
April - June 2010
35,000 
$80.77
West Texas Intermediate
Norway
April - June 2010
30,000 
$80.42
Dated Brent
Canada
April - December 2010
25,000 
$82.56
West Texas Intermediate
         
 
Term
Mmbtu per Day(a)
Weighted Average Swap Price
Benchmark
Natural Gas
       
U.S. Lower 48
April - December 2010
80,000 
$5.39
CIG Rocky Mountains(b)
U.S. Lower 48
April - December 2010
30,000 
$5.59
NGPL Mid Continent(c)
 
(a)  Million British thermal units.
 
(b)  Colorado Interstate Gas Co. (“CIG”).
 
(c)   Natural Gas Pipeline Co. of America (“NGPL”).
 
The table below summarizes our significant open commodity derivative contracts of our RM&T segment at March 31, 2010 that are not designated as hedges.  These contracts enable us to effectively correlate our commodity price exposure to the relevant market indicators, thereby mitigating fixed price risk.
 
 
Position
Bbls per Day
Weighted Average Price
Benchmark
Crude Oil
       
     Exchange-traded
Long(a)
65,019 
$79.07
NYMEX Crude
     Exchange-traded
Short(a)
(81,805)
$80.06
NYMEX Crude
         
 
Position
Bbls per Day
Weighted Average Price
Benchmark
Refined Products
       
     Exchange-traded
Long(b)
21,915 
$2.18
NYMEX Heating Oil and RBOB(c)
     Exchange-traded
Short(b)
(17,616)
$2.22
NYMEX Heating Oil and RBOB(c)
 
(a)  90 percent of these contracts expire in the second quarter of 2010.
 
(b)  98 percent of these contracts expire in the second quarter of 2010.
 
(c)  Reformulated Gasoline Blendstock for Oxygen Blending                                                                                                           .

 
The following table summarizes the effect of all derivative instruments not designated as hedges in our consolidated statements of income for the three months ended March 31, 2010 and 2009.
 
   
Gain (Loss)
 
   
Three Months Ended March 31,
 
(In millions)
Income Statement Location
2010
 
2009
 
Commodity
Sales and other operating revenues
  $ 48     $ 93  
Commodity
Cost of revenues
    (29 )     (59 )
Commodity
Other income
    2       1  
      $ 21