Marathon Oil Corporation - SEC Filing

form10q20090331.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, 2009

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     Ö    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    Ö     
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    Ö     

 
There were 707,774,176 shares of Marathon Oil Corporation common stock outstanding as of April 30, 2009.
 


 
 


 


MARATHON OIL CORPORATION
 
Form 10-Q
 
Quarter Ended March 31, 2009


 
INDEX
 
 
Page
PART I - FINANCIAL INFORMATION
Item 1.
Financial Statements:
 
 
Consolidated Statements of Income (Unaudited)
2
 
Consolidated Balance Sheets (Unaudited)
3
 
Consolidated Statements of Cash Flows (Unaudited)
4
 
Notes to Consolidated Financial Statements (Unaudited)
5
Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
18
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
28
Item 4.
Controls and Procedures
28
 
Supplemental Statistics
29
PART II - OTHER INFORMATION
Item 1.
Legal Proceedings
31
Item 1A.
Risk Factors
31
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
32
Item 4.
Submission of Matters to a Vote of Security Holders
33
Item 6.
Exhibits
34
 
Signatures
35

 
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)
 
2009
   
2008
 
Revenues and other income:
           
             
   Sales and other operating revenues (including consumer excise taxes)
  $ 10,234     $ 17,280  
   Sales to related parties
    20       542  
   Income from equity method investments
    47       209  
   Net gain on disposal of assets
    4       10  
   Other income
    52       59  
                 
             Total revenues and other income
    10,357       18,100  
Costs and expenses:
               
   Cost of revenues (excludes items below)
    7,402       14,452  
   Purchases from related parties
    95       139  
   Consumer excise taxes
    1,174       1,216  
   Depreciation, depletion and amortization
    665       451  
   Selling, general and administrative expenses
    291       300  
   Other taxes
    103       123  
   Exploration expenses
    62       129  
                 
            Total costs and expenses
    9,792       16,810  
                 
Income from operations
    565       1,290  
                 
   Net interest and other financing income (costs)
    (13 )     9  
                 
Income before income taxes
    552       1,299  
                 
   Provision for income taxes
    270       568  
                 
                 
Net income
  $ 282     $ 731  
                 
Per Share Data:
               
                 
     Net income per share - basic
  $ 0.40     $ 1.03  
     Net income per share - diluted
  $ 0.40     $ 1.02  
                 
     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)
 
2009
   
2008
 
Assets
           
Current assets:
           
    Cash and cash equivalents
  $ 1,869     $ 1,285  
    Receivables, less allowance for doubtful accounts of $5 and $6
    2,870       3,094  
    Receivables from United States Steel
    23       23  
    Receivables from related parties
    46       33  
    Inventories
    3,496       3,507  
    Other current assets
    279       461  
                 
            Total current assets
    8,583       8,403  
                 
Equity method investments
    2,046       2,080  
Receivables from United States Steel
    466       469  
Property, plant and equipment, less accumulated depreciation,
               
          depletion and amortization of $16,203 and $15,581
    30,066       29,414  
Goodwill
    1,445       1,447  
Other noncurrent assets
    706       873  
                 
            Total assets
  $ 43,312     $ 42,686  
Liabilities
               
Current liabilities:
               
    Accounts payable
  $ 4,490     $ 4,712  
    Payables to related parties
    24       21  
    Payroll and benefits payable
    357       400  
    Accrued taxes
    570       1,133  
    Deferred income taxes
    618       561  
    Other current liabilities
    768       828  
    Long-term debt due within one year
    101       98  
                 
            Total current liabilities
    6,928       7,753  
                 
Long-term debt
    8,590       7,087  
Deferred income taxes
    3,120       3,330  
Defined benefit postretirement plan obligations
    1,644       1,609  
Asset retirement obligations
    977       963  
Payable to United States Steel
    4       4  
Deferred credits and other liabilities
    538       531  
                 
            Total liabilities
    21,801       21,277  
                 
Commitments and contingencies
               
                 
Stockholders’ Equity
               
Preferred stock – 5 million shares issued, 1 million and 3 million shares
               
          outstanding (no par value, 6 million shares authorized)
    -       -  
Common stock:
               
     Issued – 769 million and 767 million shares (par value $1 per share,
               
          1.1 billion shares authorized)
    769       767  
     Securities exchangeable into common stock – 5 million shares issued,
               
          1 million and 3 million shares outstanding (no par value, unlimited
               
          shares authorized)
    -       -  
     Held in treasury, at cost – 61 million and 61 million shares
    (2,711 )     (2,720 )
Additional paid-in capital
    6,705       6,696  
Retained earnings
    17,371       17,259  
Accumulated other comprehensive loss
    (623 )     (593 )
                 
            Total stockholders' equity
    21,511       21,409  
                 
            Total liabilities and stockholders' equity
  $ 43,312     $ 42,686  
 
 
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)
 
2009
   
2008
 
Increase (decrease) in cash and cash equivalents
           
Operating activities:
           
Net income
  $ 282     $ 731  
Adjustments to reconcile net income to net cash provided by operating activities:
               
    Deferred income taxes
    51       72  
    Depreciation, depletion and amortization
    665       451  
    Pension and other postretirement benefits, net
    38       16  
    Exploratory dry well costs and unproved property impairments
    16       44  
    Net gain on disposal of assets
    (4 )     (10 )
    Equity method investments, net
    11       (73 )
    Changes in the fair value of U.K. natural gas contracts
    (82 )     70  
    Changes in:
               
          Current receivables
    233       (118 )
          Inventories
    47       (615 )
          Current accounts payable and accrued liabilities
    (777 )     271  
    All other, net
    75       (42 )
               Net cash provided by operating activities
    555       797  
Investing activities:
               
Capital expenditures
    (1,336 )     (1,537 )
Disposal of assets
    20       3  
Trusteed funds - withdrawals
    13       109  
Investments - loans and advances
    (3 )     (46 )
Investments - repayments of loans and return of capital
    26       8  
All other, net
    6       6  
               Net cash used in investing activities
    (1,274 )     (1,457 )
Financing activities:
               
Short-term debt, net
    -       958  
Borrowings
    1,491       1,247  
Debt issuance costs
    (11 )     (7 )
Debt repayments
    (3 )     (1,245 )
Purchases of common stock
    -       (143 )
Dividends paid
    (170 )     (170 )
All other, net
    -       6  
               Net cash provided by financing activities
    1,307       646  
Effect of exchange rate changes on cash
    (4 )     4  
Net increase (decrease) in cash and cash equivalents
    584       (10 )
Cash and cash equivalents at beginning of period
    1,285       1,199  
Cash and cash equivalents at end of period
  $ 1,869     $ 1,189  
 
 
The accompanying notes are an integral part of these consolidated financial statements.
 
4
 
 
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; reflect all adjustments necessary for a fair statement 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.  Certain reclassifications of prior year data have been made to conform to 2009 classifications.  These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Marathon Oil Corporation (“Marathon”) 2008 Annual Report on Form 10-K.  The results of operations for the quarter ended March 31, 2009 are not necessarily indicative of the results to be expected for the full year.
 
2.      New Accounting Standards
 
EITF 08-6 – In November 2008, the Financial Accounting Standards Board (“FASB”) ratified Emerging Issues Task Force (“EITF”) Issue No. 08-6, “Equity Method Investment Accounting Considerations” (“EITF 08-6”) which clarifies how to account for certain transactions involving equity method investments.  The initial measurement, decreases in value and changes in the level of ownership of the equity method investment are addressed.  EITF 08-6 is effective on a prospective basis on January 1, 2009 and for interim periods. Early application by an entity that has previously adopted an alternative accounting policy is not permitted.  Since this standard will be applied prospectively, adoption did not have a significant impact on our consolidated results of operations, financial position or cash flows.
 
FSP EITF 03-6-1  In June 2008, the FASB issued FASB Staff Position (“FSP”) on EITF Issue No. 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”) which provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings allocation in computing earnings per share (“EPS”) under the two-class method.  FSP EITF 03-6-1 is effective January 1, 2009 and all prior-period EPS data (including any amounts related to interim periods, summaries of earnings and selected financial data) will be adjusted retrospectively to conform to its provisions. While our restricted stock awards meet this definition of participating securities, the application of FSP EITF 03-6-1 did not have a significant impact on our reported EPS.
 
   FSP FAS 142-3 – In April 2008, the FASB issued FSP on Financial Accounting Standard (“FAS”) 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP FAS 142-3”), which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets.” The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset.   FSP FAS 142-3 is effective on January 1, 2009.  Early adoption is prohibited.  The provisions of FSP FAS 142-3 are to be applied prospectively to intangible assets acquired after the effective date, except for the disclosure requirements which must be applied prospectively to all intangible assets recognized as of, and subsequent to, the effective date.  Since this standard is applied prospectively, adoption did not have a significant impact on our consolidated results of operations, financial position or cash flows.
 
SFAS No. 161 – In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133.”  This statement expands the disclosure requirements for derivative instruments to provide information regarding (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows.  To meet these objectives, the statement requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts and gains and losses on derivative instruments and disclosures about credit-risk-related contingent features in derivative agreements.  This standard is effective January 1, 2009.  The statement encourages but does not require disclosures for earlier periods presented for comparative purposes at initial adoption.  The disclosures required by SFAS No. 161 appear in Note 12.
 
SFAS No. 141(R) – In December 2007, the FASB issued SFAS No. 141 (Revised 2007), “Business Combinations” (“SFAS No. 141(R)”).   This statement significantly changes the accounting for business combinations. Under SFAS No. 141(R), an acquiring entity will be required to recognize all the assets acquired, liabilities assumed and any noncontrolling interest in the acquiree at their acquisition-date fair value with limited exceptions. The statement expands the definition of a business and is expected to be applicable to more transactions than the previous standard on business combinations. The statement also changes the accounting treatment for changes in control, step acquisitions,

 
5
 
 
 
MARATHON OIL CORPORATION
 
 
Notes to Consolidated Financial Statements (Unaudited)
 
 
transaction costs, acquired contingent liabilities, in-process research and development, restructuring costs, changes in deferred tax asset valuation allowances as a result of a business combination and changes in income tax uncertainties after the acquisition date.  Accounting for changes in valuation allowances for acquired deferred tax assets and the resolution of uncertain tax positions for prior business combinations will impact tax expense instead of impacting recorded goodwill.  Additional disclosures are also required.  In April 2009, the FASB issued an FSP on FAS 141(R), “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies”  (“FSP FAS 141(R)-1”), which addressed SFAS No. 141(R) implementation issues related to contingent assets and liabilities acquired in a business combination.  Both SFAS No. 141(R) and FSP FAS 141(R)-1 are effective on January 1, 2009 for all new business combinations.  Because we had no business combinations in progress at January 1, 2009, adoption of these standards did not have a significant impact on our consolidated results of operations, financial position or cash flows.
 
SFAS No. 160 – In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - An Amendment of ARB No. 51.”  This statement establishes new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary.  Specifically, this statement clarifies that a noncontrolling interest in a subsidiary (sometimes called a minority interest) is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements, but separate from the parent's equity.  It requires that the amount of consolidated net income attributable to the noncontrolling interest be clearly identified and presented on the face of the consolidated income statement.  SFAS No. 160 clarifies that changes in a parent's ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest.  In addition, this statement requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated, based on the fair value of the noncontrolling equity investment on the deconsolidation date.  Additional disclosures are required that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.  In January 2009, the FASB ratified EITF Issue No. 08-10, “Selected Statement 160 Implementation Questions” (“EITF 08-10”).  Both SFAS No. 160 and EITF 08-10 are effective January 1, 2009.  The statements must be applied prospectively, except for the presentation and disclosure requirements which must be applied retrospectively for all periods presented in consolidated financial statements.  We do not have significant noncontrolling interests in consolidated subsidiaries and therefore adoption of these standards did not have a significant impact on our consolidated results of operations, financial position or cash flows.
 
SFAS No. 157In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.”  This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements.  SFAS No. 157 does not require any new fair value measurements but may require some entities to change their measurement practices.  We adopted SFAS No. 157 effective January 1, 2008 with respect to financial assets and liabilities and effective January 1, 2009 with respect to nonfinancial assets and liabilities.  Adoption did not have a significant effect on our consolidated results of operations, financial position or cash flows.
 
In February 2008, the FASB issued FSP FAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13,” which removes certain leasing transactions from the scope of SFAS No. 157, and FSP FAS 157-2, “Effective Date of FASB Statement No. 157,” which deferred the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis.
 
In October 2008, the FASB issued FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” which clarifies the application of SFAS No. 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active.  FSP FAS 157-3 was effective upon issuance, including prior periods for which financial statements had not been issued, and any revisions resulting from a change in the valuation technique or its application were required to be accounted for as a change in accounting estimate.  Application of FSP FAS 157-3 did not cause us to change our valuation techniques for assets and liabilities measured under SFAS No. 157.
 
The additional disclosures regarding assets and liabilities recorded at fair value and measured under SFAS No. 157 are presented in Note 11.
 
FSP FASB 132(R)-1Also in December 2008, the FASB issued an FSP on SFAS No. 132(R)-1, “Employers Disclosures about Postretirement Benefit Plan Assets” (“FSP FASB 132(R)-1”) which provides guidance on an employer’s disclosures about plan assets of defined benefit pension or other postretirement plans.  This FSP requires additional disclosures about investment policies and strategies, the reporting of fair value by asset category and other information about fair value measurements.  The FSP is effective January 1, 2009 and early application is permitted.  Upon initial application, the provisions of FSP FAS 132(R)-1 are not required for earlier periods that are presented for comparative purposes.  We will expand our disclosures in accordance with FSP FAS 132(R)-1 in our Annual Report on Form 10-K for

 
6
 
 
 
MARATHON OIL CORPORATION
 
 
Notes to Consolidated Financial Statements (Unaudited)
 
the year ending December 31, 2009; however, the adoption of this standard is not expected to have a significant impact on our consolidated results of operations, financial position or cash flows.
 
3.      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, provided the effect is not antidilutive.
 
 
Three Months Ended March 31,
 
 
2009
   
2008
 
(In millions, except per share data)
Basic
 
Diluted
   
Basic
 
Diluted
 
Net income
  $ 282     $ 282     $ 731     $ 731  
                     
Weighted average common shares outstanding
    709       709       713       713  
Effect of dilutive securities
    -       3       -       4  
 
                               
 Weighted average common shares, including dilutive effect
    709       712       713       717  
                     
Per share:
                               
    Net income
  $ 0.40     $ 0.40     $ 1.03     $ 1.02  
 
The per share calculations above exclude 9 million and 4 million stock options for the first three months of 2009 and 2008, as they were antidilutive.
 
4.      Assets Held for Sale
 
As of March 31, 2009, assets held for sale primarily represented our operated properties in Ireland (Exploration and Production segment) as shown in the following table:
 
(In millions)
 
Current assets
$
110 
Noncurrent assets
 
116 
     Total assets
 
226 
Current liabilities
 
Noncurrent liabilities
 
203 
     Total liabilities
 
207 
          Net assets held for sale
$
19 
 
On April 17, 2009, we closed the sale of our operated properties in Ireland for proceeds of $186 million, before adjusting for cash on hand at closing estimated to be $84 million.  An after-tax gain on the sale of these properties of approximately $100 million will be recorded in the second quarter of 2009.  In addition, we terminated our pension plan in Ireland for which a separate pretax loss of $21 million will be recognized in the second quarter of 2009.
 
In April 2009, we entered into two agreements to sell a portion of our Permian Basin producing assets in New Mexico and west Texas (Exploration and Production segment).  The total value of these transactions is $301 million, excluding any purchase price adjustments due at closing.  The carrying value of these operating assets was $83 million at March 31, 2009 and will be classified as held for sale beginning April 1, 2009.  These transactions are expected to close in the second quarter of 2009.
 
 
 
7
 
 
 
MARATHON OIL CORPORATION
 
 
Notes to Consolidated Financial Statements (Unaudited)
 
5.      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 by-products;
 
 
3)
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.; and
 
 
4)
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.
 
   
Three Months Ended March 31, 2009
 
(In millions)
 
E&P
   
OSM
   
RM&T
   
IG
   
Total
 
Revenues:
                             
    Customer
  $ 1,384     $ 97     $ 8,660     $ 11     $ 10,152  
    Intersegment (a)
    119       25       9       -       153  
    Related parties (b)
    15       -       5       -       20  
        Segment revenues
    1,518       122       8,674       11       10,325  
    Elimination of intersegment revenues
    (119 )     (25 )     (9 )     -       (153 )
    Gain on U.K. natural gas contracts
    82       -       -       -       82  
        Total revenues
  $ 1,481     $ 97     $ 8,665     $ 11     $ 10,254  
Segment income (loss)
  $ 100     $ (24 )   $ 159     $ 27     $ 262  
Income (loss) from equity method investments(b)
    11       -       (6 )     42       47  
Depreciation, depletion and amortization (c)
    470       37       152       1       660  
Income tax provision (benefit)(c)
    189       (8 )     106       13       300  
Capital expenditures (d)
    389       286       660       -       1,335  

   
Three Months Ended March 31, 2008
 
(In millions)
 
E&P
   
OSM
   
RM&T
   
IG
   
Total
 
Revenues:
                             
    Customer
  $ 2,819     $ 179     $ 14,333     $ 19     $ 17,350  
    Intersegment (a)
    159       20       165       -       344  
    Related parties (b)
    14       -       528       -       542  
        Segment revenues
    2,992       199       15,026       19       18,236  
    Elimination of intersegment revenues
    (159 )     (20 )     (165 )     -       (344 )
    Loss on U.K. natural gas contracts
    (70 )     -       -       -       (70 )
        Total revenues
  $ 2,763     $ 179     $ 14,861     $ 19     $ 17,822  
Segment income (loss)
  $ 684     $ 27     $ (75 )   $ 99     $ 735  
Income from equity method investments(b)
    62       -       28       119       209  
Depreciation, depletion and amortization (c)
    259       34       148       1       442  
Income tax provision (benefit)(c)
    687       9       (45 )     48       699  
Capital expenditures (d)
    775       248       511       1       1,535  
 
(a)
Management believes intersegment transactions were conducted under terms comparable to those with unrelated parties.
 
(b)
Pilot Travel Centers LLC, which was reported in our RM&T segment, was sold in the fourth quarter of 2008.
 
(c)
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.
 
(d)
Differences between segment totals and our totals represent amounts related to corporate administrative activities.
 
8

 
 
 
MARATHON OIL CORPORATION
 
 
Notes to Consolidated Financial Statements (Unaudited)
 

The following reconciles segment income to net income as reported in the consolidated statements of income:
 
             
 
Three Months Ended March 31,
 
(In millions)
2009
   
2008
 
Segment income
  $ 262     $ 735  
Items not allocated to segments, net of income taxes:
               
     Corporate and other unallocated items
    (22 )     32  
     Gain (loss) on U.K. natural gas contracts
    42       (36 )
          Net income
  $ 282     $ 731  

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)
2009
   
2008
 
Total revenues
  $ 10,254     $ 17,822  
Less:  Sales to related parties
    20       542  
Sales and other operating revenues (including consumer excise taxes)
  $ 10,234     $ 17,280  
 
6.      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)
 
2009
   
2008
   
2009
   
2008
 
Service cost
  $ 35     $ 34     $ 5     $ 5  
Interest cost
    42       39       11       12  
Expected return on plan assets
    (40 )     (42 )     -       -  
Amortization:
                               
    – prior service cost (credit)
    3       3       (1 )     (2 )
    – actuarial loss
    6       4       -       1  
Net periodic benefit cost
  $ 46     $ 38     $ 15     $ 16  
 
During the first three months of 2009, we made contributions of $9 million to our funded international pension plans.  We expect to make additional contributions up to an estimated $356 million to our funded pension plans over the remainder of 2009, the majority of which will occur in the third quarter of 2009.  We are still evaluating guidance issued by the Internal Revenue Service on March 31, 2009, which may defer required cash contributions to later periods.  Current benefit payments related to unfunded pension and other postretirement benefit plans were $7 million and $8 million during the first three months of 2009.
 
7.      Income Taxes
 
The following is an analysis of the effective income tax rates for the periods presented:
 
   
Three Months Ended March 31,
 
   
2009
   
2008
 
Statutory U.S. income tax rate
    35 %     35 %
Foreign taxes in excess of federal statutory rate
    13       10  
State and local income taxes, net of federal income tax effects
    1       1  
Other tax effects
    -       (2 )
        Effective income tax rate
    49 %     44 %
 
 
9
 
 
 
MARATHON OIL CORPORATION
 
 
Notes to Consolidated Financial Statements (Unaudited)
 
The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income.  The sources of income and related tax expense contributed to the increase in the effective income tax rate in the first three months of 2009 when compared to the same period in 2008.
 
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.  As of March 31, 2009, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated.
 
   
United States (a)
2001 - 2007
Canada
2000 - 2007
Equatorial Guinea
2006 - 2007
Libya
2006 - 2007
Norway
2007 
United Kingdom
2007 
 
(a)
Includes federal and state jurisdictions.
 
8.      Comprehensive Income
 
The following sets forth comprehensive income for the periods indicated:
 
   
Three Months Ended March 31,
 
(In millions)
 
2009
   
2008
 
Net income
  $ 282     $ 731  
Other comprehensive income, net of taxes:
               
     Defined benefit postretirement plans
    (1 )     11  
     Derivatives
    (30 )     3  
     Other
    1       (5 )
                 
         Comprehensive income
  $ 252     $ 740  
 
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)
 
2009
   
2008
 
Liquid hydrocarbons, natural gas and bitumen
  $ 1,289     $ 1,376  
Refined products and merchandise
    1,794       1,797  
Supplies and sundry items
    413       334  
        Total, at cost
  $ 3,496     $ 3,507  
 
10.           Property, Plant and Equipment
 
Exploratory well costs capitalized greater than one year after completion of drilling were $79 million as of March 31, 2009, an increase of $25 million from December 31, 2008.  This is primarily due to the addition of an exploration well drilled in early 2008 on the Southwest Foinaven prospect in the U.K. Atlantic Margin.  We are evaluating the potential for combined development in conjunction with nearby prospects.
 
 
10
 
 
 
MARATHON OIL CORPORATION
 
 
Notes to Consolidated Financial Statements (Unaudited)
 
11.           Fair Value Measurements
 
The following tables present our net financial assets and liabilities accounted for at fair value on a recurring basis, by fair value hierarchy level.
 
 
March 31, 2009
 
(In millions)
 
Level 1
   
Level 2
   
Level 3
   
Total
 
Derivative Instruments:
                       
     Commodity
  $ 33     $ 3     $ (20 )   $ 16  
     Interest rate
    -       -       29       29  
     Foreign currency
    -       (66 )     -       (66 )
          Total derivative instruments
    33       (63 )     9       (21 )
     Other assets
    2       -       -       2  
          Total at fair value
  $ 35     $ (63 )   $ 9     $ (19 )
                                 
 
December 31, 2008
 
(In millions)
 
Level 1
   
Level 2
   
Level 3
   
Total
 
Derivative Instruments:
                               
     Commodity
  $ 107     $ 6     $ (55 )   $ 58  
     Interest rate
    -       -       29       29  
     Foreign currency
    -       (75 )     -       (75 )
          Total derivative instruments
    107       (69 )     (26 )     12  
     Other assets
    2       -       -       2  
          Total at fair value
  $ 109     $ (69 )   $ (26 )   $ 14  

    Deposits of $39 million and $121 million, in broker accounts covered by master netting agreements, are included in the fair values of commodity derivatives as of March 31, 2009 and December 31, 2008.   As the fair value of these derivative instruments fluctuates, so does the amount of required collateral.
 
Commodity derivatives in Level 3 include two U.K. natural gas sales contracts that are accounted for as derivative instruments and crude oil options related to sales of Canadian synthetic crude oil.  The U.K. natural gas contracts originated in the early 1990s and expire in September 2009.  The crude oil options expire December 2009.  At March 31, 2009, the U.K. natural gas contracts were a net asset of $9 million and the crude oil options were a net liability of $4 million.  At December 31, 2008, the U.K. natural gas contracts were a net liability of $72 million and the crude oil options were a net asset of $52 million.
 
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, 2009
(In millions)
 
Beginning balance
$
 (26)
     Total realized and unrealized losses:
   
          Included in net income
 
 77 
     Purchases, sales, issuances and settlements, net
 
 (42)
Ending balance
$
 9 
 
 Unrealized gains of $76 million were included in net income for the first quarter of 2009 related to instruments held at March 31, 2009.
 
Amounts reported in net income are classified as sales and other operating revenues or cost of revenues for commodity derivative instruments, as net interest and other financing income for interest rate derivative instruments and as cost of revenues for foreign currency derivatives, except those designated as hedges of future capital expenditures.
 
 
11
 
 
 
MARATHON OIL CORPORATION
 
 
Notes to Consolidated Financial Statements (Unaudited)
 
12.           Derivatives
 
We may use derivatives to manage our exposure to commodity price risk, interest rate risk and foreign currency risk.  Derivative instruments are recorded at fair value.  Derivative instruments on our consolidated balance sheet arereported on a net basis by brokerage firm, as permitted by master netting agreements.  For further information regarding the fair value measurement of derivative instruments see Note 11.  The following table presents the gross fair values of derivative instruments and where they appear on the consolidated balance sheet, excluding cash collateral as of March 31, 2009.
 
(In millions)
 
Asset
   
Liability
   
Net Asset
 
Balance Sheet Location
Cash Flow Hedges
                   
     Foreign currency
  $ 1     $ -     $ 1  
Other current assets
Total Designated Hedges
    1       -       1    
                           
Not Designated as Hedges
                         
     Commodity
    292       (246 )     46  
Other current assets
Total Not Designated as Hedges
    292       (246 )     46    
                           
     Total
  $ 293     $ (246 )   $ 47    
                           
       
(In millions)
 
Asset
   
Liability
   
Net Liability
 
Balance Sheet Location
Cash Flow Hedges
                         
     Foreign currency
  $ -     $ (67 )   $ (67 )
Other current liabilities
Fair Value Hedges
                         
     Commodity
    -       (11 )     (11 )
Other current liabilities
     Interest rate
    29       -       29  
Long-term debt
Total Designated Hedges
    29       (78 )     (49 )  
                           
Not Designated as Hedges
                         
                           
     Commodity
    9       (67 )     (58 )
Other current liabilities
                           
Total Not Designated as Hedges
    9       (67 )     (58 )  
     Total
  $ 38     $ (145 )   $ (107 )  
 
Derivatives Designated as Cash Flow Hedges
 
We use foreign currency forwards and options to hedge anticipated transactions, primarily expenditures for capital projects, in certain foreign currencies and designate them cash flow hedges.  As of March 31, 2009, the following foreign currency forwards were outstanding:
 
(In millions)
Period
 
Notional Amount
   
Weighted Average Forward Rate
 
Foreign Currency Forwards:
             
    Dollar (Canada)
April 2009 - February 2010
  $ 403       1.065 (a)
    Euro
April 2009 - April 2010
  $ 12       1.257 (a)
    Kroner (Norway)
April 2009 - November 2009
  $ 60       6.273 (b)
 
(a)
Foreign currency to U.S. dollar.
 
(b)
U.S. dollar to foreign currency.
 
We may use interest rate derivative instruments to manage the market risk of interest rate movements on anticipated borrowings.  Such derivatives are usually outstanding for a period of less than one month and none were outstanding at March 31, 2009.
 
    For derivatives qualifying as hedges of future cash flows, the effective portion of any changes in fair value is recognized in other comprehensive income (“OCI”) and is reclassified to net income when the underlying forecasted
 
12
 
 
 
MARATHON OIL CORPORATION
 
 
Notes to Consolidated Financial Statements (Unaudited)
 
transaction is recognized in net income.  Any ineffective portion of cash flow hedges is recognized in net income as it occurs.  For discontinued cash flow hedges, prospective changes in the fair value of the derivative are recognized in net income. The accumulated gain or loss recognized in OCI at the time a hedge is discontinued continues to be deferred until the original forecasted transaction occurs.  However, if it is determined that the likelihood of the original forecastedtransaction occurring is no longer probable, the entire accumulated gain or loss recognized in OCI is immediately reclassified into net income.
 
Amounts currently in accumulated other comprehensive income (“AOCI”) for cash flow hedges will be reclassified from AOCI into net income through either depreciation, depletion and amortization as the fixed assets are used or net interest and financing costs over the life of the debt.  Approximately $1 million in losses are expected to be reclassified from AOCI over the next 12 months.  The ineffective portion of currently outstanding cash flow hedges was less than $1 million; therefore, ineffectiveness is not reported in the tables below.  In the quarter ended March 31, 2009 no cash flow hedges were discontinued.
 
The following table summarizes the effect of derivative instruments designated as hedges of cash flows in other comprehensive income and in our consolidated statement of income for the three months ended March 31, 2009.
 
(In millions)
 
Gain (Loss) in OCI
 
Location of Gain (Loss) Reclassified from Accumulated OCI
 
Gain (Loss) reclassified from AOCI into Income
 
               
Foreign currency
  $ (12 )
Depreciation, depletion and amortization
  $ -  
Interest rate
  $ (15 )
Net interest and other financing income (costs)
  $ 1  
 
Derivatives Designated as Fair Value Hedges
 
We use interest rate swaps to manage the mix of fixed and floating interest rate debt in our portfolio.  As of March 31, 2009, we had multiple interest rate swap agreements with a total notional amount of $550 million at a weighted average, LIBOR-based, floating rate of 4.11 percent.  For such derivatives designated as hedges of fair value, changes in the fair values of both the hedged item and the related derivative are recognized immediately in net income with an offsetting effect included in the basis of the hedged item. The net effect is to report in net income the extent to which the hedge is not effective in achieving offsetting changes in fair value.
 
We use commodity derivative instruments to manage the price risk for natural gas that is purchased to be marketed with our own natural gas production.  These are also designated as fair value hedges.  As of March 31, 2009, commodity derivative instruments for a weighted average 10,000 mcf  (“thousand cubic feet”) were outstanding for the period April 2009 through March 2010.
 
The following table summarizes the pretax effect of derivative instruments designated as hedges of fair value in our consolidated statement of income for the three months ended March 31, 2009.
 
(In millions)
Income Statement Location
 
Gain (Loss)
 
Derivative
       
     Commodity
Sales and other operating revenues
  $ (6 )
     Interest rate
Net interest and other financing income (costs)
    -  
        (6 )
Hedged Item
         
     Commodity
Sales and other operating revenues
    6  
     Interest rate
Long-term debt
    -  
      $ 6  
 
The interest rate swaps have no hedge ineffectiveness.  Hedge ineffectiveness related to the commodity derivatives is less than $1 million and is therefore not reflected in the above table.
 
Derivatives not Designated as Hedges
 
Changes in the fair value of derivatives not designated as hedges are
 
13
 
 
 
MARATHON OIL CORPORATION
 
 
Notes to Consolidated Financial Statements (Unaudited)
 
 recognized immediately in net income.  Some derivative instruments not designated as hedges may be classified as trading activities, for which all related effects, are recognized in net income and are classified as other income.
 
Two long-term natural gas delivery commitment contracts in the U.K. are classified as derivative instruments. These contracts, which expire September 2009, contain pricing provisions that are not clearly and closely related to the underlying commodity and therefore must be accounted for as derivative instruments.
Crude oil options entered by Western Oil Sands Inc. (“Western”) to protect against price decreases on a portion of future sales of synthetic crude oil were not designated as hedges upon our acquisition of Western in October 2007.  In the first quarter of 2009, we sold derivative instruments which effectively offset the open put options for the remainder of 2009.  The following table summarizes the put and call options outstanding at March 31, 2009.
 
       
Option Contract Volumes (Barrels per day)
     
Put options purchased
    20,000  
Put options sold
    20,000  
Call options sold
    15,000  
Average Exercise Price (Dollars per barrel)
       
Put options
  $ 50.50  
Call options
  $ 90.50  
 
We use commodity derivative instruments to manage price risk on inventories and natural gas held in storage before it is sold.   We also use derivative instruments to manage price risk related to fixed price sales of refined products, the acquisition of foreign-sourced crude oil, the acquisition of feedstocks used in the refining process and the acquisition of ethanol for blending with refined products.  The following table summarizes volumes related to our net open positions as of March 31, 2009.
 
   
Buy/(Sell)
Crude oil (million barrels)
 2.7 
Refined products (million barrels)
 1.7 
Natural gas (billion cubic feet)
 
 
Price
 (2.2)
 
Basis
 (1.3)
 
The following table summarizes the effect of all derivative instruments not designated as hedges in our consolidated statement of income for the three months ended March 31, 2009.
 
(In millions)
Income Statement Location
 
Gain (Loss)
 
Commodity
Sales and other operating revenues
  $ 93  
Commodity
Cost of revenues
    (59 )
Commodity
Other income
    1  
      $ 35  

Contingent Credit Features
 
Our derivative instruments contain no significant contingent credit features.
 
Concentration of Credit Risk 
 
All of our derivative instruments involve elements of credit and market risk.  The most significant portion of our credit risk relates to counterparty performance.  We are exposed to potential losses in the event of non-performance by counterparties.  The counterparties to our derivative instruments consist primarily of major financial institutions and companies within the energy industry.  To manage counterparty risk associated with these derivatives instruments, we select and monitor counterparties based on credit ratings and our assessment of their financial strength.  Additionally, we limit the level of exposure with any single counterparty.  
 
 
14
 
 
 
MARATHON OIL CORPORATION
 
 
Notes to Consolidated Financial Statements (Unaudited)
 
13.           Debt
 
At March 31, 2009, we had no borrowings against our revolving credit facility and no commercial paper outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.
 
     On February 17, 2009, we issued $700 million aggregate principal amount of senior notes bearing interest at 6.5 percent with a maturity date of February 15, 2014 and $800 million aggregate principal amount of senior notes bearing interest at 7.5 percent with a maturity date of February 15, 2019.  Interest on both issues is payable semi-annually beginning August 15, 2009.
 
14.           Commitments and Contingencies
 
We are 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.  The ultimate resolution of these contingencies could, individually or in the aggregate, be material to our consolidated financial statements.  However, management believes that we will remain a viable and competitive enterprise even though it is possible that these contingencies could be resolved unfavorably.  Certain of our commitments and contingencies are discussed below.
 
We settled a number of lawsuits pertaining to methyl tertiary-butyl ether (“MTBE”) in 2008.  Presently, we are a defendant, along with other refining companies, in 13 cases arising in three states alleging damages for MTBE contamination.   We have also received 4 Toxic Substances Control Act notice letters involving potential claims in two states.  Such notice letters are often followed by litigation.  Like the cases that were settled in 2008, the remaining MTBE cases are consolidated in a multi-district litigation (“MDL”) in the Southern District of New York for pretrial proceedings.  Twelve of the remaining cases allege damages to water supply wells, similar to the damages claimed in the settled cases. In the other remaining case, the State of New Jersey is seeking natural resources damages allegedly resulting from contamination of groundwater by MTBE. This is the only MTBE contamination case in which we are a defendant and natural resources damages are sought. Eight cases were dismissed from the MDL and 7 of those 8 cases, along with 3 new cases, have been re-filed in state courts (Nassau and Suffolk Counties, New York), however, we have not been served.  We are vigorously defending these cases.  We, along with a number of other defendants, have engaged in settlement discussions related to the majority of the cases in which we are a defendant.  We do not expect our share of liability, if any, for the remaining cases to significantly impact our consolidated results of operations, financial position or cash flows.  We voluntarily discontinued producing MTBE in 2002.
 
We are currently a party in two qui tam cases, which allege that federal and Indian leases violated the False Claims Act with respect to the reporting and payment of royalties on natural gas and natural gas liquids.  A qui tam action is an action in which the relator files suit on behalf of himself as well as the federal government.  One case is U.S. ex rel Harrold E. Wright v. Agip Petroleum Co. et al which is primarily a gas valuation case.  A settlement agreement has been reached, but not yet finalized.  Such settlement is not expected to significantly impact our consolidated results of operations, financial position or cash flows.  The other case is U.S. ex rel Jack Grynberg v. Alaska Pipeline, et al. involving allegations of natural gas measurement.  This case was dismissed by the trial court and the dismissal has been affirmed by the 10th Circuit Court of Appeals.  The relator is expected to file an appeal to the U.S. Supreme Court. The outcome of this case is not expected to significantly impact our consolidated results of operations, financial position or cash flows.
 
 A lawsuit filed in the U.S. District Court for the Southern District of West Virginia alleges that our Catlettsburg, Kentucky, refinery distributed contaminated gasoline to wholesalers and retailers for a period prior to August, 2003, causing permanent damage to storage tanks, dispensers and related equipment, resulting in lost profits, business disruption and personal and real property damages.  Following the incident, we conducted remediation operations at affected facilities.  Class action certification was granted in August 2007. We have entered into a settlement of this case.  The proposed settlement will not significantly impact our consolidated results of operations, financial position or cash flows.
 
Contractual commitments At March 31, 2009, our contract commitments to acquire property, plant and equipment totaled $3,611 million.
 
 
15
 
 
 
MARATHON OIL CORPORATION
 
 
Notes to Consolidated Financial Statements (Unaudited)
 
15.        Supplemental Cash Flow Information

   
Three Months Ended March 31,
 
(In millions)
 
2009
   
2008
 
Net cash provided from operating activities:
           
     Interest paid (net of amounts capitalized)
  $ -     $ 23  
     Income taxes paid to taxing authorities
    648       638  
Commercial paper and revolving credit arrangements, net:
               
     Commercial paper - issuances
  $ 897     $ 13,491  
                                     - repayments
    (897 )     (12,533 )
          Total
  $ -     $ 958  
Noncash investing and financing activities:
               
     Capital lease and sale-leaseback financing obligations
  $ 21     $ 18  
 
16.           Accounting Standards Not Yet Adopted

 
In April 2009, two related Financial Accounting Standards Board (“FASB”) Staff Positions were issued:
 
 
·
FASB Staff Position (“FSP”) No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” (“FSP FAS 107-1”)
 
 
·
FSP No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” (“FSP FAS 157-4”)
 
FSP FAS 107-1 amends SFAS No. 107 and Accounting Principles Board (“APB”) Opinion No. 28 to require disclosures about fair value of financial instruments in interim reporting periods for publicly traded companies.  This FSP is effective for the second quarter of 2009 and does not require disclosures for earlier periods presented for comparative purposes.  We will adopt the new disclosure provisions in the second quarter of 2009; however, the adoption of this standard is not expected to have a significant impact on our consolidated results of operations, financial position or cash flows.
 
FSP FAS 157-4 provides additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for the asset or liability has significantly decreased.  It also includes guidance on identifying circumstances that indicate a transaction is not orderly.  Additional disclosures are also required.  FSP FAS 157-4 is effective for the second quarter of 2009 and does not require disclosures for earlier periods presented for comparative purposes.  We do not expect the adoption of this standard will have a significant impact on our consolidated results of operations, financial position or cash flows.
 
    In December 2008, the SEC announced that it had approved revisions to its oil and gas reporting disclosures. The new disclosure requirements include provisions that:
 
 
·
Introduce a new definition of oil and gas producing activities. This new definition allows companies to include volumes in their reserve base from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.
 
 
·
Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end prices.  The SEC indicated that they will continue to communicate with the FASB staff to align their accounting standards with these rules.  The FASB currently requires a single-day, year-end price for accounting purposes.
 
 
·
Permit companies to disclose their probable and possible reserves on a voluntary basis. Under current rules, proved reserves were the only reserves allowed in the disclosures.
 
 
·
Require companies to provide additional disclosure regarding the aging of proved undeveloped reserves.
 
 
·
Permit the use of reliable technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.
 
 
·
Replace the existing "certainty" test for areas beyond one offsetting drilling unit from a productive well with a "reasonable certainty" test.
 
 
 
16
 
 
 
MARATHON OIL CORPORATION
 
 
Notes to Consolidated Financial Statements (Unaudited)
 
 
 
 
·
Require additional disclosures regarding the qualifications of the chief technical person who oversees the company's overall reserve estimation process. Additionally, disclosures regarding internal controls surrounding reserve estimation, as well as a report addressing the independence and qualifications of its reserves preparer or auditor will be mandatory.
 
 
·
Require separate disclosure of reserves in foreign countries if they represent more than 15 percent of total proved reserves, based on barrels of oil equivalents.
 
    We expect to begin complying with the disclosure requirements in our Annual Report on Form 10-K for the year ending December 31, 2009. The new rules may not be applied to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. We are currently in the process of evaluating the new requirements.
 
 
17
 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

    We are a global integrated energy company with significant operations in the U.S., Canada, Africa and Europe.  Our operations are organized into four reportable segments:
 
w
Exploration and Production (“E&P”) which explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis.
w
Oil Sands Mining (“OSM”) which mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and by-products.
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Refining, Marketing & Transportation (“RM&T”) which refines, markets and transports crude oil and petroleum products, primarily in the Midwest, upper Great Plains, Gulf Coast and southeastern regions of the United States.
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Integrated Gas (“IG”) which 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.
 
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 forward-looking statements.  For additional risk factors affecting our business, see Item 1A. Risk Factors in our 2008 Annual Report on Form 10-K.
 
Overview and Outlook

Exploration and Production

Production
 
Net liquid hydrocarbon and natural gas sales averaged 404 thousand barrels of oil equivalent per day (“mboepd”) during the first quarter of 2009 compared to 378 mboped in the same quarter of 2008.  This 7 percent increase in sales volumes reflects the addition of the Alvheim/Vilje development offshore Norway and the Neptune development in the Gulf of Mexico, both of which began production in mid-2008.  Natural gas sales in Equatorial Guinea have also increased due to improved reliability at the LNG and methanol plants which purchase this natural gas.
 
    In February, we began drilling the first of four development wells on the Droshky discovery in the Gulf of Mexico on Green Canyon Block 244, with first production targeted for 2010.
 
    Our net liquid hydrocarbon sales in North Dakota from the Bakken Shale resource play have increased to 8,500 barrels per day (“bpd”) in first quarter 2009 compared to 3,500 bpd in the same quarter of last year.  Development of the Bakken Shale play is part of our targeted expansion into key North America resource plays.
 
Exploration
 
During the first quarter of 2009, we announced the Leda discovery on Block 31 offshore Angola which was our 29th discovery on Blocks 31 and 32. We also participated in 2 wells in our Angola exploration and appraisal program that have reached total depth, the results of which will be announced upon receipt of government and partner approval.  We hold a 10 percent outside-operated interest in Block 31 and a 30 percent outside-operated interest in Block 32.
 
We were the apparent high bidder on 16 blocks bid in the Central Gulf of Mexico Lease Sale No. 208 conducted by the Minerals Management Service in the first quarter of 2009.  Ten blocks are 100 percent Marathon, and the remaining six blocks were bid with partners, for a total of $62 million.  
 
Divestitures
 
On April 17, 2009, we closed the sale of our operated properties located in Ireland for proceeds of $186 million, before adjusting for cash on hand at closing of $84 million.  An after-tax gain on the sale of these properties of approximately $100 million will be recorded in the second quarter of 2009.  Net production from these operations averaged 5,000 boepd in the first quarter of 2009.  Our net proved reserves associated with these assets as of December

 
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31, 2008, were 6 million barrels of oil equivalent (“mmboe”). In addition, we terminated our pension plan in Ireland for which a separate pretax loss of $21 million will be recognized in the second quarter of 2009.
 
In April 2009, we entered into two agreements to sell all of our company-operated and a portion of our outside-operated assets in the Permian Basin of New Mexico and west Texas.  The total value of these transactions is $301 million, excluding any purchase price adjustments due at closing.  We expect to close these transactions in the second quarter of 2009.  Net production from these operations averaged 8,150 boepd in the first quarter of 2009.   Our net proved reserves associated with these assets as of December 31, 2008, were 14 mmboe.
 
    The above discussions include forward-looking statements with respect to the timing and levels of future production, anticipated future exploratory drilling activity and pending divestitures.  Some factors that could potentially affect these forward-looking statements include pricing, supply and demand for petroleum products, the amount of capital available for exploration and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, 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 forward-looking statements may be further affected by the inability to obtain or delay in obtaining necessary government and third-party approvals and permits.  The divestitures could also be adversely affected by customary closing conditions. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.
 
Oil Sands Mining
 
Our net bitumen production was 25 thousand barrels per day (“mbpd”) in the first quarter of 2009 compared to 24 mbpd in the same quarter of 2008. 
 
The Athabasca Oil Sands Project (“AOSP”) Expansion 1, which includes construction of mining and extraction facilities at the Jackpine mine, expansion of treatment facilities at the existing Muskeg River mine, expansion of the Scotford upgrader and development of related infrastructure, is approximately 60 percent complete and is anticipated to begin operations in late 2010 or early 2011.
 
The above discussion includes forward-looking statements with respect to the start of operations of AOSP Expansion 1.  Factors that could affect the project are transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, delays in obtaining or conditions imposed by necessary government and third-party approvals and other risks customarily associated with construction projects.
 
Refining, Marketing and Transportation
 
Our total refinery throughputs were 1 percent lower in the first quarter of 2009 than in the first quarter of 2008.  Crude oil refined increased  1 percent for the same periods while other charge and blendstocks decreased 6 percent.
 
Planned major maintenance activities were completed at our Catlettsburg, Kentucky, refinery and initiated at our Robinson, Illinois, refinery in the first quarter of 2009. The maintenance at Robinson was completed in the second half of April 2009.  In the first quarter of 2008, major maintenance activities occurred at the Detroit, Michigan; Garyville, Louisiana and Robinson refineries.
 
Volumes under our ethanol blending program in the first quarter of 2009 increased to 67 mbpd compared to 45 mbpd in the same period of 2008.  The future expansion or contraction of our ethanol blending program will be driven by the economics of ethanol supply and government regulations.
 
First quarter 2009 Speedway SuperAmerica LLC same store gasoline sales volume increased 1 percent when compared to the first quarter of 2008 while same store merchandise sales increased 11 percent for the same period.
 
The expansion of our Garyville, Louisiana, refinery is 85 percent complete with an on-schedule startup expected in the fourth quarter 2009.  Construction activities continue on the heavy oil upgrading and expansion project at our Detroit refinery with completion expected in mid-2012.
 
The labor agreement with the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers Union covering certain employees in our Texas City, Texas, refinery was extended.  It now expires March 31, 2012.
 
The above discussion includes forward-looking statements with respect to the Garyville and Detroit refinery expansion projects.  Factors that could affect those projects include transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, delays in obtaining or conditions imposed by necessary government and third-party approvals, 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.
 
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Integrated Gas
 
Our share of LNG sales worldwide totaled 6,769 metric tonnes per day (“mtpd”) for the first quarter of 2009 compared to 6,912 mtpd in the first quarter of 2008.  These LNG sales volumes include both consolidated sales volumes and our share of the sales volumes of equity method investees.  LNG sales from Alaska are conducted through a consolidated subsidiary.  LNG and methanol sales from Equatorial Guinea are conducted through equity method investees. The LNG production facility in Equatorial Guinea had operational availability of 96 percent.
 
We continue to invest in the development of new technologies to create value and supply new energy sources.  In the first quarter of 2009, we recorded costs of approximately $18 million related to natural gas technology research, including our GTF™ technology.  Such costs were $16 million in the same period of 2008.
 
Management’s Discussion and Analysis of Results of Operations
 
Consolidated Results of Operations
 
    Consolidated net income in the first quarter of 2009 was 61 percent lower than in the same quarter of 2008.  The substantial decrease in global crude oil prices, and to a lesser extent natural gas prices, caused the decline.  Our RM&T segment benefited from improved margins, partially due to decreased costs of crude oil, reporting positive first quarter 2009 earnings compared to a loss in the same quarter of 2008.  Benchmark crude oil and natural gas price averages for the first three months of 2009 and 2008 are listed below to illustrate the price decline.
 
   
Three Months Ended March 31,
 
   
2009
   
2008
 
West Texas Intermediate crude oil (Dollars per barrel)
  $ 43.31     $ 97.82  
Brent crude oil (Dollars per barrel)
  $ 44.46     $ 96.71  
Henry Hub prompt natural gas (Dollars per mmbtu)
  $ 4.58     $ 8.58  

             
Revenues are summarized by segment in the following table:
 
             
   
Three Months Ended March 31,
 
(In millions)
 
2009
   
2008
 
E&P
  $ 1,518     $ 2,992  
OSM
    122       199  
RM&T
    8,674       15,026  
IG
    11       19  
    Segment revenues
    10,325       18,236  
Elimination of intersegment revenues
    (153 )     (344 )
Gain (loss) on U.K. natural gas contracts
    82       (70 )
    Total revenues
  $ 10,254     $ 17,822  
                 
Items included in both revenues and costs:
               
     Consumer excise taxes on petroleum products and merchandise
  $ 1,174     $ 1,216  
 
E&P segment revenues decreased $1,474 million in the first quarter of 2009 from the comparable prior-year period.  The decrease was primarily a result of lower liquid hydrocarbon and natural gas price realizations.  Liquid hydrocarbon realizations averaged $40.20 per barrel in the first quarter of 2009 compared to $88.70 in the first quarter of 2008, while natural gas realizations averaged $3.16 and $4.75 per mcf in the same periods.
 
Net sales volumes during the quarter averaged 404 mboepd, compared to 378 mboepd for the same period last year. This 7 percent increase in sales volumes reflects the liquid hydrocarbon and natural gas production increases previously discussed.
 
See Supplemental Statistics for information regarding net sales volumes and average realizations by geographic area.
 
Excluded from E&P segment revenues are gains of $82 million in the first quarter of 2009 related to natural gas sales contracts in the U.K. that are accounted for as derivative instruments.  For the first quarter of 2008, losses of $70 million are excluded from E&P segment revenues related to these contracts.
 
 
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OSM segment revenues decreased $77 million in the first quarter of 2009 from the comparable prior-year period.  The decrease was driven primarily by a 57 percent decrease in average realizations.  Net synthetic crude sales for the first quarter of 2009 were 32 mbpd at an average realized price of $38.49 per barrel compared to 31 mbpd at $88.85 in the same period of 2008.  Revenues in both periods include the impact of derivative instruments intended to mitigate price risk related to future sales of synthetic crude.  Included in segment revenues was a net gain of $8 million on crude oil derivative instruments in the first quarter of 2009 versus a net loss of $48 million for the same period in 2008.  During the first quarter 2009, we sold derivative instruments at an average exercise price of $50.50 per barrel which effectively offset the open crude oil put positions.
 
    See Note 12 to the consolidated financial statements for additional discussion about derivative instruments.
 
RM&T segment revenues decreased $6,352 million in the first quarter of 2009 from the comparable prior-year period. The decrease primarily reflects lower refined product and liquid hydrocarbon selling prices.
    
Sales to related parties decreased as a result of the sale of our interest in Pilot Travel Centers LLC (“PTC”) during the fourth quarter of 2008.
 
Income from equity method investments decreased $162 million in the first quarter of 2009 from the comparable prior-year period.  Lower commodity prices in the first quarter of 2009 compared to the same period of 2008 negatively impacted the earnings of many of our equity method investees.  The sale of our equity method investment in PTC during the fourth quarter of 2008 also contributed to the decrease.
 
Cost of revenues decreased $7,050 million in the first quarter of 2009 from the comparable prior-year period.  The decrease resulted primarily from lower acquisition costs of crude oil, refinery charge and blend stocks and purchased refined products in the RM&T segment.
 
    Depreciation, depletion and amortization (“DD&A”) increased $214 million in the first quarter from the comparable prior-year period.  The DD&A increase is primarily due to the commencement of production from the Alvheim/Vilje and Neptune developments in mid-year 2008.
 
Exploration expenses were $62 million in the first quarter of 2009, including expenses related to domestic onshore dry wells of $4 million.   Exploration expenses were $129 million in the first quarter of 2008, including expenses related to dry wells of $30 million, primarily related to offshore drilling.  Other exploration expenses in the first quarter of 2008 included the acquisition of seismic data in Indonesia and the evaluation of Canadian in-situ oil sands leases.
 
Provision for income taxes decreased $298 million in the first quarter of 2009 from the comparable period of 2008 primarily due to the decrease in income.  The effective tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income.  The sources of income and related tax expense contributed to the increase in the effective income tax rate in the first quarter of 2009 when compared to the same period in 2008.  The following is an analysis of the effective income tax rates for the first three months of 2009 and 2008.
 
   
Three Months Ended March 31,
 
   
2009
   
2008
 
Statutory U.S. income tax rate
    35 %     35 %
Foreign taxes in excess of federal statutory rate
    13       10  
State and local income taxes, net of federal income tax effects
    1       1  
Other tax effects
    -       (2 )
        Effective income tax rate
    49 %     44 %

 
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Segment Results
 
             
Segment income is summarized in the following table:
 
             
   
Three Months Ended March 31,
 
(In millions)
 
2009
   
2008
 
E&P
           
             
    United States
  $ (52 )   $ 244  
    International
    152       440  
            E&P segment
    100       684  
OSM
    (24 )     27  
RM&T
    159       (75 )
IG
    27       99  
            Segment income
    262       735  
Items not allocated to segments, net of income taxes:
               
    Corporate and other unallocated items
    (22 )     32  
    Gain (loss) on U.K. natural gas contracts
    42       (36 )
Net income
  $ 282     $ 731  
 
United States E&P income decreased $296 million in the first quarter of 2009 compared to the same period of 2008.  Revenues decreased 56 percent as a result of lower realizations on both liquid hydrocarbons and natural gas.  DD&A expense increased due to the commencement of production from the Neptune development mid-year 2008.  A downward revision in proved reserves for Neptune in the first quarter of 2009 increased DD&A expense and also led to a charge related to unutilized pipeline capacity.  Also contributing to the lower income in the first quarter of 2009 were charges related to the cancellation of drilling rigs and a partial impairment of our investment in a pipeline in the Gulf of Mexico.  Exclusive of DD&A expense, these first quarter 2009 charges totaled $37 million.
 
International E&P income decreased $288 million in the first quarter of 2009 compared to the same period of 2008.  The decrease was primarily a result of lower liquid hydrocarbon realizations. Liquid hydrocarbon sales from the Alvheim/Vilje development had a favorable income impact, partially offset by the DD&A related to the new production.  Lower exploration expenses had a positive impact.
 
 OSM segment reported a loss of $24 million in the first quarter of 2009 compared to income of $27 million in the first quarter 2008.  The decrease was primarily the result of a 57 percent decrease in average realizations for the first quarter of 2009.  This reduction in realizations was partially offset by an increase in synthetic crude sales volumes and lower operating costs primarily impacted by lower commodity prices.
 
Included in segment results was an after-tax gain of $6 million on crude oil derivative instruments in the first quarter of 2009 compared to an after-tax loss of $36 million in the same period of 2008.  These derivatives expire by the end of 2009.
 
RM&T segment income increased $234 million in the first quarter of 2009 compared to the same period of 2008.  The increase was primarily a result of a higher refining and wholesale marketing gross margin, which increased to 7.92 cents per gallon in the first quarter of 2009 from a negative 0.26 cents per gallon in the comparable period of 2008.  Our manufacturing and other expenses were lower in the first quarter of 2009 as compared to the first quarter of 2008 primarily due to lower energy and maintenance costs.  Lower ethanol blending margins partially offset these favorable impacts.
 
Our refining and wholesale marketing gross margin also included pretax derivative losses of $60 million in the first quarter of 2009 compared to losses of $120 million in the first quarter of 2008.  In 2009, we no longer use derivatives to manage domestic crude oil acquisition price risk.
 
IG segment income decreased $72 million in the first quarter of 2009 compared to the same period of 2008.  The decrease was primarily a result of lower price realizations.

 
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Management’s Discussion and Analysis of Cash Flows and Liquidity
 
Cash Flows
 
 
Net cash provided by operating activities totaled $555 million in the first three months of 2009, compared to $797 million in the first three months of 2008.  Cash provided by operating activities decreased primarily due to lower net income.  Working capital changes decreased net cash provided by operations by $497 million in the first quarter of 2009 compared to $462 million in the same period of 2008.
 
Net cash used in investing activities totaled $1,274 million in the first three months of 2009, compared to $1,457 million in the first three months of 2008.  Our long-term projects, such as the Garyville refinery major expansion, Expansion 1 of the AOSP, exploration offshore Angola and in the Gulf of Mexico, and development of Alvheim, the Bakken Shale resource play and the Droshky prospect, were the most significant investing activities in both periods. For further information regarding capital expenditures by segment, see Supplemental Statistics.
 
Net cash provided by financing activities was $1,307 million in the first three months of 2009, compared to $646 million in the first three months of 2008.  Sources of cash in the first three months of 2009 included the issuance of $1.5 billion in senior notes, while $1.0 billion in senior notes and $959 in commercial paper were issued in the three months of 2008.  Uses of cash in the first three months of 2008 included the repayment of $400 million 6.85 percent notes, and the payment and termination of the Marathon Oil Canada Corporation (previously Western Oil Sands Inc.) revolving credit facility.
 
Liquidity and Capital Resources
 
Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations and our $3.0 billion committed revolving credit facility.  Because of the alternatives available to us, including internally generated cash flow and access to capital markets, we believe that our short-term and long-term liquidity is adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, share repurchase program, dividend payments, defined benefit plan contributions, repayment of debt maturities and other amounts that may ultimately be paid in connection with contingencies.
 
Capital Resources
 
At March 31, 2009, we had no borrowings against our revolving credit facility and no commercial paper outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.
 
 On February 17, 2009, we issued $700 million aggregate principal amount of senior notes bearing interest at 6.5 percent with a maturity date of February 15, 2014 and $800 million aggregate principal amount of senior notes bearing interest at 7.5 percent with a maturity date of February 15, 2019.  Interest on both issues is payable semi-annually beginning August 15, 2009.
 
On July 26, 2007, we filed a universal shelf registration statement with the Securities and Exchange Commission, under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.
 
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+.

Our cash-adjusted debt-to-capital ratio (total debt-minus-cash to total debt-plus-equity-minus-cash) was 24 percent at March 31, 2009, compared to 22 percent at December 31, 2008.  This includes $481 million of debt that is serviced by United States Steel.

 
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March 31,
   
December 31,
 
(In millions)
 
2009
   
2008
 
    Long-term debt due within one year
  $ 101     $ 98  
    Long-term debt
    8,590       7,087  
            Total debt
  $ 8,691     $ 7,185  
                 
    Cash
  $ 1,869     $ 1,285  
    Trusteed funds from revenue bonds
  $ 3     $ 16  
    Equity
  $ 21,511     $ 21,409  
                 
    Calculation:
               
                 
    Total debt
  $ 8,691     $ 7,185  
    Minus cash
    1,869       1,285  
    Minus trusteed funds from revenue bonds
    3       16  
            Total debt minus cash
  $ 6,819     $ 5,884  
                 
    Total debt
    8,691       7,185  
    Plus equity
    21,511       21,409  
    Minus cash
    1,869       1,285  
    Minus trusteed funds from revenue bonds
    3       16  
            Total debt plus equity minus cash
  $ 28,330     $ 27,293  
                 
    Cash-adjusted debt-to-capital ratio
    24 %     22 %
                 
 
Capital Requirements
 
On April 29, 2009, our Board of Directors declared a dividend of 24 cents per share, payable June 10, 2009, to stockholders of record at the close of business on May 20, 2009.
 
Since January 2006, our Board of Directors has authorized a common share repurchase program totaling $5 billion.  As of March 31, 2009, we had repurchased 66 million common shares at a cost of $2,922 million.  We have not made any purchases under the program since August 2008.  Purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions.  This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion.  The program’s authorization does not include specific price targets or timetables.  The timing of purchases under the program will be influenced by cash generated from operations, proceeds from potential asset sales, cash from available borrowings and market conditions.
 
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. Estimates may differ from actual results.  Factors that affect the availability of financing include our performance (as measured by various factors including cash provided from operating activities), the state of 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.  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, refining and mining 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 March 31, 2009, our consolidated contractual cash obligations have decreased by $1,180 million from December 31, 2008.  Our purchase obligations under crude oil, refinery feedstock, refined product and ethanol contracts, which are primarily short term, decreased $2,214 million primarily related to decreased crude oil volumes when comparing March 31, 2009 to December 31, 2008.  Long-term debt increased by $1,528 million primarily due to the issuance of $1.5 billion in senior notes as previously discussed.  There have been no other significant changes to our obligations to make future
 
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payments under existing contracts subsequent to December 31, 2008.  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, 2008.
 
Receivable from United States Steel

We remain obligated (primarily or contingently) for $511 million of certain debt and other financial arrangements for which United States Steel Corporation (“United States Steel”) has assumed responsibility for repayment (see the USX Separation in Item 1. of our 2008 Annual Report on 10-K).  United States Steel reported in its Form 10-Q for the three months ended March 31, 2009 on certain plans and actions designed to preserve and enhance its liquidity and financial flexibility.  United States Steel management stated that it believes its liquidity will be adequate to satisfy its obligations for the foreseeable future.  Subsequent to the filing of its Form 10-Q, two debt rating agencies downgraded ratings on United States Steel debt.  On May 4, 2009, United States Steel sold its common stock and issued senior convertible notes due 2014 for net proceeds of approximately $1,496 million.
 
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.
 
Effective January 1, 2009, we adopted SFAS No. 157 with respect to nonfinancial assets and liabilities.  SFAS No. 157 defines fair value, establishes a fair value framework for measuring fair value and expands disclosures about fair value measurements.  It does not require us to make any new fair value measurements, but rather establishes a fair value hierarchy that prioritizes the inputs to the valuation techniques to measure fair value.  See Note 11 of the consolidated financial statements for disclosures regarding our fair value measurements.
 
There have been no other changes to our critical accounting estimates subsequent to December 31, 2008.
 
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 reflected in the prices of our products and services, our 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 feedstocks.
 
We previously discussed in our 2008 Annual Report on Form 10-K that legislation and regulations pertaining to climate change and greenhouse gas emissions have the potential to impact us and that we were awaiting the U.S. Environmental Protection Agency’s (“EPA”) actions upon the remand of the U.S. Supreme Court decision in Massachusetts v. EPA, which could have impacts on a number of air permitting and environmental regulatory programs.  On April 17, 2009, the EPA issued a proposed finding that greenhouse gases contribute to air pollution that may endanger public health or welfare.  The EPA will hold a 60 day public comment period and action on this finding is expected later this year.  Should EPA finalize this finding, standards or regulations limiting greenhouse gas emissions from mobile sources would then have to be developed.  Concurrent with this action, EPA has proposed greenhouse gas emission reporting rules which it plans to finalize to be effective for calendar year 2010.  Although there may be an adverse financial impact, including compliance costs, permitting delays and reduced demand for crude oil or certain refined products associated with these possible actions or proposed regulations resulting from them, the extent and magnitude of that impact cannot be reliably or accurately estimated at this time.   Because these requirements have not been finalized, uncertainty exists with respect to the additional measures or legislation being considered and the time frames for compliance.
 
We have estimated that we may spend approximately $1 billion over a five-year period that began in 2008 to comply with Mobile Source Air Toxics II (“MSAT II”) regulations relating to benzene content in refined products.  We have not finalized our strategy or cost estimates to comply with these requirements.  Our actual MSAT II expenditures since inception have totaled $103 million through March 31, 2009, with $27 million in the first quarter of 2009.  We expect
 
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2009 spending will be approximately $240 million.  The cost estimates are forward-looking statements and are subject to change as further work is completed in 2009.
 
    There have been no other significant changes to our environmental matters subsequent to December 31, 2008.
 
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 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 April 2009, two related Financial Accounting Standards Board (“FASB”) Staff Positions were issued:
 
 
·
FASB Staff Position (“FSP”) No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” (“FSP FAS 107-1”)
 
 
·
FSP No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” (“FSP FAS 157-4”)
 
    FSP FAS 107-1 amends SFAS No. 107 and Accounting Principles Board (“APB”) Opinion No. 28 to require disclosures about fair value of financial instruments in interim reporting periods for publicly traded companies.  This FSP is effective for the second quarter of 2009 and does not require disclosures for earlier periods presented for comparative purposes.  We will adopt the new disclosure provisions in the second quarter of 2009; however, the adoption of this standard is not expected to have a significant impact on our consolidated results of operations, financial position or cash flows.
 
    FSP FAS 157-4 provides additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for the asset or liability has significantly decreased.  It also includes guidance on identifying circumstances that indicate a transaction is not orderly.  Additional disclosures are also required.  FSP FAS 157-4 is effective for the second quarter of 2009 and does not require disclosures for earlier periods presented for comparative purposes.  We do not expect the adoption of this standard will have a significant impact on our consolidated results of operations, financial position or cash flows.
 
In December 2008, the SEC announced that it had approved revisions to its oil and gas reporting disclosures. The new disclosure requirements include provisions that:
 
 
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Introduce a new definition of oil and gas producing activities. This new definition allows companies to include volumes in their reserve base from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.
 
 
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Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end prices.  The SEC indicated that they will continue to communicate with the FASB staff to align their accounting standards with these rules.  The FASB currently requires a single-day, year-end price for accounting purposes.
 
 
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Permit companies to disclose their probable and possible reserves on a voluntary basis. Under current rules, proved reserves were the only reserves allowed in the disclosures.
 
 
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Require companies to provide additional disclosure regarding the aging of proved undeveloped reserves.
 
 
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Permit the use of reliable technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.
 
 
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Replace the existing "certainty" test for areas beyond one offsetting drilling unit from a productive well with a "reasonable certainty" test.
 
 
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Require additional disclosures regarding the qualifications of the chief technical person who oversees the company's overall reserve estimation process. Additionally, disclosures regarding internal controls surrounding reserve estimation, as well as a report addressing the independence and qualifications of its reserves preparer or auditor will be mandatory.
 
 
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Require additional disclosures regarding the qualifications of the chief technical person who oversees the company's overall reserve estimation process. Additionally, disclosures regarding internal controls surrounding reserve estimation, as well as a report addressing the independence and qualifications of its reserves preparer or auditor will be mandatory.
 
 
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Require separate disclosure of reserves in foreign countries if they represent more than 15 percent of total proved reserves, based on barrels of oil equivalents.