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,June 30, 2013

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 Street, 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 þRNo o£

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes þR No o£
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer    þ  
Accelerated filer             o
Non-accelerated filer       o        (Do not check if a smaller reporting company) 
Smaller reporting company        o   
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).         
Yes o No þ
 
There were 708,817,008709,671,894 shares of Marathon Oil Corporation common stock outstanding as of April 30,July 31, 2013.



MARATHON OIL CORPORATION
 
Form 10-Q
 
Quarter Ended March 31,June 30, 2013


 INDEX 
  Page
PARTPart I - FINANCIAL INFORMATION
 
Item 1.
Financial Statements:
 
 
Consolidated Statements of Income (Unaudited)
2
 
Consolidated Statements of Comprehensive Income (Unaudited)
3
 
Consolidated Balance Sheets (Unaudited)
4
 
Consolidated Statements of Cash Flows (Unaudited)
5
 
Notes to Consolidated Financial Statements (Unaudited)
6
Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
1819
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
2932
Item 4.
Controls and Procedures
2932
 
Supplemental Statistics (Unaudited)
3033
PARTPart II - OTHER INFORMATION
 
Item 1.
Legal Proceedings
3336
Item 1A.
Risk Factors
3336
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
3336
Item 4.
Mine Safety Disclosures
3337
Item 6.
Exhibits
3437
 
Signatures
3538

 
Unless the context otherwise indicates, references in this Form 10-Q to “Marathon Oil,” “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 Oil 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 EndedThree Months Ended Six Months Ended
March 31,June 30, June 30,
(In millions, except per share data)2013 20122013 2012 2013 2012
Revenues and other income:          
Sales and other operating revenues, including related party$3,440
 $2,954
$3,419
 $2,975
 $6,859
 $5,919
Marketing revenues430
 839
499
 757
 929
 1,606
Income from equity method investments118
 78
77
 60
 195
 138
Net gain on disposal of assets109
 166
Net gain (loss) on disposal of assets(107) (28) 2
 138
Other income9
 3
10
 20
 19
 23
Total revenues and other income4,106
 4,040
3,898
 3,784
 8,004
 7,824
Costs and expenses:   
 
  
    
Production578
 514
614
 485
 1,192
 987
Marketing, including purchases from related parties429
 842
495
 755
 924
 1,609
Other operating111
 92
86
 107
 197
 199
Exploration465
 135
133
 172
 598
 307
Depreciation, depletion and amortization747
 574
738
 580
 1,485
 1,154
Impairments38
 262
—
 1
 38
 263
Taxes other than income84
 68
93
 55
 177
 123
General and administrative174
 159
164
 154
 338
 313
Total costs and expenses2,626
 2,646
2,323
 2,309
 4,949
 4,955
Income from operations1,480
 1,394
1,575
 1,475
 3,055
 2,869
Net interest and other(72) (50)(71) (57) (143) (107)
Income before income taxes1,408
 1,344
1,504
 1,418
 2,912
 2,762
Provision for income taxes1,025
 927
1,078
 1,025
 2,103
 1,952
Net income$383
 $417
$426
 $393
 $809
 $810
Per Share Data 
  
 
  
  
  
Net Income: 
  
 
  
  
  
Basic
$0.54
 
$0.59
$0.60
 $0.56
 $1.14
 $1.15
Diluted
$0.54
 
$0.59
$0.60
 $0.56
 $1.14
 $1.14
Dividends paid
$0.17
 
$0.17
$0.17
 $0.17
 $0.34
 $0.34
Weighted average shares: 
  
 
  
  
  
Basic708
 706
710
 706
 709
 705
Diluted712
 710
714
 709
 713
 709
 The accompanying notes are an integral part of these consolidated financial statements.

2


MARATHON OIL CORPORATION
Consolidated Statements of Comprehensive Income (Unaudited)
Three Months EndedThree Months Ended Six Months Ended
March 31,June 30, June 30,
(In millions)2013 20122013 2012 2013 2012
Net income$383
 $417
$426
 $393
 $809
 $810
Other comprehensive income (loss) 
  
 
  
  
  
Postretirement and postemployment plans 
  
 
  
  
  
Change in actuarial loss and other13
 13
133
 (3) 146
 10
Income tax provision on postretirement and 
  
Income tax (provision) benefit on postretirement and 
  
  
  
postemployment plans(5) (5)(49) 1
 (54) (4)
Postretirement and postemployment plans, net of tax8
 8
84
 (2) 92
 6
Foreign currency translation and other 
  
 
  
  
  
Unrealized gain (loss)(1) 1
Income tax provision on foreign currency translation and other—
 —
Unrealized loss(3) (1) (4) —
Income tax benefit on foreign currency translation and other1
 —
 1
 —
Foreign currency translation and other, net of tax(1) 1
(2) (1) (3) —
Other comprehensive income7
 9
Other comprehensive income (loss)82
 (3) 89
 6
Comprehensive income$390
 $426
$508
 $390
 $898
 $816
 The accompanying notes are an integral part of these consolidated financial statements.


3


MARATHON OIL CORPORATION
Consolidated Balance Sheets (Unaudited)
March 31, December 31,June 30, December 31,
(In millions, except per share data)2013 20122013 2012
Assets      
Current assets:      
Cash and cash equivalents$768
 $684
$246
 $684
Receivables2,466
 2,418
2,443
 2,418
Inventories368
 361
368
 361
Other current assets175
 299
224
 299
Total current assets3,777
 3,762
3,281
 3,762
Equity method investments1,304
 1,279
1,244
 1,279
Property, plant and equipment, less accumulated depreciation, 
  
 
  
depletion and amortization of $20,195 and $19,26628,382
 28,272
depletion and amortization of $20,639 and $19,26627,457
 28,272
Goodwill528
 525
499
 525
Other noncurrent assets1,118
 1,468
2,567
 1,468
Total assets$35,109
 $35,306
$35,048
 $35,306
Liabilities 
  
 
  
Current liabilities: 
  
 
  
Commercial paper$—
 $200
$—
 $200
Accounts payable2,284
 2,324
2,152
 2,324
Payroll and benefits payable182
 217
137
 217
Accrued taxes1,892
 1,983
1,397
 1,983
Other current liabilities203
 173
254
 173
Long-term debt due within one year68
 184
68
 184
Total current liabilities4,629
 5,081
4,008
 5,081
Long-term debt6,476
 6,512
6,428
 6,512
Deferred tax liabilities2,401
 2,432
2,406
 2,432
Defined benefit postretirement plan obligations850
 856
739
 856
Asset retirement obligations1,795
 1,749
2,039
 1,749
Deferred credits and other liabilities370
 393
407
 393
Total liabilities16,521
 17,023
16,027
 17,023
Commitments and contingencies

 



 

Stockholders’ Equity 
  
 
  
Preferred stock – no shares issued or outstanding (no par value, 
  
 
  
26 million shares authorized)—
 —
—
 —
Common stock: 
  
 
  
Issued – 770 million and 770 million shares (par value $1 per share,      
1.1 billion shares authorized)770
 770
770
 770
Securities exchangeable into common stock – no shares issued or 
  
 
  
outstanding (no par value, 29 million shares authorized)—
 —
—
 —
Held in treasury, at cost – 62 million and 63 million shares(2,527) (2,560)
Held in treasury, at cost – 61 million and 63 million shares(2,477) (2,560)
Additional paid-in capital6,618
 6,616
6,614
 6,616
Retained earnings14,153
 13,890
14,458
 13,890
Accumulated other comprehensive loss(426) (433)(344) (433)
Total equity18,588
 18,283
19,021
 18,283
Total liabilities and stockholders' equity$35,109
 $35,306
$35,048
 $35,306
 The accompanying notes are an integral part of these consolidated financial statements.

4


MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows (Unaudited)
Three Months EndedSix Months Ended
March 31,June 30,
(In millions)2013 20122013 2012
Increase (decrease) in cash and cash equivalents      
Operating activities: 
  
 
  
Net income$383
 $417
$809
 $810
Adjustments to reconcile net income to net cash provided by operating activities: 
  
 
  
Deferred income taxes44
 (22)113
 75
Depreciation, depletion and amortization747
 574
1,485
 1,154
Impairments38
 262
38
 263
Pension and other postretirement benefits, net7
 (29)34
 (22)
Exploratory dry well costs and unproved property impairments404
 58
494
 174
Net gain on disposal of assets(109) (166)(2) (138)
Equity method investments, net(48) (21)—
 7
Changes in:   
   
Current receivables(4) (296)17
 (107)
Inventories(15) 7
(16) (18)
Current accounts payable and accrued liabilities(54) 213
(651) (450)
All other operating, net135
 (24)75
 (6)
Net cash provided by operating activities1,528
 973
2,396
 1,742
Investing activities: 
  
 
  
Additions to property, plant and equipment(1,375) (1,017)(2,676) (2,181)
Disposal of assets312
 208
333
 218
Investments - return of capital18
 15
29
 21
All other investing, net8
 (12)15
 (59)
Net cash used in investing activities(1,037) (806)(2,299) (2,001)
Financing activities: 
  
 
  
Commercial paper, net(200) —
(200) 550
Debt issuance costs—
 (9)
Debt repayments(114) (53)(148) (111)
Dividends paid(120) (121)(241) (240)
All other financing, net21
 17
46
 20
Net cash used in financing activities(413) (157)
Net cash (used in) provided by financing activities(543) 210
Effect of exchange rate changes on cash6
 10
8
 8
Net increase in cash and cash equivalents84
 20
Net decrease in cash and cash equivalents(438) (41)
Cash and cash equivalents at beginning of period684
 493
684
 493
Cash and cash equivalents at end of period$768
 $513
$246
 $452
 The accompanying notes are an integral part of these consolidated financial statements.

5

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



1.    Basis of Presentation
These consolidated financial statements are unaudited; however, in the opinion of management, these statements reflect all adjustments necessary for a fair 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 ("SEC") 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.
Beginning in the first quarter of 2013, we changed the presentation of our consolidated statements of income, primarily to present additional details of revenues and expenses and to classify certain expenses more consistently with our peer group of independent exploration and production companies. To effect these changes, reclassifications of previously reported amounts were made and are reflected in these consolidated financial statements. As a result of the reclassifications, general and administrative expenses for the second quarter and first quartersix months of 2012 increased by $3924 million and $63 million which primarily includes certain costs associated with operations support and operations management. Offsetting reductions are reflected in production, other operating and exploration expenses and taxes other than income.
These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Marathon Oil Corporation 2012 Annual Report on Form 10-K.  The results of operations for the second quarter and first quartersix months of 2013 are not necessarily indicative of the results to be expected for the full year.
2.   Accounting Standards
Not Yet Adopted
In June 2013, the Financial Accounting Standards Board ("FASB") ratified the Emerging Issues Task Force consensus on Issue 13-C, which requires that an unrecognized tax benefit or a portion of an unrecognized tax benefit be presented as a reduction to a deferred tax asset for an available net operating loss carryforward, a similar tax loss or tax credit carryforward. This accounting standards update is effective for us beginning in the first quarter of 2014 and should be applied prospectively to unrecognized tax benefits that exist as of the effective date. Early adoption and retrospective application are permitted. We do not expect this accounting standards update to have a significant impact on our consolidated results of operations, financial position or cash flows.
In February 2013, an accounting standards update was issued to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations such as asset retirement and environmental obligations, contingencies, guarantees, income taxes and retirement benefits, which are separately addressed within United States generally accepted accounting principles ("U.S. GAAP"). An entity is required to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of 1) the amount the entity agreed to pay on the basis of its arrangement among its co-obligors and 2) any amount the entity expects to pay on behalf of its co-obligors. Disclosure of the nature of the obligation, including how the liability arose, the relationship with other co-obligors and the terms and conditions of the arrangement is required. In addition, the total outstanding amount under the arrangement, not reduced by the effect of any amounts that may be recoverable from other entities, plus the carrying amount of any liability or receivable recognized must be disclosed. This accounting standards update is effective for us beginning in the first quarter of 2014 and should be applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that exist at the beginning of 2014. Early adoption is permitted. We are currently evaluating the potential impact ofdo not expect this accounting standards update to have a significant impact on our consolidated results of operations, financial position andor cash flows.
Recently Adopted
In February 2013, an accounting standards update was issued to improve the reporting of reclassifications out of accumulated other comprehensive income. This standard requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. This accounting standards update was effective for us beginning the first quarter of 2013 and we present the required disclosures in Note1415. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

6

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


In December 2011, an accounting standards update designed to enhance disclosures about offsetting assets and liabilities was issued. Further clarification limiting the scope of these disclosures to derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions was issued in January 2013. The disclosures are intended to enable financial statement users to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. Entities are required to disclose both gross information and net information about in-scope financial instruments that are either offset in the statement of financial position or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. The accounting standards update was effective for us beginning the first quarter of 2013 and we include the required disclosures in Note 1213. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.
3.   Variable Interest Entity
The owners of the Athabasca Oil Sands Project (“AOSP”), in which we hold a 20 percent undivided interest, contracted with a wholly-owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton.  The contract, originally signed in 1999 by a company we acquired, allows each holder of an undivided interest in the AOSP to ship materials in accordance with its undivided interest.  Costs under this contract are accrued and recorded on a monthly basis, with current liabilities of $2 million and $3 million recorded at March 31,June 30, 2013 and , consistent with December 31, 2012.2012.  Under this agreement, the AOSP absorbs all of the operating and capital costs of the pipeline.  Currently, no third-party shippers use the pipeline.  Should shipments be suspended, by choice or due to force majeure, we remain responsible for the portion of the payments related to our undivided interest for all remaining periods.  The contract expires in 2029; however, the shippers can extend its term perpetually.  This contract qualifies as a variable interest contractual arrangement and the Corridor Pipeline qualifies as a variable interest entity (“VIE”).  We hold a variable interest but are not the primary beneficiary because our shipments are only 20 percent of the total; therefore the Corridor Pipeline is not consolidated by us.  Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was $711728 million as of March 31,June 30, 2013.  The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term.  We have not provided financial assistance to Corridor Pipeline and we do not have any guarantees of such assistance in the future.
4.    Income per Common Share
Basic income per share is based on the weighted average number of common shares outstanding.  Diluted income per share assumes exercise of stock options and stock appreciation rights, provided the effect is not antidilutive.
Three Months Ended March 31,Three Months Ended June 30,
2013 20122013 2012
(In millions, except per share data)Basic Diluted Basic DilutedBasic Diluted Basic Diluted
Net income$383
 $383
 $417
 $417
$426
 $426
 $393
 $393
              
Weighted average common shares outstanding708
 708
 706
 706
710
 710
 706
 706
Effect of dilutive securities—
 4
 —
 4
—
 4
 —
 3
Weighted average common shares, including              
dilutive effect708
 712
 706
 710
710
 714
 706
 709
Per share: 
  
  
  
 
  
  
  
Net income
$0.54
 
$0.54
 
$0.59
 
$0.59

$0.60
 
$0.60
 
$0.56
 
$0.56
 
The per share calculations above exclude 6 million and 7 million stock options and stock appreciation rights for the first quarters of 2013 and 2012 that were antidilutive.

7

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


 Six Months Ended June 30,
 2013 2012
(In millions, except per share data)Basic Diluted Basic Diluted
Net income$809
 $809
 $810
 $810
        
Weighted average common shares outstanding709
 709
 705
 705
Effect of dilutive securities—
 4
 —
 4
Weighted average common shares, including       
dilutive effect709
 713
 705
 709
Per share: 
  
  
  
Net income$1.14 $1.14 $1.15 $1.14
The per share calculations above exclude 6 million stock options and stock appreciation rights for the second quarter and first six months of 2013. Excluded for the second quarter and first six months of 2012 were 10 million and 9 million stock options and stock appreciation rights.
5.   Dispositions
2013 - North America Exploration and Production ("E&P") Segment
In AprilJune 2013, we reached an agreement to sellclosed the sale of our interests in the DJ Basin. The transaction is expected to closeBasin for proceeds of $19 million. A loss of $114 million was recorded in mid-2013 and athe second quarter loss of approximately $115 million, before closing adjustments, is anticipated on this disposition.2013.
In February 2013, we entered an agreement to conveyconveyed our interestinterests in the Marcellus natural gas shale play to the operator. A $43 million pretax loss on this transaction was recorded in the first quarter of 2013.
In February 2013, we closed the sale of our interest in the Neptune gas plant, located onshore Louisiana, for proceeds of $166 million. A $98 million pretax gain before closing adjustments, was recorded in the first quarter of 2013.
In January 2013, we closed the sale of our remaining assets in Alaska, for proceeds of $195 million, subject to a six-month escrow of $50 million for various indemnities. Awhich was collected in July 2013. After closing adjustments made in the second quarter of 2013, the gain on this sale was $4655 million pretax gain,.
2013 - International E&P Segment
In June 2013, we entered into an agreement to sell our non-operated 10 percent working interest in the Production Sharing Contract and Joint Operating Agreement in Block 31 offshore Angola. This transaction, valued at $1.5 billion before closing adjustments, was recordedis expected to close in the firstfourth quarter of 2013.2013, subject to government, regulatory and third-party approvals. Angola Block 31 is reflected as held for sale in the June 30, 2013 consolidated balance sheet as follows:
(In millions) 
Other noncurrent assets$1,550
Total assets1,550
Other current liabilities58
Deferred credits and other liabilities39
Total liabilities$97
2012 - North America E&P Segment
In January 2012, we closed on the sale of our interests in several Gulf of Mexico crude oil pipeline systems for proceeds of $206 million.  This included our equity method interests in Poseidon Oil Pipeline Company, L.L.C. and Odyssey Pipeline L.L.C., as well as certain other oil pipeline interests, including the Eugene Island pipeline system.  A pretax gain of $166 million was recorded in the first quarter of 2012.

8

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


2012 - International E&P Segment
In May 2012, we reached an agreement to relinquish our operatorship of and interests in the Bone Bay and Kumawa exploration licenses in Indonesia. A $36 million payment to settle all of our obligations related to these licenses, including well commitments, was accrued and reported as a loss on disposal of assets in the second quarter of 2012.
6.    Segment Information
  Beginning in 2013, we changed our reportable segments and revised our management reporting to better reflect the growing importance of United States unconventional resource plays to our business. All periods presented have been recast to reflect these new segments.
We have three reportable operating segments.  Each of these segments is organized and managed based upon both geographic location and the nature of the products and services it offers.
North America E&P ("N.A. E&P") – explores for, produces and markets liquid hydrocarbons and natural gas in North America;
International E&P ("Int'l E&P") – explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets products manufactured from natural gas, such as liquefied natural gas ("LNG")and methanol, in Equatorial Guinea; and
Oil Sands Mining (“OSM”) – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”).  Segment income represents income from continuing operations excluding certain items not allocated to segments as discussed below, net of income taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. These costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities, net of associated income tax effects.  Unrealized gains or losses on crude oil derivative instruments, impairments, gains or losses on disposal of assets or other items that affect comparability (as determined by the CODM) also are not allocated to operating segments.
Differences between segment totals and our consolidated totals for income taxes and depreciation, depletion and amortization represent amounts related to corporate administrative activities and other unallocated items which are included in “Items not allocated to segments, net of income taxes” in the reconciliation below. Total capital expenditures include accruals but not corporate activities.
 Three Months Ended June 30, 2013
(In millions)N.A. E&P Int'l E&P OSM Total
Revenues:       
Sales and other operating revenues$1,284
 $1,732
 $353
 $3,369
Marketing revenues439
 51
 9
 499
Segment revenues$1,723
 $1,783
 $362
 3,868
Unrealized gain on crude oil derivative instruments      50
Total revenues      $3,918
Segment income$221
 $382
 $20
 $623
Income from equity method investments—
 77
 —
 77
Depreciation, depletion and amortization490
 189
 48
 727
Income tax provision129
 1,004
 7
 1,140
Capital expenditures904
 241
 97
 1,242

89

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Three Months Ended March 31, 2013Three Months Ended June 30, 2012
(In millions)N.A. E&P Int'l E&P OSM TotalN.A. E&P Int'l E&P OSM Total
Revenues:              
Sales and other operating revenues$1,215
 $1,887
 $388
 $3,490
$833
 $1,813
 $329
 $2,975
Marketing revenues345
 85
 —
 430
696
 56
 5
 757
Segment revenues$1,560
 $1,972
 $388
 3,920
Unrealized loss on crude oil derivative instruments      (50)
Total revenues      $3,870
$1,529
 $1,869
 $334
 $3,732
Segment income (loss)$(59) $453
 $38
 $432
Segment income$70
 $373
 $50
 $493
Income from equity method investments—
 118
 —
 118
—
 60
 —
 60
Depreciation, depletion and amortization478
 207
 52
 737
290
 228
 50
 568
Income tax provision (benefit)(30) 1,142
 13
 1,125
Income tax provision39
 1,070
 17
 1,126
Capital expenditures970
 225
 45
 1,240
1,013
 202
 43
 1,258
Three Months Ended March 31, 2012Six Months Ended June 30, 2013
(In millions)N.A. E&P Int'l E&P OSM TotalN.A. E&P Int'l E&P OSM Total
Revenues:              
Sales and other operating revenues$912
 $1,663
 $379
 $2,954
$2,499
 $3,619
 $741
 $6,859
Marketing revenues775
 64
 —
 839
784
 136
 9
 929
Segment revenues$3,283
 $3,755
 $750
 7,788
Unrealized loss on crude oil derivative instruments      —
Total revenues$1,687
 $1,727
 $379
 $3,793
      $7,788
Segment income$104
 $407
 $38
 $549
$162
 $835
 $58
 $1,055
Income from equity method investments1
 77
 —
 78
—
 195
 —
 195
Depreciation, depletion and amortization314
 200
 49
 563
968
 396
 100
 1,464
Income tax provision61
 971
 13
 1,045
99
 2,146
 20
 2,265
Capital expenditures829
 138
 52
 1,019
1,874
 466
 142
 2,482

 Six Months Ended June 30, 2012
(In millions)N.A. E&P Int'l E&P OSM Total
Revenues:       
Sales and other operating revenues$1,745
 $3,476
 $698
 $5,919
Marketing revenues1,471
 120
 15
 1,606
Total revenues$3,216
 $3,596
 $713
 $7,525
Segment income$174
 $780
 $88
 $1,042
Income from equity method investments1
 137
 —
 138
Depreciation, depletion and amortization604
 428
 99
 1,131
Income tax provision100
 2,041
 30
 2,171
Capital expenditures1,842
 340
 95
 2,277
The following reconciles total revenues to sales and other operating revenues as reported in the consolidated statements of income:
Three Months Ended March 31,Three Months Ended June 30,Six Months Ended June 30,
(In millions)2013 20122013201220132012
Total revenues$3,870
 $3,793
$3,918
$3,732
$7,788
$7,525
Less: Marketing revenues430
 839
499
757
929
1,606
Sales and other operating revenues, including related party$3,440
 $2,954
$3,419
$2,975
$6,859
$5,919

10

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)2013 2012
Segment income$432
 $549
Items not allocated to segments, net of income taxes: 
  
Corporate and other unallocated items(71) (71)
Unrealized loss on crude oil derivative instruments(32) —
     Impairments(10) (167)
     Net gain on dispositions64
 106
Net income$383
 $417

9

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
 Three Months Ended June 30,Six Months Ended June 30,
(In millions)2013201220132012
Segment income$623
$493
$1,055
$1,042
Items not allocated to segments, net of income taxes: 
 
 
 
Corporate and other unallocated items(156)(77)(227)(148)
Unrealized gain (loss) on crude oil derivative instruments32
—
—
—
     Net gain (loss) on dispositions(73)(23)(9)83
     Impairments—
—
(10)(167)
Net income$426
$393
$809
$810


7.    Defined Benefit Postretirement Plans
The following summarizes the components of net periodic benefit cost:
Three Months Ended March 31,Three Months Ended June 30,
Pension Benefits Other BenefitsPension Benefits Other Benefits
(In millions)2013 2012 2013 20122013 2012 2013 2012
Service cost$14
 $12
 $1
 $1
$14
 $13
 $1
 $1
Interest cost15
 16
 3
 4
16
 16
 3
 3
Expected return on plan assets(17) (16) —
 —
(16) (16) —
 —
Amortization: 
  
  
  
 
  
  
  
– prior service cost (credit)2
 2
 (2) (2)1
 2
 (1) (1)
– actuarial loss13
 12
 —
 —
16
 13
 —
 —
Net settlement loss(a)
17
 —
 —
 —
Net periodic benefit cost$27
 $26
 $2
 $3
$48
 $28
 $3
 $3
 Six Months Ended June 30,
  
Pension Benefits Other Benefits
(In millions)2013 2012 2013 2012
Service cost$28
 $25
 $2
 $2
Interest cost31
 32
 6
 7
Expected return on plan assets(33) (32) —
 —
Amortization: 
  
  
  
– prior service cost (credit)3
 4
 (3) (3)
– actuarial loss29
 25
 —
 —
Net settlement loss(a)
17
 —
 —
 —
Net periodic benefit cost$75
 $54
 $5
 $6
(a) Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan's total service and interest cost for that year. Such settlements were recorded for our U.S. plans in the second quarter of 2013.
During the second quarter of 2013, we recorded the effects of partial settlements of our U.S. pension plans and we remeasured the plans' assets and liabilities as of June 30, 2013, using a discount rate of 4.14 percent as of that date. As a result, we recognized a decrease of $139 million in actuarial losses, in other comprehensive income.
During the first threesix months of 2013, we made contributions of $928 million to our funded pension plans.  We expect to make additional contributions up to an estimated $5539 million to our funded pension plans over the remainder of 2013.  Current benefit payments related to unfunded pension and other postretirement benefit plans were $910 million and $47 million during the first threesix months of 2013.

11

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



8.   Income Taxes
The effective income tax rate is influenced by a variety of factors including the geographic sources of income and the relative magnitude of these sources of income. The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments. The difference between the total provision and the sum of the amounts allocated to segments and to individual items not allocated to segments is presentedreported in Corporate“Corporate and other unallocated itemsitems” in Note 6.
Our effective income tax rates in the first threesix months of 2013 and 2012 were 7372 percent and 6971 percent.   These rates are higher than the U.S. statutory rate of 35 percent due to earnings from foreign jurisdictions, primarily Norway and Libya, where the tax rates are in excess of the U.S. statutory rate.  In Libya, where the statutory tax rate is in excess of 90 percent, there remains uncertainty around sustained production and sales levels.  Reliable estimates of 2013 and 2012 annual ordinary income from our Libyan operations could not be made and the range of possible scenarios when including ordinary income from our Libyan operations in the worldwide annual effective tax rate calculation demonstrates significant variability.  As such, for the first threesix months of 2013 and 2012, an estimated annual effective tax rate wasrates were calculated excluding Libya and applied to consolidated ordinary income excluding Libya and the tax provision applicable to Libyan ordinary income was recorded as a discrete item in the period.periods.  Excluding Libya, the effective tax raterates would be 6563 percent and 64 percent for the first threesix months of 2013 and 2012.
    
9.   Inventories
 Inventories are carried at the lower of cost or market value.
March 31, December 31,June 30, December 31,
(In millions)2013 20122013 2012
Liquid hydrocarbons, natural gas and bitumen$54
 $73
$48
 $73
Supplies and other items314
 288
320
 288
Inventories, at cost$368
 $361
$368
 $361

10

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


10.  Property, Plant and Equipment
March 31, December 31,June 30, December 31,
(In millions)2013 20122013 2012
North America E&P$24,500
 $23,748
$25,129
 $23,748
International E&P13,429
 13,214
12,213
 13,214
Oil Sands Mining10,171
 10,127
10,270
 10,127
Corporate477
 449
484
 449
Total property, plant and equipment48,577
 47,538
48,096
 47,538
Less accumulated depreciation, depletion and amortization(20,195) (19,266)(20,639) (19,266)
Net property, plant and equipment$28,382
 $28,272
$27,457
 $28,272
In the first quarter of 2011, production operations in Libya were suspended. In the fourth quarter of 2011, limited production resumed.  Since that time, average sales volumes have increased to near pre-conflict levels.  We and our partners in the Waha concessions continue to assess the condition of our assets in Libya and uncertainty around sustained production and sales levels remains. As of March 31,June 30, 2013, our net property, plant and equipment investment in Libya was approximately $748740 million.
Exploratory well costs capitalized greater than one year after completion of drilling were $220 million as of March 31,June 30, 2013.  The net decrease in such costs from December 31, 2012 primarily related to the conveyance of our interestinterests in the Marcellus natural gas shale play to the operator in February 2013.

12

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


11. Asset Retirement Obligations
The following summarizes the changes in asset retirement obligations during the first six months of 2013:
(In millions) 
Beginning balance$1,783
Incurred, including acquisitions8
Settled, including dispositions(27)
Accretion expense (included in depreciation, depletion and amortization)48
Revisions to previous estimates306
Held for sale(39)
Ending balance(a)
$2,079
(a) Includes asset retirement obligations of $40 million classified as a short-term at June 30,2013.
12.  Fair Value Measurements
 Fair Values - Recurring
The following tables present assets and liabilities accounted for at fair value on a recurring basis as of March 31,June 30, 2013 and December 31, 2012 by fair value hierarchy level.
March 31, 2013June 30, 2013
(In millions)Level 1 Level 2 Level 3 Collateral TotalLevel 1 Level 2 Level 3 Collateral Total
Derivative instruments, assets                  
Commodity$—
 $8
 $—
 $1
 $9
$—
 $52
 $—
 $—
 $52
Interest rate—
 18
 —
 —
 18
—
 6
 —
 —
 6
Derivative instruments, assets$—
 $26
 $—
 $1
 $27
$—
 $58
 $—
 $—
 $58
Derivative instruments, liabilities                  
Commodity$—
 $6
 $—
 $—
 $6
Foreign currency—
 20
 —
 —
 20
$—
 $30
 $—
 $—
 $30
Derivative instruments, liabilities$—
 $26
 $—
 $—
 $26
$—
 $30
 $—
 $—
 $30
December 31, 2012December 31, 2012
(In millions)Level 1 Level 2 Level 3 Collateral TotalLevel 1 Level 2 Level 3 Collateral Total
Derivative instruments, assets                  
Commodity$—
 $52
 $—
 $1
 $53
$—
 $52
 $—
 $1
 $53
Interest rate—
 21
 —
 —
 21
—
 21
 —
 —
 21
Foreign currency—
 18
 —
 —
 18
—
 18
 —
 —
 18
Derivative instruments, assets$—
 $91
 $—
 $1
 $92
$—
 $91
 $—
 $1
 $92

11

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Commodity swaps in Level 2 are measured at fair value with a market approach using prices obtained from exchanges or pricing services, which have been corroborated with data from active markets for similar assets or liabilities.  Commodity options in Level 2 are valued using Thethe Black-Scholes Model.  Inputs to this model include prices as noted above, discount factors, and implied market volatility.  The inputs to this fair value measurement are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.  Collateral deposits related to commodity derivatives are in broker accounts covered by master netting agreements.
Interest rate swaps are measured at fair value with a market approach using actionable broker quotes which are Level 2 inputs.  Foreign currency forwards are measured at fair value with a market approach using third-party pricing services, such as Bloomberg L.P., which have been corroborated with data from active markets for similar assets or liabilities, and are Level 2 inputs.

13

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Fair Values - Nonrecurring
The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.
Three Months Ended March 31,Three Months Ended June 30,
2013 20122013 2012
(In millions)Fair Value Impairment Fair Value ImpairmentFair Value Impairment Fair Value Impairment
Long-lived assets held for use$—
 $38
 $75
 $262
$—
 $—
 $—
 $1
 Six Months Ended June 30,
 2013 2012
(In millions)Fair Value Impairment Fair Value Impairment
Long-lived assets held for use$—
 $38
 $75
 $263

All long-lived assets held for use that were impaired in the first quarterssix months of 2013 and 2012 were held by our North America E&P segment. The fair values of each discussed below were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs.  Inputs to the fair value measurement included reserve and production estimates made by our reservoir engineers, estimated commodity prices adjusted for quality and location differentials, and forecasted operating expenses for the remaining estimated life of the reservoir.
In the first quarter of 2013, as a result of our decision to wind down operations in the Powder River Basin due to poor economics, an impairment of $15 million was recorded.
In early 2012, production rates from the Ozona development in the Gulf of Mexico declined significantly. Accordingly, our reserve engineers prepared evaluations of our future production as well as our reserves and an impairment of $261 million was recorded in the first quarter of 2012.  As the development produced towards abandonment pressures, further downward revisions of reserves were taken, resulting in an additional impairment recorded in the fourth quarter of 2012. Ozona production ceased in the first quarter of 2013 and an additional $21 million impairment was recorded.
Other impairments of long-lived assets held for use by our North America E&P segment in the first quarterssix months of 2013 and 2012 were a result of reduced drilling expectations, reductions of estimated reserves or declining natural gas prices.
Fair Values – Financial Instruments
Our current assets and liabilities include financial instruments, the most significant of which are receivables, commercial paper and payables. We believe the carrying values of our receivables, commercial paper and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our investment-grade credit rating, and (3) our historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk.

12

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


The following table summarizes financial instruments, excluding receivables, commercial paper, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at March 31,June 30, 2013 and December 31, 2012.2012.
March 31, 2013 December 31, 2012June 30, 2013 December 31, 2012
Fair Carrying Fair CarryingFair Carrying Fair Carrying
(In millions)Value Amount Value AmountValue Amount Value Amount
Financial assets              
Other noncurrent assets$174
 $169
 $189
 $186
$165
 $164
 $189
 $186
Total financial assets 174
 169
 189
 186
165
 164
 189
 186
Financial liabilities 
  
  
  
 
  
  
  
Other current liabilities13
 13
 13
 13
13
 13
 13
 13
Long-term debt, including current portion(a)
7,347
 6,494
 7,610
 6,642
6,991
 6,460
 7,610
 6,642
Deferred credits and other liabilities146
 141
 94
 94
141
 140
 94
 94
Total financial liabilities $7,506
 $6,648
 $7,717
 $6,749
$7,145
 $6,613
 $7,717
 $6,749
(a)      Excludes capital leases.

14

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Fair values of our financial assets included in other noncurrent assets, and of our financial liabilities included in other current liabilities and deferred credits and other liabilities are measured using an income approach and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value.
Most of our long-term debt instruments are publicly-traded. A market approach, based upon quotes from major financial institutions, is used to measure the fair value of such debt. Because these quotes cannot be independently verified to an active market they are considered Level 3 inputs. The fair value of our debt that is not publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.

13

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


12.13. Derivatives
For information regarding the fair value measurement of derivative instruments, see Note 1112. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. Netting is assessed by counterparty, and as of March 31,June 30, 2013 and December 31, 2012, there were no offsetting amounts. Positions by contract were all either assets or liabilities. The following tables present the gross fair values of derivative instruments, excluding cash collateral, and the reported net amounts along with where they appear on the consolidated balance sheets as of March 31,June 30, 2013 and December 31, 2012.2012.
March 31, 2013 June 30, 2013 
(In millions)Asset Liability Net Asset Balance Sheet LocationAsset Liability Net Asset Balance Sheet Location
Fair Value Hedges            
Interest rate$18
 $—
 $18
 Other noncurrent assets$6
 $—
 $6
 Other noncurrent assets
Total Designated Hedges18
 —
 18
 6
 —
 6
 
            
Not Designated as Hedges            
Commodity8
 —
 8
 Other current assets52
 —
 52
 Other current assets
Total Not Designated as Hedges8
 —
 8
 52
 —
 52
 
Total$26
 $—
 $26
 $58
 $—
 $58
 
 
March 31, 2013 June 30, 2013 
(In millions)Asset Liability Net Liability Balance Sheet LocationAsset Liability Net Liability Balance Sheet Location
Fair Value Hedges            
Foreign currency$—
 $20
 $20
 Other current liabilities$—
 $30
 $30
 Other current liabilities
Total Designated Hedges—
 20
 20
 —
 30
 30
 
      
Not Designated as Hedges      
Commodity—
 6
 6
 Other current liabilities
Total Not Designated as Hedges—
 6
 6
 
Total$—
 $26
 $26
 $—
 $30
 $30
 
 December 31, 2012  
(In millions)Asset Liability Net Asset Balance Sheet Location
Fair Value Hedges       
     Foreign currency$18
 $—
 $18
 Other current assets
     Interest rate21
 —
 21
 Other noncurrent assets
Total Designated Hedges39
 —
 39
  
        
Not Designated as Hedges       
     Commodity52
 —
 52
 Other current assets
Total Not Designated as Hedges52
 —
 52
  
     Total$91
 $—
 $91
  

15

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Derivatives Designated as Fair Value Hedges
As of March 31,June 30, 2013 and December 31, 2012, we had multiple interest rate swap agreements with a total notional amount of $600 million with a maturity date of October 1, 2017 at a weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate of 4.694.68 percent and 4.70 percent.

14

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


As of March 31,June 30, 2013 and December 31, 2012, our foreign currency forwards had an aggregate notional amount of 3,5712,965 million and 3,043 million Norwegian Kroner at a weighted average forward rate of 5.6785.738 and 5.780. These forwards hedge our current Norwegian tax liability and have settlement dates through AugustDecember 2013.
The pretax effect of derivative instruments designated as hedges of fair value in our consolidated statements of income are summarized in the table below.
 Gain (Loss) Gain (Loss)
 Three Months Ended March 31, Three Months Ended June 30, Six Months Ended June 30,
(In millions)Income Statement Location2013 2012Income Statement Location2013 2012 2013 2012
Derivative            
Interest rateNet interest and other$(3) $(1)Net interest and other$(12) $12
 $(15) $12
Foreign currencyProvision for income taxes$(25) $(8)Provision for income taxes$(21) $(32) $(46) $(40)
Hedged Item  
  
  
  
  
  
Long-term debtNet interest and other$3
 $1
Net interest and other$12
 $(12) $15
 $(12)
Accrued taxesProvision for income taxes$25
 $8
Provision for income taxes$21
 $32
 $46
 $40
 Derivatives not Designated as Hedges
In August 2012, we entered into crude oil derivatives related to a portion of our forecast North America E&P crude oil sales through December 31, 2013. These commodity derivatives were not designated as hedges and are shown in the table below.
Remaining TermBbls per DayWeighted Average Price per BblBenchmark
Swaps   
April 2013 - December 201320,000$96.29West Texas Intermediate
April 2013 - December 201325,000$109.19Brent
Option Collars   
April 2013 - December 201315,000$90.00 floor / $101.17 ceilingWest Texas Intermediate
April 2013 - December 201315,000$100.00 floor / $116.30 ceilingBrent
Remaining TermBbls per DayWeighted Average Price per BblBenchmark
Swaps   
July 2013 - December 201320,000$96.29West Texas Intermediate
July 2013 - December 201325,000$109.19Brent
Option Collars   
July 2013 - December 201315,000$90.00 floor / $101.17 ceilingWest Texas Intermediate
July 2013 - December 201315,000$100.00 floor / $116.30 ceilingBrent
The impactfollowing table summarizes the effect of commodityall derivative instruments not designated as hedges appears in the sales and operating revenues, including related party, line of our consolidated statements of income and was a net loss of $55 million in the first quarter of 2013 and a net gain of $2 million in the first quarter of 2012.income.
  Gain (Loss)
  Three Months Ended Six Months Ended
  June 30, June 30,
(In millions)Income Statement Location2013 2012 2013 2012
CommoditySales and other operating revenues, including related party$67
 $(1) $13
 $2

1516

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


13.14.    Incentive Based Compensation
 Stock option and restricted stock awards
  The following table presents a summary of stock option and restricted stock award activity for the first quartersix months of 2013: 
Stock Options Restricted StockStock Options Restricted Stock
Number of
Shares
 
Weighted
Average
Exercise Price
 Awards 
Weighted
Average Grant
Date Fair Value
Number of
Shares
 
Weighted
Average
Exercise Price
 Awards 
Weighted
Average Grant
Date Fair Value
Outstanding at December 31, 201219,536,965
 
$26.19
 4,177,884
 
$29.02
19,536,965
 
$26.19
 4,177,884
 
$29.02
Granted1,002,400
(a) 

$32.86
 137,722
 
$33.04
1,381,321
(a) 

$32.85
 1,087,731
 
$32.38
Options Exercised/Stock Vested(839,273)

$21.33
 (493,840) 
$30.66
(1,422,488)

$21.53
 (605,209) 
$29.73
Cancelled(215,262)

$35.17
 (78,778) 
$28.98
(386,186)

$34.54
 (182,958) 
$29.35
Outstanding at March 31, 201319,484,830
 
$26.65
 3,742,988
 
$28.96
Outstanding at June 30, 201319,109,612
 
$26.85
 4,477,448
 
$29.79
(a)    The weighted average grant date fair value of stock option awards granted was $10.5010.25 per share.
Performance unit awards
 DuringIn the first quarter of 2013,, we granted 353,600 performance units to certain officers that provide a cash payout upon the achievement of certain performance goals at the end of a 36-month performance period.  The performance goals are tied to our total shareholder return (“TSR”) as compared to TSR for a group of peer companies determined by the Compensation Committee of the Board of Directors.   At the grant date, each unit represents the value of one share of our common stock, while payout after completion of the performance period will be based on the value of anywhere from zero to two times the number of units granted.  Dividend equivalents accrue during the performance period and are paid in cash at the end of the performance period based on the number of shares that would represent the value of the units.  The fair value of these performance units is re-measured on a quarterly basis using the Monte Carlo simulation method.  These performance units are accounted for as liability awards because they are to be settled in cash at the end of the performance period and their fair value is expensed over the performance period.
14.15.  Reclassifications Out of Accumulated Other Comprehensive Loss
The following table presents a summary of amounts reclassified from accumulated other comprehensive loss for the first quarter of 2013:to net income in their entirety:
Three Months Ended March 31, 2013Three Months Ended June 30, 2013Six Months Ended June 30, 2013 
(In millions) Reclassified to Income (Expense) Income Statement Line Income Statement Line
Accumulated Other Comprehensive Loss Components   Accumulated Other Comprehensive Loss Components 
Income (Expense) 
Amortization of postretirement and postemployment plans   Amortization of postretirement and postemployment plans  
Actuarial loss $(13) General and administrative$(16)$(29) General and administrative
Net settlement loss(17)(17) General and administrative
 5
 Provision for income taxes12
17
 Provision for income taxes
Total reclassifications for the period $(8) Net income$(21)$(29) Net income

1617

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


15.16.  Supplemental Cash Flow Information
Three Months Ended March 31,Six Months Ended June 30,
(In millions)2013 20122013 2012
Net cash provided from operating activities:      
Interest paid (net of amounts capitalized)$61
 $50
$160
 $113
Income taxes paid to taxing authorities1,003
 828
2,474
 2,317
Commercial paper, net: 
  
 
  
Commercial paper - issuances$200
 $100
$2,075
 $4,252
- repayments(400) (100)(2,275) (3,702)
Noncash investing activities: 
  
 
  
Asset retirement costs capitalized$27
 $1
$314
 $34
Debt payments made by United States Steel—
 14
Change in capital expenditure accrual(105) 46
(149) 159
Asset retirement obligations assumed by buyer

88
 7
92
 7
Receivable for disposal of assets50
 —
50
 —
16.17.   Commitments and Contingencies
 We are a defendant in a number of lawsuits arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims.  While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.  Certain of these matters are discussed below.
 Litigation – In March 2011, Noble Drilling (U.S.) LLC (“Noble”) filed a lawsuit against us in the District Court of Harris County, Texas, alleging, among other things, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation, relating to a multi-year drilling contract for a newly constructed drilling rig to be deployed in the U.S. Gulf of Mexico.  We filed an answer in April 2011, contending, among other things, failure to perform, failure to comply with material obligations, failure to mitigate alleged damages and that Noble failed to provide the rig according to the operating, performance and safety requirements specified in the drilling contract. In April 2013, we filed a counterclaim against Noble alleging, among other things, breach of contract and breach of the duty of good faith relating to the multi-year drilling contract. The counterclaim also included a breach of contract claim for reimbursement for the value of fuel used by Noble under an offshore daywork drilling contract. We are vigorously defending this litigation.  The ultimate outcome of this lawsuit, including any financial effect on us, remains uncertain.  We do not believe an estimate of a reasonably probable loss (or range of loss) can be made for this lawsuit at this time.
Contractual commitments – At March 31,June 30, 2013, Marathon’s contract commitments to acquire property, plant and equipment were $1,2091,122 million.

1718



Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
  Beginning in 2013, we changed our reportable segments and revised our management reporting to better reflect the growing importance of United States unconventional resource plays to our business. All periods presented have been recast to reflect these new segments.
We are an international energy company with operations in the United States, Canada, Africa, the Middle East and Europe.  We have three reportable operating segments. Each of these segments is organized and managed based upon both geographic location and the nature of the products and services it offers.
North America Exploration and Production ("E&P") – explores for, produces and markets liquid hydrocarbons and natural gas in North America;
International E&P – explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in Equatorial Guinea; and
Oil Sands Mining – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
 Certain sections of this Quarterly Report on Form 10-Q, including Management’s Discussion and Analysis of Financial Condition and Results of Operations contain forward-looking statements concerning trends or events potentially affecting our business.  These statements typically contain words such as “anticipates,” “believes,” “estimates,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain.  In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements.  For additional risk factors affecting our business, see Item 1A. Risk Factors in our 2012 Annual Report on Form 10-K. We assume no duty to update these statements as to any future date.
Key Operating and Financial Activities
In the firstsecond quarter of 2013, notable items were:
Total net sales volumes averaged 523506 thousand barrels of oil equivalent per day (“mboed”), a 2212 percent increase over the same quarter of last year
Liquid hydrocarbon and synthetic crude oilNorth America E&P net sales volumes accounted for 93increased 38 percent over the same quarter of the increaselast year
Eagle Ford shale averaged net sales volumes of 7280 mboed, a four-fold286 percent increase
Bakken shale averaged net sales volumes of 3739 mboed, a 4649 percent increase
Libya averaged net sales volumes of 38 mboed, a 123 percent increase
Oil Sands Mining averaged net sales volumes of 51 thousand barrels per day ("mbbld"), a 16 percent increase
Sale of our interest in the Neptune gas plant closed for proceeds of $166 million before closing adjustments
Sale of our Alaska assets closed for proceeds of $195 million subject to a six-month escrow of $50 million and closing adjustments
Government approval received for acquisition of a 20 percent non-operated interest in the onshore South Omo concession in Ethiopia, and exploratory drilling commenced
Successful appraisal well on non-operated Shenandoah prospect in the Gulf of Mexico announced
Sales commenced at the PSVM development located on the northeastern portion of Angola Block 31
Apparent high bidder on two blocks in the March 2013 Gulf of Mexico lease sale
Unproved property impairments of approximately $340 million recorded related to expiring Eagle Ford leases and leases we do not intend to drill
Changed reportable segments to reflect the growing importance of the United States unconventional resource plays



18


Some significant second quarter activities through May 10, 2013 include:
Decision made to conclude exploration activities in Poland
Agreement reached to sell interests in DJ Basin
Turnaround in Equatorial Guinea started and safely completed in April, eight days ahead of schedule and below budget
Successful appraisal well on non-operated Gunflint prospect in the Gulf of Mexico announced by operator
Two Gulf of Mexico leases from Lease Sale 227 awarded to us
Entered into agreement to sell our working interest in Angola Block 31 in a transaction valued at $1.5 billion before closing adjustments
Concluded exploration activities in Poland
Closed sale of interests in DJ Basin and recorded a $114 million loss on sale
Some significant third quarter activities to August 8, 2013 include:
Increased dividend 12 percent to 19 cents per share

19

Overview and Outlook
North America E&P
Production
 Net liquid hydrocarbon and natural gas sales volumes averaged 198201 mboed and 200 mboed during the second quarter and first quartersix months of 2013 andcompared to 147146 mboed in the same periodboth periods of 2012, a 35for increases of approximately 37 percent increase. in both periods.  Net liquid hydrocarbon sales volumes increased for both the quarter and the first six months of 2013, primarily reflecting the impact of our ongoing development programs in the Eagle Ford and Bakken shale resource plays, while net natural gas sales volumes decreased slightly during the same periods due to the sale of our Alaska assets in January 2013. Excluding the sales volume related to Alaska in both six-month periods, our average net liquid hydrocarbon and natural gas sales volumes increased 4750 percent.
Eagle Ford – In 2013, production growth continued in the Eagle Ford shale play. Average net sales volumes were 7280 mboed and 76 mboed in the second quarter and first quartersix months of 2013 compared to 1421 mboed and 18 mboed in the same periodperiods of 2012. Approximately 6463 percent of the first quartersix months of 2013 production was crude oil and condensate, 17 percent was natural gas liquids ("NGLs") and 1920 percent was natural gas. DuringIn the firstsecond quarter of 2013,, we reached total depth on 76 gross operated wells and brought 68 gross operated wells to sales. We continue to advance our drilling performance, reducingincreased the average time to drill a well from 28 days in the first quarteramount of 2012 to 18 days in the first quarter of 2013. We expect these drilling times to continue dropping during 2013 as additional efficiencies are gained from pad drilling.
We continue to build infrastructure to support production growth across the Eagle Ford operating area. Approximately 148 miles of gathering lines were installed in the first quarter of 2013, while five new central gathering and treating facilities were commissioned, with two additional facilities in various stages of planning or construction. As of March 31, 2013, we transport approximately 65 percent of our crude oil and condensate transported by pipeline with additional contract negotiations and facility designs under way that are expected to push that figure to 7570 percent byfrom 65 percent in the end of May.previous quarter. The ability to transport more barrels by pipeline enables us to reduce costs, improve reliability and lessen our environmental footprint.
We are confidentDuring the second quarter of 2013, we reached total depth on 82 gross operated wells and brought 70 gross operated wells to sales, with 158 gross operated wells reaching total depth and 138 gross operated wells brought on line in the first six months of 2013. With approximately 85 percent pad drilling, which continues to improve efficiencies and reduce costs, our coresecond quarter average spud-to-total depth time was 12 days and spud-to-spud was 18 days.
To support production growth across the Eagle Ford acreage position will be developed on a maximumoperating area, approximately 170 miles of 80-acre spacinggathering lines were installed in the first six months of 2013, bringing the total to more than 650 miles. We also commissioned six new central gathering and treating facilities and have three additional facilities in various stages of planning or construction, bringing the total to 27.
We continue to evaluate the potential of downspacing to 40-acre and 60-acre units.units, with the results of the downspacing pilots expected to be released in December 2013. We have begun drilling wells inalso continue to evaluate the Austin Chalk and Pearsall formations across our acreage position. To date, we have completed four Austin Chalk wells with average 24-hour initial production ("IP") rates of 980 gross barrels of oil equivalent per day (“boed”) (485 barrels per day ("bbld") of crude oil and condensate, 220 bbld of NGLs and 1.65 million cubic feet per day ("mmcfd") of natural gas). Early Austin Chalk production results suggest that the mix of crude oil and condensate, NGLs and natural gas is similar to further test the potential of these horizons. The results to-date of the downspacing pilots have been in line with our expectations, and we anticipate releasing more definitive results of both the downspacing pilots and the additional formation testingEagle Ford condensate wells. Also in the second halfquarter of 2013.2013, one Pearsall well was completed with a 24-hour IP rate of 580 gross boed.
Bakken – Average net sales volumes from the Bakken shale were 3739 mboed and 38 mboed in the second quarter and first quartersix months of 2013 compared to 2526 mboed in the same periodperiods of 2012. Our Bakken production averages approximately 90 percent crude oil, 5 percent NGLs and 5 percent natural gas. During the firstsecond quarter of 2013, we reached total depth on 1822 gross operated wells and brought 2216 gross operated wells to sales. During the first six months of 2013 we reached total depth on 40 gross operated wells and brought 38 gross operated wells to sales. Our second quarter average time to drill a well was 25 days.continued to improve, averaging 15 days spud-to-total depth and 22 days spud-to-spud.
 In the Oklahoma Resource Basins net– Net sales volumes from the Anadarko Woodford shale averaged 13 mboed in the second quarter and first quartersix months of 2013 compared to 6 compared tomboed and 5 mboed in the same periodperiods of 2012.  All net sales volumes are from the Anadarko Woodford shale.  During the firstsecond quarter of 2013, fourwe reached total depth on two gross operated wells and three gross operated wells were brought to sales, while during the first six months of 2013 we reached total depth on two gross operated wells and brought seven gross operated wells to sales. We anticipate drilling will begin on two wells each in the Mississippi Lime formation in central Oklahoma and the Granite Wash formationsformation in northwestern Oklahoma during the second half of 2013.
Exploration
Exploration activity continuesGulf of Mexico – Late in the Gulfthird quarter of Mexico. 2013, we expect to begin drilling the first exploration well on the Madagascar prospect located on De Soto Canyon Block 757. We reduced our working interest in the Madagascar prospect from 100 percent to 70 percent as a result of a farm-down in the second quarter of 2013 with no up-front cash proceeds. We anticipate further reducing our interest to a target of 40 to 50 percent working interest by the time of drilling.
We participated in an appraisal well on the Gunflint prospect located on Mississippi Canyon Block 992 in which we hold an 18 percent non-operated working interest. The appraisal well successfully encountered 109 feet of net pay within the primary reservoir targets. After penetrating the initial appraisal targets, the well was deepened to a previously untested Lower Miocene interval. Commercial hydrocarbons were not encountered in the deeper exploration objective. Additional exploration potential

20

remains in an adjacent structure to the north, which is a candidate for future exploration following development of the confirmed resources.
The first appraisal well on the Shenandoah prospect located on Walker Ridge Block 51, in which we have a 10 percent outside-operatednon-operated working interest, reached total depth in the first quarter of 2013. We are currently participating in a Gunflint prospectThis appraisal well located on Mississippi Canyon Block 992 where we hold an 18 percent non-operated working interest.successfully encountered more than 1,000 net feet of oil pay in multiple high-quality Lower Tertiary-aged reservoirs.
In March 2013, we submitted the apparent high bids totaling $33 million for 100 percent working interest in two blocks in the Central Gulf of Mexico Lease Sale 227: Keathley Canyon Block 340 on the Colonial prospect and Keathley Canyon Block 153, an extension to the Meteor prospect on our existing Keathley Canyon 196 lease. Keathley Canyon Blocks 340 and 153 are both inboard-Paleogene prospects. These leases were awarded to us in the second quarter of 2013.
Canada – During the first quarter of 2012, we submitted a regulatory application relating to our Canada in-situ assets at Birchwood, for a proposed 12 mbbldthousand barrels per day ("mbbld") steam assisted gravity drainage ("SAGD") demonstration project. We are expecting to receive regulatory approval for this project in late 2013 or early 2014.  Upon receiving this approval, we will further evaluate our development plans.

19


International E&P
Production
Net liquid hydrocarbon and natural gas sales volumes averaged 274262 mboed and 268 mboed during the second quarter and first quartersix months of 2013 compared to 261 mboed and 236249 mboed in the same periodperiods of 2012, awhich is flat for the quarter and an increase of 168 percentincrease. for the six-month period.  During the first six months of first quarter of 2013, Libya net liquid hydrocarbon and natural gas sales volumes increased 215 mboed and 13 mboed, compared to the same periodperiods of 2012, primarily due to limited sales in the first quarter of 2012 upon the resumption of sales in early 2012 after the 2011 civil unrest.  In addition, both the second quarter and first quartersix months of 2013 includesinclude net liquid hydrocarbon sales volumes of 9 mboed from the PSVM development located on the northeastern portion of Angola Block 31 which had first sales in February 2013.
Strong operational performance continues in Equatorial Guinea with– Average net sales volumes were 97 mboed and 105 mboed in the second quarter and first six months compared to 101 mboed and 103 mboed in the same periods of 2012. The planned turnaround that occurred in April 2013 was safely completed in 22 days, eight days ahead of schedule and below budget. Sales in the second quarter of 2013 were impacted by the turnaround, but operational availability of nearly 98 percent in the first quarter of 2013 which bolstered production duringsales for the first quarter of 2013. We started a 30-day planned turnaround in Equatorial Guinea on April 1, 2013 which was safely completed eight days ahead of schedule and below budget. The Alba field, associated gas plant and liquefied natural gas facility each resumed full production on April 22, 2013.six-month period.
Norway – The production decline in the Alvheim area offshore Norway continues to be less severe than expected.  Average net sales volumes from Norway were 88 mboed in both the second quarter and first six months of 2013 compared to 86 mboed and 92 mboed in the same periods of 2012. These better-than-expected results have been achieved through continued strong operational performance that delivered availability of approximately 96 percent in the second quarter and 97 percent in the first quarter of 2013; production optimization from well management; and reservoir and well performance at the upper end of expectations primarily due to a delay in anticipated water breakthrough at the Volund fieldfield. A planned 10-day turnaround in Norway is scheduled during the third quarter of 2013.
United Kingdom – Production at non-operated Foinaven was shut-in in mid-July 2013 due to compression and sustained contributions fromsubsea equipment issues and is expected to resume at partial rates in mid-August. Planned pipeline curtailments and a turnaround at Brae in the recently completed development drilling program.North Sea in the second half of 2013 will also reduce third quarter 2013 production.
Exploration
In the Kurdistan Region of Iraq we– We hold 45 percent operated working interests in both the Harir and Safen blocks. Current exploratory drilling includes the Mirawa well which began in March 2013 on the Harir Block and the Safen well which commenced drilling in April 2013 on the Safen Block. Both of these wells areThe Mirawa well reached total depth in July 2013 and is currently testing. The Safen well is expected to reach projected total depth in the third quarter ofAugust 2013, with testing programs to follow on each well.follow.
Additionally, following the successful appraisal program on the non-operated Atrush Block a declaration of commerciality was filed with the government in 2012, and a plan of development is anticipated to bewas filed in May 2013. DrillingThe development plan is currently under review with final approval expected in the third quarter of the2013.  We anticipate first production in 2015. The Atrush-3 appraisal well commencedhas reached total depth and is currently testing. We hold a 15 percent non-operated working interest in March. the Atrush Block.
On the non-operated Sarsang block, two exploration wells, the Mangesh and the Gara, exploration wells began drilling in the second half of 2012. Both wells are currently drilling2012 and are expected to reachhave reached total depth, during the second quarter of 2013, with testing programs to follow on each well.ongoing. Also on the Sarsang block, the East Swara Tika exploration well is expectedbegan drilling in July 2013 to begin drilling late intest additional resource potential to the second quarter or early innortheast of the third quarter of 2013.previously announced Swara Tika discovery. We hold a 15 percent working interest in the Atrush block and a 25 percent working interest in the Sarsang block.Block.

21

Ethiopia – The Sabisa-1 exploration well, inon the onshore South Omo block onshore Ethiopia has been drilled to total depthin a frontier rift basin, encountered reservoir quality sands, oil and recorded hydrocarbon indications in sands beneathheavy gas shows and a thick claystone top seal. Hole instabilityshale section. The presence of oil prone source rocks, reservoir sands and good seals is encouraging for the numerous fault bounded traps identified in the basin. Because of mechanical issues, have required the drilling ofwell was abandoned before a sidetrackfull evaluation could be completed. The rig will mobilize to comprehensively log and sample zones of interest. Resultsthe nearby Tultule prospect, approximately two miles from the sidetrack are expected inSabisa-1 during the second quarterhalf of 2013. We hold a 20 percent non-operated working interest in the South Omo block.
Gabon – Exploration drilling began in April 2013 on the Diaman No. 1 well in the Diaba License G4-223, offshore Gabon, to test the deepwater presalt play. We expect theThe well to reachreached total depth in the third quarter of 2013. Logging and evaluation are underway. We hold a 21 percent non-operated working interest in the Diaba License.
Offshore Norway – We commenced drilling of the Sverdrup exploration well on PL 330 offshore Norway in June 2013 and total depth is expected to be reached in early September 2013. We hold a 30 percent non-operated working interest in this license. The Darwin (formerly Veslemoy) exploration well was drilled in the first quarter of 2013 on PL 531 in which we hold a 10 percent non-operated fully-carried working interest. Gas shows were recorded in the Paleocene objective section, although no hydrocarbons were found in the Cretaceous section and the well has been plugged and abandoned. We expect drilling to commence in the third quarter of 2013 on the Sverdrup exploration well on PL 330, in which we hold a 30 percent non-operated working interest.
Poland – After an extensive evaluation of our exploration activities in Poland and unsuccessful attempts to find commercial levels of hydrocarbons, we have elected to conclude operations in the country. We are evaluating disposition options for our concessions, which hadconcessions.
Kenya – The first exploratory well on Block 9 is expected to commence before the end of 2013 onshore Kenya where we hold a book value at March 31,50 percent non-operated working interest.
Angola – The Kaombo development, located in the southeastern portion of Block 32, is expected be sanctioned late in 2013 of $12 million.so that production from the Kaombo development is possible in 2017.
 Oil Sands Mining
 Our Oil Sands Mining operations consist of a 20 percent non-operated working interest in the Athabasca Oil Sands Project (“AOSP”).  Our net synthetic crude oil sales were 5143 mbbld and 47 mbbld in the second quarter and first six months quarter of 2013 compared to 44 mbbld in each of the same periodperiods of 2012.  BothSales were relatively flat in all periods with the exception of the first six months of 2013. The impact of strong reliability experienced at both mines and the upgrader experienced significantly improved reliability during the first quarter of 2013. Primarily because of reliability improvements, combined production from2013 was partially offset by unplanned mine downtime and a planned turnaround during the Jack Pine and Muskeg River mines set a record bitumen production rate in the firstsecond quarter of 2013.  In addition, upgrader availability was 100 percent for the entire first quarter of 2013, allowing the facility to maximize production of lighter synthetic crude oils, which improved realizations and profit margins.2013.

20


Acquisitions and Dispositions
In AprilJune 2013, we reachedentered into an agreement to sell our interestsnon-operated 10 percent working interest in the DJ Basin. TheProduction Sharing Contract and Joint Operating Agreement in Block 31 offshore Angola. This transaction, valued at $1.5 billion before closing adjustments, is expected to close in mid-2013the fourth quarter of 2013, subject to government, regulatory and athird-party approvals.
In June 2013, we closed the sale of our interests in the DJ Basin for proceeds of $19 million. A pretax loss of $114 million was recorded in the second quarter loss of approximately $115 million, before closing adjustments, is anticipated on this disposition.2013.
In February 2013, we entered an agreement to conveyconveyed our interests in the Marcellus natural gas shale play to the operator. A $43 million pretax loss on this transaction was recorded in the first quarter of 2013.
In February 2013, we closed the sale of our interest in the Neptune gas plant, located onshore Louisiana, for proceeds of $166 million. A $98 million pretax gain before closing adjustments, was recorded in the first quarter of 2013.
In January 2013, we closed the sale of our remaining assets in Alaska, for proceeds of $195 million, subject to a six-month escrow of $50 million for various indemnities. A $46 millionwhich was collected in July 2013. After closing adjustments made in the second quarter of 2013, the pretax gain before closing adjustments,on this sale was recorded in the first quarter of 2013.$55 million.
In January 2013, government approval was received for our acquisition of a 20 percent non-operated interest in the onshore South Omo concession in Ethiopia.
As previously disclosed, we had engaged in discussions with respect to a potential sale of a portion of our 20 percent outside-operated interest in the AOSP. An agreement was not reached with the prospective purchaser and negotiations have been terminated. We are not engaged in further discussions with respect to a potential sale of these assets.
We continue to progress the potential sale of assets in an ongoing effort to optimize our portfolio for profitable growth, with a previously stated goal of divesting between $1.5 billion and $3 billion over the period of 2011 through 2013. To date, we have agreed upon or completed divestitures of approximately $1.3 billion in divestitures.$2.9 billion.
The above discussions include forward-looking statements with respect to anticipated drilling activity, the timing of closing the sale of our interests in the DJ Basin, possible increased recoverable resources from optimized well spacing in the Eagle Ford resource play, possible decreased average drilling timesplanned infrastructure improvements in the

22

Eagle Ford resource play, central batteries and pipeline construction projects,operating area, additional farm-down of our working interest in the filingMadagascar prospect in the Gulf of a plan of development for the Atrush Block,Mexico, anticipated exploration activity in the Gulf of Mexico, Ethiopia, Gabon, Norway, and the Kurdistan Region of Iraq, Ethiopia, Gabon, Norway, and Kenya, the development of our in-situ assets, a planned turnaround in Norway, planned pipeline curtailments and turnaround at Brae in the North Sea, expected timing and rate of production returning at Foinaven, the timing of approval of a plan of development and first production for the Atrush Block, plans to exit Poland, the timing of closing the sale of our 10 percent working interest in Block 31 offshore Angola, and the goal of divesting between $1.5 to $3.0 billion of other assets over the period of 2011projected asset dispositions through 2013. The average times to drill a well and expectations as to future drilling times may not be indicative of future drilling times. The current production rates may not be indicative of future production rates. Factors that could potentially affect anticipated drilling activity, possible increased recoverable resources from optimized well spacing in the Eagle Ford resource play, possible decreased average drilling timesplanned infrastructure improvements in the Eagle Ford resource play, central batteries and pipeline construction projects andoperating area, anticipated exploratory activity in the Gulf of Mexico, Ethiopia, Gabon, Norway, and the Kurdistan Region of Iraq, Ethiopia, Gabon, Norway, and Kenya, a planned turnaround in Norway and planned pipeline curtailments and turnaround at Brae in the North Sea include pricing, supply and demand for liquid hydrocarbons and natural gas, the amount of capital available for exploration and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, availability of materials and labor, other associated risks with construction projects, the inability to obtain or delay in obtaining necessary government and third-party approvals and permits, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto, and other geological, operating and economic considerations. The timing of closing the sale of our interests10 percent working interest in the DJ BasinBlock 31 offshore Angola is subject to the satisfaction of customary closing conditions. Plansconditions and obtaining necessary government, regulatory and third-party approvals. The expected timing and rate of production returning at Foinaven, additional farm-down of the our working interest in the Madagascar prospect in the Gulf of Mexico, plans to exit Poland, the timing of filing theapproval of a plan of development and first production for the Atrush Block and the projected asset dispositions through 2013 are based on current expectations, estimates, and projections and are not guarantees of future performance. The development of our in-situ assets is dependent on obtaining regulatory approval and future development plans. 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 difficult to predict. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.
Market Conditions
 Prevailing prices for the various qualities of crude oil and natural gas that we produce significantly impact our revenues and cash flows.  Worldwide prices have been volatile in recent years.  The following table lists benchmark crude oil and natural gas price averages relative to our North America E&P and International E&P segments in the second quarter and first six months quarters of 2013 and 2012.
Three Months Ended March 31,Three Months Ended June 30, Six Months Ended June 30,
Benchmark2013 20122013 2012 2013 2012
West Texas Intermediate ("WTI") crude oil (Dollars per barrel)

$94.36
 
$103.03

$94.17
 
$93.35
 $94.26 $98.15
Brent (Europe) crude oil (Dollars per barrel)

$112.49
 
$118.49

$102.58
 
$108.42
 $107.54 $113.45
Henry Hub natural gas (Dollars per million British thermal units ("mmbtu"))(a)

$3.34
 
$2.74
Henry Hub natural gas (Dollars per million British thermal units ("mmbtu"))(a)

$4.09
 
$2.22
 $3.71 $2.48
(a) 
Settlement date average.

21


North America E&P
Liquid hydrocarbons – The quality, location and composition of our liquid hydrocarbon production mix willcan cause our U.S. liquid hydrocarbon realizations to differ from the WTI benchmark.
Quality – Light sweet crude contains less sulfur and tends to be lighter than sour crude oil so that refining it is less costly and produces higher value products; therefore, light sweet crude is considered of higher quality and typically sells at a price that approximates WTI or at a premium to WTI. The percentage of our North America E&P crude and condensate production that is light sweet crude has been increasing as onshore production from the Eagle Ford and Bakken shale plays increases and production from the Gulf of Mexico declines. In the second quarter and first six months quarter of 2013, the percentage of our U.S. crude oil and condensate production that was sweet averaged 75 percent and 74 percent compared to 5342 percent and 45 percent in the same periodperiods of 2012.
Location – In recent years, crude oil sold along the United States Gulf Coast, such as that from the Eagle Ford shale, has been priced based on the Louisiana Light Sweet benchmark which prices at a premium to WTI because the Louisiana Light Sweet benchmark has been trackingand tracks closest to Brent, while production from inland areas farther from large refineries has been at a discount to WTI.

23


Composition – The proportion of our liquid hydrocarbon sales that are NGLs continues to increase due to our development of United States unconventional liquids-rich plays. NGLs were 14 percent of our North America E&P liquid hydrocarbon sales volumes in the second quarter and first six months quarter of 2013 compared to 89 percent in the same periodperiods of 2012.
Natural gas – A significant portion of our natural gas production in the lower 48 states of the United StatesU.S. is sold at bid-week prices, or first-of-month indices relative to our specific producing areas.  Average Henry Hub settlement prices for natural gas were 2284 percent and 50 percent higher for the second quarter and first six months quarter of 2013 compared to the same periodperiods of the prior year. 
International E&P
Liquid hydrocarbons – Our international crude oil production is relatively sweet and is generally sold in relation to the Brent crude benchmark, which was 5 percent lower in both the second quarter and first six months quarter of 2013 than the same quarterperiods of 2012.
Natural gas – Our major international natural gas-producing regions are Europe and Equatorial Guinea.  Natural gas prices in Europe have been considerably higher than in the U.S. in recent years.  In the case of Equatorial Guinea, our natural gas sales are subject to term contracts, making realized prices in these areas less volatile.  The natural gas sales from Equatorial Guinea are at fixed prices; therefore, our reported average natural gas realized prices may not fully track market price movements.
Oil Sands Mining
 The Oil Sands Mining segment produces and sells various qualities of synthetic crude oil. Output mix can be impacted by operational problems or planned unit outages at the mines or upgrader. Sales prices for roughly two-thirds of the normal output mix will track movements in WTI and one-third will track movements in the Canadian heavy sour crude oil marker, primarily Western Canadian Select ("WCS"). TheA decrease in the WTI benchmark pricingprices, coupled with the increaseda higher WCS discount from WTI in the first quartersix months of 2013 compared to same period of 2012 combined to create, created downward pressure on our average realizations. However, in the second quarter of 2013 compared to the second quarter of 2012, the WCS discount from WTI has narrowed, with the discount remaining at these lower levels into July 2013.
The operating cost structure of the Oil Sands Mining operations is predominantly fixed and therefore many of the costs incurred in times of full operation continue during production downtime. Per-unit costs are sensitive to production rates. Key variable costs are natural gas and diesel fuel, which track commodity markets such as the Canadian Alberta Energy Company ("AECO") natural gas sales index and crude oil prices, respectively.
The table below shows benchmark prices that impacted both our revenues and variable costs for the second quarter and first six months quarters of 2013 and 2012:
Three Months Ended March 31,Three Months Ended June 30, Six Months Ended June 30,
Benchmark2013 20122013 2012 2013 2012
WTI crude oil (Dollars per barrel)

$94.36
 
$103.03

$94.17
 
$93.35
 $94.26 $98.15
WCS crude oil (Dollars per barrel)(a)

$62.41
 
$81.51

$75.06
 
$70.63
 $68.74 
$76.07
AECO natural gas sales index (Dollars per mmbtu)(b)

$3.16
 
$2.18

$3.45
 
$1.84
 $3.31 
$2.04
(a) 
Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.
(b) 
Monthly average AECO day ahead index.

2224


Results of Operations
Consolidated Results of Operation
Consolidated income before income taxes in the second quarter and first six months quarter of 2013 was 5approximately 6 percent higher than in the same periodperiods of 2012 primarily related to the 22 percent increaseincreases in sales volumes on a boe basis.volumes. The effective tax rate was 7372 percent in the first six months quarter of 2013 compared to 6971 percent in the first six months quarter of 2012, with the increase related to higher income from operations in higher tax jurisdictions, primarily Norway and Libya.
Sales and other operating revenues, including related party are summarized by segment in the following table:
Three Months Ended March 31,Three Months Ended June 30,Six Months Ended June 30,
(In millions)2013 20122013201220132012
Sales and other operating revenues, including related party:      
North America E&P$1,215
 $912
$1,284
$833
$2,499
$1,745
International E&P1,887
 1,663
1,732
1,813
3,619
3,476
Oil Sands Mining388
 379
353
329
741
698
Segment sales and other operating revenues, including related party$3,490
 $2,954
$3,369
$2,975
$6,859
$5,919
Unrealized loss on crude oil derivative instruments(50) —
Unrealized gain (loss) on crude oil derivative instruments50
—
—
—
Total sales and other operating revenues, including related party$3,440
 $2,954
$3,419
$2,975
$6,859
$5,919
 
Total sales and other operating revenues increased $486$444 million and $940 million in the second quarter and first six months quarter of 2013 from the comparable prior-year period, withperiods. The $451 million and $754 million increases in each segment. The $303 million increase in the North America E&P segment wasin the second quarter and first six months of 2013 were primarily due to liquid hydrocarbon net sales volumes which increased 5759 percent over the same quarterperiods of 2012. Most of this net sales volume increase is a result of, primarily due to ongoing development programs in the Eagle Ford and Bakken shale resourceresources plays. Partially offsetting this increase were lower liquid hydrocarbon and natural gas realizations.
The following table gives details of net sales volumes and average realizations of our North America E&P segment.
Three Months Ended March 31,Three Months Ended June 30,Six Months Ended June 30,
2013 20122013201220132012
North America E&P Operating Statistics     
Net liquid hydrocarbon sales volumes (mbbld) (a)
141
 90
148
93
145
91
Liquid hydrocarbon average realizations (per bbl) (b) (c)

$86.14
 
$93.63
$84.51$84.72$85.30$89.23
Net crude oil and condensate sales volumes (mbbld)
121
 83
126
85
124
83
Crude oil and condensate average realizations (per bbl) (b)

$94.68
 
$97.28
$93.75$89.04$94.20$93.25
Net natural gas liquids sales volumes (mbbld)
20
 7
22
8
21
8
Natural gas liquids average realizations (per bbl) (b)

$35.48
 
$51.55
$31.72$40.54$33.51$45.65
    
Net natural gas sales volumes (mmcfd)
340
 344
316
319
328
331
Natural gas average realizations (per mcf)(b)

$3.86
 
$4.13
$4.19$3.42$4.02$3.79
(a) 
Includes crude oil, condensate and natural gas liquids.
(b) 
Excludes gains and losses on derivative instruments
(c) 
Inclusion of realized gains (losses) on crude oil derivative instruments would have increased (decreased) average liquid hydrocarbon realizations by ($0.37)$1.22 per bbl and $0.45 per bbl for the second quarter and first quartersix months of 2013.2013. There were no realized gains (losses) on crude oil derivative instruments in the second quarter and first quartersix months of 2012.2012.
The $224 million increase inAs compared to prior year periods, International E&P sales and other operating revenues decreased $81 million in the International E&P segment was primarilysecond quarter of 2013 due to lower liquid hydrocarbon realizations and increased $143 million in the first six months of 2013 as a result of increased liquid hydrocarbon and natural gas sales volumes, from our African operations as previously discussed.  Lowerpartially offset by lower liquid hydrocarbon realizations partially offset the volume impact.realizations.

2325


The following table gives details of net sales volumes and average realizations of our International E&P segment.
Three Months Ended March 31,Three Months Ended June 30,Six Months Ended June 30,
2013 20122013201220132012
International E&P Operating Statistics     
Net liquid hydrocarbon sales volumes (mbbld)(a)
    
Europe100
 97
93
99
96
98
Africa80
 52
84
78
82
65
Total International E&P180
 149
177
177
178
163
Liquid hydrocarbon average realizations (per bbl)(b)
    
Europe
$116.13
 
$123.76
$106.41$111.12$111.43$117.37
Africa
$97.13
 
$94.41
$92.92$96.84$94.96$95.87
Total International E&P
$107.68
 
$113.55
$100.00$104.82$103.86$108.80
    
Net natural gas sales volumes (mmcfd)
    
Europe(c)
95
 104
89
102
92
103
Africa473
 418
425
399
449
409
Total International E&P568
 522
514
501
541
512
Natural gas average realizations (per mcf)(b)
    
Europe
$12.83
 
$9.99
$11.37$10.05$12.12$10.02
Africa
$0.51
 
$0.24
$0.49$0.25$0.50$0.25
Total International E&P
$2.57
 
$2.19
$2.37$2.25$2.47$2.22
(a) 
Includes crude oil, condensate and natural gas liquids. The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.
(b) 
Excludes gains and losses on derivative instruments.
(c) 
Includes natural gas acquired for injection and subsequent resale of 118 mmcfd and 1417 mmcfd for the second quarters of 2013 and 2012, and 10 mmcfd and 15 mmcfd for the first six months quarters of 2013 and 2012.
Oil Sands Mining sales and other operating revenues increased $9 million.$24 million and $43 million in the second quarter and first six months of 2013 from the comparable prior-year periods. Synthetic crude oil sales volumes were slightly lower in the 16second quarter of 2013 than in the second quarter of 2012; however, a decrease in the discount of WCS to WTI in second quarter of 2013 resulted in increases in average realizations compared to the prior-year period. Synthetic crude oil sales volumes for the first six months of 2013 were 7 percent higher than in the first quartersix months of 2012, reflecting increased reliability of the mines and upgrader in the first quarter of 2013.  However, an increase in the discount of WCS to WTI resulted in decreases in average realizations during the first quarter of 2013, partially offsetting the positive volume impact.  The following table gives details of net sales volumes and average realizations of our Oil Sands Mining segment.
Three Months Ended March 31,Three Months Ended June 30, Six Months Ended June 30,
2013 20122013 2012 2013 2012
Oil Sands Mining Operating Statistics          
Net synthetic crude oil sales volumes (mbbld) (a)
51
 44
43
 44
 47
 44
Synthetic crude oil average realizations (per bbl)

$79.98
 
$90.88
$89.39 $79.31 $84.31 $85.07
(a) 
Includes blendstocks.
Unrealized gains and losses on crude oil derivative instruments are included in total sales and other operating revenues but are not allocated to the segments. In the firstsecond quarter quarter of 2013, the net unrealized lossgain on crude oil derivative instruments was $50 million withwhile unrealized gains and losses did not have a significant impact on the first six months of 2013. There was no comparable crude oil derivative activity in the same periodperiods of 2012. See Note 1213 to the consolidated financial statements and Item 3. Quantitative and Qualitative Disclosures About Market Risk for additional information about our derivative positions.

26


Marketing revenues decreased $409258 million and $677 million in the second quarter and first six months quarter of 2013 from the comparable prior-year period.periods. North America E&P segment marketing activities, formerly referred to as supply optimization activities, which include the purchase of commodities from third parties for resale, have been decreasing in 2013 due to market dynamics. Related commodity prices have also been lower in 2013 than in 2012.  These activities serve to aggregate volumes in order to satisfy transportation commitments and to achieve flexibility within product types and delivery points.  
 Income from equity method investments increased $4017 million and $57 million in the second quarter and first six months quarter of 2013 from the comparable prior-year period,periods, primarily due to higher LNG realizations and partially due to highernet sales volumes since turnarounds at our facilities in Equatorial Guinea reduced sale volumes in the first quarter ofvolumes.  2012.  

24


Net gain (loss) on disposal of assets in the firstsecond quarter quarter of 2013 includes a $114 million loss on the sale of our interests in the DJ Basin. In addition, the first six months of 2013 include a $98 million gain on the sale of our interest in the Neptune gas plant, a $46$55 million gain on the sale of our remaining assets in Alaska and a $43 million loss on the conveyance of our interestinterests in the Marcellus natural gas shale play to the operator. The net loss on disposal of assets in the second quarter of 2012 reflects $36 million to settle all obligations as a result of the assignment of exploration licenses in Indonesia. The net gain on disposal of assets in the first six months quarter of 2012 consists primarily of the $166 million gain on the sale of our interests in several Gulf of Mexico crude oil pipeline systems.systems, and the second quarter Indonesia loss. See Note 5 to the consolidated financial statements for information about these dispositions.
Production expenses increased $64129 million and $205 million in the second quarter and first six months quarter of 2013 from the comparable periodperiods of 2012. The increase isincreases are primarily related to increased sales volumes in each segment.the North America E&P and International E&P segments and a planned turnaround in the OSM segment during the second quarter of 2013.
Marketing expenses decreased $413260 million and $685 million in the second quarter and first six months quarter of 2013 from the same periodperiods of 2012, consistent with the marketing revenue decline discussed above.
 Exploration expenses were lower in the second quarter of 2013 than in the same quarter in 2012 due to lower dry well costs and geological and geophysical costs. Exploration costs were higher in the first six months quarter of 2013 than in the same quarterperiod of 2012, primarily due to larger unproved property impairments. The first quarter of 2013 included $340 million in unproved property impairments on Eagle Ford shale leases that either have expired or that we do not expect to drill or extend. The following table summarizes the components of exploration expenses.
Three Months Ended March 31,Three Months Ended June 30,Six Months Ended June 30,
(In millions)2013 20122013201220132012
Unproved property impairments$383
 $35
$40
$35
$423
$70
Dry well costs21
 23
50
81
71
104
Geological and geophysical27
 45
12
29
39
74
Other34
 32
31
27
65
59
Total exploration expenses$465
 $135
$133
$172
$598
$307
Depreciation, depletion and amortization (“DD&A”) increased $173158 million and $331 million in the second quarter and first quartersix months of 2013 from the comparable prior-year period.periods.  Our segments apply the units-of-production method to the majority of their assets; therefore, the previously discussed increases in sales volumes generally result in similar changes in DD&A. The DD&A rate (expense per barrel of oil equivalent), which is impacted by changes in reserves and capitalized costs, can also cause changes in our DD&A. An increase in the North America E&P DD&A rate in the second quarter and first six months of 2013 compared to the same prior-year periods was primarily due to the ongoing development programs in the Eagle Ford and Bakken shale resources plays. A lower International E&P DD&A rate in the second quarter and first six months quarter of 2013, primarily due to reserve increases at the end of 2012 and in the second quarter of 2013 for Norway, compared to the same periodperiods in 2012 partially offset the impact of the higher North America E&P rate and higher sales volumes.  The following table provides DD&A rates for each segment.
Three Months Ended March 31,Three Months Ended June 30,Six Months Ended June 30,
($ per boe)2013 20122013201220132012
DD&A rate     
 
North America E&P
$27
 
$23

$27

$22

$27

$23
International E&P
$8
 
$9

$8

$10

$8

$9
Oil Sands Mining
$12
 
$13

$12

$13

$12

$13

27


 Impairments in the first six months quarter of 2013 related primarily to the Powder River Basin and to the Ozona development in the Gulf of Mexico. Impairments in the first six months quarter of 2012 were also primarily related to the Ozona development in the Gulf of Mexico.  See Note 1112 to the consolidated financial statements for information about these impairments.
 Taxes other than income include production, severance and ad valorem taxes in the United States which tend to increase or decrease in relation to sales volumes and revenues.
General and administrative expenses increased $10 million and $25 million in the second quarter and first six months of 2013 from the comparable prior year periods primarily due to pension settlement charges of $17 million in the second quarter of 2013.
Net interest and other increased $2214 million and $36 million in the second quarter and first six months quarter of 2013 from the comparable periodperiods of 2012 primarily due to lower capitalized interest in 2013.
Provision for income taxes increased $53 million and $98151 million in the firstsecond quarter quarterand first six months of 2013 from the comparable periodperiods of 2012 primarily due to the increase in pretax income in high tax rate jurisdictions.income.
The effective income tax rate is influenced by a variety of factors including the geographic sources of income and the relative magnitude of these sources of income. The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments. The difference between the total provision and the sum of the amounts allocated to segments and to items not allocated to segments is shown in corporate and other unallocated items in the segment income table below.

25


Our effective tax rates in the first three six months of 2013 and 2012 were 7372 percent and 6971 percent.   These rates are higher than the U.S. statutory rate of 35 percent due to earnings from foreign jurisdictions, primarily Norway and Libya, where the tax rates are in excess of the U.S. statutory rate.  In Libya, where the statutory tax rate is in excess of 90 percent, there remains uncertainty around sustained production and sales levels.  Reliable estimates of 2013 and 2012 annual ordinary income from our Libyan operations could not be made and the range of possible scenarios when including ordinary income from our Libyan operations in the worldwide annual effective tax rate calculation demonstrates significant variability.  As such, for the first three six months of 2013 and 2012 an, estimated annual effective tax rate wasrates were calculated excluding Libya and applied to consolidated ordinary income excluding Libya and the tax provision applicable to Libyan ordinary income was recorded as a discrete item in the period.periods.  Excluding Libya, the effective tax raterates would be 6563 percent and 64 percent for the first three six months of 2013 and 2012.2012.
 Segment Income (Loss)
Three Months Ended March 31,Three Months Ended June 30, Six Months Ended June 30,
(In millions)2013 20122013 2012 2013 2012
North America E&P$(59) $104
$221
 $70
 $162
 $174
International E&P453
 407
382
 373
 835
 780
Oil Sands Mining38
 38
20
 50
 58
 88
Segment income432
 549
623
 493
 1,055
 1,042
Items not allocated to segments, net of income taxes: 
  
 
  
    
Corporate and other unallocated items(71) (71)(156) (77) (227) (148)
Unrealized loss on crude oil derivative instruments(32) —
Unrealized gain (loss) on crude oil derivative instruments32
 —
 —
 —
Net gain (loss) on dispositions(73) (23) (9) 83
Impairments(10) (167)—
 —
 (10) (167)
Net gain on dispositions64
 106
Net income$383
 $417
$426
 $393
 $809
 $810
 North America E&P segment income decreased $163increased $151 million in the firstsecond quarter of 2013 and decreased $12 million in the first six months of 2013 compared to the same periodperiods of 2012. The increase in the second quarter of 2013 is largely due to increased liquid hydrocarbon net sales volumes primarily in the Eagle Ford and Bakken shale resource plays. The decrease in the first six months of 2013 was primarily the result of unproved property impairments, higher DD&A and lower liquid hydrocarbon realizations, partially offset by higher liquid hydrocarbon net sales volumes, as discussed above.
 International E&P segment income increased $46$9 million and $55 million in the second quarter and first six months quarter of 2013 compared to the same periodperiods of 2012. The increase was2012. These increases were primarily related to higher liquid hydrocarbon net sales volumes and increased income from equity method investments, partially offset by higher income taxes.  
 Oil Sands Mining segment incomedecreased $30 million in the second quarter and first six months of 2013 compared to the same periods of 2012. These decreases are primarily due to higher production expenses, including the costs of the scheduled upgrader turnaround in the second quarter of 2013.

28



Critical Accounting Estimates
There have been no changes to our critical accounting estimates subsequent to December 31, 2012.2012.
Accounting Standards Not Yet Adopted
In June 2013, the Financial Accounting Standards Board ("FASB") ratified the Emerging Issues Task Force consensus on Issue 13-C, which requires that an unrecognized tax benefit or a portion of an unrecognized tax benefit be presented as a reduction to a deferred tax asset for an available net operating loss carryforward, a similar tax loss or tax credit carryforward. This accounting standards update is effective for us beginning in the first quarter of 2014 and should be applied prospectively to unrecognized tax benefits that exist as of the effective date. Early adoption and retrospective application are permitted. We do not expect this accounting standards update to have a significant impact on our consolidated results of operations, financial position or cash flows.
In February 2013, an accounting standards update was issued to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations such as asset retirement and environmental obligations, contingencies, guarantees, income taxes and retirement benefits, which are separately addressed within United States generally accepted accounting principles ("U.S. GAAP.GAAP"). An entity is required to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of 1) the amount the entity agreed to pay on the basis of its arrangement among its co-obligors and 2) any amount the entity expects to pay on behalf of its co-obligors. Disclosure of the nature of the obligation, including how the liability arose, the relationship with other co-obligors and the terms and conditions of the arrangement is required. In addition, the total outstanding amount under the arrangement, not reduced by the effect of any amounts that may be recoverable from other entities, plus the carrying amount of any liability or receivable recognized must be disclosed. This accounting standards update is effective for us beginning in the first quarter of 2014 and should be applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that exist at the beginning of 2014. Early adoption is permitted. We are currently evaluating the potential impact ofdo not expect this accounting standards update to have a significant impact on our consolidated results of operations, financial position andor cash flows.

26


Cash Flows and Liquidity
 Cash Flows
 Net cash provided by operating activities was $1,5282,396 million in the first threesix months of 2013, compared to $9731,742 million in the first threesix months of 2012, primarily reflecting the impact of increased liquid hydrocarbon, natural gas and synthetic crude oil sales volumes on operating income.
 Net cash used in investing activities totaled $1,0372,299 million in the first threesix months of 2013, compared to $8062,001 million in the first threesix months of 2012.  Significant investing activities are additions to property, plant and equipment and disposal of assets.  Additions in both periods primarily related to spending on U.S. unconventional resource plays, particularly the Eagle Ford shale. Disposals of assets totaled $312333 million and $208218 million in first threesix months of 2013 and 2012, with 2013 net proceeds primarily related to the sales of our interests in our Alaska assets, and our interest in the Neptune gas plant.plant, and the DJ Basin. In 2012, net proceeds resulted primarily from the sale of our interests in several Gulf of Mexico crude oil pipeline systems.
 For further information regarding capital expenditures by segment, see Supplemental Statistics.
 Net cash used in financing activities was $413543 million in the first threesix months of 2013, compared to $157210 million provided by financing activities in the first threesix months of 2012.  Repayments of debt at maturity were $114148 million in the first threesix months of 2013 and $53111 million in the first threesix months of 2012. We also repaid all $200a net $200 million of our outstanding commercial paper during the first threesix months of 2013.2013 compared to the same period in 2012, when we drew a net $550 million of commercial paper.   Dividends paid of approximately $120241 million were a significant use of cash in both periods.
 Liquidity and Capital Resources
 Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, the issuance of notes, our committed revolving credit facility and sales of non-strategic assets. Our working capital requirements are supported by these sources and we may issue commercial paper backed by our $2.5 billion revolving credit facility to meet short-term cash requirements.  Because of the alternatives available to us as discussed above, and our 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, dividend payments, defined benefit plan contributions, repayment of debt maturities, share repurchase program and other amounts that may ultimately be paid in connection with contingencies.

29


 Capital Resources
Credit Arrangements and Borrowings
 At March 31,June 30, 2013, we had no borrowings against our revolving credit facility or under our U.S. commercial paper program that is backed by the revolving credit facility. During the first quartersix months of 2013, $200$2,075 million of commercial paper was issued and $400$2,275 million of commercial paper was repaid.
At March 31,June 30, 2013, we had $6,5446,496 million in long-term debt outstanding, $68 million of which is due within one year. We do not have any triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit ratings.
The sale of our non-operated 10 percent working interest in Block 31 offshore Angola, a transaction valued at $1.5 billion before closing adjustments, is expected to close in the fourth quarter of 2013, subject to government, regulatory and third-party approvals. We expect to use the proceeds from this sale principally to repurchase shares, but also to strengthen our balance sheet and for general corporate purposes.
Shelf Registration
We have a universal shelf registration statement filed with the SEC under which we, asare a "well-known seasoned issuer" for purposes of SEC rules, have the abilitythereby allowing us to use a universal shelf registration statement should we choose to issue and sell an indeterminate amount of various types of equity and debt securities. Beginning in the first quarter of 2013, we changed our reportable segments and equity securities.expect to recast all periods presented to reflect these new segments in our consolidated financial statements no later than upon filing our 2013 Annual Report on Form 10-K with the SEC. When appropriate, we will update and file our universal shelf registration statement.

27


Cash-Adjusted-Debt-To-CapitalCash-Adjusted Debt-To-Capital Ratio
 Our cash-adjusted debt-to-capital ratio (total debt-minus-cash to total debt-plus-equity-minus-cash) was 2425 percent at March 31,June 30, 2013, compared to 25 percent at and December 31, 2012.
March 31, December 31,June 30, December 31,
(In millions)2013 20122013 2012
Commercial paper$—
 $200
$—
 $200
Long-term debt due within one year68
 184
68
 184
Long-term debt6,476
 6,512
6,428
 6,512
Total debt$6,544
 $6,896
$6,496
 $6,896
Cash$768
 $684
$246
 $684
Equity$18,588
 $18,283
$19,021
 $18,283
Calculation: 
  
 
  
Total debt$6,544
 $6,896
$6,496
 $6,896
Minus cash768
 684
246
 684
Total debt minus cash5,776
 6,212
6,250
 6,212
Total debt6,544
 6,896
6,496
 6,896
Plus equity18,588
 18,283
19,021
 18,283
Minus cash768
 684
246
 684
Total debt plus equity minus cash$24,364
 $24,495
$25,271
 $24,495
Cash-adjusted debt-to-capital ratio24% 25%25% 25%
 Capital Requirements
 On April 24,July 31, 2013, our Board of Directors approved a dividend of 1719 cents per share for the firstsecond quarter of 2013, a 12 percent increase over the previous quarter, payable JuneSeptember 10, 2013 to stockholders of record at the close of business on May 16,August 21, 2013.
As of March 31,June 30, 2013, we plan to make contributions of up to $55$39 million to our funded pension plans during the remainder of 2013.
Since January 2006, our Board of Directors has authorized a common share repurchase program totaling $5 billion. As of June 30, 2013, we had repurchased 78 million common shares at a cost of $3,222 million, with 66 million shares purchased for $2,922 million prior to the spin-off of our downstream business and 12 million shares acquired at a cost of $300 million in 2013, $17 millionthe third quarter of which were made2011. Purchases under the program may be in April 2013.either open market transactions, including block purchases, or in

30


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. 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 discussion of liquidity above also contains forward-looking statements regarding the timing of closing the sale of our 10 percent working interest in Block 31 offshore Angola, including the use of proceeds. The timing of closing the sale of our 10 percent working interest in Block 31 offshore Angola is subject to the satisfaction of customary closing conditions and obtaining necessary government, regulatory and third-party approvals.  The expectations with respect to the use of proceeds from the sale of our 10 percent working interest in Block 31 offshore Angola could be affected by changes in the prices and demand for liquid hydrocarbons and natural gas, actions of competitors, disruptions or interruptions of the our exploration or production operations, unforeseen hazards such as weather conditions or acts of war or terrorist acts and other operating and economic considerations. The discussion of liquidity above also contains forward-looking statements regarding planned funding of pension plans, which are based on current expectations, estimates and projections and are not guarantees of actual 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 include prices of and demand for liquid hydrocarbons, natural gas and synthetic crude oil, actions of competitors, disruptions or interruptions of our production or oil sands mining and bitumen upgrading 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,June 30, 2013, our total contractual cash obligations were consistent with December 31, 2012.2012.
          
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 and production processes.
There have been no significant changes to our environmental matters subsequent to December 31, 2012.2012.

28


Other Contingencies
We are a defendant in a number of lawsuits arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims.  While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.  
 See Part II Item 1. Legal Proceedings for updated information about ongoing litigation.

31


Item 3. Quantitative and Qualitative Disclosures About Market Risk
For a detailed discussion of our risk management strategies and our derivative instruments, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk in our 2012 Annual Report on Form 10-K. Additional disclosures regarding our open derivative positions, such asincluding underlying notional quantities, how they are reported in our consolidated financial statements and how their fair values are measured, may be found in Notes 1112 and 1213 to the consolidated financial statements.
Sensitivity analysis of the incremental effects on income from operations (“IFO”) of hypothetical 10 percent and 25 percent increases and decreases in commodity prices on our open commodity derivative instruments, by contract type as of March 31,June 30, 2013 is provided in the following table.
Incremental Change in IFO from a Hypothetical Price Increase of

 
Incremental Change in IFO from a Hypothetical Price Decrease of

Incremental Change in IFO from a Hypothetical Price Increase of Incremental Change in IFO from a Hypothetical Price Decrease of
10% 25% 10% 25%10% 25% 10% 25%
Crude oil              
Swaps$(127) $(317) $127
 $317
$(81) $(203) $81
 $203
Option Collars(52) (160) 47
 155
(30) (92) 34
 109
Total crude oil(179) (477) 174
 472
$(111) $(295) $115
 $312
Natural gas       
Futures(1) (1) 1
 1
Total natural gas(1) (1) 1
 1
Total$(180) $(478) $175
 $473
Sensitivity analysis of the projected incremental effect of a hypothetical 10 percent change in interest rates on financial assets and liabilities as of March 31,June 30, 2013 is provided in the following table.
  Incremental  Incremental
  Change in  Change in
(In millions) Fair Value Fair ValueFair Value Fair Value
Financial assets (liabilities): (a)
      
Interest rate swap agreements$18
(b) 
$2
$6
(b) 
$3
Long-term debt, including amounts due within one year$(7,347)
(b) 
$(231)$(6,991)
(b) 
$(241)
(a) 
Fair values of cash and cash equivalents, receivables, commercial paper, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments.  Accordingly, these instruments are excluded from the table.
(b) 
Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.
The aggregate cash flow effect on foreign currency derivative contracts of a hypothetical 10 percent change in exchange rates at March 31,June 30, 2013 would be $6149 million.
Item 4. Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in RuleRules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer.  Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our company's design and operation of disclosure controls and procedures were effective for the period ending March 31, 2013.  as of June 30, 2013.  
In the first quarter of 2013, we completed the update of our existing Enterprise Resource Planning ("ERP") system. This update included a new general ledger, consolidations system and reporting tools. There were no changes in our internal control over financial reporting that have materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

2932

MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)


Three Months EndedThree Months Ended Six Months Ended
March 31,June 30, June 30,
(In millions)2013 20122013 2012 2013 2012
Segment Income (Loss)   
Segment Income       
North America E&P$(59) $104
$221
 $70
 $162
 $174
International E&P453
 407
382
 373
 835
 780
Oil Sands Mining38
 38
20
 50
 58
 88
Segment income432
 549
623
 493
 1,055
 1,042
Items not allocated to segments, net of income taxes(49) (132)(197) (100) (246) (232)
Net income$383
 $417
$426
 $393
 $809
 $810
Capital Expenditures(a)
        
  
North America E&P$970
 $829
$904
 $1,013
 $1,874
 $1,842
International E&P225
 138
241
 202
 466
 340
Oil Sands Mining45
 52
97
 43
 142
 95
Corporate30
 44
15
 19
 45
 63
Total$1,270
 $1,063
$1,257
 $1,277
 $2,527
 $2,340
Exploration Expenses        
  
North America E&P$435
 $106
$76
 $147
 $511
 $253
International E&P30
 29
57
 25
 87
 54
Total$465
 $135
$133
 $172
 $598
 $307
(a) 
Capital expenditures include changes in accruals.



3033

MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)


Three Months EndedThree Months Ended Six Months Ended
March 31,June 30, June 30,
Net Sales Volumes2013 20122013 2012 2013 2012
North America E&P 
  
 
  
  
  
Crude Oil and Condensate (mbbld)
121
 83
126
 85
 124
 83
Natural Gas Liquids (mbbld)
20
 7
22
 8
 21
 8
Total Liquid Hydrocarbons141
 90
148
 93
 145
 91
Natural Gas (mmcfd)
340
 344
316
 319
 328
 331
Total North America E&P (mboed)
198
 147
201
 146
 200
 146
          
International E&P 
  
 
  
    
Liquid Hydrocarbons (mbbld)
          
Europe100
 97
93
 99
 96
 98
Africa80
 52
84
 78
 82
 65
Total Liquid Hydrocarbons180
 149
177
 177
 178
 163
Natural Gas (mmcfd)
 
   
      
Europe(b)
95
 104
89
 102
 92
 103
Africa473
 418
425
 399
 449
 409
Total Natural Gas568
 522
514
 501
 541
 512
Total International E&P (mboed)
274
 236
262
 261
 268
 249
          
Oil Sands Mining          
Synthetic Crude Oil (mbbld)(c)
51
 44
43
 44
 47
 44
          
Total Company (mboed)
523
 427
506
 451
 515
 439
Net Sales Volumes of Equity Method Investees 
  
 
  
    
LNG (mtd)
6,787
 6,291
5,820
 5,467
 6,301
 5,879
Methanol (mtd)
1,410
 1,312
973
 1,268
 1,191
 1,290
(b) 
Includes natural gas acquired for injection and subsequent resale of 118 mmcfd and 1417 mmcfd for the second quarters of 2013 and 2012, and 10 mmcfd and 15 mmcfd for the first quarterssix months of 2013 and 2012.
(c) 
Includes blendstocks.




3134

MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)


Three Months EndedThree Months Ended Six Months Ended
March 31,June 30, June 30,
Average Realizations(d)
2013 20122013 2012 2013 2012
North America E&P       
Crude Oil and Condensate (per bbl)

$94.68
 
$97.28

$93.75
 
$89.04
 $94.20 $93.25
Natural Gas Liquids (per bbl)

$35.48
 
$51.55

$31.72
 
$40.54
 $33.51 $45.65
Total Liquid Hydrocarbons(e)

$86.14
 
$93.63

$84.51
 
$84.72
 $85.30 $89.23
Natural Gas (per mcf)

$3.86
 
$4.13

$4.19
 
$3.42
 $4.02 $3.79
       
International E&P       
Liquid Hydrocarbons (per bbl)
       
Europe
$116.13
 
$123.76

$106.41
 
$111.12
 $111.43 $117.37
Africa
$97.13
 
$94.41

$92.92
 
$96.84
 $94.96 $95.87
Total Liquid Hydrocarbons
$107.68
 
$113.55

$100.00
 
$104.82
 $103.86 $108.80
Natural Gas (per mcf)
       
Europe
$12.83
 
$9.99

$11.37
 
$10.05
 $12.12 $10.02
Africa(f)

$0.51
 
$0.24

$0.49
 
$0.25
 $0.50 $0.25
Total Natural Gas
$2.57
 
$2.19

$2.37
 
$2.25
 $2.47 $2.22
       
Oil Sands Mining       
Synthetic Crude Oil (per bbl)

$79.98
 
$90.88

$89.39
 
$79.31
 $84.31 $85.07
(d) 
Excludes gains and losses on derivative instruments.
(e) 
Inclusion of realized gains (losses) on crude oil derivative instruments would have increased (decreased) average liquid hydrocarbon realizations by ($0.37)$1.22 per bbl and $0.45 per bbl for the second quarter and first quartersix months of 2013.2013. There were no realized gains (losses) on crude oil derivative instruments in the first quartersame periods of 2012.2012.
(f) 
Primarily represents fixed prices under long-term contracts with Alba Plant LLC, Atlantic Methanol Production Company LLC and Equatorial Guinea LNG Holdings Limited, which are equity method investees.  We include our share of income from each of these equity method investees in our International E&P segment.

3235


Part II – OTHER INFORMATION
Item 1. Legal Proceedings
We are a defendant in a number of lawsuits arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims.  While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.  Certain of those matters are discussed below.
Litigation
In March 2011, Noble Drilling (U.S.) LLC (“Noble”) filed a lawsuit against us in the District Court of Harris County, Texas, alleging, among other things, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation, relating to a multi-year drilling contract for a newly constructed drilling rig to be deployed in the U.S. Gulf of Mexico.  We filed an answer in April 2011, contending, among other things, failure to perform, failure to comply with material obligations, failure to mitigate alleged damages and that Noble failed to provide the rig according to the operating, performance and safety requirements specified in the drilling contract. In April 2013, we filed a counterclaim against Noble alleging, among other things, breach of contract and breach of the duty of good faith relating to the multi-year drilling contract. The counterclaim also included a breach of contract claim for reimbursement for the value of fuel used by Noble under an offshore daywork drilling contract. We are vigorously defending this litigation.  The ultimate outcome of this lawsuit, including any financial effect on us, remains uncertain.  We do not believe an estimate of a reasonably probable loss (or range of loss) can be made for this lawsuit at this time.
Environmental
 We continue to workexecuted a settlement agreement with the North Dakota Department of Health to resolveregarding voluntary disclosures we made in 2009 relating toof potential Clean Air Act violations made in 2009 relating to our operations on state lands in the Bakken shale. The proposed settlementshale and paid a fine of $169,800 in June 2013.
SEC Investigation Relating to Libya
On May 25, 2011, we received a subpoena issued by the SEC requiring production of documents related to payments made to the government of Libya, or to officials and persons affiliated with officials of the fine is $169,800government of Libya. By letter dated April 26, 2013, the SEC further notified us that they completed their investigation and is expecteddid not intend to be executed by the partiesrecommend any enforcement action in the second quarter of 2013.this matter.
Item 1A. Risk Factors
We are subject to various risks and uncertainties in the course of our business.  The discussion of such risks and uncertainties may be found under Item 1A. Risk Factors in our 2012 Annual Report on Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table provides information about purchases by Marathon Oil during the quarter ended March 31,June 30, 2013, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities Exchange Act of 1934.
 Column (a) Column (b) Column (c) Column (d)
 Total Number of Average Price 
Total Number of
Shares Purchased
as Part of
Publicly Announced
 
Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Period
Shares Purchased (a)(b)
 Paid per Share 
 Plans or Programs(c)
 
Plans or Programs(c)
01/01/13 – 01/31/135,910
 $31.34 —
 $1,780,609,536
02/01/13 – 02/28/13107,389
 $33.74 —
 $1,780,609,536
03/01/13 – 03/31/1334,051
 $33.56 —
 $1,780,609,536
Total147,350
 $33.60 —
  
 Column (a) Column (b) Column (c) Column (d)
 Total Number of Average Price 
Total Number of
Shares Purchased
as Part of
Publicly Announced
 
Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Period
Shares Purchased (a)(b)
 Paid per Share 
 Plans or Programs(c)
 
Plans or Programs(c)
04/01/13 - 04/30/13

12,135
 $33.64 —
 $1,780,609,536
05/01/13 - 05/31/133,795
 $32.05 —
 $1,780,609,536
06/01/13 - 06/30/1336,664
 $34.84 —
 $1,780,609,536
Total52,594
 $34.36 —
  
(a) 
120,43127,051 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.
(b) 
In MarchJune 2013, 26,91925,543 shares were repurchased in open-market transactions to satisfy the requirements for dividend reinvestment under the Marathon Oil Corporation Dividend Reinvestment and Direct Stock Purchase Plan (the “Dividend Reinvestment Plan”) by the administrator of the Dividend Reinvestment Plan. Shares needed to meet the requirements of the Dividend Reinvestment Plan are either purchased in the open market or issued directly by Marathon Oil.
(c) 
We announced a share repurchase program in January 2006, and amended it several times in 2007 for a total authorized program of $5 billion. As of March 31,June 30, 2013, 78 million split-adjusted common shares had been acquired at a cost of $3,222 million, which includes transaction fees and commissions that are not reported in the table above.  Of this total, 66 million shares had been acquired at a cost of $2,922 million prior to the spin-off of the downstream business.

36


Item 4. Mine Safety Disclosures
 Not applicable.

33


Item 6.  Exhibits
The following exhibits are filed as a part of this report:
Incorporated by Reference
Exhibit NumberExhibit DescriptionFormExhibitFiling DateSEC File No.Filed HerewithFurnished Herewith
10.1Form of Performance Unit Award Agreement (2013-2015 Performance Cycle) for Section 16 Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation PlanX
10.2Form of Performance Unit Award Agreement (2013-2015 Performance Cycle) for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation PlanX
12.1Computation of Ratio of Earnings to Fixed Charges.X
31.1Certification of Chairman, President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.X
31.2Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.X
32.1Certification of Chairman, President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.X
32.2Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.X
101.INSXBRL Instance Document.X
101.SCHXBRL Taxonomy Extension Schema.X
101.PREXBRL Taxonomy Extension Presentation Linkbase.X
101.CALXBRL Taxonomy Extension Calculation Linkbase.X
101.DEFXBRL Taxonomy Extension Definition Linkbase.X
101.LABXBRL Taxonomy Extension Label Linkbase.X
    Incorporated by Reference    
Exhibit Number Exhibit Description Form Exhibit Filing Date SEC File No. Filed Herewith Furnished Herewith
3.1 Restated Certificate of Incorporation of Marathon Oil Corporation.         X  
3.2 Amended By-laws of Marathon Oil Corporation effective May 29, 2013.         X  
3.3 Amended By-Laws of Marathon Oil Corporation effective August 1, 2013.         X  
10.1 Marathon Oil Corporation 2011 Officer Change in Control Severance Benefits Plan (For Officers Hired or Promoted after October 26, 2011). 10-Q 10.4 5/4/2012 001-05153    
12.1 Computation of Ratio of Earnings to Fixed Charges.         X  
31.1 Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.         X  
31.2 Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.         X  
32.1 Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.         X  
32.2 Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.         X  
101.INS XBRL Instance Document.         X  
101.SCH XBRL Taxonomy Extension Schema.         X  
               
101.CAL XBRL Taxonomy Extension Calculation Linkbase.         X  
101.DEF XBRL Taxonomy Extension Definition Linkbase.         X  
101.LAB XBRL Taxonomy Extension Label Linkbase.         X  
101.PRE XBRL Taxonomy Extension Presentation Linkbase.         X  


3437



SIGNATURES

 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
May 10,August 8, 2013 MARATHON OIL CORPORATION
   
 By:/s/ Michael K. Stewart
   Michael K. Stewart
  
Vice President, Finance and Accounting,
Controller and Treasurer

3538



Exhibit Index

Incorporated by Reference
Exhibit NumberExhibit DescriptionFormExhibitFiling DateSEC File No.Filed HerewithFurnished Herewith
10.1Form of Performance Unit Award Agreement (2013-2015 Performance Cycle) for Section 16 Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation PlanX
10.2Form of Performance Unit Award Agreement (2013-2015 Performance Cycle) for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation PlanX
12.1Computation of Ratio of Earnings to Fixed Charges.X
31.1Certification of Chairman, President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.X
31.2Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.X
32.1Certification of Chairman, President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.X
32.2Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.X
101.INSXBRL Instance Document.X
101.SCHXBRL Taxonomy Extension Schema.X
101.PREXBRL Taxonomy Extension Presentation Linkbase.X
101.CALXBRL Taxonomy Extension Calculation Linkbase.X
101.DEFXBRL Taxonomy Extension Definition Linkbase.X
101.LABXBRL Taxonomy Extension Label Linkbase.X
    Incorporated by Reference    
Exhibit Number Exhibit Description Form Exhibit Filing Date SEC File No. Filed Herewith Furnished Herewith
3.1 Restated Certificate of Incorporation of Marathon Oil Corporation.         X  
3.2 Amended By-laws of Marathon Oil Corporation effective May 29, 2013.         X  
3.3 Amended By-Laws of Marathon Oil Corporation effective August 1, 2013.         X  
10.1 Marathon Oil Corporation 2011 Officer Change in Control Severance Benefits Plan (For Officers Hired or Promoted after October 26, 2011). 10-Q 10.4 5/4/2012 001-05153    
12.1 Computation of Ratio of Earnings to Fixed Charges.         X  
31.1 Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.         X  
31.2 Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.         X  
32.1 Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.         X  
32.2 Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.         X  
101.INS XBRL Instance Document.         X  
101.SCH XBRL Taxonomy Extension Schema.         X  
101.CAL XBRL Taxonomy Extension Calculation Linkbase.         X  
101.DEF XBRL Taxonomy Extension Definition Linkbase.         X  
101.LAB XBRL Taxonomy Extension Label Linkbase.         X  
101.PRE XBRL Taxonomy Extension Presentation Linkbase.         X