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

FORM 10-Q

(Mark One) 
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 For the Quarterly Period Ended September 30, 20122013

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 706,417,267696,634,081 shares of Marathon Oil Corporation common stock outstanding as of October 31, 20122013.



MARATHON OIL CORPORATION
 
Form 10-Q
 
Quarter Ended September 30, 20122013


 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
21
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
3536
Item 4.
Controls and Procedures
36
 
Supplemental Statistics (Unaudited)
37
PARTPart II - OTHER INFORMATION
 
Item 1.
Legal Proceedings
3940
Item 1A.
Risk Factors
3940
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
3940
Item 4.
Mine Safety Disclosures
3940
Item 6.
Exhibits
4041
 
Signatures
4142

 
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 Ended Nine Months EndedThree Months Ended Nine Months Ended
September 30, September 30,September 30, September 30,
(In millions, except per share data)2012 2011 2012 20112013 2012 2013 2012
Revenues and other income:              
Sales and other operating revenues$4,018
 $3,633
 $11,513
 $10,969
Sales to related parties16
 16
 43
 45
Sales and other operating revenues, including related party$3,119
 $3,405
 $9,978
 $9,324
Marketing revenues668
 631
 1,597
 2,237
Income from equity method investments122
 123
 260
 360
114
 122
 309
 260
Net gain (loss) on disposal of assets(12) 13
 126
 63
(6) (12) (4) 126
Other income17
 14
 43
 36
19
 15
 38
 38
Total revenues and other income4,161
 3,799
 11,985
 11,473
3,914
 4,161
 11,918
 11,985
Costs and expenses: 
  
  
  
 
  
    
Cost of revenues (excludes items below)1,296
 1,600
 4,005
 4,671
Purchases from related parties72
 57
 191
 184
Production575
 601
 1,767
 1,581
Marketing, including purchases from related parties664
 629
 1,588
 2,238
Other operating126
 112
 323
 311
Exploration153
 170
 751
 477
Depreciation, depletion and amortization625
 517
 1,779
 1,716
720
 625
 2,205
 1,779
Impairments8
 —
 271
 307
11
 8
 49
 271
General and administrative expenses139
 104
 389
 371
Other taxes63
 59
 208
 170
Exploration expenses176
 129
 491
 504
Taxes other than income91
 55
 268
 178
General and administrative152
 179
 490
 499
Total costs and expenses2,379
 2,466
 7,334
 7,923
2,492
 2,379
 7,441
 7,334
Income from operations1,782
 1,333
 4,651
 3,550
1,422
 1,782
 4,477
 4,651
Net interest and other(53) (30) (160) (62)(66) (53) (209) (160)
Loss on early extinguishment of debt—
 —
 —
 (279)
Income from continuing operations       
before income taxes1,729
 1,303
 4,491
 3,209
Income before income taxes1,356
 1,729
 4,268
 4,491
Provision for income taxes1,279
 898
 3,231
 2,051
787
 1,279
 2,890
 3,231
Income from continuing operations450
 405
 1,260
 1,158
Discontinued operations—
 —
 —
 1,239
Net income$450
 $405
 $1,260
 $2,397
$569
 $450
 $1,378
 $1,260
Per Share Data 
  
  
  
 
  
  
  
Basic: 
  
  
  
Income from continuing operations$0.64 $0.57 $1.79 $1.63
Discontinued operations—
 —
 —
 $1.74
Net income$0.64 $0.57 $1.79 $3.37
Diluted: 
  
    
Income from continuing operations$0.63 $0.57 $1.78 $1.62
Discontinued operations—
 —
 —
 $1.73
Net income$0.63 $0.57 $1.78 $3.35
Net Income: 
  
  
  
Basic$0.80
 $0.64
 $1.95
 $1.79
Diluted$0.80
 $0.63
 $1.94
 $1.78
Dividends paid$0.17 $0.15 $0.51 $0.65$0.19
 $0.17
 $0.53
 $0.51
Weighted average shares: 
  
  
  
 
  
  
  
Basic706
 711
 705
 712
707
 706
 708
 705
Diluted709
 714
 709
 716
711
 709
 712
 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 Ended Nine Months EndedThree Months Ended Nine Months Ended
September 30, September 30,September 30, September 30,
(In millions)2012 2011 2012 20112013 2012 2013 2012
Net income$450
 $405
 $1,260
 $2,397
$569
 $450
 $1,378
 $1,260
Other comprehensive income 
  
  
  
Other comprehensive income (loss) 
  
  
  
Postretirement and postemployment plans 
  
  
  
 
  
  
  
Change in actuarial loss and other(90) 13
 (80) 110
34
 (90) 180
 (80)
Spin-off downstream business—
 —
 —
 968
Income tax benefit (provision) on postretirement and 
  
  
  
Income tax (provision) benefit on postretirement and 
  
  
  
postemployment plans32
 6
 28
 (409)(13) 32
 (67) 28
Postretirement and postemployment plans, net of tax(58) 19
 (52) 669
21
 (58) 113
 (52)
Derivative hedges 
  
  
  
 
  
  
  
Net unrecognized gain (loss)1
 (1) 1
 9
Spin-off downstream business—
 —
 —
 (7)
Net unrecognized gain—
 1
 —
 1
Income tax provision on derivatives—
 —
 —
 (1)—
 —
 —
 —
Derivative hedges, net of tax1
 (1) 1
 1
—
 1
 —
 1
Foreign currency translation and other 
  
  
  
 
  
  
  
Unrealized loss—
 —
 —
 (1)
Income tax provision on foreign currency translation and other—
 —
 —
 —
Unrealized gain (loss)1
 —
 (3) —
Income tax benefit on foreign currency translation and other—
 —
 1
 —
Foreign currency translation and other, net of tax—
 —
 —
 (1)1
 —
 (2) —
Other comprehensive income (loss)(57) 18
 (51) 669
22
 (57) 111
 (51)
Comprehensive income$393
 $423
 $1,209
 $3,066
$591
 $393
 $1,489
 $1,209
 The accompanying notes are an integral part of these consolidated financial statements.


3


MARATHON OIL CORPORATION
Consolidated Balance Sheets (Unaudited)
September 30, December 31,September 30, December 31,
(In millions, except per share data)2012 20112013 2012
Assets      
Current assets:      
Cash and cash equivalents$671
 $493
$354
 $684
Receivables2,553
 1,917
2,562
 2,418
Receivables from related parties22
 35
Inventories324
 361
360
 361
Prepayments111
 96
Deferred tax assets87
 99
Other current assets269
 223
179
 299
Total current assets4,037
 3,224
3,455
 3,762
Equity method investments1,319
 1,383
1,216
 1,279
Property, plant and equipment, less accumulated depreciation, 
  
 
  
depletion and amortization of $18,438 and $17,24827,446
 25,324
depletion and amortization of $21,171 and $19,26627,822
 28,272
Goodwill525
 536
499
 525
Other noncurrent assets1,231
 904
2,784
 1,468
Total assets$34,558
 $31,371
$35,776
 $35,306
Liabilities 
  
 
  
Current liabilities: 
  
 
  
Commercial paper$1,839
 $—
$200
 $200
Accounts payable2,335
 1,864
2,406
 2,324
Payables to related parties44
 18
Payroll and benefits payable148
 193
162
 217
Accrued taxes2,027
 2,015
1,511
 1,983
Other current liabilities206
 163
326
 173
Long-term debt due within one year183
 141
68
 184
Total current liabilities6,782
 4,394
4,673
 5,081
Long-term debt4,518
 4,674
6,433
 6,512
Deferred tax liabilities2,495
 2,544
2,481
 2,432
Defined benefit postretirement plan obligations817
 789
713
 856
Asset retirement obligations1,516
 1,510
2,027
 1,749
Deferred credits and other liabilities366
 301
455
 393
Total liabilities16,494
 14,212
16,782
 17,023
Commitments and contingencies

 



 

Stockholders’ Equity 
  
 
  
Preferred stock – no shares issued and outstanding (no par value, 
  
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 and 
  
Securities exchangeable into common stock – no shares issued or 
  
outstanding (no par value, 29 million shares authorized)—
 —
—
 —
Held in treasury, at cost – 64 million and 66 million shares(2,607) (2,716)
Held in treasury, at cost – 74 million and 63 million shares(2,949) (2,560)
Additional paid-in capital6,634
 6,680
6,603
 6,616
Retained earnings13,688
 12,788
14,892
 13,890
Accumulated other comprehensive loss(421) (370)(322) (433)
Total equity of Marathon Oil's stockholders18,064
 17,152
Noncontrolling interest—
 7
Total equity18,064
 17,159
Total stockholders' equity18,994
 18,283
Total liabilities and stockholders' equity$34,558
 $31,371
$35,776
 $35,306
 The accompanying notes are an integral part of these consolidated financial statements.

4


MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows (Unaudited)
Nine Months EndedNine Months Ended
September 30,September 30,
(In millions)2012 20112013 2012
Increase (decrease) in cash and cash equivalents      
Operating activities: 
  
 
  
Net income$1,260
 $2,397
$1,378
 $1,260
Adjustments to reconcile net income to net cash provided by operating activities: 
  
 
  
Discontinued operations—
 (1,239)
Loss on early extinguishment of debt—
 279
Deferred income taxes(27) (75)17
 (27)
Depreciation, depletion and amortization1,779
 1,716
2,205
 1,779
Impairments271
 307
49
 271
Pension and other postretirement benefits, net(56) 28
41
 (56)
Exploratory dry well costs and unproved property impairments287
 311
619
 287
Net gain on disposal of assets(126) (63)
Net loss (gain) on disposal of assets4
 (126)
Equity method investments, net(14) 16
12
 (14)
Changes in:   
   
Current receivables(646) 202
(151) (646)
Inventories(6) 47
(8) (6)
Current accounts payable and accrued liabilities156
 361
(286) 156
All other operating, net(66) 113
161
 (66)
Net cash provided by continuing operations2,812
 4,400
Net cash provided by discontinued operations—
 1,090
Net cash provided by operating activities2,812
 5,490
4,041
 2,812
Investing activities: 
  
 
  
Acquisitions, net of cash acquired(806) —
(74) (806)
Additions to property, plant and equipment(3,509) (2,437)(3,818) (3,509)
Disposal of assets193
 385
402
 193
Investments - return of capital42
 41
45
 42
Investing activities of discontinued operations—
 (493)
Property deposit—
 (120)
All other investing, net49
 13
34
 49
Net cash used in investing activities(4,031) (2,611)(3,411) (4,031)
Financing activities: 
  
 
  
Commercial paper, net1,839
 —
—
 1,839
Debt issuance costs(9) —
—
 (9)
Debt repayments(111) (2,843)(148) (111)
Purchases of common stock—
 (300)(500) —
Dividends paid(360) (462)(376) (360)
Financing activities of discontinued operations—
 2,916
Distribution in spin-off—
 (1,622)
All other financing, net26
 129
70
 26
Net cash provided by (used in) financing activities1,385
 (2,182)
Net cash (used in) provided by financing activities(954) 1,385
Effect of exchange rate changes on cash12
 (15)(6) 12
Net increase in cash and cash equivalents178
 682
Net increase (decrease) in cash and cash equivalents(330) 178
Cash and cash equivalents at beginning of period493
 3,951
684
 493
Cash and cash equivalents at end of period$671
 $4,633
$354
 $671
 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 spin-off (see Note 2),reclassifications, general and administrative expenses for the resultsthird quarter and first nine months of 2012 increased by $40 million and $110 million which primarily includes certain costs associated with operations for our downstream (Refining, Marketingsupport and Transportation) business have been classified as discontinued operations management. Offsetting reductions are reflected in 2011.  The disclosures in this report are presented on the basis of continuing operations, unless otherwise stated. Any reference to “Marathon” indicates Marathon Oil Corporation as it existed prior to the June 30, 2011 spin-off.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 20112012 Annual Report on Form 10-K.  The results of operations for the third quarter and first nine months of 20122013 are not necessarily indicative of the results to be expected for the full year.
2.   Spin-off Downstream Business
 On June 30, 2011, the spin-off of the downstream business was completed, creating two independent energy companies: Marathon Oil and Marathon Petroleum Corporation (“MPC”).  On June 30, 2011, stockholders of record as of 5:00 p.m. Eastern Daylight Savings time on June 27, 2011 (the “Record Date”) received one common share of MPC stock for every two common shares of Marathon stock held as of the Record Date.
The following table presents selected financial information regarding the results of operations of our downstream business which are reported as discontinued operations.  Transaction costs incurred to affect the spin-off of $74 million are included in discontinued operations for 2011.
 Three Months Ended Nine Months Ended
 September 30, September 30,
(In millions)2011 2011
Revenues applicable to discontinued operations$—
 $38,602
Pretax income from discontinued operations—
 2,012
3.     Accounting Standards
RecentlyNot Yet Adopted
In September 2011,June 2013, the Financial Accounting Standards Board (“FASB”("FASB") amendedratified 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 to simplify how entities test goodwill for impairment.  The amendment reduces complexity by allowing an entity the option to make a qualitative evaluation of whether it is necessary to perform the two-step goodwill impairment test.  The amendmentupdate is effective for our interim and annual periodsus beginning within the first quarter of 2012.2014 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 do not expect this accounting standards update to have a significant impact on our consolidated results of operations, financial position or 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 Note 16. Adoption of this amendmentstandard did not have a significant impact on our consolidated results of operations, financial position or cash flows.
 The FASB amended the reporting standards for comprehensive income in June 2011 to eliminate the option to present the components of Other Comprehensive Income (“OCI”) as part of the statement of changes in stockholders' equity.  All non-owner changes in stockholders’ equity are required to be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements.  In the two statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of OCI, and total comprehensive income.  The presentation of items that are reclassified from OCI to net income on the income statement is also required.  The amendments did not change the items that must be reported in OCI or when an item of OCI must be reclassified to net income.  The amendments are effective for us beginning with the first quarter of 2012, except for the presentation of reclassifications, which has been deferred.  Adoption of these amendments did not have a significant impact on our consolidated results of operations, financial position or cash flows.
In May 2011, the FASB issued an update amending the accounting standards for fair value measurement and disclosure, resulting in common principles and requirements under accounting principles generally accepted in the U.S. (“U.S. GAAP”) and International Financial Reporting Standards (“IFRS”).  The amendments change the wording used to describe certain of the U.S.

6

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


GAAP requirementsIn 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 clarify the intentan enforceable master netting arrangement or similar agreement, irrespective of existing requirements, to change measurement or expand disclosure principles or to conform to the wording used in IFRS.whether they are offset. The amendments are to be applied prospectivelyaccounting standards update was effective for our interim and annual periodsus beginning with the first quarter of 2012.  The adoption2013 and we include the required disclosures in Note 14. Adoption of the amendmentsthis standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.  To the extent they were necessary, we have made the expanded disclosures in Note 13.
4.3.   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 acurrent liabilities of $3 million current liability recorded at September 30, 20122013, consistent with December 31, 2011.2012.  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 Entityvariable 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 Marathon Oil.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 $697707 million as of September 30, 20122013.  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.
5.4.    Income per Common Share
Basic income per share is based on the weighted average number of common shares outstanding.  Diluted income per share includesassumes exercise of stock options and stock appreciation rights, provided the effect is not antidilutive.
Three Months Ended September 30,Three Months Ended September 30,
2012 20112013 2012
(In millions, except per share data)Basic Diluted Basic DilutedBasic Diluted Basic Diluted
Net income$450
 $450
 $405
 $405
$569
 $569
 $450
 $450
              
Weighted average common shares outstanding706
 706
 711
 711
707
 707
 706
 706
Effect of dilutive securities—
 3
 —
 3
—
 4
 —
 3
Weighted average common shares, including              
dilutive effect706
 709
 711
 714
707
 711
 706
 709
Per share: 
  
  
  
 
  
  
  
Net income$0.64 $0.63 $0.57 $0.57
$0.80
 
$0.80
 
$0.64
 
$0.63
 
7

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Nine Months Ended September 30,Nine Months Ended September 30,
2012 20112013 2012
(In millions, except per share data)Basic Diluted Basic DilutedBasic Diluted Basic Diluted
Income from continuing operations$1,260
 $1,260
 $1,158
 $1,158
Discontinued operations—
 —
 1,239
 1,239
Net income$1,260
 $1,260
 $2,397
 $2,397
$1,378
 $1,378
 $1,260
 $1,260
              
Weighted average common shares outstanding705
 705
 712
 712
708
 708
 705
 705
Effect of dilutive securities—
 4
 —
 4
—
 4
 —
 4
Weighted average common shares, including              
dilutive effect705
 709
 712
 716
708
 712
 705
 709
Per share: 
  
  
  
 
  
  
  
Income from continuing operations$1.79 $1.78 $1.63 $1.62
Discontinued operations—
 —
 $1.74 $1.73
Net income$1.79 $1.78 $3.37 $3.35$1.95 $1.94 $1.79 $1.78
The per share calculations above exclude 104 million and 5 million stock options and stock appreciation rights for the third quarter quarter and first nine months of20122013, as they were antidilutive. Excluded for the third quarter quarter and first nine months of20112012 were 9 million and 710 million stock options and stock appreciation rights.options.
6.     Acquisitions5. Dispositions
2013 - North America Exploration and Production ("E&P") Segment
We acquiredIn June 2013, we closed the sale of our interests in the DJ Basin for proceeds of $19 million. A loss of $114 million was recorded in the second quarter of 2013.
In February 2013, we conveyed our interests in the Marcellus natural gas shale play to the operator. A $43 million 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 gain 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 which was collected in July 2013. After closing adjustments made in the second quarter of 2013, the gain on this sale was $55 million.
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, is expected to close in the fourth quarter of 2013, subject to government and regulatory approvals. Angola Block 31 is reflected as held for sale in the September 30, 2013 consolidated balance sheet as follows:
(In millions) 
Other current assets$15
Other noncurrent assets1,598
Total assets1,613
Other current liabilities42
Deferred credits and other liabilities41
Total liabilities$83
2012 - North America E&P Segment
In the third quarter of 2012, we sold approximately 20,0005,800 net undeveloped acres inlocated outside the core of the Eagle Ford shale duringfor proceeds of $9 million. A net loss of $18 million was recorded.
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 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 and we paid the accrued amount in the third quarter of 2012.
6. Acquisitions
During the third quarters and first nine months of 2012. All2013 and 2012, our business combinations related to properties acquired by our North America E&P segment in the Eagle Ford properties are includedshale in south Texas. The pro forma impact of these transactions, individually and in the aggregate, is not material to our Exploration and Production (“E&P”) segment.  The largest transaction was the acquisitionconsolidated statements of Paloma Partners II, LLC, which closed August 1, 2012income for cash consideration of $768 million. This transaction was accounted for as a business combination. Smaller transactions closed during the second quarter of 2012. any periods presented.
The following table summarizes the amounts allocated to the assets acquired and liabilities assumed based upon their fair values at the acquisition date:
(In millions)  
Assets:  
Cash $8
Receivables 22
Inventories 1
Total current assets acquired 31
Property, plant and equipment 822
Total assets acquired 853
Liabilities:  
Accounts payable 78
Asset retirement obligations 7
Total liabilities assumed 85
Net assets acquired $768
The fair values of assets acquired and liabilities assumed in each of these business combinations were measured primarily using an income approach, specifically utilizing a discounted cash flow analysis. The estimated fair values were based on significant inputs not observable in the market, and therefore represent Level 3 measurements. Significant inputs included estimated reserve volumes, the expected future production profile, estimated commodity prices and assumptions regarding future operating and development costs. AThe discount rate of approximately 10 percent wasrates used in the discounted cash flow analysis.analyses were approximately 10 percent for the both the 2013 and 2012 transactions.
2013
In July 2013, we acquired 4,800 net undeveloped acres in the core of the Eagle Ford shale in a transaction valued at $97 million, including carried interest of $23 million. The accountingtransaction was accounted for this transaction is complete. The pro forma impact of thisas a business combination, is not materialwith the entire up-front cash consideration of $74 million allocated to our consolidated statementsproperty, plant and equipment at the acquisition date.
2012
We acquired approximately 20,000 net acres in the core of income for the third quarter andEagle Ford shale during the first nine months of 20122012. The largest transaction was the acquisition of Paloma Partners II, LLC, which closed during the third quarter for cash consideration of $768 million. This transaction was accounted for as a business combination. Smaller transactions closed during the second quarter of 2012.
The following table summarizes the amounts allocated to the assets acquired and 2011.liabilities assumed for Paloma Partners II, LLC based upon their fair values at the acquisition date:
(In millions)  
Assets:  
Cash $8
Receivables 22
Inventories 1
Total current assets acquired 31
Property, plant and equipment 822
Total assets acquired $853
Liabilities:  
Accounts payable 78
Asset retirement obligations 7
Total liabilities assumed 85
Net assets acquired $768

89

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


7.    Dispositions
2012
In the third quarter of 2012, we sold approximately 5,800 net undeveloped acres located outside the core of the Eagle Ford shale, held by our E&P segment, for proceeds of $9 million. A pretax loss of $18 million was recorded.
In May 2012, we executed agreements to relinquish our E&P segment’s operatorship of and participating interests in the Bone Bay and Kumawa exploration licenses in Indonesia.  As a result, we accrued and reported a $36 million loss on disposal of assets in the second quarter of 2012.  Government ratification of the agreements was received during the third quarter of 2012, which released us from our obligations and further commitments related to these licenses, and we paid the amount accrued. 
 In April 2012, we entered into agreements to sell all of our E&P segment’s assets in Alaska.  One transaction closed in the second quarter of 2012 with proceeds and a net pretax gain of $7 million.  The remaining transaction, with a value of $375 million before closing adjustments, is currently under review by the U.S. Federal Trade Commission and the Alaska Attorney General's office, which could impact the closing of this transaction. Assets held for sale are included in the September 30, 2012 balance sheet as follows:
(In millions) 
Other current assets$59
Other noncurrent assets190
Total assets249
Other current liabilities1
Deferred credits and other liabilities90
Total liabilities$91
In January 2012, we closed on the sale of our E&P segment’s interests in several Gulf of Mexico crude oil pipeline systems for proceeds of $206 million.  This includes 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.
2011
In September 2011, we sold our Integrated Gas segment's equity interest in a liquefied natural gas (“LNG”) processing facility in Alaska. A gain on the transaction of $8 million was recorded in the third quarter of 2011.
In April 2011, we assigned a 30 percent undivided working interest in our E&P segment’s approximately 180,000 acres in the Niobrara shale play located within the DJ Basin of southeast Wyoming and northern Colorado for total consideration of $270 million, recording a pretax gain of $39 million.  We remain operator of this jointly owned leasehold.
 In March 2011, we closed the sale of our E&P segment's outside-operated interests in the Gudrun field development and the Brynhild and Eirin exploration areas offshore Norway for net proceeds of $85 million, excluding working capital adjustments.  A $64 million pretax loss on this disposition was recorded in the fourth quarter of 2010.
8.    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 prior-year 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 they offer.it offers.
 Exploration and Production (“North America E&P”&P ("N.A. E&P") – explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis;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; and
Integrated Gas (“IG”) – produces and markets products manufactured from natural gas, such as LNG and methanol, in Equatorial Guinea.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

9

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


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.  Impairments,Unrealized gains or losses on disposal of assetscrude oil derivative instruments, impairments, gains or losses on dispositions 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.
As discussed in Note 2, our downstream business was spun-off on June 30, 2011 and has been reported as discontinued operations in 2011.
 Three Months Ended September 30, 2012
(In millions)E&P OSM IG Total
Revenues: 
  
  
  
Customer$3,503
 $470
 $—
 $3,973
Related parties16
 —
 —
 16
Segment revenues$3,519
 $470
 $—
 3,989
Unrealized gain on crude oil derivative instruments      45
Total revenues      $4,034
Segment income$486
 $65
 $39
 $590
Income from equity method investments74
 —
 48
 122
Depreciation, depletion and amortization556
 60
 —
 616
Income tax provision1,252
 20
 9
 1,281
Capital expenditures1,274
 41
 1
 1,316
Three Months Ended September 30, 2011Three Months Ended September 30, 2013
(In millions)E&P OSM IG TotalN.A. E&P Int'l E&P OSM Total
Revenues: 
  
  
  
       
Customer$3,190
 $427
 $16
 $3,633
Intersegment6
 —
 —
 6
Related parties16
 —
 —
 16
Sales and other operating revenues$1,321
 $1,396
 $463
 $3,180
Marketing revenues607
 58
 3
 668
Segment revenues$3,212
 $427
 $16
 3,655
$1,928
 $1,454
 $466
 3,848
Elimination of intersegment revenues  

 

 (6)
Unrealized loss on crude oil derivative instruments      (61)
Total revenues

 

 

 $3,649
      $3,787
Segment income$330
 $92
 $55
 $477
$242
 $321
 $106
 $669
Income from equity method investments63
 —
 60
 123
—
 114
 —
 114
Depreciation, depletion and amortization454
 55
 —
 509
490
 179
 54
 723
Income tax provision890
 31
 19
 940
143
 714
 35
 892
Capital expenditures684
 36
 1
 721
831
 254
 65
 1,150

10

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Nine Months Ended September 30, 2012Three Months Ended September 30, 2012
(In millions)E&P OSM IG TotalN.A. E&P Int'l E&P OSM Total
Revenues: 
  
  
  
       
Customer$10,284
 $1,184
 $—
 $11,468
Related parties43
 —
 —
 43
Sales and other operating revenues$993
 $1,907
 $460
 $3,360
Marketing revenues548
 73
 10
 631
Segment revenues$10,327
 $1,184
 $—
 11,511
$1,541
 $1,980
 $470
 3,991
Unrealized gain on crude oil derivative instruments      45
      45
Total revenues

 

 

 $11,556
      $4,036
Segment income$1,380
 $157
 $56
 $1,593
$107
 $405
 $66
 $578
Income from equity method investments176
 —
 84
 260
1
 121
 —
 122
Depreciation, depletion and amortization1,593
 159
 —
 1,752
360
 194
 60
 614
Income tax provision3,398
 51
 15
 3,464
66
 1,219
 20
 1,305
Capital expenditures3,459
 136
 2
 3,597
1,045
 229
 41
 1,315
Nine Months Ended September 30, 2011Nine Months Ended September 30, 2013
(In millions)E&P OSM IG TotalN.A. E&P Int'l E&P OSM Total
Revenues: 
  
  
  
       
Customer$9,696
 $1,180
 $93
 $10,969
Intersegment47
 —
 —
 47
Related parties45
 —
 —
 45
Sales and other operating revenues$3,820
 $5,015
 $1,204
 $10,039
Marketing revenues1,391
 194
 12
 1,597
Segment revenues$9,788
 $1,180
 $93
 11,061
$5,211
 $5,209
 $1,216
 11,636
Elimination of intersegment revenues  

 

 (47)
Unrealized loss on crude oil derivative instruments      (61)
Total revenues      $11,014
      $11,575
Segment income$1,599
 $193
 $158
 $1,950
$404
 $1,156
 $164
 $1,724
Income from equity method investments187
 —
 173
 360
—
 309
 —
 309
Depreciation, depletion and amortization1,541
 141
 3
 1,685
1,458
 575
 154
 2,187
Income tax provision2,101
 64
 62
 2,227
242
 2,860
 55
 3,157
Capital expenditures2,101
 236
 2
 2,339
2,705
 720
 207
 3,632
 Nine Months Ended September 30, 2012
(In millions)N.A. E&P Int'l E&P OSM Total
Revenues:       
Sales and other operating revenues$2,738
 $5,383
 $1,158
 $9,279
Marketing revenues2,019
 193
 25
 2,237
Segment revenues$4,757
 $5,576
 $1,183
 11,516
Unrealized gain on crude oil derivative instruments      45
Total revenues      $11,561
Segment income$281
 $1,185
 $154
 $1,620
Income from equity method investments2
 258
 —
 260
Depreciation, depletion and amortization964
 622
 159
 1,745
Income tax provision166
 3,260
 50
 3,476
Capital expenditures2,887
 569
 136
 3,592

11

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


The following reconciles total revenues to sales and other operating revenues as reported in the consolidated statements of income:
Three Months Ended Nine Months Ended
September 30, September 30,Three Months Ended September 30,Nine Months Ended September 30,
(In millions)2012 2011 2012 20112013201220132012
Total revenues$4,034
 $3,649
 $11,556
 $11,014
$3,787
$4,036
$11,575
$11,561
Less: Sales to related parties16
 16
 43
 45
Sales and other operating revenues$4,018
 $3,633
 $11,513
 $10,969
Less: Marketing revenues668
631
1,597
2,237
Sales and other operating revenues, including related party$3,119
$3,405
$9,978
$9,324


11

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 Nine Months Ended
 September 30, September 30,
(In millions)2012 2011 2012 2011
Segment income$590
 $477
 $1,593
 $1,950
Items not allocated to segments, net of income taxes: 
  
  
  
Corporate and other unallocated items(158) (56) (267) (209)
Unrealized gain on crude oil derivative instruments29
 —
 29
 —
     Gain (loss) on dispositions(11) (1) 72
 23
     Impairments—
 —
 (167) (195)
Loss on early extinguishment of debt—
 —
 —
 (176)
     Tax effect of subsidiary restructuring—
 —
 —
 (122)
Deferred income tax items—
 (15) —
 (65)
Water abatement - Oil Sands—
 —
 —
 (48)
Income from continuing operations450
 405
 1,260
 1,158
Discontinued operations—
 —
 —
 1,239
Net income$450
 $405
 $1,260
 $2,397
 Three Months Ended September 30,Nine Months Ended September 30,
(In millions)2013201220132012
Segment income$669
$578
$1,724
$1,620
Items not allocated to segments, net of income taxes: 
 
 
 
Corporate and other unallocated items(61)(146)(288)(294)
Unrealized gain (loss) on crude oil derivative instruments(39)29
(39)29
     Net gain (loss) on dispositions—
(11)(9)72
     Impairments—
—
(10)(167)
Net income$569
$450
$1,378
$1,260
9.8.    Defined Benefit Postretirement Plans
The following summarizes the components of net periodic benefit cost:
Three Months Ended September 30,Three Months Ended September 30,
Pension Benefits Other BenefitsPension Benefits Other Benefits
(In millions)2012 2011 2012 20112013 2012 2013 2012
Service cost$12
 $12
 $1
 $1
$14
 $12
 $1
 $1
Interest cost16
 17
 4
 4
16
 16
 3
 4
Expected return on plan assets(14) (16) —
 —
(17) (14) —
 —
Amortization: 
  
  
  
 
  
  
  
– prior service cost (credit)2
 1
 (2) (2)2
 2
 (2) (2)
– actuarial loss12
 12
 —
 —
9
 12
 —
 —
– net settlement loss(a)
34
 —
 —
 —
Net settlement loss(a)
15
 34
 —
 —
Net periodic benefit cost$62
 $26
 $3
 $3
$39
 $62
 $2
 $3
 Nine Months Ended September 30,
  
Pension Benefits Other Benefits
(In millions)2012 2011 2012 2011
Service cost$37
 $35
 $3
 $3
Interest cost48
 50
 11
 12
Expected return on plan assets(46) (49) —
 —
Amortization: 
  
  
  
– prior service cost (credit)6
 4
 (5) (5)
– actuarial loss37
 37
 —
 —
– net settlement loss(a)
34
 —
 —
 —
Net periodic benefit cost$116
 $77
 $9
 $10
(a)
Settlement losses are recorded when lump sum payments from a plan in a period exceed the plan's total service and interest costs for the period. Such settlements occurred in our U.S. pension plans during the third quarter of 2012.

12

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



 Nine months Ended September 30,
  
Pension Benefits Other Benefits
(In millions)2013 2012 2013 2012
Service cost$42
 $37
 $3
 $3
Interest cost47
 48
 9
 11
Expected return on plan assets(50) (46) —
 —
Amortization: 
  
  
  
– prior service cost (credit)5
 6
 (5) (5)
– actuarial loss38
 37
 —
 —
Net settlement loss(a)
32
 34
 —
 —
Net periodic benefit cost$114
 $116
 $7
 $9
(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 and third quarters of 2013 and the third quarter of 2012.
During the second and third quarters of 2013 and the third quarter of 2012, we recorded the effects of partial settlements of our U.S. pension plans. Weplans and we remeasured the plans' assets and liabilities as of the applicable balance sheet dates. As a result, we recognized decreases of $24 million and $163 million in actuarial losses in other comprehensive income for the three months and nine months ended September 30, 20122013, and as a result, recognized settlement expense along with an increase of $103$103 million in actuarial losses, net of settlement expenses. The net increase in actuarial losses is reported in other comprehensive income.loss, for the three months and nine months ended September 30, 2012.
During the first nine months of 20122013, we made contributions of $16250 million to our funded pension plans.  We expect to make additional contributions up to an estimated $217 million to our funded pension plans over the remainder of 2012.2013.  Current benefit payments related to unfunded pension and other postretirement benefit plans were $719 million and $12 million during the first nine months of 20122013.
10.9.   Income Taxes
The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments. The difference between the total provision and the sum of the amounts allocated to segments and to individual items not allocated to segments is reported in “Corporate and other unallocated items” in Note 8.7.
Our effective income tax raterates in the first nine months of 20122013 wasand 2012 were 68 percent and 72 percent.   This rate isThese rates are higher than the U.S. statutory rate of 35 percent primarily due to earnings from foreign jurisdictions, primarily Norway and Libya, where the tax rates are in excess of the U.S. statutory rate.  An increase in earnings and associated taxes from foreign jurisdictions, primarily Norway, as compared to prior periods caused an increase in our valuation allowance on current year foreign tax credits.  In Libya, where the statutory tax rate is in excess of 90 percent, limited production resumedsales decreased in the fourththird quarter of 20112013 due to labor strikes at the Es Sider oil terminal and liquid hydrocarbonthere remains uncertainty around future production and sales resumed in the first quarterlevels. Reliable estimates of 2012.  A reliable estimate of2013 and 2012 annual ordinary income from our Libyan operations cannotcould 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 nine 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 be60 percent and 64 percent for the first nine months of 2012.
Our effective tax rate in the first nine2013 months of 2011 was 64 percent which is higher thanand 2012. In the U.S. statutory tax rate of 35 percent primarily due to earnings from foreign jurisdictions where the tax rates are in excess of the U.S. statutory rate and the valuation allowance recorded against 2011 foreign tax credits.  In addition, in the secondthird quarter of 2011,2013, we recorded a deferrednet favorable tax chargeadjustment of $42 million, largely related to an internal restructuringgreater expected utilization of our international subsidiaries.foreign tax credits in future periods than previously estimated.
The following table summarizes10.   Inventories
 Inventories are carried at the activity in unrecognized tax benefits:lower of cost or market value.
 Nine Months Ended September 30,
(In millions)2012 2011
Beginning balance$157
 $103
Additions based on tax positions related to the current year2
 3
Reductions based on tax positions related to the current year(1) (3)
Additions for tax positions of prior years97
 71
Reductions for tax positions of prior years(66) (24)
Settlements(12) (9)
Ending balance$177
 $141
 If the unrecognized tax benefits as of September 30, 2012 were recognized, $114 million would affect our effective income tax rate.  There were $143 million of uncertain tax positions as of September 30, 2012 for which it is reasonably possible that the amount of unrecognized tax benefits would decrease during the next twelve months.
 September 30, December 31,
(In millions)2013 2012
Liquid hydrocarbons, natural gas and bitumen$46
 $73
Supplies and other items314
 288
Inventories, at cost$360
 $361

13

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


11.  Inventories
 Inventories are carried at the lower of cost or market value.
 September 30, December 31,
(In millions)2012 2011
Liquid hydrocarbons, natural gas and bitumen$72
 $147
Supplies and sundry items252
 214
Total inventories, at cost$324
 $361
12.  Property, Plant and Equipment
 September 30, December 31,
(In millions)2012 2011
E&P   
United States$22,167
 $19,679
International13,185
 12,579
Total E&P35,352
 32,258
OSM10,070
 9,936
IG38
 37
Corporate424
 341
Total property, plant and equipment45,884
 42,572
Less accumulated depreciation, depletion and amortization(18,438) (17,248)
Net property, plant and equipment$27,446
 $25,324
 September 30, December 31,
(In millions)2013 2012
North America E&P$25,858
 $23,748
International E&P12,342
 13,214
Oil Sands Mining10,337
 10,127
Corporate456
 449
Total property, plant and equipment48,993
 47,538
Less accumulated depreciation, depletion and amortization(21,171) (19,266)
Net property, plant and equipment$27,822
 $28,272
InDuring the third quarter of 2013, our Libya production operations were impacted due to labor strikes at the Es Sider oil terminal. We had three oil liftings from Libya in July 2013, but no oil liftings in August or September. Uncertainty around sustained production and sales levels from Libya have existed since the first quarter of 2011 when production operations in Libya were suspended. Insuspended until limited production resumed in the fourth quarter of 2011, limited production resumed.  Since that time, average net liquid hydrocarbon sales volumes have increased to 49 thousand barrels per day (“mbbld”) in the third quarter of 2012 and 37 mbbld in the first nine months of 2012.same year.  We and our partners in the Waha concessions continue to assess the situation and the condition of our assets in Libya. As of September 30, 2013, our net property, plant and equipment investment in Libya and uncertainty around sustained production and sales levels remains.was approximately $743 million.
Exploratory well costs capitalized greater than one year after completion of drilling (“suspended”) were $207220 million as of September 30, 20122013.  The net decrease in such costsof $9 million from December 31, 20112012 primarily related to changesthe conveyance of our interests in three areas.  Norway explorationthe Marcellus natural gas shale play to the operator in February 2013.
Included in the total costs of $55 million incurred between 2009 and 2011 have been suspended for greater than one year pending commencement of the Boyla development which was submittedare $127 million related to the Norwegian government for approval in JuneAngola Block 31 and approved in October 2012.  Drilling on the Shenandoah prospect in the Gulf of Mexico resumed in June 2012.  Costs of $3822 million related to ShenandoahEquatorial Guinea. The Angola Block 31 costs are no longer suspended. included in the other noncurrent assets held for sale reported in Note 5. We intend to develop Block D offshore Equatorial Guinea through a unitization with the Alba field, which is now expected be completed late in 2014.
12. Asset Retirement Obligations
The Innsbruck well was reenteredfollowing summarizes the changes in September 2012; therefore, costsasset retirement obligations during the first nine months of2013:
(In millions) 
Beginning balance(a)
$1,783
Incurred, including acquisitions10
Settled, including dispositions(41)
Accretion expense (included in depreciation, depletion and amortization)103
Revisions to previous estimates306
Held for sale(41)
Ending balance(a)
$2,120
(a) Beginning and ending balances include asset retirement obligations of $6034 million related to the prospect are no longer suspended.and $93 million classified as short-term at December 31, 2012 and September 30,2013.

14

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


13.  Fair Value Measurements
 Fair Values - Recurring
The following table presentstables present assets and liabilities accounted for at fair value on a recurring basis as of September 30, 2013 and December 31, 2012 by fair value hierarchy level.
September 30, 2012September 30, 2013
(In millions)Level 1 Level 2 Level 3 Collateral TotalLevel 1 Level 2 Level 3 Collateral Total
Derivative instruments, assets                  
Commodity$—
 $47
 $—
 $1
 $48
$—
 $5
 $—
 $—
 $5
Interest rate—
 22
 —
 —
 22
—
 11
 —
 —
 11
Foreign currency—
 20
 —
 —
 20
—
 1
 —
 —
 1
Derivative instruments, assets—
 89
 —
 1
 90
$—
 $17
 $—
 $—
 $17
Derivative instruments, liabilities                  
Commodity—
 2
 —
 —
 2
$—
 $14
 $—
 $—
 $14
Foreign currency—
 1
 —
 —
 1
—
 14
 —
 —
 14
Derivative instruments, liabilities$—
 $3
 $—
 $—
 $3
$—
 $28
 $—
 $—
 $28
 December 31, 2012
(In millions)Level 1 Level 2 Level 3 Collateral Total
Derivative instruments, assets         
Commodity$—
 $52
 $—
 $1
 $53
Interest rate—
 21
 —
 —
 21
Foreign currency—
 18
 —
 —
 18
Derivative instruments, assets$—
 $91
 $—
 $1
 $92
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 andor 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 used to estimatethis 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 andor liabilities, and are Level 2 inputs.
As of December 31, 2011, balances related to interest rate swaps accounted for at fair value on a recurring basis were noncurrent assets of $5 million measured at fair value using actionable broker quotes which are Level 2 inputs. There were no other significant recurring fair value measurements as of December 31, 2011.
Fair Values - Nonrecurring
The following tables showtable shows the values of assets, by major class,category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.
Three Months Ended September 30,Three Months Ended September 30,
2012 20112013 2012
(In millions)Fair Value Impairment Fair Value ImpairmentFair Value Impairment Fair Value Impairment
Long-lived assets held for use$2
 $8
 $—
 $—
$5
 $11
 $2
 $8
 Nine Months Ended September 30,
 2012 2011
(In millions)Fair Value Impairment Fair Value Impairment
Long-lived assets held for use$77
 $271
 $226
 $282
Intangible assets$—
 $—
 $—
 $25
Our E&P segment’s Ozona development in the Gulf of Mexico began production in December 2011.  During the first quarter of 2012, production rates declined significantly and have remained below initial expectations.  Accordingly, our reserve engineers performed an evaluation of our future production as well as our reserves which concluded in early April 2012.  This resulted in a
 Nine Months Ended September 30,
 2013 2012
(In millions)Fair Value Impairment Fair Value Impairment
Long-lived assets held for use$5
 $49
 $77
 $271

15

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



2 million barrel of oil equivalent reduction in proved reserves and a $261 million impairment chargeAll long-lived assets held for use that were impaired in the first quarternine months of 2012.2013 and 2012 were held by our North America E&P segment. The fair valuevalues of the Ozona development was determinedeach 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 liquid hydrocarboncommodity prices based on the Louisiana Light Sweet 12-month price range, as we think production will not be significant beyond twelve months, adjusted for quality and location differentials, and forecasted operating expenses for the remaining estimated life of the reservoir.
In May 2011, significant waterthe 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 and reservoir pressure declines occurred at our E&P segment’s Droshkyrates from the Ozona development in the Gulf of Mexico. Consequently, 3.4 million barrelsMexico declined significantly. Accordingly, our reserve engineers prepared evaluations of oil equivalent of provedour future production as well as our reserves were written off and a $273 millionan impairment of this long-lived asset to fair value$261 million was recorded in the secondfirst quarter of 2011.  The2012.  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 $22621 million fair value of the Droshky developmentimpairment was determined using an income approach based upon internal estimates of future production levels, prices and discount rate, all Level 3 inputs.recorded.
In the second quarter of 2011, our outlook for U.S. natural gas prices indicated that it was unlikely that sufficient U.S. demand for LNG would materialize by 2021, which is when our rights lapse under arrangements at the Elba Island, Georgia regasification facility.  Using an income approach based upon internal estimates of natural gas prices and future deliveries, which are Level 3 inputs, we determined that the contract had no remaining fair value and recorded a full impairment of this intangible asset held in our Integrated Gas segment.
Other impairments of long-lived assets held for use by our North America E&P segment in the third quarter and first nine months of 20122013 and 20112012 were a result of reduced drilling expectations, reductionreductions of estimated reserves or declining natural gas prices.  The fair values of those assets were measured using an income approach based upon internal estimates of future production levels, commodity prices and discount rate, which are Level 3 inputs.
Fair Values – ReportedFinancial Instruments
Our current assets and liabilities include financial instruments, the most significant of which are accounts receivables, commercial paper and payables. We believe the carrying values of these accountsour 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.
The following table summarizes financial instruments, excluding trade accounts receivables, andcommercial paper, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at September 30, 20122013 and December 31, 20112012:.
September 30, 2012 December 31, 2011September 30, 2013 December 31, 2012
Fair Carrying Fair CarryingFair Carrying Fair Carrying
(In millions)Value Amount Value AmountValue Amount Value Amount
Financial assets              
Other current assets$135
 $134
 $146
 $148
Other noncurrent assets158
 158
 68
 68
$168
 $165
 $189
 $186
Total financial assets 293
 292
 214
 216
168
 165
 189
 186
Financial liabilities 
  
  
  
 
  
  
  
Other current liabilities13
 13
 —
 —
13
 13
 13
 13
Long-term debt, including current portion(a)
5,639
 4,653
 5,479
 4,753
6,941
 6,461
 7,610
 6,642
Deferred credits and other liabilities100
 101
 36
 38
164
 161
 94
 94
Total financial liabilities $5,752
 $4,767
 $5,515
 $4,791
$7,118
 $6,635
 $7,717
 $6,749
(a)      Excludes capital leases.
Fair values of our remaining financial assets included in other current assets and 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

16

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


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.

16

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


14. Derivatives
For information regarding the fair value measurement of derivative instruments, see Note 13.13. 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 September 30, 2013 and December 31, 2012, there were no offsetting amounts. Positions by contract were all either assets or liabilities. The following table presentstables present the gross fair values of derivativesderivative instruments, excluding cash collateral, and the reported net amounts along with where they appear on the consolidated balance sheets as of September 30, 2013 and December 31, 2012.
September 30, 2012 September 30, 2013 
(In millions)Asset Liability Net Asset Balance Sheet LocationAsset Liability Net Asset Balance Sheet Location
Fair Value Hedges            
Foreign currency$20
 $—
 $20
 Other current assets$1
 $—
 $1
 Other current assets
Interest rate22
 —
 22
 Other noncurrent assets11
 —
 11
 Other noncurrent assets
Total Designated Hedges42
 —
 42
 12
 —
 12
 
            
Not Designated as Hedges            
Commodity30
 —
 30
 Other current assets5
 —
 5
 Other current assets
Commodity20
 —
 20
 Other noncurrent assets
Total Not Designated as Hedges50
 —
 50
 5
 —
 5
 
Total$92
 $—
 $92
 $17
 $—
 $17
 
 
 September 30, 2013  
(In millions)Asset Liability Net Liability Balance Sheet Location
Fair Value Hedges       
     Foreign currency$—
 $14
 $14
 Other current liabilities
Total Designated Hedges—
 14
 14
  
        
Not Designated as Hedges       
     Commodity—
 14
 14
 Other current liabilities
Total Not Designated as Hedges—
 14
 14
  
     Total$—
 $28
 $28
  
September 30, 2012 December 31, 2012 
(In millions)Asset Liability Net Liability Balance Sheet LocationAsset Liability Net Asset Balance Sheet Location
Fair Value Hedges            
Foreign currency$—
 $1
 $1
 Other current liabilities$18
 $—
 $18
 Other current assets
Interest rate21
 —
 21
 Other noncurrent assets
Total Designated Hedges—
 1
 1
 39
 —
 39
 
            
Not Designated as Hedges            
Commodity—
 5
 5
 Other current liabilities52
 —
 52
 Other current assets
Total Not Designated as Hedges—
 5
 5
 52
 —
 52
 
Total$—
 $6
 $6
 $91
 $—
 $91
 

17

As of December 31, 2011, our derivatives outstanding were interest rate swaps that were fair value hedges, which had an asset value of $5 million and are located on the consolidated balance sheet in Other noncurrent assets.MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Derivatives Designated as Fair Value Hedges
AsThe following table presents by maturity date, information about our interest rate swap agreements as of September 30, 2013, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.
Maturity Dates
Aggregate Notional Amount (in millions)
Weighted Average, LIBOR-Based, Floating Rate
October 1, 2017$600
4.67%
March 15, 2018$300
4.51%
As of December 31, 2012, we had multiple interest rate swap agreements with a total notional amount of $600 million at, a weighted average, London Interbank Offer Rate (“LIBOR”)-based,LIBOR-based, floating rate of 4.714.70 percent. and a maturity date of October 1, 2017.
As of September 30, 2013 and December 31, 2012, our foreign currency forwards had an aggregate notional amount of 3,9393,115 million and 3,043 million Norwegian Kroner at a weighted average forward rate of 5.9115.874 and 5.780. These forwards hedge our current Norwegian tax liability and have settlement dates through February 2013.
In connection with the debt retired in February and March 2011 discussed in Note 15, we settled interest rate swaps with a notional amount of $1,450 million2014.

17

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


The pretax effect of derivative instruments designated as hedges of fair value in our consolidated statements of income are summarized in the table below. There is no ineffectiveness related to the fair value hedges.
 Gain (Loss)
 Three Months Ended Nine Months Ended Gain (Loss)
 September 30, September 30, Three Months Ended September 30, Nine Months Ended September 30,
(In millions)Income Statement Location2012 2011 2012 2011Income Statement Location2013 2012 2013 2012
Derivative                
Interest rateNet interest and other$6
 $26
 $17
 $25
Net interest and other$5
 $6
 $(9) $17
Interest rateLoss on early extinguishment of debt—
 —
 —
 29
Foreign currencyProvision for income taxes$22
 $—
 $(18) $—
Provision for income taxes$5
 $22
 $(41) $(18)
Hedged Item  
  
  
  
  
  
  
  
Long-term debtNet interest and other$(6) $(26) $(17) $(25)Net interest and other$(5) $(6) $9
 $(17)
Long-term debtLoss on early extinguishment of debt—
 —
 —
 (29)
Accrued taxesProvision for income taxes$(22) $—
 $18
 $—
Provision for income taxes$(5) $(22) $41
 $18
 Derivatives not Designated as Hedges
In August 2012, we entered into crude oil derivatives related to a portion of our forecast U.S.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.
TermBbls per DayWeighted Average Price per BblBenchmark
Swaps   
October 2012 - December 201320,000$96.29West Texas Intermediate
October 2012 - December 201325,000$109.19Brent
Option Collars   
October 2012 - December 201315,000$90.00 floor / $101.17 ceilingWest Texas Intermediate
October 2012 - December 201315,000$100.00 floor / $116.30 ceilingBrent
Remaining TermBbls per DayWeighted Average Price per BblBenchmark
Swaps   
October 2013 - December 201320,000$96.29West Texas Intermediate
October 2013 - December 201325,000$109.19Brent
Option Collars   
October 2013 - December 201315,000$90.00 floor / $101.17 ceilingWest Texas Intermediate
October 2013 - December 201315,000$100.00 floor / $116.30 ceilingBrent
The following table summarizes the effect of all derivative instruments not designated as hedges in our consolidated statements of income.
  Gain (Loss)
  Three Months Ended Nine Months Ended
  September 30, September 30,
(In millions)Income Statement Location2012 2011 2012 2011
CommoditySales and other operating revenues$45
 $2
 $46
 $3
15.   Debt
 On October 29, 2012, we issued $1 billion aggregate principal amount of senior notes bearing interest at 0.9 percent with a maturity date of November 1, 2015 and $1 billion aggregate principal amount of senior notes bearing interest at 2.8 percent with a maturity date of November 1, 2022. Interest on the senior notes is payable semi-annually beginning May 1, 2013. The proceeds are being used to pay off commercial paper and for general corporate purposes.
At September 30, 2012, we had no borrowings against our revolving credit facility, described below, and $1,839 million in commercial paper outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.
 In April 2012, we terminated our $3.0 billion five-year revolving credit facility and replaced it with a new $2.5 billion unsecured five-year revolving credit facility (the “Credit Facility”).  The Credit Facility matures in April 2017 but allows us to request two one-year extensions.   It contains an option to increase the commitment amount by up to an additional $1.0 billion, subject to the consent of any increasing lenders, and includes sub-facilities for swing-line loans and letters of credit up to an aggregate amount of $100 million and $500 million, respectively.  Fees on the unused commitment of each lender range from 10 basis points to 25 basis points depending on our credit ratings.  Borrowings under the Credit Facility bear interest, at our option,
  Gain (Loss)
  Three Months Ended September 30, Nine Months Ended September 30,
(In millions)Income Statement Location2013 2012 2013 2012
CommoditySales and other operating revenues, including related party$(86) $45
 $(73) $46

18

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


at either (a) an adjusted LIBOR rate plus a margin ranging from 87.5 basis points to 162.5 basis points per year depending on our credit ratings or (b) the Base Rate plus a margin ranging from 0.0 basis points to 62.5 basis points depending on our credit ratings.  Base Rate is defined as a per annum rate equal to the greatest of (a) the prime rate, (b) the federal funds rate plus one-half of one percent and (c) LIBOR for a one-month interest period plus 1 percent.
 The agreement contains a covenant that requires our ratio of total debt to total capitalization not to exceed 65 percent as of the last day of each fiscal quarter.  If an event of default occurs, the lenders may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility.
In the second quarter of 2012, we retired the remaining $23 million principal amount of our 5.375 percent revenue bonds due December 2013.  No gain or loss was recorded on this early extinguishment of debt.  During the first quarter of 2012, $53 million principal amount of debt carrying a 9.375 percent interest rate was repaid at maturity.
During the first quarter of 2011, we retired $2,498 million aggregate principal amount of debt at a weighted average price equal to 112 percent of face value. A $279 million loss on early extinguishment of debt was recognized in the first quarter of 2011.  The loss includes related deferred financing and premium costs partially offset by the gain on settled interest rate swaps.
16.15.    Incentive Based Compensation
 Stock Optionoption and Restricted Stock Awardsrestricted stock awards
  The following table presents a summary of stock option award and restricted stock award activity for the first nine months of 20122013: 
 Stock Options Restricted Stock
 
Number of
Shares
 
Weighted
Average
Exercise Price
 Awards 
Weighted
Average Grant
Date Fair Value
Outstanding at December 31, 201121,370,715
 
$24.41
 3,703,978
 
$25.88
Granted1,858,872
(a) 

$33.52
 2,169,744
 
$31.61
Options Exercised/Stock Vested(1,256,318)

$18.25
 (1,142,195) 
$25.18
Cancelled(509,748)

$28.29
 (287,278) 
$27.96
Outstanding at September 30, 201221,463,521
 
$25.47
 4,444,249
 
$28.72
 Stock Options Restricted Stock
 
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
Granted1,704,734
(a) 

$33.30
 1,254,935
 
$32.96
Options Exercised/Stock Vested(2,098,887) 
$22.31
 (1,609,730) 
$28.09
Canceled(708,701) 
$34.01
 (384,719) 
$29.91
Outstanding at September 30, 201318,434,111
 
$26.99
 3,438,370
 
$30.80
(a)    The weighted average grant date fair value of stock option awards granted was $9.9410.51 per share.
Performance Unit Awardsunit awards
 DuringIn the first quarter of 2012,2013, we granted 13 million353,600 performance units to executive officers.  These units havecertain officers that provide a cash payout upon the achievement of certain performance goals at the end of a 36-month performance period.  The performance goals are tied to our total shareholder return (“TSR”) as compared to TSR for a group of peer companies determined by the Compensation Committee of the Board of Directors.   At the grant date, each unit represents the value of one share of our common stock, while payout after completion of the performance period will be based on the value of anywhere from zero to two times the number of units granted. Dividend equivalents accrue during the performance period and are paid in cash at the end of the performance period based on the number of shares that would represent the value of the units.  The fair value of these performance units is re-measured on a quarterly basis using the Monte Carlo simulation method.  These performance units are accounted for as liability awards because they are to be settled in cash at the end of the performance period and their fair value is expensed over the performance period.
16.  Reclassifications Out of Accumulated Other Comprehensive Loss
The following table presents a summary of amounts reclassified from accumulated other comprehensive loss to net income in their entirety:
 Three Months Ended September 30, 2013Nine Months Ended September 30, 2013  
(In millions) Income Statement Line
Accumulated Other Comprehensive Loss Components  
 Income (Expense)  
Postretirement and postemployment plans   
Amortization of actuarial loss$(9)$(38) General and administrative
Net settlement loss(15)(32) General and administrative
 9
26
 Provision for income taxes
 (15)(44) Net of tax
Other insignificant items, net of tax—
(1)  
Total reclassifications for the period$(15)$(45) Net income
17.  Supplemental Cash Flow InformationStockholders' Equity
 Nine Months Ended September 30,
(In millions)2012 2011
Net cash provided from operating activities:   
Interest paid (net of amounts capitalized)$164
 $197
Income taxes paid to taxing authorities3,457
 2,183
Commercial paper, net: 
  
Commercial paper - issuances$10,420
 $—
- repayments(8,581) —
Noncash investing activities: 
  
Debt payments made by United States Steel$19
 $18
Liabilities assumed in acquisition85
 —
Change in capital expenditure accrual170
 (61)

In the third quarter of 2013, we acquired 14 million common shares at a cost of $500 million under our $5 billion authorized share repurchase program.

19

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


18.  Supplemental Cash Flow Information
 Nine Months Ended September 30,
(In millions)2013 2012
Net cash provided from operating activities:   
Interest paid (net of amounts capitalized)$216
 $164
Income taxes paid to taxing authorities3,218
 3,457
Commercial paper, net: 
  
Commercial paper - issuances$4,975
 $10,420
- repayments(4,975) (8,581)
Noncash investing activities: 
  
Asset retirement costs capitalized$316
 $47
Debt payments made by United States Steel—
 19
Liabilities assumed in acquisition—
 85
Change in capital expenditure accrual(129) 170
Asset retirement obligations assumed by buyer92
 7
19.   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 is seekingalleging, 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 unspecified amount for damages.  We are vigorously defendingoffshore daywork drilling contract. The parties have reached a tentative settlement of this litigation. The ultimate outcomeWe believe that the settlement of this lawsuit, including any financiallitigation will not have a material adverse effect on us, remains uncertain.  We do not believe an estimateour consolidated results of a reasonably probable loss (or range of loss) can be made for this lawsuit at this time.
Guarantees– After our 2009 sale of the subsidiary holding our interest in the Corrib natural gas development offshore Ireland, one guarantee of that entity's performance related to asset retirement obligations remains issued to certain Irish government entities until the Irish government and the current Corrib partners agree to release our guarantee and accept the purchaser's guarantee to replace it. The maximum potential undiscounted payments related to asset retirement obligations under this guarantee as of September 30, 2012 are $40 million.operations, financial position or cash flows.
Contractual commitments – At September 30, 2012 and December 31, 20112013, Marathon’s contract commitments to acquire property, plant and equipment were $974 million and $6641,154 million.

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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 prior-year periods presented have been recast to reflect these new segments.
We are an international energy company with operations in the U.S.,United States, Canada, Africa, the Middle East and Europe.  Our operations are organized intoWe have three reportable segments: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”&P") which– explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis.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 (“OSM”) which– mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
Integrated Gas (“IG”) which produces and markets products manufactured from natural gas, such as liquefied natural gas (“LNG”) and methanol, in Equatorial Guinea.
 Certain sections of this Quarterly Report on Form 10-Q, including Management’s Discussion and Analysis of Financial Condition and Results of Operations includecontain 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 20112012 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 third quarter of 2012,2013, notable items were:
Net liquid hydrocarbon and natural gas sales volumes of 452 thousand barrels of oil equivalent per day (“mboed”), of which 65 percent was liquid hydrocarbons
Net internationalNorth America E&P net liquid hydrocarbon sales volumes for which average realizations have exceeded West Texas Intermediate (“WTI”) crude oil, were 62increased 35 percent of total liquid hydrocarbon sales
Eagle Ford shale average net sales volumes of 40 mboed, an increase of 90 percent from the second quarter of 2012
Production from Libya increased over the second quarter of 2012, with average net sales of 53 mboed
Bakken shale average net sales volumes of 30 mboed, a 87 percent increase over the same quarter of last year
Closed the acquisitionEagle Ford shale averaged net liquid hydrocarbon sales of Paloma Partners II, LLC66 thousand barrels per day ("mbbld"), a 100 percent increase
Assumed operatorshipBakken shale averaged net liquid hydrocarbon sales of the Vilje field offshore Norway36 mbbld, a 24 percent increase
Some significant fourth quarter activities through November 7, 2012 include:
Closed acquisitionAcquisition of an additional 4,3004,800 net acres in the core of the Eagle Ford shale in a transaction valued at $97 million including a carried interest
Signed agreement for a 20 percent non-operatedLabor strikes at Es Sider oil terminal in Libya since late July with no oil liftings in August or September
Norway turnaround completed in nine days, on time and on budget
Madagascar operated exploration well began drilling in deepwater Gulf of Mexico on De Soto Canyon Block 757
Agreement in principle reached to sell our working interest in Angola Block 32 with an anticipated transaction value of $590 million, excluding purchase price adjustments
First deepwater Gabon pre-salt discovery with the South Omo concession onshore Ethiopianon-operated Diaman-1B exploration well
Reentered GabonDividend increased by acquiring12 percent to 19 cents per share
14 million common shares repurchased for $500 million at an interest in an exploration licenseaverage price of $35.53 per share
Acquired interests in two onshore exploration blocks in KenyaSome significant fourth quarter activities to November 6, 2013 include:
Farmed out 35 percent working interestsAnnounced receipt of approval from the Kurdistan Regional Government for the first phase in the Harir and Safen blocksoil development of the Atrush Block in the Kurdistan Region of Iraq
Issued $2 billionAnnounced Mirawa-1 oil and natural gas discovery on our operated Harir block in the Kurdistan Region of senior notesIraq
High bidder as operator on two deepwater blocks in the pre-salt play offshore Gabon: G13 and E12, which is subject to government approvals and negotiation of the exploration and production sharing contracts


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Overview and Outlook
Exploration and ProductionNorth America E&P
Production
 Net liquid hydrocarbon and natural gas sales volumes averaged 452 mboed during200 thousand barrels of oil equivalent per day ("mboed") in both the third quarter and 414 mboed in the first nine months of20122013 compared to 349172 mboed and 362155 mboed in the same periodsthird quarter and first nine months of 2011.2012, for increases of approximately 16 percent and 29 percent, respectively.  Net liquid hydrocarbon sales volumes increased in the U.S.increased for both the third quarter and first nine months of20122013, primarily reflecting the impact of production from the Eagle Ford shale assets acquired in the fourth quarter of 2011 and our ongoing development programs in the Eagle Ford Bakken and Anadarko WoodfordBakken shale resource plays. The resumptionplays, while net natural gas sales volumes decreased 19 percent and 7 percent during the same periods, primarily due to the sale of our Alaska assets in January 2013. Excluding the sales from Libyavolumes related to Alaska in both nine-month periods, our average net natural gas sales volumes increased 21 percent primarily due to the previously mentioned development programs.
Eagle Ford – In 2013, production growth continued in the first quarter of 2012 after production had ceased there in February of 2011 was the most significant increase in international sales volumes. In addition,Eagle Ford shale play. Average net liquid hydrocarbon sales volumes from the U.K. were lower81 mboed and 78 mboed in the 2012 periods thanthird quarter and first nine months of2013 compared to 40 mboed and 25 mboed in the same periods of 2011 due2012. Approximately 63 percent of the first nine months of 2013 production was crude oil and condensate, 17 percent was natural gas liquids ("NGLs") and 20 percent was natural gas. In the third quarter of 2013, the amount of crude oil and condensate transported by pipeline was approximately 70 percent. The ability to turnaroundstransport more barrels by pipeline enables us to reduce costs, improve reliability and lessen our environmental footprint.
During the third quarter of 2013, we reached total depth on 70 gross operated wells and brought 71 gross operated wells to sales, with 228 gross operated wells reaching total depth and 219 gross operated wells brought on line in the first nine months of 2013. With approximately 97 percent pad drilling in the third quarter of 2013, which continues to improve efficiencies and reduce costs, our third quarter average spud-to-total depth time was 12 days, compared to 15 days spud-to-total depth in the timingsame period of liftings.2012.
In 2012, we continued to ramp up operations in the core of the Eagle Ford shale play in Texas. Average net sales volumes from the Eagle Ford shale were 40 mboed and 25 mboed in the third quarter and first nine months of 2012. As announced in August, we have reduced our rig count to 18 operated rigs while maintaining four dedicated hydraulic fracturing crews and two more on a spot basis.  During the third quarter of 2012, we drilled 78 gross wells and brought 73 gross wells to sales for a total of 180 gross wells drilled in the first nine months of 2012. Our average time to drill a well in the Eagle Ford shale has decreased to approximately 24 days; therefore, we now expect to drill 250 to 260 gross Eagle Ford wells during 2012, an increase of approximately 20 wells from previous estimates. In addition to the improvements in the speed and efficiency in drilling and completions, we continue to optimize well spacing which could significantly increase drillable locations and recoverable resources. We have been performing spacing pilot programs in the Eagle Ford shale which will complete early in 2013 so that we will have applicable technical results by mid-year. To complement drilling and completion activity in the Eagle Ford shale, we continue to build infrastructure to support production growth across the operating area. We are now able to transport approximately 60 percent of our Eagle Ford production by pipeline.operating area, approximately 192 miles of gathering lines were installed in the first nine months of 2013, for a total of over 670 miles. We now have 24 central gathering and treating facilities, with one more to be completed in 2013.
We continue to evaluate the potential of downspacing to 40-acre and 60-acre units, with the results of the downspacing pilots expected to be released in December 2013. We also continue to evaluate the Austin Chalk and Pearsall formations across our acreage position. To date, we have completed four Austin Chalk wells. Early Austin Chalk production results suggest that the mix of crude oil and condensate, NGLs and natural gas is similar to Eagle Ford condensate wells. Also in the second quarter of 2013, one Pearsall well was completed.
Bakken – Average net sales volumes from the Bakken shale were 30 mboed and 2738 mboed in both the third quarter and first nine months of months of 20122013 compared to 1730 mboed and 1527 mboed in the same periods of 2011.2012. Our Bakken shale liquid hydrocarbon volumes averagedproduction averages approximately 90 percent crude oil, 54 percent NGLs and 6 percent natural gas liquids and 5 percent natural gas in the first nine months of 2012.gas. During the third quarter and first nine months of 20122013, we drilled 25reached total depth on 21 gross operated wells and 72brought the same number to sales. During the first nine months of 2013, we reached total depth on 61 gross operated wells with seven rigs, withand brought 56 gross operated wells to sales. Our third quarter average time to drill a total of 30 gross and 77 gross wells broughtwell continued to salesimprove, averaging 14 days spud-to-total depth, compared to 18 days spud-to-total depth in the third quarter and the first nine monthssame period of 2012.  By the end of October 2012, we had reduced our operated rig count in the Bakken shale to five. We continue to focus on downspacing and development in the Three Forks area.2012.
 InOklahoma Resource Basins – Net sales volumes from the Anadarko Woodford shale net sales volumes averaged 15 mboed in the third quarter and 13 mboed in the first nine months of 2013 compared to 10 mboed and 7 mboed during the third7 quarter and first nine months of 2012 compared to 2 mboed and 2 mboed in the same periods of 2011.2012.  During the third quarter of 20122013, eightwe reached total depth on three gross operated wells and two gross operated wells were brought to sales, with 14 gross wells brought to sales in the first nine months of 2012. As announced in August, in response to the continued decline in natural gas liquids prices and low natural gas prices, we have reduced our rig count in the Anadarko Woodford play from six to two.  Other areas of potential growth exist in Oklahoma and we are currently evaluating opportunities on legacy assets where the acreage is held by production. Future activity in these Oklahoma resource basins will be dependent upon the recovery of natural gas and natural gas liquids prices.
 In the first quarter 2011, production operations in Libya were suspended. In the fourth quarter of 2011, limited production resumed and has increased during 2012 so thatwhile during the third quarter and first nine months of 2012, net sales volumes averaged 53 mboed2013 we reached total depth on eight gross operated wells and 51 mboed.brought nine gross operated wells to sales. We and our partnersspud two wells in the Waha concessions continueMississippi Lime formation in central Oklahoma during October 2013 and expect to assess the condition of our assets in Libya and uncertainty around sustained production and sales levels remains.
 In June 2012, we submitted a plan for the development and operation of the Boyla field (PL 340)spud wells in the North Sea to the Norwegian MinistryGranite Wash around year end.
Exploration
Gulf of Petroleum and Energy, which was approved in October 2012. The Boyla field is located approximately 17 miles south ofMexico – In September 2013, we began drilling our operated Alvheim field.exploration well on the Madagascar prospect located on De Soto Canyon Block 757. We hold a 65 percenthave reduced our working interest in the field.  First productionMadagascar prospect from Boyla is expected100 percent to 40 percent as a result of two farm-outs. We expect the well to reach total depth late in the fourth quarter of 2014.  2013.
InWe participated in an appraisal well on the second quarter of 2012, we completed a four-day turnaround in Norway that was originally scheduled for 14 days in the third quarter.  During the third quarter of 2012, we became operator of the Vilje field offshore NorwayGunflint prospect located on Mississippi Canyon Block 992 in which we ownhold 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 47 percent interest.
 A 28-day turnaround began at our production operations in Equatorial Guinea on March 23, 2012.  It was completed in April 2012, seven days ahead of schedule and below budget.
Our Ozona developmentpreviously untested Lower Miocene interval. Commercial hydrocarbons were not encountered in the Gulfdeeper exploration objective. Additional exploration potential remains in an adjacent structure to the north, which is a candidate for future exploration following development of Mexico began production in December 2011.  During the first quarter of 2012, production rates declined significantly and have remained below initial expectations.  Accordingly, our reserve engineers performedconfirmed resources.

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an evaluation of our future production as well as our reserves which concluded in early April 2012.  This resulted in a 2 million barrels of oil equivalent reduction in proved reserves and a $261 million impairment charge in theThe first quarter of 2012.
Exploration
The appraisal well on the Shenandoah prospect located on Walker Ridge Block 51, in the Gulf of Mexico, in which we have a 10 percent outside-operatednon-operated working interest, reached total depth in the first quarter of 2013. This appraisal well successfully encountered more than 1,000 net feet of oil pay in multiple high-quality Lower Tertiary-aged reservoirs. Additional appraisal drilling is currently drilling.  anticipated to begin in 2014.
In the second quarter of 2013, at a total cost of $33 million, we were awarded 100 percent working interest leases in two Gulf of Mexico blocks: Keathley Canyon Block 340 on the Colonial prospect and Keathley Canyon Block 153, an extension to the Meteor prospect on our existing Keathley Canyon Block 196 lease. Keathley Canyon Blocks 340 and 153 are both inboard-Paleogene prospects.
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 mbbld steam assisted gravity drainage ("SAGD") demonstration project. We are expecting to receive regulatory approval for this project in mid-2014.  Upon receiving this approval, we will further evaluate our development plans.
International E&P
Production
Net liquid hydrocarbon and natural gas sales volumes averaged 231 mboed and 255 mboed during the third quarter and first nine months of2013 compared to 280 mboed and 259 mboed in the same periods of 2012, which is 18 percent lower for the quarter and an slight decrease for the nine-month period.   We had three oil liftings in Libya during July 2013 but no oil liftings in August or September due to labor strikes at the Es Sider oil terminal, for average net liquid hydrocarbon sales volumes of 16 mbbld in the third quarter of 2012, we resumed drilling2013 compared to 49 mbbld in the exploration wellsame quarter of 2012. Both the third quarter and first nine months of2013 include net liquid hydrocarbon sales volumes of 9 mbbld from the PSVM development located on the Gulfnortheastern portion of Mexico Innsbruck prospect on Mississippi CanyonAngola Block 99331 which had first sales in which weFebruary 2013.
 Equatorial Guinea – Average net sales volumes were 109 mboed and 105 mboed in the third quarter and first nine months of 2013 compared to 116 mboed and 106 mboed in the same periods of 2012. Third quarter 2012 sales volumes were higher than normal due to the timing of liquid hydrocarbon liftings. 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 recovered in the third quarter.
Norway – Average net sales volumes from Norway were 68 mboed and 81 mboed in the third quarter and first nine months of2013 compared to 89 mboed and 91 mboed in the same periods of 2012. A planned nine-day turnaround in Norway resulted in lower production and sales volumes during the third quarter of 2013, with rates returning to normal levels within the latter half of the quarter. Production declines, while present, continue to be less than expected as a result of strong operational performance (with unplanned downtime at less than 2 percent for the first nine months of 2013), production optimization efforts, recent infill well performance at the upper end of expectations, as well as a delay in anticipated water breakthrough at the Volund field.
United Kingdom – Average net sales volumes were 24 mboed in the third quarter and first nine months of2013 compared to 22 mboed and 23 mboed in the same periods of 2012. Production at the non-operated Foinaven field was shut-in in mid-July 2013 due to compression and subsea equipment issues and resumed at partial rates in late August. Maintenance activities as well as planned pipeline curtailments also impacted production at the operated, North Sea Brae fields during the third quarter of 2013. Sales volumes for prior-year periods were also impacted by both planned and unplanned maintenance activities as well as the timing of liquid hydrocarbon liftings.
Exploration
Kurdistan Region of Iraq – We hold a 45 percent operated working interest.  Through September 30, 2012, our net costs related to the well were $71 million. The well has drilled through multiple horizons with no commercial hydrocarbons found as of November 6, 2012. We anticipate reaching total depth within the next few days at a total net cost, including asset retirement obligations and leasehold costs, of approximately $100 million.
In the second quarter of 2012, a Gunflint prospect appraisal well confirmed expected reservoir properties and continuity, establishing the commercial viability of the field.  The Gunflint discovery is located on Mississippi Canyon Block 948 and we have a 15 percent outside-operated working interest in the prospect.  DuringHarir block. In October 2013, we announced the second quarter of 2012, the well costs and related unproved property costs related to the Kilchurn well were charged to exploration expenses.
 We continue exploratory drilling in Poland where we hold a 51 percent working interest in 10 operated concessions and a 100 percent working interest in one concession. We have drilled 4 exploratory wells and are currently drilling a fifth well.  We have collected extensive data, including well logs and core samples, which are being evaluated. We plan to begin a sixth well by year end 2012 which should reach total depth in 2013.  
In the Kurdistan Region of Iraq, we began drilling our first operated exploration wellMirawa-1 discovery on the Harir blockblock. The Mirawa-1 was drilled to a total depth of 14,000 feet and encountered multiple stacked oil and natural gas producing zones with equipment constrained test flow rates of more than 11 mbbld of oil, 72 million cubic feet per day ("mmcfd") of non-associated natural gas and 1,700 barrels per day of condensate. We have suspended the well for potential future use as a producing well, and moved the drilling rig to the Jisik-1 prospect located nine miles to the northwest to test a similar structure on the Harir Block.
Following evaluation of the Safen-1 dry well in July 2012 and planOctober, we notified the Kurdistan Ministry of Natural Resources that we do not intend to drill an operatedparticipate in any further exploration well on the Safen block inBlock.
Following the first quarter of 2013.   After the farm out discussed below, we have 45 percent working interests in both the Harir and Safen blocks.  Onsuccessful appraisal program on the non-operated Atrush block, we participatedBlock and a declaration of commerciality, a plan for field development was approved by the Kurdistan Ministry of Natural Resources in late September 2013.  The development project will consist of drilling three production wells and constructing a central processing facility. We expect first production by early 2015 with estimated initial gross production of approximately 30 mbbld of oil. The approval of the field development plan for Phase 1 provides for a 25-year production period. Subject to further drilling and testing results, and partner and government approvals, a potential Phase 2 development could add an additional 30 gross mbbld facility. Within the potential Phase 2 development area, the Atrush-3 appraisal well, duringlocated approximately four miles east of existing wells, confirmed the third quarter extension

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of 2012. Additionally, we participated inthe oil bearing reservoir and has been suspended as a non-operated well that commenced drilling on the Sarsang block in September 2012.potential future producer.  We hold a 2015 percent working interest in the Atrush Block.
On the non-operated Sarsang block, of the two exploration wells which began drilling in the second half of 2012, tests have been completed on the Gara well. All zones were water-wet and the well was plugged and abandoned in August 2013. On the Mangesh well, five drill stem tests have been completed and further testing is planned. The East Swara Tika exploration well, which began in July 2013, has been drilled to a depth of 5,300 feet toward a planned total depth of 11,000 feet. This well will test additional resource potential to the northeast of the previously announced Swara Tika discovery. We hold a 25 percent working interest in the Sarsang block.Block.
DuringEthiopia – Drilling on the Tultule prospect, approximately two miles from the Sabisa-1 well on the onshore South Omo block in a frontier rift basin, commenced in September 2013 with a projected total depth of 7,900 feet. The well is expected to reach total depth by the end of the fourth quarter of 2013. The Sabisa-1 exploration well encountered reservoir quality sands, oil and heavy gas shows and a thick shale 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, the well was abandoned before a full evaluation could be completed. We hold a 20 percent non-operated working interest in the South Omo block.
Gabon – The Diaman-1B well in the Diaba License G4-223 offshore Gabon reached total depth in the third quarter of 2013, encountering 160-180 net feet of hydrocarbon pay in the deepwater pre-salt play. Preliminary analysis suggests that the hydrocarbons are natural gas with condensate content, pending results of ongoing analyses of well data. We hold a 21 percent non-operated working interest in the Diaba License.
In late October 2013, we were the high bidder as operator on two deepwater blocks in the pre-salt play. Award of the blocks, G13 and E12, is subject to government approvals and negotiation of the exploration and production sharing contracts.
Norway – The non-operated Sverdrup exploration well on PL 330 offshore Norway that commenced drilling in June 2013 was deemed to be dry. The Darwin (formerly Veslemoy) exploration well was drilled in the first quarter of 2012,2013 on PL 531 in which we hold a 10 percent non-operated fully-carried working interest. Gas shows were recorded in the Birchwood oil sands leasePaleocene objective section, although no hydrocarbons were found in the Cretaceous section and the well has been plugged and abandoned.
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 in the process of relinquishing the concessions.
Kenya – The first exploratory well on Block 9, the Bahasi-1, began drilling in September 2013 and is expected to reach a total depth of 9,800 feet in the fourth quarter of 2013. We hold a 50 percent non-operated working interest in Block 9.
Angola – The Kaombo development, located in Alberta, Canada, we conducted a seismic survey and drilled six water wells.  We also submitted a regulatory application for a proposed 12 thousand barrel per day (“mbbld”) steam assisted gravity drainage ("SAGD") project at Birchwood. Pending regulatory approval, project sanctionthe southeastern portion of Block 32, is expected to be sanctioned late in 2013 or early in 2014. First production from the Kaombo development is expected in 2014, with2017. See discussion of the anticipated disposal of our interest in Block 32 below.
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 49 mbbld and 47 mbbld in the third quarter and first oil projectednine months of2013 compared to 53 mbbld and 47 mbbld in 2017.  We havethe same periods of 2012. For the first nine months of 2013, the impact of strong reliability experienced at both mines and the upgrader during the first and third quarters of 2013, was offset by unplanned mine downtime and a 100planned upgrader turnaround during the second quarter of 2013.
Acquisitions and Dispositions
In September 2013, we announced that we had reached an agreement in principle to sell our non-operated 10 percent working interest in Birchwood.the Production Sharing Contract and Joint Operating Agreement in Angola Block 32. The anticipated transaction has a value of approximately $590 million, excluding closing adjustments. Pending execution of definitive agreements and government approval, the transaction is expected to close in the fourth quarter of 2013.
AcquisitionsIn July 2013, we acquired 4,800 net undeveloped acres in the core of the Eagle Ford shale in a transaction valued at $97 million, including carried interest of $23 million.
In June 2013, we entered into an agreement to sell our non-operated 10 percent working interest in the Production Sharing Contract and DispositionsJoint Operating Agreement in Angola Block 31. This transaction, valued at $1.5 billion before closing adjustments, is expected to close in the fourth quarter of 2013, subject to government and regulatory 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 of 2013.
In February 2013, we conveyed 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.

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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 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 which was collected in July 2013. After closing adjustments made in the second quarter of 2013, the pretax gain on this sale was $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 continually evaluate wayscontinue to progress the sale of assets in an ongoing effort to optimize our portfolio for profitable growth, through acquisitions and dispositions, 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 entered into agreements for approximately $1.1 billion in divestitures, of which more than $700 million have been completed. Included inIncluding the $1.1 billion noted above is the pendinganticipated sale of our Alaska assets which is discussed below.
 On November 1, 2012,interest in Angola Block 32, we closed the acquisition of an additional 4,300 net acres in the core of the Eagle Ford shale at a transaction costhave agreed upon or completed divestitures of approximately $232 million before closing adjustments. This acquisition increased our average working interest by 5 to 7 percent in four core areas of mutual interest, included wells producing 3 net mboed at closing, and added 40 net drilling locations to our inventory. The closing of this transaction combined with$3.5 billion, surpassing the acquisition of Paloma Partners II, LLC ("Paloma acquisition"), brings our acquisitions thus far in 2012 in the core of the play to almost 25,000 additional net acres at an approximate cost of $1 billion. The Paloma acquisition closed in August 2012 as discussed below. We now have approximately 230,000 net acres in the core of the Eagle Ford shale. The unproved property costs related to an additional 100,000 non-core net acres were impaired in the third quarter of 2012 as discussed below in Results of Operations.
In October 2012, we entered into an agreement to acquire a 20 percent non-operated working interest in the South Omo concession onshore Ethiopia with an effective date of August 17, 2012. An exploration well is anticipated to commence drilling in South Omo during the fourth quarter of 2012.  Cash consideration for this transaction will be $40 million, before closing adjustments, with an additional payment of $10 million due upon declaration of a commercial discovery. We expect to close the transaction, subject to necessary Ethiopian government approvals, before the$3 billion upper end of 2012.
We acquired approximately 20,000 net acres in the core of the Eagle Ford shale during the first nine months of 2012. The largest transaction was the acquisition of Paloma Partners II, LLC, which closed August 1, 2012 for cash consideration of $768 million.   In addition to the over 17,100 net acres acquired, at closing 17 gross operated and 9 gross non-operated wells were producing an average of 9 net mboed, of which 70 percent was liquid hydrocarbons. Smaller transactions closed during the second quarter of 2012. See Note 6 to the consolidated financial statements for further details of the Paloma acquisition.
In the third quarter of 2012, we sold approximately 5,800 net undeveloped acres located outside the core of the Eagle Ford shale for proceeds of $9 million, recording a loss of $18 million.

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In July 2012, we entered into an agreement to acquire outside-operated positions in two onshore exploration blocks in northwest Kenya.  Upon closing the $35 million transaction in October 2012, we now hold a 50 percent working interest in Block 9, where an exploration well is currently planned in mid-2013, and a 15 percent working interest in Block 12A.
 Also in July 2012, we agreed to farm out interests in the Harir and Safen blocks in the Kurdistan Region of Iraq.  The transaction closed in October 2012 and we received cash proceeds of $140 million, so that we now have a 45 percent working interest and carry the KRG for an additional 11 percent in each of the two blocks.
In June 2012, we entered an agreement to acquire a 21 percent outside-operated working interest in the Diaba License G4-223 and its related permit onshore Gabon.  The transaction closed in October 2012.  The start of exploration drilling is expected in the first quarter of 2013.
During June 2012, we signed a new production sharing contract with the government of Equatorial Guinea for the exploration of Block A-12 offshore Bioko Island, located immediately west of our operated Alba Field. We have an 80 percent operated working interest in this block. The contract was ratified by the government in the third quarter of 2012. We also acquired an additional interest in Block D, bringing our working interest to 80 percent.
In May 2012, we executed agreements to relinquish our E&P segment’s operatorship of and participating interests in the Bone Bay and Kumawa exploration licenses in Indonesia.  As a result, we accrued and reported a $36 million loss on disposal of assets in the second quarter of 2012.  Government ratification of the agreements was received during the third quarter of 2012, which released us from our obligations and further commitments related to these licenses, and we paid the amount accrued. 
In April 2012, we entered agreements to sell our Alaska assets.  One transaction closed in the second quarter of 2012 with proceeds and a net gain of $7 million.  The remaining transaction, with a value of $375 million before closing adjustments, is currently under review by the Federal Trade Commission and the Alaska Attorney General's office, which could impact the closing of this transaction.
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 includes 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.three-year target.
The above discussions include forward-looking statements with respect to the expected productionexpectations to spud wells in the Eagle Ford, Anadarko Woodford and Bakken plays, timing of first production from the Boyla field, anticipated drilling rig andGranite Wash, exploration drilling activity the sale of our Alaska assets, possible increased recoverable resources from optimized well spacing in the Eagle Ford resource play, the expected closingGulf of an agreement inMexico, Ethiopia, anticipated exploration activity in Ethiopia, Gabon, Poland and the Kurdistan Region of Iraq and Kenya, the timing of the commencement of constructionsanction and first oilproduction from the Kaombo development in Angola, the timing of first production for the Atrush Block, a potential Phase 2 development on the SAGD project. TheAtrush Block and other potential development projects, plans to exit Poland, the award of two blocks in Gabon, the timing of closing the sale of our 10 percent working interest in Block 31 offshore Angola, the anticipated sale of our 10 percent working interest in Block 32 offshore Angola, and the projected asset dispositions through 2013 are based on current expectations, estimates, and projections and are2013. The average times to drill a well may not guaranteesbe indicative of future performance.drilling times. The current production rates may not be indicative of future production rates. Factors that could potentially affect the expected productionwells to be spud in the Eagle Ford, Anadarko Woodford and Bakken plays, timing of first production from the Boyla field, exploratoryGranite Wash, exploration drilling activity in the Gulf of Mexico, Ethiopia, Gabon, Poland and the Kurdistan Region of Iraq possible increased recoverable resourcesand Kenya, the timing of sanction and first production from optimized well spacingthe Kaombo development in Angola, the Eagle Ford resource playtiming of first production for the Atrush Block, and anticipated drilling riga potential Phase 2 development on the Atrush Block and drilling activityother potential development projects 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, 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 completionaward of two blocks in Gabon is subject to government approvals and negotiation of the Exploration and Production Sharing Contracts. The timing of closing the sale of our Alaska assetsworking interest in Block 31offshore Angola is subject to the satisfaction of customary closing conditions and obtaining necessary government and regulatory approvals and customary closing conditions.approvals. The agreementanticipated sale of our working interest in EthiopiaAngola Block 32 is subject to the execution of definitive agreements and obtaining government approvals.approval. The expected timing and rate of commencementproduction for the Atrush Block, the potential development of construction and first oil onPhase 2 of the SAGD project can be affected by delays in obtaining and conditions imposed by necessary government and third-party approvals, board approval, transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions,Atrush Block, plans to exit Poland and the other risks associated with construction projects. Actual results may differ materially from theseprojected asset dispositions through 2013 are based on current expectations, estimates, and projections and are subject to certain risks, uncertainties and other factors, somenot guarantees of which are beyond the 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.
Oil Sands Mining
 Our OSM operations consist of a 20 percent non-operated working interest in the Athabasca Oil Sands Project (“AOSP”).  As announced in October 2012, we have engaged in discussions with respect to a potential sale of a portion of our 20 percent interest. Given the uncertainty of such a transaction, potential proceeds have not been included in our previously stated goal of divesting between $1.5 billion and $3 billion between 2011 and 2013.
Our net synthetic crude oil sales were 53 mbbld and 47 mbbld in the third quarter and first nine months of 2012 compared to 50 mbbld and 43 mbbld in the same periods of 2011.  The upgrader expansion was completed and commenced operations in the third quarter of 2011 and subsequent periods’ sales volumes have increased as a result. With production capacity at the AOSP

24


now at 255,000 gross barrels per day, the focus will be on improving operating efficiencies and adding capacity through debottlenecking.
The Energy and Resources Conservation Board, Alberta’s primary energy regulator, conditionally approved the AOSP’s Quest Carbon Capture and Storage (“Quest CCS”) project in July 2012. The AOSP partners approved Quest CCS in the third quarter of 2012.
 The above discussion contains forward-looking statements with regard to discussions with respect to a potential sale of a portion of our 20 percent interest in the AOSP. The potential sale of a portion of our interest in the AOSP is subject to successful negotiations and execution of definitive agreements.future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and difficult to predict. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Integrated Gas
25
 LNG and methanol sales from Equatorial Guinea are conducted through equity method investees that purchase dry gas from our E&P assets in Equatorial Guinea.  Our share of LNG sales totaled 7,065 metric tonnes per day (“mtd”) for the third quarter and 6,277 mtd for the first nine months of 2012 compared to 6,935 mtd and 7,121 mtd in the same periods of 2011.  For the first nine months, LNG sales volumes are below the prior year due to a turnaround in the second quarter of 2012 at the facility in Equatorial Guinea, but primarily because the first nine months of 2011 also included LNG sales from Alaska, which ceased when our interest in that production facility was sold in the third quarter of 2011.  


Market Conditions
Exploration and Production
 Prevailing prices for the various qualities of crude oil and natural gas that we produce significantly impact our revenues and cash flows.  PricesWorldwide 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 third quarter and first nine months ofnine2013 months ofand 2012 compared to the same periods in 2011.
 Three Months Ended September 30, Nine Months Ended September 30,
Benchmark2012 2011 2012 2011
WTI crude oil (Dollars per barrel)
$92.20 $89.54 $96.16 $95.47
Brent (Europe) crude oil (Dollars per barrel)
$109.61 $113.46 $112.17 $111.93
Henry Hub natural gas  (Dollars per million
       
British thermal units  ("mmbtu"))(a)  
$2.81 $4.19 $2.59 $4.16
 Three Months Ended September 30,Nine Months Ended September 30,
Benchmark2013201220132012
West Texas Intermediate ("WTI") crude oil (Dollars per barrel)

$105.81

$92.20
$98.20$96.16
Brent (Europe) crude oil (Dollars per barrel)

$110.27

$109.61
$108.45$112.17
Henry Hub natural gas (Dollars per million British thermal units  ("mmbtu"))(a)  

$3.58

$2.81
$3.65$2.59
(a) 
Settlement date average.
North America E&P
AverageLiquid hydrocarbons – The quality, location and composition of our liquid hydrocarbon production mix can 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 benchmark prices increased 3 percent inso 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 oil 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 third quarter and first nine months of2013 quarter, the percentage of 2012our U.S. crude oil and condensate production that was sweet averaged 76 percent and 75 percent compared to the same quarter of 2011.  Our international crude oil production is relatively sweet and a majority is sold in relation to the Brent crude oil benchmark, which was 3 percent lower in the third quarter of 2012 than the same quarter of 2011. Both crude benchmarks were relatively flat on average when comparing the nine-month periods of 2012 and 2011.
  Our domestic crude oil production was about 35 percent sour in the third quarter and 42 percent sour in the first nine months of 2012 compared to 6465 percent and 6258 percent in the same periods of 20112012. Reduced production
Location – In recent years, crude oil sold along the United States Gulf Coast, such as that from the Gulf of Mexico and increased onshore production from the Bakken and Eagle Ford shale, plays contributed tohas been priced based on the lower sour crude percentage in 2012.  Sour crude oil contains more sulfur than light sweet WTI.  Sour crude oil also tends to be heavier than and sellsLouisiana Light Sweet benchmark which prices at a premium to WTI and moves similarly to Brent, while production from inland areas farther from large refineries has been priced lower. During the third quarter of 2013, the WTI discount from Brent narrowed significantly.
Composition – The proportion of our liquid hydrocarbon sales that are NGLs continues to light sweet crude oil becauseincrease due to our development of its higher refining costsUnited States unconventional liquids-rich plays. NGLs were 16 percent of our North America E&P liquid hydrocarbon sales volumes in the third quarter and lower refined product values.15 percent in the first nine months of 2013 compared to 12 percent and 10 percent in the same periods of 2012.
Natural gas –A significant portion of our natural gas production in the lower 48 states of the U.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 lower27 percent and 41 percent higher for the third quarter and first nine months of20122013 compared to the same periods of the prior year. A decline
International E&P
Liquid hydrocarbons – Our international crude oil production is relatively sweet and is generally sold in average settlement date Henry Hub natural gas prices beganrelation to the Brent crude benchmark, which changed little comparing the third quarters of 2013 and 2012, but was 3 percent lower in September 2011 and continued into 2012. Although prices have stabilized recently, they have not increased appreciably.  the first nine months of 2013 than in the same period of 2012.
Natural gas –Our other 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 periods.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.

2526


Oil Sands Mining
 OSM The Oil Sands Mining segment revenues correlate with prevailing market prices for theproduces and sells various qualities of synthetic crude oil and vacuum gas oil we produce.  Roughlyoil. Output mix can be impacted by operational problems or planned unit outages at the mines or upgrader. Sales prices for roughly two-thirds of ourthe normal output mix will track movements in WTI and one-third will track movements in the Canadian heavy sour crude oil market,marker, primarily Western Canadian Select (“WCS”("WCS"). In 2012,An increase in the WTI benchmark prices, coupled with a smaller WCS discount from WTI has increased, bringing downin the third quarter of 2013 compared to the same period of 2012, is reflected in our improved average price realizations. Output mix can be impacted by operational problems or planned unit outages atThis narrowing of the mines or upgrader.discount began in March 2013.
The operating cost structure of the oil sands miningour Oil Sands Mining operations is predominantly fixed and therefore many of the costs incurred in times of full operation continue during production downtime, making per unitdowntime. Per-unit costs are sensitive to production rate.rates. Key variable costs are natural gas and diesel fuel, which track commodity markets such as the Canadian Alberta Energy Company (“AECO”("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 third quarter and first nine months of20122013 and 20112012:
Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended September 30,Nine Months Ended September 30,
Benchmark2012 2011 2012 20112013201220132012
WTI crude oil (Dollars per barrel)
$92.20 $89.54 $96.16 $95.47
$105.81

$92.20
$98.20$96.16
Western Canadian Select (Dollars per barrel)(a)
$70.49 $72.14 $74.21 $76.10
WCS crude oil (Dollars per barrel)(a)

$88.35

$70.49
$75.27
$74.21
AECO natural gas sales index (Dollars per mmbtu)(b)
$2.27 $3.70 $2.03 $3.86
$2.35

$2.27
$2.99
$2.03
(a) 
Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.
(b) 
Monthly average AECO day ahead index.

Integrated Gas
27
 We have a 60 percent ownership in a production facility in Equatorial Guinea, which sells LNG under a long-term contract principally based upon Henry Hub natural gas prices.
 We own a 45 percent interest in a methanol plant located in Equatorial Guinea.  Methanol demand has a direct impact on the plant’s earnings.  Because global demand for methanol is rather limited, changes in the supply-demand balance can have a significant impact on sales prices.  The plant capacity of 1.1 million tonnes is about 2 percent of 2011 estimated world demand.


Results of Operations
Consolidated Results of Operation
 Due to the spin-off of our downstream business on June 30, 2011, which is reported as discontinued operations, income from continuing operations is more representative of Marathon Oil as an independent energy company.  Consolidated income from continuing operations before income taxes in the third quarter and first nine months of2013 quarterwas approximately 22 percent and 5 percent lower than in the same periods of 2012 was 33 percent higher thanprimarily related to decreases in the same period of 2011 primarily due to the previously discussed resumption of our operations in Libya.international liquid hydrocarbon sales volumes and average realizations. The effective tax rate was 7468 percent in the thirdfirst nine months of quarter of 20122013 compared to 6972 percent in the thirdfirst nine months of quarter of 20112012, with the increasedecrease primarily related to higherlower income from continuing operations in Libya and Norway, which are higher tax jurisdictions, primarily Libya.
 Consolidated income from continuing operations before income taxes in the first nine months of 2012 was 40 percent higher than in the same period of 2011 primarily due to increased income in Libya.jurisdictions. As a result, of increasednet income from continuing operations before tax in higher tax jurisdictions, primarily Norway and Libya, the effective tax rate was 72 percent for the third quarter and first nine months of 2013 increased 26 percent and 9 percent.
Sales and other operating revenues, including related party 2012 compared to 64 percent for the same period of 2011.

26


 Revenues are summarized by segment in the following table:
 Three Months Ended September 30, Nine Months Ended September 30,
(In millions)2012 2011 2012 2011
E&P$3,519
 $3,212
 $10,327
 $9,788
OSM470
 427
 1,184
 1,180
IG—
 16
 —
 93
Segment revenues3,989
 3,655
 11,511
 11,061
Unrealized gain on crude oil derivative instruments45
 —
 45
 —
Elimination of intersegment revenues—
 (6) —
 (47)
Total revenues$4,034
 $3,649
 $11,556
 $11,014
 Three Months Ended September 30,Nine Months Ended September 30,
(In millions)2013201220132012
Sales and other operating revenues, including related party:    
North America E&P$1,321
$993
$3,820
$2,738
International E&P1,396
1,907
5,015
5,383
Oil Sands Mining463
460
1,204
1,158
Segment sales and other operating revenues, including related party$3,180
$3,360
$10,039
$9,279
Unrealized gain (loss) on crude oil derivative instruments(61)45
(61)45
Total sales and other operating revenues, including related party$3,119
$3,405
$9,978
$9,324
 
E&P segmentTotal sales and other operating revenues decreased increased $307$286 million in the third quarter quarter and $539increased $654 million in the first nine months of20122013 from the comparable prior-year periods. IncludedThe $328 million and $1,082 million increases in ourthe North America E&P segment are supply optimization activities which includein the purchasethird quarter and first nine months of commodities from third parties for resale.  Supply optimization serves to aggregate volumes in order to satisfy transportation commitments and to achieve flexibility within product types and delivery points.  Volumes associated with supply optimization have been decreasing in 20122013 were primarily due to market dynamicshigher liquid hydrocarbon sales volumes resulting from ongoing development programs in the Eagle Ford and related commodity prices have also beenBakken shale resource plays as well as higher liquid hydrocarbon realizations, partially offset by lower in 2012. Seenatural gas sales volumes, primarily the Costresult of revenues discussion as revenues from supply optimization approximate the related costs.  
Revenues from the sale of our U.S. production are higherAlaska assets, over the same periods of 2012. Realized losses on our North America E&P crude oil derivative instruments were $25 million and $12 million in the third quarter and first nine months of20132012 primarily as a result of increased liquid hydrocarbon sales volumes from our U.S. shale plays.  Lower liquid hydrocarbon and natural gas realizations partially offset the volume impact.  The following table gives details of net sales and average realizations of our U.S. operations.
 Three Months Ended September 30, Nine Months Ended September 30,
 2012 2011 2012 2011
United States Operating Statistics       
     Net liquid hydrocarbon sales (mbbld) (a)
111
 69
 98
 73
     Liquid hydrocarbon average realizations (per bbl) (b)
$83.80
 $88.89
 $86.98
 $91.53
        
Net natural gas sales (mmcfd)
366
 296
 343
 326
     Natural gas average realizations (per mcf)(b)
$3.61
 $4.85
 $3.73
 $5.04
(a)Includes, while there were no realized gains or losses on crude oil condensate and natural gas liquids.
(b)Excludes gains and losses on derivative instruments
Revenues from our international operations are higher in the third quarter and first nine monthssame periods of 2012 primarily as a result of the previously discussed resumption of liquid hydrocarbon sales from Libya.  Higher average liquid hydrocarbon realizations during the third quarter and first nine months of 2012 also contributed to the revenue increase for both periods.  2012.

27


The following table gives details of net sales volumes and average realizations of our international operations.North America E&P segment.
 Three Months Ended September 30, Nine Months Ended September 30,
 2012 2011 2012 2011
International Operating Statistics       
     Net liquid hydrocarbon sales (mbbld)(a)
       
Europe94
 108
 97
 102
Africa88
 34
 73
 44
Total International182
 142
 170
 146
     Liquid hydrocarbon average realizations (per bbl)(b)
       
Europe$112.34
 $117.05
 $115.73
 $115.91
Africa98.65
 63.51
 97.00
 75.38
Total International$105.71
 $104.24
 $107.69
 $103.75
        
Net natural gas sales (mmcfd)
       
           Europe(c)
100
 79
 102
 92
Africa485
 453
 434
 440
Total International585
 532
 536
 532
     Natural gas average realizations (per mcf)(b)
       
Europe$10.10
 $9.81
 $10.05
 $10.07
Africa0.63
 0.24
 0.39
 0.24
Total International$2.25
 $1.67
 $2.23
 $1.95
 Three Months Ended September 30,Nine Months Ended September 30,
 2013201220132012
North America E&P Operating Statistics    
Net liquid hydrocarbon sales volumes (mbbld) (a)
150
111
147
98
Liquid hydrocarbon average realizations (per bbl) (b) (c)
$90.49$83.56$87.09$87.07
Net crude oil and condensate sales volumes (mbbld)
126
98
125
88
     Crude oil and condensate average realizations (per bbl) (b)
$101.05$89.89$96.54$92.00
     Net natural gas liquids sales volumes (mbbld)
24
13
22
10
     Natural gas liquids average realizations (per bbl) (b)
$35.01$37.88$34.06$41.99
     
Net natural gas sales volumes (mmcfd)
297
366
318
343
Natural gas average realizations (per mcf)(b)
$3.51$3.61$3.86$3.73
(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 decreased average liquid hydrocarbon realizations by $1.81 per bbl and $0.30 per bbl for the third quarter and first nine months of of 2013. There were no realized gains (losses) on crude oil derivative instruments in the third quarter and first nine months of of 2012.

28


International E&P sales and other operating revenues decreased $511 million and $368 million in the third quarter and first nine months of2013 from the comparable prior-year periods. The decrease in the third quarter of 2013 was primarily due to lower liquid hydrocarbon sales volumes in Libya and Norway, partially offset by higher liquid hydrocarbon sales volumes in Angola as previously discussed. The decrease in the first nine months of 2013 was primarily due to lower liquid hydrocarbon sales volumes in Norway and Libya and lower liquid hydrocarbon realizations, partially offset by higher liquid hydrocarbon sales volumes in Angola.
The following table gives details of net sales volumes and average realizations of our International E&P segment.
 Three Months Ended September 30,Nine Months Ended September 30,
 2013201220132012
International E&P Operating Statistics    
     Net liquid hydrocarbon sales volumes (mbbld)(a)
    
Europe81
94
91
97
Africa57
88
73
73
Total International E&P138
182
164
170
     Liquid hydrocarbon average realizations (per bbl)
    
Europe$113.73$112.34$112.12$115.73
Africa$84.58$98.65$92.26$97.00
Total International E&P$101.68$105.71$103.25$107.69
     
Net natural gas sales volumes (mmcfd)
    
Europe(b)
69
100
84
102
Africa493
485
464
434
Total International E&P562
585
548
536
     Natural gas average realizations (per mcf)
    
Europe$11.61$10.10$11.98$10.05
Africa(c)
$0.59$0.63$0.53$0.39
Total International E&P$1.95$2.25$2.29$2.23
(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
Includes natural gas acquired for injection and losses on derivative instruments.subsequent resale of 4 mmcfd and 18 mmcfd for the third quarters of 2013 and 2012, and 8 mmcfd and 16 mmcfd for the first nine months of2013 and 2012.
(c) 
Includes natural gas acquired for injectionPrimarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO, and subsequent resaleEGHoldings, equity method investees. We include our share of 18 mmcfdAlba Plant LLC's, AMPCO's and 16 mmcfd for the third quarters of 2012 and 2011, and 16 mmcfd and 15 mmcfd for the first nine months of 2012 and 2011.
EGHoldings' income in our International E&P segment.
OSM segmentOil Sands Mining sales and other operating revenuesincreased $43$3 million and $46 million in the third quarter and $4 millionfirst nine months of2013 from the comparable prior-year periods. Synthetic crude oil sales volumes were lower in the third quarter of 2013; however, average realizations were higher versus the comparable 2012 period primarily due to increases in the WTI and WCS benchmark prices. The increase for the first nine months of 20122013 resulted from higher synthetic crude oil average realizations primarily as a result of a larger proportion of sales attributable to a premium grade of synthetic crude oil when compared to the same periods of 2011. The upgrader expansion was completed and commenced operationsperiod in the third quarter of 2011, resulting in higher sales volumes in both periods.  However, an increase in the discount of WCS to WTI resulted in the decreases in average realizations during the third quarter and first nine months of 2012, partially offsetting the positive volume variance.  .
The following table gives details of net sales volumes and average realizations of our OSM operations.Oil Sands Mining segment.
 Three Months Ended September 30, Nine Months Ended September 30,
 2012 2011 2012 2011
OSM Operating Statistics       
    Net synthetic crude oil sales (mbbld) (a)
53
 50
 47
 43
Synthetic crude oil average realizations (per bbl)
$81.13
 $87.29
 $83.58
 $90.91
 Three Months Ended September 30,Nine Months Ended September 30,
 2013201220132012
Oil Sands Mining Operating Statistics    
    Net synthetic crude oil sales volumes (mbbld) (a)
49
53
47
47
Synthetic crude oil average realizations (per bbl)
$102.64$81.13$90.65$83.58
(a) 
Includes blendstocks.
IG segment revenuesdecreased $16 millionin the third quarter and $93 million in the first nine months of 2012 compared to the same periods of 2011.  Sales of LNG from our Alaska operations ceased in the third quarter of 2011 when we sold our interest in this production facility.
Unrealized gaingains and losses on crude oil derivative instruments is are included in total sales and other operating revenues but are not segment revenues. Inallocated to the segments. These crude oil derivative instruments resulted in a $61 million net unrealized loss in the third quarter and first nine months of 2012, the2013 compared to a net unrealized gain on crude oil derivative instruments wasof $45 million and there was no comparable derivative activity in similarthe same periods of 2011.2012. See Note 14 to the consolidated financial statements and Item 3. Quantitative and Qualitative Disclosures About Market Risk for additional information about our derivative positions.

29


Marketing revenues increased $37 million in the third quarter of 2013 and decreased $640 million in the first nine months of of 2013 from the comparable prior-year 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 and represented the majority of these variances, decreased in the first nine months of 2013 due to market dynamics. Despite this year-to-date trend, there was a slight increase in the third quarter of 2013 when compared to 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 investmentsdecreased $8 million in the third quarter of 2013 versus the third quarter of 2012; however, it increased $10049 million in the first nine months of 20122013 from the comparable prior-year period, primarily due to lower natural gas prices and turnarounds early in 2012 at our facilities in Equatorial Guinea.  Also, in January 2012, we sold our equity investments in several Gulf of Mexico crude oil pipelines.higher LNG average realizations.  

28


Net gain (loss) on disposal of assets in the thirdfirst nine months of2013 quarter of 2012 primarily reflects an $18includes a $114 million loss on the sale of undeveloped acreage outsideour interests in the coreDJ Basin, a $43 million loss on the conveyance of our interests in the Eagle FordMarcellus natural gas shale resource play.play to the operator, a $98 million gain on the sale of our interest in the Neptune gas plant and a $55 million gain on the sale of our remaining assets in Alaska. The net gain on disposal of assets in the first nine months of2012 consists primarily of the $166 million gain on the sale of our interests in several Gulf of Mexico crude oil pipeline systems reduced by theand a $36 million loss on the assignment ofrelated to our Bone Bay and Kumawa exploration licenses in Indonesia and the $18 million loss on the Eagle Ford acreage.exit from Indonesia. See Note 75 to the consolidated financial statements for information about these dispositions.
Cost of revenuesProduction expenses decreased $304 million and $66626 million in the third quarter quarter and first nine months of 2013 compared to the same quarter in 2012 primarily due to lower feedstock and contract labor costs in the OSM segment, partially offset by higher production expenses in the North America E&P segment related to increased sales volumes in the Eagle Ford and Bakken shale plays. Production expenses increased $186 million in the first nine months of2013 from the comparable periods of 2011 primarily due to our supply optimization activities.  Volumes associated with supply optimization have been decreasing in 2012 due to market dynamics and related commodity prices have also been lower in 2012. Comparatively, costs related to supply optimization were lower by $438 million for the third quarter and by $677 million for the first nine monthsperiod of 2012. Excluding the impact of supply optimization activities,The North America E&P segment operatingincrease is primarily related to increased sales volumes in Eagle Ford and Bakken, partially offset by lower Alaska production expenses have increased in proportion to our increased production from U.S. shale plays. Additionally, Integrated Gas segment costs are lower in 2012 due to the asset sale of our interest in the Alaska LNG facilityfirst quarter of 2013. The International E&P increase is primarily related to 2013 first production from Angola Block 31 and a planned Norway third quarter 2013 turnaround. The OSM segment increase is primarily related to a planned turnaround in the second quarter of 2013.
Marketing expenses increased $35 million and decreased $650 million in the third quarter and first nine months of2013 from the same periods of 2011.2012, consistent with the marketing revenue changes discussed above.
 Exploration expenseswere $17 million lower in the third quarter of 2013 than in the same quarter in 2012 due to lower unproved property impairments and geological and geophysical costs partially offset by higher dry well costs, including the Sverdrup well in Norway. Exploration costs were $274 million higher in the first nine months of2013 than in the same period 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 had expired or that we do not expect to drill or extend. The following table summarizes the components of exploration expenses.
 Three Months Ended September 30,Nine Months Ended September 30,
(In millions)2013201220132012
Unproved property impairments$42
$78
$465
$148
Dry well costs83
35
154
139
Geological and geophysical9
30
48
104
Other19
27
84
86
Total exploration expenses$153
$170
$751
$477
Depreciation, depletion and amortization (“DD&A”) increased $10895 million and $426 million in the third quarter and $63 million in the first nine months of20122013 from the comparable prior-year periods.  Because both our E&P and OSMOur segments apply the units-of-production method to the majority of their assets,assets; therefore, the previously discussed increases in North America E&P 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.  Lower U.S. and InternationalAn increase in the North America E&P DD&A ratesrate in the third quarter and first nine months of20122013 compared to the same prior-year periods was primarily due to the ongoing development programs in the Eagle Ford and Bakken shale resource plays. A slightly lower International E&P DD&A rate in the 2011first nine months of2013 compared to the same period in 2012, was primarily due to reserve increases for Norway and partially offset the impact of the higher North America E&P rate and higher sales volumes in those periods.  Also, there was no depletion of our Alaska assets in the second and third quarters of 2012 because they are held for sale.  volumes.  

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The following table provides DD&A rates for our E&P and OSM segments.each segment.
 Three Months Ended September 30, Nine Months Ended September 30,
($ per boe)2012 2011 2012 2011
DD&A rate 
  
  
  
E&P Segment   
  
  
United States$23
 $24
 $23
 $26
International8
 10
 9
 10
OSM Segment$6
 $6
 $6
 $6
 Three Months Ended September 30,Nine Months Ended September 30,
($ per boe)2013201220132012
DD&A rate   
 
North America E&P
$27

$23

$27

$23
International E&P
$8

$8

$8

$9
Oil Sands Mining
$12

$13

$12

$13
 Impairments in the first nine months ofnine2013 months of 2012primarily related primarily to the Powder River Basin and the Ozona development in the Gulf of Mexico. Impairments in the first nine months ofnine2012 months of 2011were also related primarily to the DroshkyOzona development in the Gulf of Mexico and an intangible asset for an LNG delivery contract at Elba Island.Mexico.  See Note 13 to the consolidated financial statements for information about these impairments.
Taxes other than incomeinclude 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 expensesdecreased $27 million increased $35and $9 million in the third quarter quarter and $18 million in the first nine months of 2012 compared to2013 from the same periods in 20112012. The decrease in the third quarter of 2012 includes2013 is primarily due to a lower pension settlement expense of $34 million. See Note 9 to the consolidated financial statements for information about the pension settlement. The cost increase for the nine-month period of 2012 is lower because 2011 included higher incentive compensation expense due to the increase in Marathon’s stock price in the period leading up to the spin-off. 
Exploration expenseswere higherloss in the third quarter quarter of 2012 than in the same quarter of 2011, primarily due to larger unproved property impairments. The third quarter of 2012 included $51 million related to unproved property impairments associated with approximately 100,000 net non-core acres in the Eagle Ford shale. Exploration expenses were lower in the first nine months of 2012 than in the previous year, primarily due to dry wells in the Gulf of Mexico, Norway and Indonesia in 2011 compared to one dry Gulf of Mexico well plus various U.S. onshore dry wells in 2012; however, higher unproved property impairments in the Marcellus shale, Eagle Ford shale and Indonesia in 2012 partially offset this decrease. Geological and geophysical (“G&G”) costs increased in the nine months of 2012 primarily related to activity in the Kurdistan Region of Iraq and the seismic survey on our Birchwood oil sands in-situ lease.  2013.

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The following table summarizes the components of exploration expenses.
 Three Months Ended September 30, Nine Months Ended September 30,
(In millions)2012 2011 2012 2011
Unproved property impairments$79
 $16
 $149
 $59
Dry well costs35
 31
 138
 252
G&G24
 39
 94
 67
Other38
 43
 110
 126
Total exploration expenses$176
 $129
 $491
 $504
Net interest and other increased $2313 million and $9849 million in the third quarter and first nine months of20122013 from the comparable periods of 20112012. Foreign currency gains were primarily due to lower in the third quarter of 2012 than in the same quarter of 2011. In addition, capitalized interest has been lower in both periods of 2012.
Loss on early extinguishment of debtrelates to debt retirements in February and March of 2011.  See Note 15 to the consolidated financial statements for additional discussion of these transactions.2013.
Provision for income taxes increaseddecreased $381492 million and $1,180341 million in the third quarter quarter and first nine months of 20122013 from the comparable periods of 20112012 primarily due to the increasedecrease in pretax income, primarily in high tax rate jurisdictions, including the impact of the previously discussed resumption of sales in Libya in the first quarter of 2012.Libya.
The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The 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 reportedshown in “Corporatecorporate and other unallocated items”items in Note 8 to the consolidated financial statements.segment income table below.
Our effective income tax raterates in the first nine months of 20122013 was and 2012 were 68 percent and 72 percent.   This rate ispercent.   These rates are higher than the U.S. statutory rate of 35 percent primarily due to earnings from foreign jurisdictions, primarily Norway and Libya, where the tax rates are in excess of the U.S. statutory rate.  An increase in earnings and associated taxes from foreign jurisdictions, primarily Norway, as compared to prior periods caused an increase in our valuation allowance on current year foreign tax credits.  In Libya, where the statutory tax rate is in excess of 90 percent, limited production resumedsales decreased in the fourththird quarter of 20112013 due to labor strikes at the Es Sider oil terminal and liquid hydrocarbonthere remains uncertainty around future production and sales resumed in the first quarterlevels. Reliable estimates of 2012.  A reliable estimate of2013 and 2012 annual ordinary income from our Libyan operations cannotcould 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 nine 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 60 percent and 64 percent for the first nine months of 2012.
Our effective tax rate in the first nine2013 months of 2011 was 64 percent which is higher thanand 2012. In the U.S. statutory tax rate of 35 percent primarily due to earnings from foreign jurisdictions where the tax rates are in excess of the U.S. statutory rate and the valuation allowance recorded against 2011 foreign tax credits.  In addition, in the secondthird quarter of 2011,2013, we recorded a deferrednet favorable tax chargeadjustment of $42 million, largely related to an internal restructuringgreater expected utilization of our international subsidiaries.
Discontinued operationsreflect the June 30, 2011 spin-off of our downstream business and the historical results of those operations, net offoreign tax for allcredits in future periods presented.than previously estimated.

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 Segment ResultsIncome
 Segment income is summarized in the following table.
 Three Months Ended September 30, Nine Months Ended September 30,
(In millions)2012 2011 2012 2011
E&P 
  
  
  
United States$110
 $81
 $289
 $237
International376
 249
 1,091
 1,362
E&P segment486
 330
 1,380
 1,599
OSM65
 92
 157
 193
IG39
 55
 56
 158
Segment income590
 477
 1,593
 1,950
Items not allocated to segments, net of income taxes: 
  
  
  
Corporate and other unallocated items(158) (56) (267) (209)
Unrealized gain on crude oil derivative instruments29
 —
 29
 —
Gain (loss) on dispositions(11) (1) 72
 23
Impairments—
 —
 (167) (195)
Loss on early extinguishment of debt—
 —
 —
 (176)
Tax effect of subsidiary restructuring—
 —
 —
 (122)
Deferred income tax items—
 (15) —
 (65)
Water abatement - Oil Sands—
 —
 —
 (48)
Income from continuing operations450
 405
 1,260
 1,158
Discontinued operations—
 —
 —
 1,239
Net income$450
 $405
 $1,260
 $2,397
 Three Months Ended September 30, Nine Months Ended September 30,
(In millions)2013 2012 2013 2012
North America E&P$242
 $107
 $404
 $281
International E&P321
 405
 1,156
 1,185
Oil Sands Mining106
 66
 164
 154
Segment income669
 578
 1,724
 1,620
Items not allocated to segments, net of income taxes: 
  
    
Corporate and other unallocated items(61) (146) (288) (294)
Unrealized gain (loss) on crude oil derivative instruments(39) 29
 (39) 29
Net gain (loss) on dispositions—
 (11) (9) 72
Impairments—
 —
 (10) (167)
Net income$569
 $450
 $1,378
 $1,260
United States North America E&P segment income increased $29$135 million and $123 million in the third quarter and increased $52 million in the first nine months of20122013 compared to the same periods of 20112012. The income increase in both periods was primarily the result of higherincreases are largely due to increased liquid hydrocarbon sales volumes as previously discussed,primarily in the Eagle Ford and Bakken shale resource plays. The third quarter increase also reflects a $92 million decrease in exploration expenses, however, the first nine months of 2013 includes unproved property impairments which partially offset by lower liquid hydrocarbon realizations and the impact of increased production operations on DD&A and operating expenses. In addition, exploration expenses were higher primarily due to higher unproved property impairments.  revenue increase.
 International E&P segment income increased $127decreased $84 million and $29 million in the third quarter and decreased $271 million in the first nine months of 2012 compared to the same periods of 2011.  Segment income, before taxes, increased in both periods primarily due to the previously discussed higher liquid hydrocarbon sales volumes and realizations, partially offset by increased operating costs. As previously discussed, increased income before tax in higher tax jurisdictions resulted in a higher effective tax rate in the first nine months of 2012 compared to the same period of 2011. 
OSM segment incomedecreased $27 million and $36 million in the third quarter and first nine months of2012.  As previously discussed, lower synthetic crude oil price realizations were the primary reason for the decrease in income.  This was partially offset by decreased costs on a per unit basis and higher sales volumes.
IG segment income decreased $16 million and $102 million in the third quarter and first nine months of 20122013 compared to the same periods of 2011 primarily due to lower natural gas prices and turnarounds early in 2012 at our facilities in Equatorial Guinea. In addition, LNG. These decreases are primarily related to the lower liquid hydrocarbon sales volumes are lowerand higher production expenses previously discussed, as well as increases of $75 million and $108 million in exploration expenses for the third quarter and first nine months of 2013, partially offset by lower income taxes.  
 Oil Sands Mining segment incomeincreased $40 million and $10 million in the third quarter and first nine months of2013 compared to the same periods of 2012. These increases are primarily due to the sale of our interest in the Alaska LNG facility in the third quarter of 2011.higher synthetic crude oil realizations.
Critical Accounting Estimates
There have been no changes to our critical accounting estimates subsequent to December 31, 2011.2012.
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"). 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 do not expect this accounting standards update to have a significant impact on our consolidated results of operations, financial position or cash flows.

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Cash Flows and Liquidity
 Cash Flows
 Net cash provided by continuing operationsoperating activities was$4,041 million in the first nine months of 2013, compared to $2,812 million in the first nine months of 2012, compared to $4,400 million in the first nine months of 2011 primarily reflecting the impact of lower U.S.increased North America liquid hydrocarbon and natural gas pricesvolumes on operating income and higher cash tax payments. See Note 17 to the consolidated financial statements for amounts of the cash tax payments.income.
 Net cash used in investing activities totaled$3,411 million in the first nine months of 2013, compared to $4,031 million in the first nine months of 2012, compared to $2,118 million related to continuing operations in the first nine months of 2011.  Significant investing activities are additions to property, plant and equipment and disposal of assets.  In the first nine months of 2012, most of the additions wereAdditions in the E&P segment with continuedboth periods primarily related to spending on U.S. unconventional resource plays, particularly the Eagle Ford shale. This compares to additionsDisposals of assets totaled $402 million and $193 million in the first nine months of 20112013 which also included spending on U.S. unconventional resource plays, though at a lower level, and drilling in Norway, Indonesia and the Kurdistan Region of Iraq.  In the first nine2012 months of 2012, expenditures for acquisitions totaled $806 million, with 2013 net proceeds primarily related to acquiring additional Eagle Ford shale properties. Deposits totaling $120 million were paidthe sales of our interests in our Alaska assets, the first nine monthsNeptune gas plant, and the DJ Basin. In 2012, net proceeds resulted primarily from the sale of 2011 related to the Eagle Ford shale acreage acquisitions that closed later that year.our interests in several Gulf of Mexico crude oil pipeline systems.
 For further information regarding capital expenditures by segment, see Supplemental Statistics.
 Net cash provided byused in financing activities was $1,385954 million in the first nine months of 20122013, compared to net cash used in$1,385 million provided by financing activities related to continuing operations of $5,098 millionin the first nine months of 20112012.  During the first nine months of 2013, we repurchased $500 million of our common stock under our authorized share repurchase program. Repayments of debt were $148 million in the first nine months of 2013 and $111 million in the first nine months of 2012, we. We also drew a net $1,839 million under ourof commercial paper program, retired $23 million principal amount of debt before it was due and repaid $88 million of debt upon its maturity.  Duringin the first nine months of 2011, we retired $2.5 billion aggregate principal amount of our debt before it was due and distributed $1.6 billion to Marathon Petroleum Corporation in connection with the spin-off of the downstream business.2012.   Dividends paid of $376 million and $360 million were a significant use of cash in both nine-month 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.  We issued $10.4 billion and repaid $8.6 billion of commercial paper in the first nine months of 2012 leaving a balance of $1.8 billion outstanding at September 30, 2012.  After September 30, 2012, we continued to utilize our sources of liquidity, including additional issuances of commercial paper and notes as discussed below, to fund working capital requirements.  Because of the alternatives available to us as discussed above, and access to capital markets, we believe that our short-term and long-term liquidity is adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, 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.
Capital Resources
Credit Arrangements and Borrowings
 At September 30, 20122013, we had no borrowings against our revolving credit facility described below, and $1.8 billion in commercial paper$200 million outstanding under our U.S. commercial paper program that is backed by the revolving credit facility. During the first nine months of 2013, $4,975 million of commercial paper was issued and $4,975 million of commercial paper was repaid.
On October 29, 2012,At September 30, 2013, we issued $1had $6,501 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.
Anticipated Asset Disposals
The previously discussed sale of our interest in Angola Block 31 and the agreement in principle to sell our interest in Angola Block 32 are both expected to close in the fourth quarter of 2013, subject to the execution of definitive agreements for Block 32 and government and regulatory approvals. Anticipated proceeds from these transactions are $1.5 billion aggregate principal amountand $590 million, respectively, before closing adjustments. We expect to use a portion of senior notes bearing interest at 0.9 percent with a maturity date of November 1, 2015the proceeds to repurchase common shares as discussed below and $1 billion aggregate principal amount of senior notes bearing interest at 2.8 percent with a maturity date of November 1, 2022. Interest on the senior notes is payable semi-annually beginning May 1, 2013. The proceeds are being usedremainder to pay off commercial paperstrengthen our balance sheet and for general corporate purposes.
 In April 2012, we terminated our $3.0 billion five-year revolving credit facility and replaced it withShelf Registration
We are a new $2.5 billion unsecured five-year revolving credit facility (the “Credit Facility”).  The Credit Facility matures in April 2017 but allows"well-known seasoned issuer" for purposes of SEC rules, thereby allowing us to request two one-year extensions.   It contains an optionuse a universal shelf registration statement should we choose to increaseissue and sell various types of equity and debt securities. Beginning in the commitment amount by upfirst quarter of 2013, we changed our reportable segments and expect to an additional $1.0 billion, subjectrecast 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 consent of any increasing lenders,SEC. When appropriate, we will update and includes sub-facilities for swing-line loans and letters of credit up to an aggregate amount of $100 million and $500 million, respectively.  Fees on the unused commitment of each lender range from 10 basis points to 25 basis points per year depending onfile our credit ratings.  Borrowings under the Credit Facility bear interest, at our option, at either (a) an adjusted London Interbank Offered Rate (“LIBOR”) plus a margin ranging from 87.5 basis points to 162.5 basis points per year depending on our credit ratings or (b) the Base Rate plus a margin ranging from 0.0 basis points to 62.5 basis points depending on our credit ratings.  Base Rate is defined as a per annum rate equal to the greatest of (a) the prime rate, (b) the federal funds rate plus one-half of one percent and (c) LIBOR for a one-month interest period plus 1 percent.
 The agreement contains a covenant that requires our ratio of total debt to total capitalization not to exceed 65 percent as of the last day of each fiscal quarter.  If an event of default occurs, the lenders may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility.universal shelf registration statement.

3233


We have a universal shelf registration statement filed with the Securities and Exchange Commission under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.Cash-Adjusted Debt-To-Capital Ratio
 Our cash-adjusted debt-to-capital ratio (total debt-minus-cash to total debt-plus-equity-minus-cash) was 25 percent at September 30, 20122013, compared to 20 percent at and December 31, 20112012.
September 30, December 31,September 30, December 31,
(In millions)2012 20112013 2012
Commercial paper$1,839
 $—
$200
 $200
Long-term debt due within one year183
 141
68
 184
Long-term debt4,518
 4,674
6,433
 6,512
Total debt6,540
 4,815
$6,701
 $6,896
Cash671
 493
$354
 $684
Equity$18,064
 $17,159
$18,994
 $18,283
Calculation: 
  
 
  
Total debt$6,540
 $4,815
$6,701
 $6,896
Minus cash671
 493
354
 684
Total debt minus cash5,869
 4,322
6,347
 6,212
Total debt6,540
 4,815
6,701
 6,896
Plus equity18,064
 17,159
18,994
 18,283
Minus cash671
 493
354
 684
Total debt plus equity minus cash$23,933
 $21,481
$25,341
 $24,495
Cash-adjusted debt-to-capital ratio25% 20%25% 25%
 Capital Requirements
 On October 31, 2012,30, 2013, our Board of Directors approved a dividend of 1719 cents per share for the third quarter of 20122013, payable December 10, 20122013 to stockholders of record at the close of business on November 21, 2012.20, 2013.
In October and early November 2012,As of September 30, 2013, we paid $264plan to make contributions of up to $17 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 September 30, 2013, we had repurchased 92 million common shares at a cost of $3,722 million, with 66 million shares purchased for closed acquisition transactions.
In$2,922 million prior to the firstspin-off of our downstream business, 12 million shares acquired at a cost of $300 million in the third quarter of 2012, we increased2011 and 14 million shares acquired at a cost of $500 million during the third quarter of 2013. An additional $500 million repurchase of common shares is anticipated to be completed after closing the previously discussed sale of our 2012 capital, investmentinterest in Angola Block 31, which is expected in the fourth quarter of 2013. Purchases under the repurchase program may be in either open market transactions, including block purchases, or in privately negotiated transactions. This program may be changed based upon our financial condition or changes in market conditions and exploration budget, excluding acquisition costs, from $4.8 billionis subject to $5.0 billion,termination prior to completion. The program’s authorization does not include specific price targets or timetables. The timing of which $4.6 billionpurchases under the program will be used for capital expenditures.  The increase reflects development plans for the additional acreage acquired in the Eagle Ford shaleinfluenced by cash generated from operations, proceeds from potential asset sales, cash from available borrowings and other adjustments.market conditions.
Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Estimates may differ from actual results. Factors that affect the availability of financing include our performance (as measured by various factors including cash provided from operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies.  The discussion of liquidity above discussions also containcontains forward-looking statements aboutregarding the timing of closing the sales of our 2012 capital, investmentinterests in Angola Blocks 31 and 32, including the use of proceeds, and the timing and amount of repurchasing additional common stock. The timing of closing the sale of our interest in Angola Block 31 is subject to the satisfaction of customary closing conditions and obtaining necessary government and regulatory approvals.  The sale of our interest in Angola Block 32 is subject to the execution of definitive agreements and obtaining necessary government approval. The expectations with respect to the use of proceeds from the sale of our interests in Angola Block 31 and 32 and the timing and amount of repurchasing additional common stock could be affected by changes in the prices and demand for liquid hydrocarbons and natural gas, actions of competitors, disruptions or interruptions of our exploration budget.  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.

34


Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict.  Some factors that could cause actual results to differ materially are changes ininclude prices of and demand for liquid hydrocarbons and natural gas, actions of competitors, disruptions or interruptions of our production or oil sands mining and miningbitumen 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.

33


Contractual Cash Obligations
 The table below provides aggregated information onAs of September 30, 2013, our consolidatedtotal contractual cash obligations to make future payments under existing contracts as ofwere consistent with September 30,December 31, 2012.
     2013- 2015- Later
(In millions)Total 2012 2014 2016 Years
Short and long-term debt (excludes interest)$6,504
 $1,874
 $250
 $69
 $4,311
Lease obligations281
 39
 80
 65
 97
Purchase obligations: 
  
  
  
  
Oil and gas activities(a)
993
 351
 505
 59
 78
Service and materials contracts(b)
909
 45
 227
 131
 506
Transportation and related contracts1,301
 63
 317
 190
 731
Drilling rigs and fracturing crews894
 139
 730
 25
 —
Other234
 57
 93
 27
 57
Total purchase obligations4,331
 655
 1,872
 432
 1,372
Other long-term liabilities reported 
  
  
  
  
   in the consolidated balance sheet(c)
1,122
 174
 272
 253
 423
Total contractual cash obligations(d)
$12,238
 $2,742
 $2,474
 $819
 $6,203
(a)
Oil and gas activities include contracts to acquire property, plant and equipment and commitments for oil and gas exploration such as costs related to contractually obligated exploratory work programs that are expensed immediately.
(b)
Service and materials contracts include contracts to purchase services such as utilities, supplies and various other maintenance and operating services.
(c)
Primarily includes obligations for pension and other postretirement benefits including medical and life insurance, which we have estimated through 2021.  Also includes amounts for uncertain tax positions.
(d)
This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties of $1,516 million.
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, 2011.2012.
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.  
 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 contractSee Part II Item 1. Legal Proceedings 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.  Noble is seeking an unspecified amount of damages.  We are vigorously defending thisupdated information about ongoing 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.

3435



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 20112012 Annual Report on Form 10-K.
 In August 2012, we entered crude oil derivatives related to a portion of Additional disclosures regarding our forecast U.S. E&P crude oil sales through December 31, 2013. Disclosures aboutopen derivative positions, including underlying notional quantities, how derivativesthey are reported in our consolidated financial statements and how thetheir fair values of our derivative instruments are measured, may be found in Notes 13 and 14 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 September 30, 20122013 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$(207) $(519) $207
 $519
$43
 $108
 $(43) $(108)
Option Collars(105) (277) 103
 275
(17) (55) 14
 50
Total crude oil(312) (796) 310
 794
$26
 $53
 $(29) $(58)
Natural gas       
Futures(1) (2) 1
 2
Total natural gas(1) (2) 1
 2
Total$(313) $(798) $311
 $796
Sensitivity analysis of the projected incremental effect of a hypothetical 10 percent change in interest rates on financial assets and liabilities as of September 30, 20122013 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$22
(b) 
$1
$11
(b) 
$5
Long-term debt, including amounts due within one year$(5,639)
(b) 
$(206)$(6,941)
(b) 
$(236)
(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 September 30, 20122013 would be $69 million.$52 million.

35


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.  As of the end of the period covered by this report basedBased upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that theour company's design and operation of these disclosure controls and procedures were effective.  effective as of September 30, 2013.  
In 2012,the first quarter of 2013, we began a project tocompleted the update of our existing ERPEnterprise Resource Planning ("ERP") system. The project includes implementation ofThis update included a new general ledger, consolidations system and reporting tools. This project is currently in testing phases and we expect full implementation in the first half of 2013. We believe that controls over project development and implementation are adequate to assure there will be no material effect, or a reasonable likelihood of a material effect, on our internal control over financial reporting.
During the quarter ended September 30, 2012,2013, 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.



36

MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)


        
 Three Months Ended Nine Months Ended
 September 30, September 30,
(In millions)2012 2011 2012 2011
Segment Income       
Exploration and Production 
  
  
  
United States$110
 $81
 $289
 $237
International376
 249
 1,091
 1,362
E&P segment486
 330
 1,380
 1,599
Oil Sands Mining65
 92
 157
 193
Integrated Gas39
 55
 56
 158
Segment income590
 477
 1,593
 1,950
Items not allocated to segments, net of income taxes(140) (72) (333) (792)
Income from continuing operations450
 405
 1,260
 1,158
         Discontinued operations(a)
—
 —
 —
 1,239
Net income$450
 $405
 $1,260
 $2,397
Capital Expenditures(b)
 
  
  
  
Exploration and Production 
  
  
  
United States$1,046
 $502
 $2,891
 $1,407
International228
 182
 568
 694
E&P segment1,274
 684
 3,459
 2,101
Oil Sands Mining41
 36
 136
 236
Integrated Gas1
 1
 2
 2
Corporate23
 7
 82
 37
Total$1,339
 $728
 $3,679
 $2,376
Exploration Expenses 
  
  
  
United States$132
 $75
 $369
 $280
International44
 54
 122
 224
Total$176
 $129
 $491
 $504
 Three Months Ended Nine Months Ended
 September 30, September 30,
(In millions)2013 2012 2013 2012
Segment Income       
North America E&P$242
 $107
 $404
 $281
International E&P321
 405
 1,156
 1,185
Oil Sands Mining106
 66
 164
 154
Segment income669
 578
 1,724
 1,620
Items not allocated to segments, net of income taxes(100) (128) (346) (360)
Net income$569
 $450
 $1,378
 $1,260
Capital Expenditures(a)
     
  
North America E&P$831
 $1,045
 $2,705
 $2,887
International E&P254
 229
 720
 569
Oil Sands Mining65
 41
 207
 136
Corporate12
 24
 57
 87
Total$1,162
 $1,339
 $3,689
 $3,679
Exploration Expenses     
  
North America E&P$48
 $140
 $559
 $393
International E&P105
 30
 192
 84
Total$153
 $170
 $751
 $477
(a)
The spin-off of our downstream business was completed on June 30, 2011, and has been reported as discontinued operations in 2011.
(b) 
Capital expenditures include changes in accruals.



37

MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)


 Three Months Ended Nine Months Ended
 September 30, September 30,
 2012 2011 2012 2011
E&P Operating Statistics 
  
  
  
Net Liquid Hydrocarbon Sales (mbbld) 
  
  
  
United States111
 69
 98
 73
        
Europe94
 108
 97
 102
Africa88
 34
 73
 44
Total International182
 142
 170
 146
Worldwide293
 211
 268
 219
Net Natural Gas Sales (mmcfd) 
  
  
  
United States366
 296
 343
 326
        
Europe(c)
100
 79
 102
 92
Africa485
 453
 434
 440
Total International585
 532
 536
 532
Worldwide951
 828
 879
 858
Total Worldwide Sales (mboed)452
 349
 414
 362
Average Realizations (d)
 
  
  
  
Liquid Hydrocarbons (per bbl) 
  
  
  
United States$83.80 $88.89 $86.98 $91.53
        
Europe$112.34 $117.05 $115.73 $115.91
Africa$98.65 $63.51 $97.00 $75.38
Total International$105.71 $104.24 $107.69 $103.75
Worldwide$97.40 $99.24 $100.10 $99.68
Natural Gas (per mcf)       
United States$3.61 $4.85 $3.73 $5.04
        
Europe$10.10 $9.81 $10.05 $10.07
Africa(e)
$0.63 $0.24 $0.39 $0.24
Total International$2.25 $1.67 $2.23 $1.95
Worldwide$2.77 $2.81 $2.81 $3.12
OSM Operating Statistics 
  
  
  
    Net Synthetic Crude Oil Sales (mbbld) (f)
53
 50
 47
 43
    Synthetic Crude Oil Average Realizations (per bbl)(d)
$81.13
 $87.29
 $83.58
 $90.91
IG Operating Statistics 
  
  
  
     Net Sales (mtd) (g)
 
  
  
  
LNG7,065
 6,935
 6,277
 7,121
Methanol1,146
 1,366
 1,242
 1,310
 Three Months Ended Nine Months Ended
 September 30, September 30,
Net Sales Volumes2013 2012 2013 2012
North America E&P 
  
  
  
Crude Oil and Condensate (mbbld)
126
 98
 125
 88
Natural Gas Liquids (mbbld)
24
 13
 22
 10
Total Liquid Hydrocarbons150
 111
 147
 98
Natural Gas (mmcfd)
297
 366
 318
 343
Total North America E&P (mboed)
200
 172
 200
 155
        
International E&P 
  
    
Liquid Hydrocarbons (mbbld)
       
Europe81
 94
 91
 97
Africa57
 88
 73
 73
Total Liquid Hydrocarbons138
 182
 164
 170
Natural Gas (mmcfd)
 
      
Europe(b)
69
 100
 84
 102
Africa493
 485
 464
 434
Total Natural Gas562
 585
 548
 536
Total International E&P (mboed)
231
 280
 255
 259
        
Oil Sands Mining       
Synthetic Crude Oil (mbbld)(c)
49
 53
 47
 47
        
Total Company (mboed)
480
 505
 502
 461
Net Sales Volumes of Equity Method Investees 
  
    
LNG (mtd)
7,302
 7,065
 6,638
 6,277
Methanol (mtd)
1,364
 1,146
 1,249
 1,242
(c)(b) 
Includes natural gas acquired for injection and subsequent resale of 4 mmcfd and 18 mmcfd for the third quarters of 2013 and 2012, and 8 mmcfd and 16 mmcfd for thethirdfirst nine months of quarters of 20122013 and 2011, and 16 mmcfd and 15 mmcfd for the first nine months of 2012 and 2011.
(c)
Includes blendstocks.




38

MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)


 Three Months Ended Nine Months Ended
 September 30, September 30,
Average Realizations2013 2012 2013 2012
North America E&P       
Crude Oil and Condensate (per bbl)

$101.05
 
$89.89
 $96.54 $92.00
Natural Gas Liquids (per bbl)

$35.01
 
$37.88
 $34.06 $41.99
Total Liquid Hydrocarbons(d)

$90.49
 
$83.56
 $87.09 $87.07
Natural Gas (per mcf)

$3.51
 
$3.61
 $3.86 $3.73
        
International E&P       
Liquid Hydrocarbons (per bbl)
       
Europe
$113.73
 
$112.34
 $112.12 $115.73
Africa
$84.58
 
$98.65
 $92.26 $97.00
Total Liquid Hydrocarbons
$101.68
 
$105.71
 $103.25 $107.69
Natural Gas (per mcf)
       
Europe
$11.61
 
$10.10
 $11.98 $10.05
Africa(e)

$0.59
 
$0.63
 $0.53 $0.39
Total Natural Gas
$1.95
 
$2.25
 $2.29 $2.23
        
Oil Sands Mining       
    Synthetic Crude Oil (per bbl)

$102.64
 
$81.13
 $90.65 $83.58
(d) 
Excludes
Inclusion of realized gains (losses) on crude oil derivative instruments would have decreased average liquid hydrocarbon realizations by $1.81 per bbl and losses$0.30 per bbl for the third quarter and first nine months of2013. There were no realized gains (losses) on crude oil derivative instruments.instruments in the same periods of 2012.
(e) 
Primarily represents a fixed priceprices under long-term contracts with Alba Plant LLC, Atlantic Methanol Production Company LLC (“AMPCO”) and Equatorial Guinea LNG Holdings Limited, (“EGHoldings”),which are equity method investees.  We include our share of Alba Plant LLC’s income in our E&P segment and we include our sharefrom each of AMPCO’s and EGHoldings’ income in our Integrated Gas segment.
(f)
Includes blendstocks.
(g)
Includes both consolidated sales volumes and our share of the sales volumes ofthese equity method investees in 2011.  LNG sales from Alaska, conducted through a consolidated subsidiary, ceased when these operations were sold in the third quarter of 2011.  LNG and methanol sales from Equatorial Guinea are conducted through equity method investees.our International E&P segment.

3839


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.  ThereCertain 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. The parties have been no significant changes in legalreached a tentative settlement of this litigation. We believe that the settlement of this litigation will not have a material adverse effect on our consolidated results of operations, financial position or environmental proceedings during the first nine months of 2012.cash flows.
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 20112012 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 September 30, 2012,2013, 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)
07/01/12 – 07/31/1212,285 $25.62 —
 $1,780,609,536
08/01/12 – 08/31/12143,642 $27.59 —
 $1,780,609,536
09/01/12 – 09/30/1238,963 $28.43 —
 $1,780,609,536
Total194,890 $27.63 —
  
 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)
07/01/13 - 07/31/13

10,481
 $35.24 —
 $1,780,609,536
08/01/13 - 08/31/133,253
 $37.18 —
 $1,780,609,536
09/01/13 - 09/30/1314,281,443
 $35.53 14,066,840
 $1,280,820,541
Total14,295,177
 $35.52 14,066,840
  
(a) 
162,184201,089 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.
(b) 
In September 2012,  32,7062013, 27,248 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 September 30, 2012, 782013, 92 million split-adjusted common shares had been acquired at a cost of $3,222$3,722 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.
Item 4. Mine Safety Disclosures
 Not applicable.

3940


Item 6.  Exhibits
The following exhibits are filed as a part of this report:
    Incorporated by Reference    
Exhibit Number Exhibit Description Form Exhibit Filing Date SEC File No. Filed Herewith Furnished Herewith
3.110.1 Amended By-lawsForm of Initial CEO Option Grant Agreement granted under Marathon Oil Corporation’s 2012 Incentive Compensation Plan.X
10.2Form of CEO Restricted Stock Agreement granted under Marathon Oil Corporation’s 2012 Incentive Compensation Plan (3-year prorata vesting).X
10.3Form of CEO Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2012 Incentive Compensation Plan (3-year cliff vesting).X
10.4Marathon Oil Corporation effective January 1, 2013.Bonus Agreement Upon Commencement of Employment for Lee M. Tillman.         X  
12.1 Computation of Ratio of Earnings to Fixed Charges.         X  
31.1 Certification 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  
31.2 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 Chairman, 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.CALXBRL Taxonomy Extension Calculation Linkbase.X
101.DEFXBRL Taxonomy Extension Definition Linkbase.X
101.LABXBRL Taxonomy Extension Label Linkbase.X
101.PRE XBRL Taxonomy Extension Presentation Linkbase.X


41



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.
November 6, 2013MARATHON OIL CORPORATION
By:/s/ Michael K. Stewart
 Michael K. Stewart
Vice President, Finance and Accounting,
Controller and Treasurer

42



Exhibit Index

Incorporated by Reference
Exhibit NumberExhibit DescriptionFormExhibitFiling DateSEC File No.Filed HerewithFurnished Herewith
10.1Form of Initial CEO Option Grant Agreement granted under Marathon Oil Corporation’s 2012 Incentive Compensation Plan.X
10.2Form of CEO Restricted Stock Agreement granted under Marathon Oil Corporation’s 2012 Incentive Compensation Plan (3-year prorata vesting).X
10.3Form of CEO Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2012 Incentive Compensation Plan (3-year cliff vesting).X
10.4Marathon Oil Corporation Bonus Agreement Upon Commencement of Employment for Lee M. Tillman.X
12.1Computation of Ratio of Earnings to Fixed Charges.X
31.1Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.X
31.2Certification 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 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.CAL XBRL Taxonomy Extension Calculation Linkbase.         X  
101.DEF XBRL Taxonomy Extension Definition Linkbase.         X  
101.LAB XBRL Taxonomy Extension Label Linkbase.         X  


40



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.
November 7, 2012101.PRE MARATHON OIL CORPORATIONXBRL Taxonomy Extension Presentation Linkbase.
   
By:/s/ Michael K. Stewart
  Michael K. Stewart
  
Vice President, Finance and Accounting,
Controller and Treasurer
X


41