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

FORM 10-Q

(Mark One) 
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 For the Quarterly Period Ended March 31, 20132014

OR

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

Commission file number 1-5153

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

Delaware 25-0996816
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
5555 San Felipe Street, Houston, TX  77056-2723
(Address of principal executive offices)

(713) 629-6600
(Registrant’s telephone number, including area code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.       Yes þRNo o£

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes þR No o£
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer     þ  
Accelerated filer             o
Non-accelerated filer       o        (Do not check if a smaller reporting company) 
Smaller reporting company        o   
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).         
Yes o No þ
 
There were 708,817,008676,077,784 shares of Marathon Oil Corporation common stock outstanding as of April 30, 20132014.



MARATHON OIL CORPORATION
 
Form 10-Q
 
Quarter Ended March 31, 20132014


 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
1817
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
2928
Item 4.
Controls and Procedures
2928
 
Supplemental Statistics (Unaudited)
3029
PARTPart II - OTHER INFORMATION
 
Item 1.
Legal Proceedings
3334
Item 1A.
Risk Factors
3334
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
3334
Item 4.
Mine Safety Disclosures
3334
Item 6.
Exhibits
3435
 
Signatures
3536

 
Unless the context otherwise indicates, references in this Form 10-Q to “Marathon Oil,” “we,” “our,” or “us” are references to Marathon Oil Corporation, including its wholly-owned and majority-owned subsidiaries, and its ownership interests in equity method investees (corporate entities, partnerships, limited liability companies and other ventures over which Marathon Oil exerts significant influence by virtue of its ownership interest).


1


Part I - Financial Information
Item 1. Financial Statements

MARATHON OIL CORPORATION
Consolidated Statements of Income (Unaudited)
Three Months EndedThree Months Ended
March 31,March 31,
(In millions, except per share data)2013 20122014 2013
Revenues and other income:      
Sales and other operating revenues, including related party$3,440
 $2,954
$2,830
 $3,354
Marketing revenues430
 839
540
 430
Income from equity method investments118
 78
137
 118
Net gain on disposal of assets109
 166
2
 109
Other income9
 3
20
 9
Total revenues and other income4,106
 4,040
3,529
 4,020
Costs and expenses:   
   
Production578
 514
613
 564
Marketing, including purchases from related parties429
 842
540
 429
Other operating111
 92
114
 111
Exploration465
 135
76
 463
Depreciation, depletion and amortization747
 574
697
 720
Impairments38
 262
17
 38
Taxes other than income84
 68
98
 84
General and administrative174
 159
192
 172
Total costs and expenses2,626
 2,646
2,347
 2,581
Income from operations1,480
 1,394
1,182
 1,439
Net interest and other(72) (50)(52) (72)
Income before income taxes1,408
 1,344
Income from continuing operations before income taxes1,130
 1,367
Provision for income taxes1,025
 927
590
 987
Income from continuing operations540
 380
Discontinued operations609
 3
Net income$383
 $417
$1,149
 $383
Per Share Data 
  
 
  
Net Income: 
  
Basic
$0.54
 
$0.59
Diluted
$0.54
 
$0.59
Dividends paid
$0.17
 
$0.17
Basic: 
  
Income from continuing operations$0.78
 $0.54
Discontinued operations$0.88
 $—
Net income$1.66
 $0.54
Diluted: 
  
Income from continuing operations$0.77
 $0.54
Discontinued operations$0.88
 $—
Net income$1.65
 $0.54
Dividends$0.19
 $0.17
Weighted average shares: 
  
 
  
Basic708
 706
693
 708
Diluted712
 710
696
 712
 The accompanying notes are an integral part of these consolidated financial statements.

2


MARATHON OIL CORPORATION
Consolidated Statements of Comprehensive Income (Unaudited)
Three Months EndedThree Months Ended
March 31,March 31,
(In millions)2013 20122014 2013
Net income$383
 $417
$1,149
 $383
Other comprehensive income (loss) 
  
 
  
Postretirement and postemployment plans 
  
 
  
Change in actuarial loss and other13
 13
(30) 13
Income tax provision on postretirement and 
  
postemployment plans(5) (5)
Income tax benefit (provision)10
 (5)
Postretirement and postemployment plans, net of tax8
 8
(20) 8
Foreign currency translation and other 
  
 
  
Unrealized gain (loss)(1) 1
Income tax provision on foreign currency translation and other—
 —
Unrealized loss—
 (1)
Income tax benefit—
 —
Foreign currency translation and other, net of tax(1) 1
—
 (1)
Other comprehensive income7
 9
Other comprehensive income (loss)(20) 7
Comprehensive income$390
 $426
$1,129
 $390
 The accompanying notes are an integral part of these consolidated financial statements.


3


MARATHON OIL CORPORATION
Consolidated Balance Sheets (Unaudited)
March 31, December 31,March 31, December 31,
(In millions, except per share data)2013 20122014 2013
Assets      
Current assets:      
Cash and cash equivalents$768
 $684
$1,964
 $264
Receivables2,466
 2,418
2,222
 2,134
Inventories368
 361
405
 364
Other current assets175
 299
196
 213
Total current assets3,777
 3,762
4,787
 2,975
Equity method investments1,304
 1,279
1,223
 1,201
Property, plant and equipment, less accumulated depreciation, 
  
 
  
depletion and amortization of $20,195 and $19,26628,382
 28,272
depletion and amortization of $22,336 and $21,89528,426
 28,145
Goodwill528
 525
499
 499
Other noncurrent assets1,118
 1,468
1,216
 2,800
Total assets$35,109
 $35,306
$36,151
 $35,620
Liabilities 
  
 
  
Current liabilities: 
  
 
  
Commercial paper$—
 $200
$—
 $135
Accounts payable2,284
 2,324
2,382
 2,206
Payroll and benefits payable182
 217
180
 240
Accrued taxes1,892
 1,983
1,476
 1,445
Other current liabilities203
 173
208
 239
Long-term debt due within one year68
 184
68
 68
Total current liabilities4,629
 5,081
4,314
 4,333
Long-term debt6,476
 6,512
6,392
 6,394
Deferred tax liabilities2,401
 2,432
2,517
 2,492
Defined benefit postretirement plan obligations850
 856
660
 604
Asset retirement obligations1,795
 1,749
2,062
 2,009
Deferred credits and other liabilities370
 393
401
 444
Total liabilities16,521
 17,023
16,346
 16,276
Commitments and contingencies

 



 

Stockholders’ Equity 
  
 
  
Preferred stock – no shares issued or outstanding (no par value, 
  
   
26 million shares authorized)—
 —
—
 —
Common stock: 
  
 
  
Issued – 770 million and 770 million shares (par value $1 per share,      
1.1 billion shares authorized)770
 770
770
 770
Securities exchangeable into common stock – no shares issued or 
  
 
  
outstanding (no par value, 29 million shares authorized)—
 —
—
 —
Held in treasury, at cost – 62 million and 63 million shares(2,527) (2,560)
Held in treasury, at cost – 89 million and 73 million shares(3,445) (2,903)
Additional paid-in capital6,618
 6,616
6,599
 6,592
Retained earnings14,153
 13,890
16,151
 15,135
Accumulated other comprehensive loss(426) (433)(270) (250)
Total equity18,588
 18,283
Total stockholders' equity19,805
 19,344
Total liabilities and stockholders' equity$35,109
 $35,306
$36,151
 $35,620
 The accompanying notes are an integral part of these consolidated financial statements.

4


MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows (Unaudited)
Three Months EndedThree Months Ended
March 31,March 31,
(In millions)2013 20122014 2013
Increase (decrease) in cash and cash equivalents      
Operating activities: 
  
 
  
Net income$383
 $417
$1,149
 $383
Adjustments to reconcile net income to net cash provided by operating activities: 
  
 
  
Discontinued operations(609) (3)
Deferred income taxes44
 (22)105
 45
Depreciation, depletion and amortization747
 574
697
 720
Impairments38
 262
17
 38
Pension and other postretirement benefits, net7
 (29)21
 7
Exploratory dry well costs and unproved property impairments404
 58
43
 404
Net gain on disposal of assets(109) (166)(2) (109)
Equity method investments, net(48) (21)(43) (48)
Changes in:   
   
Current receivables(4) (296)(46) 39
Inventories(15) 7
(41) (17)
Current accounts payable and accrued liabilities(54) 213
129
 (71)
All other operating, net135
 (24)(28) 115
Net cash provided by continuing operations1,392
 1,503
Net cash provided by discontinued operations78
 25
Net cash provided by operating activities1,528
 973
1,470
 1,528
Investing activities: 
  
 
  
Additions to property, plant and equipment(1,375) (1,017)(1,051) (1,321)
Disposal of assets312
 208
2,123
 312
Investments - return of capital18
 15
20
 18
Investing activities of discontinued operations(49) (54)
All other investing, net8
 (12)5
 8
Net cash used in investing activities(1,037) (806)
Net cash provided by (used in) investing activities1,048
 (1,037)
Financing activities: 
  
 
  
Commercial paper, net(200) —
(135) (200)
Debt repayments(114) (53)—
 (114)
Purchases of common stock(551) —
Dividends paid(120) (121)(133) (120)
All other financing, net21
 17
9
 21
Net cash used in financing activities(413) (157)(810) (413)
Effect of exchange rate changes on cash6
 10
(8) 6
Net increase in cash and cash equivalents84
 20
1,700
 84
Cash and cash equivalents at beginning of period684
 493
264
 684
Cash and cash equivalents at end of period$768
 $513
$1,964
 $768
 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 inAs the first quarter of 2013, we changed the presentation of our consolidated statements of income, primarily to present additional details of revenues and expenses and to classify certain expenses more consistently with our peer group of independent exploration and production companies. To effect these changes, reclassifications of previously reported amounts were made and are reflected in these consolidated financial statements. As a result of the reclassifications, general and administrative expenses forsale of our Angola assets (see Note 5), the first quarter of 2012 increased by $39 million which primarily includes certain costs associated withAngola operations support and operations management. Offsetting reductions are reflected as discontinued operations in production, other operatingall periods presented. The disclosures in this report related to results of operations and exploration expenses and taxes other than income.cash flows are presented on the basis of continuing operations, unless otherwise noted.
These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Marathon Oil Corporation 20122013 Annual Report on Form 10-K.  The results of operations for the first quarter of of 20132014 are not necessarily indicative of the results to be expected for the full year.
2.   Accounting Standards
Not Yet Adopted
In April 2014, the Financial Accounting Standards Board ("FASB") issued an amendment to accounting standards that changes the criteria for reporting discontinued operations while enhancing related disclosures.  Under the amendment, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization’s operations and financial results. Examples include disposal of a major geographic area, a major line of business, or a major equity method investment.  Expanded disclosures about the assets, liabilities, income, and expenses of discontinued operations will be required.  In addition, disclosure of the pretax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting will be made in order to provide users with information about the ongoing trends in an organization’s results from continuing operations.  The amendments are effective for us in the first quarter of 2015 and early adoption is permitted. We are evaluating the provisions of this amendment and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.
Recently Adopted
In June 2013, the FASB ratified the Emerging Issues Task Force consensus which requires that an unrecognized tax benefit (or a portion thereof) 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 was effective for us beginning in the first quarter of 2014 and is required to be applied prospectively. Adoption of this standard did not 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.Generally Accepted Accounting Principles. This accounting standards update iswas effective for us beginning in the first quarter of 2014 and should be applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that exist at the beginning of 2014. Early adoption is permitted. We are currently evaluating the potential impact of this accounting standards update on our consolidated results of operations, financial position and 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 Note14.applied retrospectively. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

6

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


In December 2011, an accounting standards update designed to enhance disclosures about offsetting assets and liabilities was issued. Further clarification limiting the scope of these disclosures to derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions was issued in January 2013. The disclosures are intended to enable financial statement users to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. Entities are required to disclose both gross information and net information about in-scope financial instruments that are either offset in the statement of financial position or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. The accounting standards update was effective for us beginning the first quarter of 2013 and we include the required disclosures in Note 12. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.
3.   Variable Interest Entity
The owners of the Athabasca Oil Sands Project (“AOSP”), in which we hold a 20 percent undivided interest, contracted with a wholly-ownedwholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton.  The contract, originally signed in 1999 by a company we acquired, allows each holder of an undivided interest in the AOSP to ship materials in accordance with its undivided interest.  Costs under this contract are accrued and recorded on a monthly basis, with current liabilities of $2 million and $3 million recorded at March 31, 20132014 and , consistent with December 31, 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.2013.  This contract qualifies as a variable interest contractual arrangement and the Corridor Pipeline qualifies as a variable interest entity (“VIE”).  We hold a variable interest but are not the primary beneficiary because our shipments are only 20 percent of the total; therefore the Corridor Pipeline is not consolidated by us.  Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was $711741 million as of March 31, 20132014.  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

6

MARATHON OIL CORPORATION
Notes to Corridor Pipeline and we do not have any guarantees of such assistance in the future.Consolidated Financial Statements (Unaudited)


4.    Income per Common Share
Basic income per share is based on the weighted average number of common shares outstanding.  Diluted income per share assumes exercise of stock options and stock appreciation rights, provided the effect is not antidilutive.
 Three Months Ended March 31,
 2013 2012
(In millions, except per share data)Basic Diluted Basic Diluted
Net income$383
 $383
 $417
 $417
        
Weighted average common shares outstanding708
 708
 706
 706
Effect of dilutive securities—
 4
 —
 4
Weighted average common shares, including       
dilutive effect708
 712
 706
 710
Per share: 
  
  
  
Net income
$0.54
 
$0.54
 
$0.59
 
$0.59
The per share calculations above exclude 6 million and 7 million stock options and stock appreciation rights for the first quarters of 2013 and 2012 that were antidilutive.
        
 Three Months Ended March 31,
 2014 2013
(In millions, except per share data)Basic Diluted Basic Diluted
Income from continuing operations$540
 $540
 $380
 $380
Discontinued operations609
 609
 3
 3
Net income$1,149
 $1,149
 $383
 $383
        
Weighted average common shares outstanding693
 693
 708
 708
Effect of dilutive securities—
 3
 —
 4
Weighted average common shares, including       
dilutive effect693
 696
 708
 712
Per share: 
  
  
  
Income from continuing operations$0.78
 $0.77
 $0.54
 $0.54
Discontinued operations$0.88
 $0.88
 $—
 $—
Net income$1.66
 $1.65
 $0.54
 $0.54
The per share calculations above exclude 5 million and 6 million stock options for the first three months of 2014 and 2013 as they were antidilutive.
5. Dispositions
2014 - International Exploration and Production ("E&P") Segment
In the first quarter of 2014, we closed the sales of our non-operated 10 percent working interests in the Production Sharing Contracts and Joint Operating Agreements for Angola Blocks 31 and 32 for aggregate proceeds of approximately $2 billion. A $576 million after-tax gain on the sale of our Angola assets was recorded in the first quarter of 2014. Included in this after-tax gain is a deferred tax benefit reflecting our ability to utilize foreign tax credits that would have otherwise needed a valuation allowance. Our Angola operations are reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for all periods presented.
Select amounts reported in discontinued operations were as follows:
 Three Months Ended March 31,
(In millions)2014 2013
Revenues applicable to discontinued operations$58
 $86
Pretax income from discontinued operations (a)
$51
 $41
Pretax gain on disposition of discontinued operations$470
 $—
(a) After-tax income of $33 million and $3 million for the three months ended March 31, 2014 and 2013.


7

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


5.   DispositionsAssets held for sale in the December 31, 2013 consolidated balance sheet related to the Angola Block 31 disposition that was pending at that date included:
(In millions)December 31, 2013
Other current assets$41
Other noncurrent assets1,647
Total assets$1,688
Other current liabilities$25
Deferred credits and other liabilities43
Total liabilities$68
2013 - North America Exploration and Production ("E&P")&P Segment
In April 2013, we reached an agreement to sell our interests in the DJ Basin. The transaction is expected to close in mid-2013 and a second quarter loss of approximately $115 million, before closing adjustments, is anticipated on this disposition.
In February 2013, we entered an agreement to conveyconveyed our interestinterests in the Marcellus natural gas shale play to the operator. A $43$43 million pretax loss on this transaction was recorded in the first quarter of 2013.
In February 2013, we closed the sale of our interest in the Neptune gas plant, located onshore Louisiana, for proceeds of $166$166 million. A $98 million. A $98 million pretax gain before closing adjustments, was recorded in the first quarter of 2013.
In January 2013, we closed the sale of our remaining assets in Alaska, for proceeds of $195$195 million,, subject to a six-month escrow of $50$50 million for various indemnities. which was collected in July 2013. A $46$46 million pretax gain, before closing adjustments, was recorded in the first quarter of 2013.
2012 - North America E&P Segment
In January 2012, we closed on the sale of our interests in several Gulf of Mexico crude oil pipeline systems for proceeds of $206 An additional $9 million.  This included our equity method interests in Poseidon Oil Pipeline Company, L.L.C. and Odyssey Pipeline L.L.C., as well as certain other oil pipeline interests, including the Eugene Island pipeline system.  A pretax gain of $166 millionwas recorded after finalizing closing adjustments in the firstsecond quarter of 2012.2013.
  
6.    Segment Information
  Beginning in 2013, we changed our reportable segments and revised our management reporting to better reflect the growing importance of United States unconventional resource plays to our business. All periods presented have been recast to reflect these new segments.
We have three reportable operating segments.  Each of these segments is organized and managed based upon both geographic location and the nature of the products and services it offers.
North America E&P ("N.A. E&P") – explores for, produces and markets liquid hydrocarbons and natural gas in North America;
International E&P ("Int'l E&P") – explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets products manufactured from natural gas, such as liquefied natural gas ("LNG")and methanol, in Equatorial Guinea; and
Oil Sands Mining (“OSM”) – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”).  Segment income represents income from continuing operations excluding certain items not allocated to segments, as discussed below, net of income taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. These costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities, net of associated income tax effects.activities. Unrealized gains or losses on crude oil derivative instruments, certain impairments, gains or losses on disposal of assetsdispositions 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 includedAs discussed in “Items not allocated to segments, net of income taxes”Note 5, in the reconciliation below. Total capital expenditures include accruals but not corporate activities.first quarter of 2014, we sold our Angola assets. The Angola operations are reflected as discontinued operations and excluded from the International E&P segment in all periods presented.

8

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Three Months Ended March 31, 2014
Three Months Ended March 31, 2013  Not Allocated  
(In millions)N.A. E&P Int'l E&P OSM TotalN.A. E&P Int'l E&P OSM to Segments Total
Revenues:       
Sales and other operating revenues$1,215
 $1,887
 $388
 $3,490
$1,392
 $1,061
 $377
 $—
 $2,830
Marketing revenues345
 85
 —
 430
440
 69
 31
 —
 540
Segment revenues$1,560
 $1,972
 $388
 3,920
Unrealized loss on crude oil derivative instruments      (50)
Total revenues      $3,870
1,832
 1,130
 408
 —
 3,370
Segment income (loss)$(59) $453
 $38
 $432
Income from equity method investments—
 118
 —
 118
—
 137
 —
 —
 137
Net gain on disposal of assets and other income3
 17
 2
 —
 22
Less:         
Production expenses211
 171
 231
 —
 613
Marketing costs440
 69
 31
 —
 540
Exploration expenses57
 19
 —
 —
 76
Depreciation, depletion and amortization478
 207
 52
 737
515
 125
 45
 12
 697
Impairments17
 —
 —
 —
 17
Other expenses (a)
110
 54
 13
 129
(c) 
306
Taxes other than income90
 3
 5
 —
 98
Net interest and other—
 —
 —
 52
 52
Income tax provision (benefit)(30) 1,142
 13
 1,125
153
 512
 21
 (96) 590
Capital expenditures970
 225
 45
 1,240
Segment income/Income from continuing operations$242
 $331
 $64
 $(97) $540
Capital expenditures (b)
$867
 $171
 $68
 $3
 $1,109
(a)
Includes other operating expenses and general and administrative expenses.
(b)
Includes accruals.
(c)
Includes pension settlement loss of $63 million.
Three Months Ended March 31, 2013
Three Months Ended March 31, 2012  Not Allocated  
(In millions)N.A. E&P Int'l E&P OSM TotalN.A. E&P Int'l E&P OSM to Segments Total
Revenues:       
Sales and other operating revenues$912
 $1,663
 $379
 $2,954
$1,215
 $1,801
 $388
 $(50)
(c) 
$3,354
Marketing revenues775
 64
 —
 839
345
 85
 —
 —
 430
Total revenues$1,687
 $1,727
 $379
 $3,793
1,560
 1,886
 388
 (50) 3,784
Segment income$104
 $407
 $38
 $549
Income from equity method investments1
 77
 —
 78
—
 118
 —
 —
 118
Net gain on disposal of assets and other income—
 16
 —
 102
 118
Less:         
Production expenses184
 109
 271
 —
 564
Marketing costs347
 82
 —
 —
 429
Exploration expenses435
 28
 —
 —
 463
Depreciation, depletion and amortization314
 200
 49
 563
478
 180
 52
 10
 720
Income tax provision61
 971
 13
 1,045
Capital expenditures829
 138
 52
 1,019
Impairments23
 —
 —
 15
 38
Other expenses (a)
106
 65
 8
 104
 283
Taxes other than income76
 2
 6
 —
 84
Net interest and other—
 —
 —
 72
 72
Income tax provision (benefit)(30) 1,100
 13
 (96) 987
Segment income/Income from continuing operations$(59) $454
 $38
 $(53) $380
Capital expenditures (b)
$970
 $171
 $45
 $30
 $1,216
(a)
Includes other operating expenses and general and administrative expenses.
(b)
Includes accruals.
(c)
Unrealized loss on crude oil derivative instruments.

The following reconciles total revenues to sales and other operating revenues as reported in the consolidated statements of income:
 Three Months Ended March 31,
(In millions)2013 2012
Total revenues$3,870
 $3,793
Less:  Marketing revenues430
 839
Sales and other operating revenues, including related party$3,440
 $2,954

The following reconciles segment income to net income as reported in the consolidated statements of income:
 Three Months Ended March 31,
(In millions)2013 2012
Segment income$432
 $549
Items not allocated to segments, net of income taxes: 
  
Corporate and other unallocated items(71) (71)
Unrealized loss on crude oil derivative instruments(32) —
     Impairments(10) (167)
     Net gain on dispositions64
 106
Net income$383
 $417

9

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


        
7.    Defined Benefit Postretirement Plans
The following summarizes the components of net periodic benefit cost:
Three Months Ended March 31,Three Months Ended March 31,
Pension Benefits Other BenefitsPension Benefits Other Benefits
(In millions)2013 2012 2013 20122014 2013 2014 2013
Service cost$14
 $12
 $1
 $1
$14
 $14
 $1
 $1
Interest cost15
 16
 3
 4
16
 15
 3
 3
Expected return on plan assets(17) (16) —
 —
(18) (17) —
 —
Amortization: 
  
  
  
 
  
  
  
– prior service cost (credit)2
 2
 (2) (2)1
 2
 (1) (2)
– actuarial loss13
 12
 —
 —
6
 13
 —
 —
Net settlement loss(a)
63
 —
 —
 —
Net periodic benefit cost$27
 $26
 $2
 $3
$82
 $27
 $3
 $2
(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 first quarter of 2014.
During the first quarter of 2014, we recorded the effects of partial settlements of our United States ("U.S.") pension plans and we remeasured the plans' assets and liabilities as of March 31, 2014. As a result, we recognized a pretax increase of $36 million in actuarial losses, net of settlement loss, in other comprehensive income for the three months ended March 31, 2014.
During the first three months of 20132014, we made contributions of $920 million to our funded pension plans.  We expect to make additional contributions up to an estimated $5557 million to our funded pension plans over the remainder of 20132014.  Current benefit payments related to unfunded pension and other postretirement benefit plans were $940 million and $4 million during the first three months of 20132014.
8.   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.income, and foreign currency remeasurement, net of any foreign currency hedge effects. The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments. The difference between the total provision and the sum of the amounts allocated to segments andis reported in the “Not Allocated to items not allocated to segments is presented in Corporate and other unallocated itemsSegments” column of the tables in Note 6.
Our effective income tax rates inon continuing operations for the first three months of 20132014 and 20122013 were 7352 percent and 6972 percent.  These rates are higher than the U.S. statutory rate of 35 percent due to earnings from foreign jurisdictions, primarily Norway in 2014 and 2013 and Libya in 2013, where the tax rates are in excess of the U.S. statutory rate.  The decrease in the effective tax rate on continuing operations in the first three months of 2014 is due to higher projected annual ordinary income from our North American operations, which are in a lower tax jurisdiction, and pretax losses in Libya.
The tax provision (benefit) applicable to Libyan ordinary income (loss) was recorded as a discrete item in the first three months of 2014 and 2013.  Excluding Libya, the effective tax rates on continuing operations would be 53 percent and 64 percent for the first three months of 2014 and 2013. In Libya, where the statutory tax rate is in excess of 90 percent, we have had no oil liftings since July 2013 due to third-party labor strikes at the Es Sider oil terminal and there remains uncertainty around sustainedfuture production and sales levels. Reliable estimates of 2014 and 2013 and 2012Libyan annual ordinary income from our Libyan operations could not be made and the range of possible scenarios when including ordinary income from our Libyan operations in the worldwide annual effective tax rate calculation demonstrates significant variability.  As such, for the first three months of 20132014 and 2012, an2013, 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.  Excluding Libya, the effective tax rate would be Libya.65 percent and 64 percent for the first three months of 2013 and 2012.
9.   Inventories
 Inventories are carried at the lower of cost or market value.
 March 31, December 31,
(In millions)2013 2012
Liquid hydrocarbons, natural gas and bitumen$54
 $73
Supplies and other items314
 288
Inventories, at cost$368
 $361

10

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


9.   Inventories
 Inventories are carried at the lower of cost or market value.
 March 31, December 31,
(In millions)2014 2013
Liquid hydrocarbons, natural gas and bitumen$68
 $55
Supplies and other items337
 309
Inventories, at cost$405
 $364
10.  Property, Plant and Equipment
March 31, December 31,March 31, December 31,
(In millions)2013 20122014 2013
North America E&P$24,500
 $23,748
$27,309
 $26,755
International E&P13,429
 13,214
12,519
 12,428
Oil Sands Mining10,171
 10,127
10,514
 10,436
Corporate477
 449
420
 421
Total property, plant and equipment48,577
 47,538
50,762
 50,040
Less accumulated depreciation, depletion and amortization(20,195) (19,266)(22,336) (21,895)
Net property, plant and equipment$28,382
 $28,272
$28,426
 $28,145
InBeginning in the firstthird quarter of 2011,2013, our Libya operations have been impacted by on-going third-party labor strikes at the Es Sider oil terminal and there remains uncertainty around future production operationsand sales levels. We have had no oil liftings in Libya were suspended. In the fourth quarter of 2011, limited production resumed.  Since that time, average sales volumes have increased to near pre-conflict levels.since July 2013. We and our partners in the Waha concessions continue to assess the situation and the condition of our assets in Libya and uncertainty around sustained production and sales levels remains.Libya. As of March 31, 2013,2014, our net property, plant and equipment investment in Libya wasis approximately $748 million.$770 million.
Exploratory well costs capitalized greater than one year after completion of drilling were $220153 million as of March 31, 2014, a net decrease of $128 million from December 31, 2013. TheThis net decrease was the result of: a decrease of $153 million due to the sale of our interests in such costs from DecemberAngola Blocks 31 2012 primarilyand 32, a decrease of $26 million due to the commencement of drilling at the Boyla development offshore Norway, and an increase of $51 million related to the conveyance of our interestShenandoah prospect in the Marcellus natural gas shale playGulf of Mexico, with costs incurred primarily in 2012 and 2013, which has now been suspended for more than one year. Additional appraisal drilling on the non-operated Shenandoah prospect is expected to the operatorbegin in February 2013.2014.
11.  Fair Value Measurements
 Fair Values - Recurring
The following tables present assets and liabilities accounted for at fair value on a recurring basis as of March 31, 20132014 and December 31, 20122013 by fair value hierarchy level.
 March 31, 2013
(In millions)Level 1 Level 2 Level 3 Collateral Total
Derivative instruments, assets         
     Commodity$—
 $8
 $—
 $1
 $9
     Interest rate—
 18
 —
 —
 18
          Derivative instruments, assets$—
 $26
 $—
 $1
 $27
Derivative instruments, liabilities         
     Commodity$—
 $6
 $—
 $—
 $6
     Foreign currency—
 20
 —
 —
 20
          Derivative instruments, liabilities$—
 $26
 $—
 $—
 $26
December 31, 2012March 31, 2014
(In millions)Level 1 Level 2 Level 3 Collateral TotalLevel 1 Level 2 Level 3 Collateral Total
Derivative instruments, assets                  
Commodity$—
 $52
 $—
 $1
 $53
Interest rate—
 21
 —
 —
 21
$—
 $7
 $—
 $—
 $7
Foreign currency—
 18
 —
 —
 18
—
 10
 —
 —
 10
Derivative instruments, assets$—
 $91
 $—
 $1
 $92
$—
 $17
 $—
 $—
 $17
Derivative instruments, liabilities         
Foreign currency$—
 $2
 $—
 $—
 $2
Derivative instruments, liabilities$—
 $2
 $—
 $—
 $2

11

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Commodity swaps in Level 2 are measured at fair value with a market approach using prices obtained from exchanges or pricing services, which have been corroborated with data from active markets for similar assets or liabilities.  Commodity options in Level 2 are valued using The Black-Scholes Model.  Inputs to this model include prices as noted above, discount factors, and implied market volatility.  The inputs to this fair value measurement are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.  Collateral deposits related to commodity derivatives are in broker accounts covered by master netting agreements.
 December 31, 2013
(In millions)Level 1 Level 2 Level 3 Collateral Total
Derivative instruments, assets         
Interest rate$—
 $8
 $—
 $—
 $8
Foreign currency—
 2
 —
 —
 2
Derivative instruments, assets$—
 $10
 $—
 $—
 $10
Derivative instruments, liabilities         
     Foreign currency$—
 $4
 $—
 $—
 $4
Derivative instruments, liabilities$—
 $4
 $—
 $—
 $4
Interest rate swaps are measured at fair value with a market approach using actionable broker quotes which are Level 2 inputs.  Foreign currency forwards are measured at fair value with a market approach using third-party pricing services, such as Bloomberg L.P., which have been corroborated with data from active markets for similar assets or liabilities, and are Level 2 inputs.
Fair Values - Nonrecurring
The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.
 Three Months Ended March 31,
 2013 2012
(In millions)Fair Value Impairment Fair Value Impairment
Long-lived assets held for use$—
 $38
 $75
 $262

 Three Months Ended March 31,
 2014 2013
(In millions)Fair Value Impairment Fair Value Impairment
Long-lived assets held for use$—
 $17
 $—
 $38
All long-lived assets held for use that were impaired in the first quarters of 20132014 and 20122013 were held by our North America E&P segment. The fair values of each discussed below were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs.  Inputs to the fair value measurement included reserve and production estimates made by our reservoir engineers, estimated commodity prices adjusted for quality and location differentials, and forecasted operating expenses for the remaining estimated life of the reservoir.
The Ozona development in the Gulf of Mexico ceased producing in the first quarter of 2013 and a $21 million impairment was recorded. In the first quarter of 2014, we recorded an additional $17 million impairment as a result of estimated abandonment cost revisions.
In the first quarter of 2013, as a result of our decision to wind down operations in the Powder River Basin due to poor economics, an impairment of $15 million was recorded.
In early 2012, production rates from the Ozona development in the Gulf of Mexico declined significantly. Accordingly, our reserve engineers prepared evaluations of our future production as well as our reserves and an impairment of $261 million was recorded in the first quarter of 2012.  As the development produced towards abandonment pressures, further downward revisions of reserves were taken, resulting in an additional impairment recorded in the fourth quarter of 2012. Ozona production ceased in the first quarter of 2013 and an additional $21 million impairment was recorded.
Other impairments of long-lived assets held for use by our North America E&P segment in the first quartersquarter of 2013 and 2012 were a result of reduced drilling expectations, reductions of estimated reserves or declining natural gas prices.
Fair Values – Financial Instruments
Our current assets and liabilities include financial instruments, the most significant of which are receivables, commercial paper and payables. We believe the carrying values of our receivables, commercial paper and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our investment-grade credit rating, and (3) our historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk.

12

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


The following table summarizes financial instruments, excluding receivables, commercial paper, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at March 31, 20132014 and December 31, 2012.2013.

12

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


March 31, 2013 December 31, 2012March 31, 2014 December 31, 2013
Fair Carrying Fair CarryingFair Carrying Fair Carrying
(In millions)Value Amount Value AmountValue Amount Value Amount
Financial assets              
Other noncurrent assets$174
 $169
 $189
 $186
$154
 $147
 $154
 $147
Total financial assets 174
 169
 189
 186
154
 147
 154
 147
Financial liabilities 
  
  
  
 
  
  
  
Other current liabilities13
 13
 13
 13
13
 13
 13
 13
Long-term debt, including current portion(a)
7,347
 6,494
 7,610
 6,642
7,020
 6,427
 6,922
 6,427
Deferred credits and other liabilities146
 141
 94
 94
153
 149
 149
 147
Total financial liabilities $7,506
 $6,648
 $7,717
 $6,749
$7,186
 $6,589
 $7,084
 $6,587
(a)      Excludes capital leases.
Fair values of our financial assets included in other noncurrent assets and of our financial liabilities included in other current liabilities and deferred credits and other liabilities are measured using an income approach and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value.
Most of our long-term debt instruments are publicly-traded. A market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is used to measure the fair value of such debt. Because these quotes cannot be independently verified to an active market they are considered Level 3 inputs. The fair value of our debt that is not publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.

13

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


12. Derivatives
For further information regarding the fair value measurement of derivative instruments, see Note 11. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. Netting is assessed by counterparty, and as of March 31, 20132014 and December 31, 2012,2013, there were no offsetting amounts. Positions by contract were all either assets or liabilities. The following tables present the gross fair values of derivative instruments, excluding cash collateral, and the reported net amounts along with where they appear on the consolidated balance sheets as of March 31, 2013 and December 31, 2012.
 March 31, 2013  
(In millions)Asset Liability Net Asset Balance Sheet Location
Fair Value Hedges       
     Interest rate$18
 $—
 $18
 Other noncurrent assets
Total Designated Hedges18
 —
 18
  
        
Not Designated as Hedges       
     Commodity8
 —
 8
 Other current assets
Total Not Designated as Hedges8
 —
 8
  
     Total$26
 $—
 $26
  
 March 31, 2013  
(In millions)Asset Liability Net Liability Balance Sheet Location
Fair Value Hedges       
     Foreign currency$—
 $20
 $20
 Other current liabilities
Total Designated Hedges—
 20
 20
  
        
Not Designated as Hedges       
     Commodity—
 6
 6
 Other current liabilities
Total Not Designated as Hedges—
 6
 6
  
     Total$—
 $26
 $26
  
 December 31, 2012  
(In millions)Asset Liability Net Asset Balance Sheet Location
Fair Value Hedges       
     Foreign currency$18
 $—
 $18
 Other current assets
     Interest rate21
 —
 21
 Other noncurrent assets
Total Designated Hedges39
 —
 39
  
        
Not Designated as Hedges       
     Commodity52
 —
 52
 Other current assets
Total Not Designated as Hedges52
 —
 52
  
     Total$91
 $—
 $91
  
Derivatives Designated as Fair Value Hedges
As of March 31, 2013 and December 31, 2012, we had multiple interest rate swap agreements with a total notional amount of $600 million with a maturity date of October 1, 2017 at a weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate of 4.69 percent2014 and 4.70 percentDecember 31, 2013.
 March 31, 2014  
(In millions)Asset Liability Net Asset Balance Sheet Location
Fair Value Hedges       
     Interest rate$7
 $—
 $7
 Other noncurrent assets
     Foreign currency10
 —
 10
 Other current assets
Total Designated Hedges$17
 $—
 $17
  
 March 31, 2014  
(In millions)Asset Liability Net Liability Balance Sheet Location
Fair Value Hedges       
     Foreign currency$—
 $2
 $2
 Other current liabilities
Total Designated Hedges$—
 $2
 $2
  

1413

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


 December 31, 2013  
(In millions)Asset Liability Net Asset Balance Sheet Location
Fair Value Hedges       
     Interest rate$8
 $—
 $8
 Other noncurrent assets
     Foreign currency2
 —
 2
 Other current assets
Total Designated Hedges$10
 $—
 $10
  
        
 December 31, 2013  
(In millions)Asset Liability Net Liability Balance Sheet Location
Fair Value Hedges       
     Foreign currency$—
 $4
 $4
 Other current liabilities
Total Designated Hedges$—
 $4
 $4
  
Derivatives Designated as Fair Value Hedges
The following table presents by maturity date, information about our interest rate swap agreements as of March 31, 2014 and December 31, 2013, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.
 Aggregate NotionalMarch 31, 2014 December 31, 2013
 AmountWeighted Average, LIBOR-Based,
Maturity Dates(in millions)Floating Rate
October 1, 2017$600
4.64% 4.65%
March 15, 2018$300
4.49% 4.50%
As of March 31, 20132014 and December 31, 20122013, our foreign currency forwards had an aggregate notional amount of 3,5714,261 million and 3,0432,387 million Norwegian Kroner at a weighted average forward raterates of 5.6786.069 and 5.780.6.060. These forwards hedge our current Norwegian tax liability and those outstanding at March 31, 2014 have settlement dates through August 20132014.
The pretax effect of derivative instruments designated as hedges of fair value in our consolidated statements of income are summarized in the table below. There is no ineffectiveness related to the fair value hedges.
 Gain (Loss) Gain (Loss)
 Three Months Ended March 31, Three Months Ended March 31,
(In millions)Income Statement Location2013 2012Income Statement Location2014 2013
Derivative        
Interest rateNet interest and other$(3) $(1)Net interest and other$(1) $(3)
Foreign currencyProvision for income taxes$(25) $(8)Provision for income taxes$3
 $(25)
Hedged Item  
  
  
  
Long-term debtNet interest and other$3
 $1
Net interest and other$1
 $3
Accrued taxesProvision for income taxes$25
 $8
Provision for income taxes$(3) $25
 Derivatives not Designated as Hedges
In August 2012, we entered into crude oil derivatives related to a portion of our forecast North America E&P crude oil sales through December 31, 2013. These commodity derivatives were not designated as hedges and are shown in the table below.
Remaining TermBbls per DayWeighted Average Price per BblBenchmark
Swaps   
April 2013 - December 201320,000$96.29West Texas Intermediate
April 2013 - December 201325,000$109.19Brent
Option Collars   
April 2013 - December 201315,000$90.00 floor / $101.17 ceilingWest Texas Intermediate
April 2013 - December 201315,000$100.00 floor / $116.30 ceilingBrent
The impact of all commodity derivative instruments not designated as hedges appears in the sales and other operating revenues including related party, line ofin our consolidated statements of income and was a net loss of $55$55 million in the first quarter of 2013 and a net gain of $2 million in the first quarter of 2012.
2013.

1514

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


13.    Incentive Based Compensation
 Stock option and restricted stock awards
  The following table presents a summary of stock option and restricted stock award activity for the first quarterthree months of 20132014: 
 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
Granted1,002,400
(a) 

$32.86
 137,722
 
$33.04
Options Exercised/Stock Vested(839,273)

$21.33
 (493,840) 
$30.66
Cancelled(215,262)

$35.17
 (78,778) 
$28.98
Outstanding at March 31, 201319,484,830
 
$26.65
 3,742,988
 
$28.96
 Stock Options Restricted Stock
 
Number of
Shares
 
Weighted
Average
Exercise Price
 Awards 
Weighted
Average Grant
Date Fair Value
Outstanding at December 31, 201318,104,887
 
$27.27
 4,031,888
 
$31.80
Granted901,447
(a) 

$33.94
 138,851
 
$33.85
Options Exercised/Stock Vested(289,709) 
$20.89
 (368,263) 
$33.60
Canceled(246,363) 
$33.60
 (201,215) 
$31.33
Outstanding at March 31, 201418,470,262
 
$27.61
 3,601,261
 
$31.72
(a)    The weighted average grant date fair value of stock option awards granted was $10.5010.47 per share.
PerformanceStock-based performance unit awards
 During the first quarter of 2013,2014, we granted 353,600221,491 stock-based performance units to certain officers that provide a cash payout upon the achievement of certain performance goals at the end of a 36-month performance period.officers. 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.per unit was $34.28.
14.  Reclassifications Out of Accumulated Other Comprehensive Loss
The following table presents a summary of amounts reclassified from accumulated other comprehensive loss forto net income in their entirety:
 Three Months Ended March 31,  
(In millions)2014 2013 Income Statement Line
Accumulated Other Comprehensive Loss Components  
 Income (Expense)  
Postretirement and postemployment plans    
Amortization of actuarial loss$(6) $(13) General and administrative
Net settlement loss(63) —
 General and administrative
 (69) (13) Income from operations
 23
 5
 Provision for income taxes
Total reclassifications for the period$(46) $(8) Net income
15.  Stockholders' Equity
During the first quarter of 2013:2014, we acquired 16 million common shares at a cost of $551 million under our share repurchase program.
16.  Supplemental Cash Flow Information
 Three Months Ended March 31, 2013
(In millions) Reclassified to Income (Expense) Income Statement Line
Accumulated Other Comprehensive Loss Components    
Amortization of postretirement and postemployment plans    
Actuarial loss $(13) General and administrative
  5
 Provision for income taxes
Total reclassifications for the period $(8) Net income
 Three Months Ended March 31,
(In millions)2014 2013
Net cash provided from operating activities:   
Interest paid (net of amounts capitalized)$56
 $61
Income taxes paid to taxing authorities453
 1,003
Commercial paper, net: 
  
Commercial paper - issuances$2,235
 $200
- repayments(2,370) (400)
Noncash investing activities, related to continuing operations: 
  
Asset retirement costs capitalized$37
 $27
Change in capital expenditure accrual58
 (105)
Asset retirement obligations assumed by buyer43
 88
Receivable for disposal of assets44
 50

1615

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


15.  Supplemental Cash Flow Information
 Three Months Ended March 31,
(In millions)2013 2012
Net cash provided from operating activities:   
Interest paid (net of amounts capitalized)$61
 $50
Income taxes paid to taxing authorities1,003
 828
Commercial paper, net: 
  
Commercial paper - issuances$200
 $100
- repayments(400) (100)
Noncash investing activities: 
  
Asset retirement costs capitalized$27
 $1
Change in capital expenditure accrual(105) 46
Asset retirement obligations assumed by buyer

88
 7
Receivable for disposal of assets50
 —
16.17.   Commitments and Contingencies
 We are a defendant in a number of lawsuits arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims.  While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.  Certain of these matters are discussed below.
Litigation– In March 2011, Noble Drilling (U.S.) LLC (“Noble”) filed a lawsuit against us in the District Court of Harris County, Texas, alleging, among other things, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation, relating to a multi-year drilling contract for a newly constructed drilling rig to be deployed in the U.S. Gulf of Mexico.  We filed an answer in April 2011, contending, among other things, failure to perform, failure to comply with material obligations, failure to mitigate alleged damages and that Noble failed to provide the rig according to the operating, performance and safety requirements specified in the drilling contract. In April 2013, we filed a counterclaim against Noble alleging, among other things, breach of contract and breach of the duty of good faith relating to the multi-year drilling contract. The counterclaim also included a breach of contract claim for reimbursement for the value of fuel used by Noble under an offshore daywork drilling contract. We are vigorously defending this litigation.  The ultimate outcome of this lawsuit, including any financial effect on us, remains uncertain.  We do not believe an estimate of a reasonably probable loss (or range of loss) can be made for this lawsuit at this time.
Contractual commitments – At March 31, 20132014, Marathon’s contract commitments to acquire property, plant and equipment were $1,209 million.$1,190 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 periods presented have been recast to reflect these new segments.
We are an international energy company based in Houston, Texas, with operationsactivities in the United States, Canada,North America, Europe, Africa the Middle East and Europe.Asia.  We have three reportable operating segments. Each of these segments is organized and managed based upon both geographic location and the nature of the products and services it offers.
North America Exploration and Production ("E&P")&P – explores for, produces and markets liquid hydrocarbons and natural gas in North America;
International E&P – explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in Equatorial Guinea;Guinea ("E.G."); and
Oil Sands Mining – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
 Certain sections of this Quarterly Report on Form 10-Q, including Management’s Discussion and Analysis of Financial Condition and Results of Operations, contain forward-looking statements concerning trends or events potentially affecting our business.  These statements typically contain words such as “anticipates,” “believes,” “estimates,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain.  In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements.  For additional risk factors affecting our business, see Item 1A. Risk Factors in our 20122013 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 first quarter of 20132014, notable itemsactivities were:
TotalIncreased net sales volumesincome per diluted share to $1.65, which includes $0.83 per diluted share related to the after-tax gain on the sale of our Angola assets, an increase of over 200 percent from the same quarter of last year
Increased income from continuing operations per diluted share to $0.77, up 43 percent from the same quarter of last year
Three high-quality U.S. resource plays averaged 523net production of 154 thousand barrels of oil equivalent per day (“mboed”("mboed"), a 22up 26 percent increase overfrom the samefirst quarter of last year2013
◦Eagle Ford downspacing results continued to consistently outperform modeled type curves
◦Austin Chalk and Eagle Ford co-development continuing on plan with completion of first 2014 Austin Chalk well at 30-day initial production ("IP") rate of 1,600 barrels of oil equivalent per day ("boed")
◦Bakken and Three Forks co-development progressing with high density pilots delivering strong results; testing eight wells per 1,280-acre drilling spacing unit
◦Bakken recompletions program delivered five wells with initial 24-hour and 30-day IP rates exceeding expectations
◦South Central Oklahoma Oil Province ("SCOOP") extended-reach (XL) wells delivering strong results with two wells at 30-day IP rates of up to 1,550 boed
Recorded 97 percent average operational availability for operated assets
Liquid hydrocarbonMarketing of North Sea businesses on schedule; bids due in second quarter
Closed on sales of Angola Blocks 31 and synthetic crude oil sales volumes accounted32 for 93 percent of the increase
Eagle Ford shale averaged net sales volumes of 72 mboed, a four-fold increase
Bakken shale averaged net sales volumes of 37 mboed, a 46 percent increase
Libya averaged net sales volumes of 38 mboed, a 123 percent increase
Oil Sands Mining averaged net sales volumes of 51 thousand barrels per day ("mbbld"), a 16 percent increase
Sale of our interest in the Neptune gas plant closed foraggregate cash proceeds of $166approximately $2 billion, resulting in after-tax gain of $576 million before closing adjustments
SaleCompleted second phase of our Alaska assets closed for proceeds of $195$1 billion share repurchase; initiated additional $500 million subject to a six-month escrow of $50share repurchase
Significant second quarter activity through May 7, 2014 includes:
Substantially completed additional $500 million and closing adjustmentsshare repurchase
Government approval received for acquisition of a 20 percent non-operated interest in the onshore South Omo concession in Ethiopia, and exploratory drilling commenced
Successful appraisal well on non-operated Shenandoah prospect in the Gulf of Mexico announced
Sales commenced at the PSVM development located on the northeastern portion of Angola Block 31
Apparent high bidder on two blocks in the March 2013 Gulf of Mexico lease sale
Unproved property impairments of approximately $340 million recorded related to expiring Eagle Ford leases and leases we do not intend to drill
Changed reportable segments to reflect the growing importance of the United States unconventional resource plays



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Some significant second quarter activities through May 10, 2013 include:
Decision made to conclude exploration activities in Poland
Agreement reached to sell interests in DJ Basin
Turnaround in Equatorial Guinea started and safely completed in April, eight days ahead of schedule and below budget

Overview and Outlook
Our net sales volumes from continuing operations for the first quarter of 2014 averaged 457 mboed compared to 514 mboed for the first quarter of 2013. Excluding Libya, where we had no oil liftings in the first quarter of 2014 as a result of on-going third-party labor strikes at the Es Sider oil terminal, our net sales volumes from continuing operations for the first quarter of 2014 averaged 457 mboed compared to 476 mboed for the first quarter of 2013. See Supplemental Statistics for a tabular presentation of net sales volumes by product and location for each period.
North America E&P
Production
 Net liquid hydrocarbon and natural gas sales volumes averaged 198213 mboed duringin the first quarter of 20132014 and 147compared to 198 mboed in the same periodfirst quarter of20122013, a 35 percent increase.for an increase of approximately 8 percent.  Net liquid hydrocarbon sales volumes increased,increased 22 thousand barrels per day ("mbbld") for the first quarter of2014, primarily reflecting the impactcontinued growth across our three U.S. resource plays partially offset by natural declines in Gulf of our ongoing development programsMexico production. Extreme winter weather impacts on availability and completion operations negatively impacted production in the Eagle Ford and Bakken shale resource plays, while netfirst quarter of 2014. Net natural gas sales volumes decreased slightly40 million cubic feet per day ("mmcfd") during the same period, due primarily to the cessation of production from operated wells in the Powder River Basin in Wyoming and to the sale of our Alaska assets in January 2013. Excluding the sales volume related to AlaskaThese decreases were somewhat offset by increases in both periods, our average net liquid hydrocarbon andassociated natural gas sales volumes increased 47 percent.production from our U.S. resource plays.
In 2013, production growth continued in the Eagle Ford shale play.– Average net sales volumes from Eagle Ford were 7296 mboed in the first quarter of 20132014 compared to 1472 mboed in the same period of 2012.2013, for an increase of 33 percent. Approximately 6465 percent of the first quarter 2013of2014 production was crude oil and condensate, 17 percent was natural gas liquids ("NGLs") and 1918 percent was natural gas.
Individual well results were strong during the quarter and continued to consistently outperform the modeled type curves. With the transition to higher density pad drilling, from an average of three to four wells per pad, coupled with a period of rebuilding uncompleted well inventory, the number of wells we brought to sales was lower compared to the fourth quarter of 2013. During the first quarter of 20132014, we reached total depth on 7683 gross operated wells and brought 6849 gross operated wells to sales. We continuesales compared to advance our drilling performance, reducing the average time76 reaching total depth and 69 brought to drill a well from 28 days in the first quarter of 2012 to 18 dayssales in the first quarter of 2013. We expect these drilling timesOur first quarter average spud-to-total depth time was 14 days, which reflected the addition and ramp up of three new rigs and an increased number of wells with longer laterals, compared to continue dropping during 12 days in the same period of 2013 as additional efficiencies are gained from pad drilling..
We continuecontinued to build infrastructure to support production growth across the Eagle Ford operating area. Approximately 148 miles of gathering lines were installed in the first quarter of 2013, while five new central gathering and treating facilities were commissioned, with two additional facilities in various stages of planning or construction. As of March 31, 2013, we transport approximately 65 percent of our crude oil and condensate by pipeline, with additional contract negotiations and facility designs under way that are expected to push that figure to 75 percent by the end of May. The ability to transport more barrels by pipeline enables us to reduce costs, improve reliability and lessen our environmental footprint.
We are confident our core Eagle Ford acreage position will be developed on a maximum of 80-acre spacing and continue to evaluate the potential of downspacing to 40-acre and 60-acre units. We have begun drilling wellsprogress co-development opportunities in the Austin Chalk. In early April, we brought online an Austin Chalk appraisal well, the Children Weston 4H, with a 30-day IP rate of 1,600 boed (76 percent liquid hydrocarbons) constrained at a 16/64 choke. This is our sixth Austin Chalk producer which continues the further appraisal of full Austin Chalk potential. Two additional Austin Chalk wells are waiting on completion and Pearsall formations to further test the potentialthree more pilot groups, with a total of these horizons. The results to-date of the downspacing pilots have been in line with our expectations, and we anticipate releasing more definitive results of both the downspacing pilots and the additional formation testing in the second half of 2013.six Austin Chalk wells, are currently drilling.
Bakken – Average net sales volumes from the Bakken shale were 3743 mboed in the first quarter of 20132014 compared to 2537 mboed in the same period of 2012.2013, for an increase of 16 percent. Our Bakken production averages approximately 90 percent crude oil, 54 percent NGLs and 56 percent natural gas. During the first quarter of 20132014, we reached total depth on 1816 gross operated wells and brought 2215 gross operated wells to sales. Our first quarter average time to drill a well was 25 days.18 days spud-to-total depth, compared to 16 days in the same period of 2013. Both our drilling and completion activities were impacted by extraordinary winter weather in the first quarter of 2014.
 InWe recompleted five wells during the first quarter of 2014 with favorable results in the Myrmidon area and have recently expanded south in the Hector area. We continue high density pilots to test 320-acre spacing for co-development with four Middle Bakken and four Three Forks wells per 1,280-acre spacing unit. Further high density pilots with up to 12 wells per 1,280-acre spacing unit are planned by the end of 2014.
Oklahoma resource basins – Net sales volumes from the Oklahoma Resource Basins, net sales volumesresource basins averaged 1315 mboed in the first quarter of 20132014 compared to 5 mboed in, for an increase of 15 percent over the same period of 2012.  All net sales2013.  Importantly, liquid hydrocarbon volumes are fromincreased approximately 28 percent compared to the Anadarko Woodford shale.first quarter of 2013. During the first quarter of 20132014, fourwe reached total depth on five gross operated wells wereand brought four gross SCOOP wells to sales. The 30-day IP rates for the two SCOOP XL wells were 990 boed (70 percent liquid hydrocarbons) and 1,550 boed (66 percent liquid hydrocarbons). We anticipate drilling two wells eachhave accumulated more than 100,000 net acres in the SCOOP area.
We continue to test other horizons in Oklahoma with two operated wells producing in the Southern Mississippi LimeTrend and the first of two Granite Wash formations during 2013.horizontal wells online. Two additional wells in the Southern Mississippi Trend are scheduled to spud in the second quarter of 2014.
Wyoming – Operated production at the Powder River Basin field ceased in March 2014. Plug and abandonment activities are expected to be completed in the fall of 2014.

18

Exploration
Exploration activity continuesGulf of Mexico – The Key Largo prospect, located on Walker Ridge Block 578, is anticipated to spud in the Gulfthird quarter of Mexico. The2014 as the first well with the new-build deepwater drillship. We are operator and hold a 60 percent working interest in the prospect.
We expect the second appraisal well on the non-operated Shenandoah prospect to be spud in the second quarter of 2014. The well will be located on Walker Ridge Block 51, in which we havehold a 10 percent outside-operated working interest, reached total depthinterest.
We have farmed into the Perseus prospect located on Desoto Canyon Blocks 143, 187, 188, 230 and 231. A well is anticipated to spud in the first quartersecond half of 2013.2014. We are currently participating inhold a Gunflint prospect appraisal well located on Mississippi Canyon Block 992 where we hold an 1830 percent non-operated working interest.
In March 2013, we submitted the apparent high bids totaling $33 million for 100 percent working interest in two blocks in Central Gulf of Mexico Lease Sale 227: Keathley Canyon Block 340 on the Colonial prospect and Keathley Canyon Block 153, an extension to the Meteor prospect on our existing Keathley Canyon 196 lease. Keathley Canyon Blocks 340 and 153 are both inboard-Paleogene prospects.
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 late 2013 or early 2014.  Upon receiving this approval, we will further evaluate our development plans.

19


International E&P
Production
Net liquid hydrocarbon and natural gas sales volumes averaged 274197 mboed during the first quarter of 20132014 and 236compared to 265 mboed in the same period of 20122013, a 1626 percentincrease.  During decrease.  We had no oil liftings in Libya in the first quarter of 2014 as a result of on-going third-party labor strikes at the Es Sider oil terminal. Excluding Libya, net sales volumes decreased 13 percent in the first quarter of2014 compared to the first quarter of2013, Libya primarily as a result of significant unplanned downtime at the non-operated Foinaven field in the United Kingdom ("U.K.") and unplanned downtime at the methanol plant in Equatorial Guinea, as well as natural decline from North Sea assets and production curtailments at Alvheim in Norway due to severe winter weather.
 Equatorial Guinea – Average net liquid hydrocarbon and natural gas sales volumes increased 21were 108 mboed in the first quarter of2014compared to 111 mboed in the same period of 2012,2013. During the first quarter of 2014, work was completed on scheduled offshore riser repairs, an unplanned repair at the methanol plant, as well as a planned 8-day partial shut-down at the LNG plant, which was accomplished ahead of schedule and under budget.
Norway – Average net sales volumes from Norway decreased 20 percent to 70 mboed in the first quarter of2014 compared to 88 mboed in the same period of 2013, primarily due to limited salesreflecting natural field production decline. Alvheim was also impacted in the first quarter of 2012 upon the resumption2014 by severe winter weather which resulted in eight days of curtailed production.
United Kingdom – Average net sales after the 2011 civil unrest.  In addition,volumes were 18 mboed in the first quarter of 20132014 includes net liquid hydrocarbon sales volumes of 9compared to 28 mboed from the PSVM development located on the northeastern portion of Angola Block 31 which had first sales in February 2013.
Strong operational performance continues in Equatorial Guinea, with availability of nearly 98 percent in the firstsame period of 2013, a 36 percent decrease as a result of reliability issues at the non-operated Foinaven field, as well as natural decline and a delayed reinstatement of gas compression at Brae. During the second quarter of 2013, which bolstered production during2014, a turnaround is planned at Brae. The reliability issues at Foinaven continue into the firstsecond quarter of 2013. We started2014 and will impact production and the timing of future liftings. Additionally, we expect a 30-day planned turnaround in Equatorial Guinea on April 1, 2013 which was safely completed eight days ahead of schedule and below budget. The Alba field, associated gas plant and liquefied natural gas facility each resumed full production on April 22, 2013.
The production declineat Foinaven to begin in the Alvheim area offshore Norway continues to be less severe than expected. These better-than-expected results have been achieved through continued strong operational performance that delivered availability of 97 percent insecond quarter and extend into the firstthird quarter of 2014.
Libya – We have had no oil liftings in Libya since July 2013 reservoir and well performancedue to ongoing third-party labor strikes at the upper end of expectations primarily due to a delay in anticipated water breakthroughEs Sider oil terminal. Despite reported progress at other terminals, the Volund field and sustained contributions from the recently completed development drilling program.Es Sider oil terminal remains closed.
Exploration
In the Kurdistan Region of Iraq we hold 45 percent operated working interests in both the Harir and Safen blocks. Current exploratory drilling includes the Mirawa– The Jisik-1 exploration well which began in March 2013was spud on the Harir Block andin December 2013. We expect the Safen well which commenced drillingto reach a projected total depth of 13,100 feet in Aprilthe second quarter of 2014. Following the successful 2013 onMirawa-1 discovery, the Safen Block. Both of these wells areMirawa-2 appraisal well is expected to reach projected total depthspud in the third quarter of 2013 with testing programs to follow on each well.2014. We hold a 45 percent operated working interest in the Harir Block.
Additionally, following the successful appraisal programThe Atrush-4 development well reached total depth on the non-operated Atrush Block in January 2014. Well testing was completed in April and the well has been suspended as a declaration of commerciality was filed with the government and a plan offuture producer. The Chiya Khere-5 development is anticipated to be filed in May 2013. Drilling of the Atrush-3 appraisal well commenced in March. On the non-operated Sarsang block, the Mangesh and Gara exploration wells began drilling(formerly Atrush-5), included in the second half of 2012. Both wells are currently drilling and arepreviously approved Atrush development plan, is expected to reach total depth duringspud in the second quarter of 2013, with testing programs to follow on each well. Also on2014. First oil from the Sarsang block, the East Swara Tika wellAtrush Block is expected to begin drilling late in the second quarter or early in the third quarter of 2013.2015. We hold a 15 percent non-operated working interest in the Atrush block and a 25 percent working interest in the Sarsang block.Block.
Kenya – The Sabisa-1Sala-1 exploration well was spud in February 2014 on the South Omo block onshore Ethiopia has beeneastern side of Block 9, where previous wells drilled had confirmed a working petroleum system. The Sala-1 is expected to reach a total depth and recorded hydrocarbon indications in sands beneath a thick claystone top seal. Hole instability issues have required the drilling of a sidetrack to comprehensively log and sample zones of interest. Results from the sidetrack are expectedapproximately 11,300 feet in the second quarter of 2013.2014. We hold a 50 percent non-operated working interest in Block 9 with the option to operate any commercial development.
Ethiopia – The Shimela-1 spud in March 2014 on the South Omo Block and is expected to reach a total depth of 8,850 feet in the second quarter of 2014. We hold a 20 percent non-operated working interest in the South Omo block.Block.
Exploration drilling beganWe increased our acreage in April 2013 onEthiopia through a farm-in to the Diaman No. 1 well in the Diaba License G4-223, offshore Gabon, to test the deepwater presalt play. We expect the well to reach total depth in the third quarter of 2013.Rift Basin Area Block with 10.5 million gross acres. We hold a 2150 percent non-operated working interest in the Diaba License.block with the option to operate if a discovery is made.
Offshore Norway,Gabon – In late October 2013, we were the Darwin (formerly Veslemoy) exploration well was drilledhigh bidder as operator of the G13 deepwater block in the pre-salt play offshore Gabon. We have received a Model Production Sharing Contract ("PSC") from the Gabonese government and negotiations toward a final PSC are ongoing. Award of the block is subject to government approval.

19

 Poland – During the first quarter of 2013 on PL 531 in which2014, we hold a 10 percent non-operated fully-carried working interest. Gas shows were recorded inrelinquished our remaining 4 operated concessions to the Paleocene objective section, although no hydrocarbons were found in the Cretaceous section and the well has been plugged and abandoned. We expect drilling to commence in the third quarter of 2013 on the Sverdrup exploration well on PL 330, in which we hold a 30 percent non-operated working interest.government.
After an extensive evaluation of our exploration activities in Poland and unsuccessful attempts to find commercial levels of hydrocarbons, we have elected to conclude operations in the country. We are evaluating disposition options for our concessions, which had a book value at March 31, 2013 of $12 million.
Oil Sands Mining
 Our Oil Sands Mining operations consist of a 20 percent non-operated working interest in the Athabasca Oil Sands Project (“AOSP”).AOSP.  Our net synthetic crude oil sales volumes were 5147 mbbld in the first quarter of20132014 compared to 4451 mbbld in the same period of 20122013.  Both mines, as a result of lower mine reliability and nine days of planned mine maintenance. We expect a planned turnaround in the upgrader experienced significantly improved reliability duringsecond quarter of 2014.
Acquisitions and Dispositions
In the first quarter of 2013. Primarily because2014, we closed the sales of reliability improvements, combined production from the Jack Pine and Muskeg River mines set a record bitumen production rate in the first quarter of 2013.  In addition, upgrader availability was 100our non-operated 10 percent for the entire first quarter of 2013, allowing the facility to maximize production of lighter synthetic crude oils, which improved realizations and profit margins.

20


Acquisitions and Dispositions
In April 2013, we reached an agreement to sell ourworking interests in the DJ Basin. The transaction is expected to close in mid-2013Production Sharing Contracts and a second quarter lossJoint Operating Agreements for Angola Blocks 31 and 32 for aggregate proceeds of approximately $115 million, before closing adjustments, is anticipated on this disposition.
In February 2013, we entered an agreement to convey our interests in the Marcellus natural gas shale play$2 billion. See Note 5 to the operator. A $43 million pretax loss on this transaction was recorded in the first quarter of 2013.
In February 2013, we closed the sale of our interest in the Neptune gas plant, located onshore Louisiana,consolidated financial statements for proceeds of $166 million. A $98 million pretax gain, before closing adjustments, was recorded in the first quarter of 2013.
In January 2013, we closed the sale of our remaining assets in Alaska, for proceeds of $195 million, subject to a six-month escrow of $50 million for various indemnities. A $46 million pretax gain, before closing adjustments, was recorded in the first quarter of 2013.
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.
We continue to progress the potential sale of assets in an ongoing effort to optimize our portfolio for profitable growth, with a previously stated goal of divesting between $1.5 billion and $3 billion over the period of 2011 through 2013. To date, we have agreed upon or completed approximately $1.3 billion in divestitures.information about these dispositions.
The above discussions include forward-looking statements with respect to anticipatedfuture drilling activity, the timing of closing the sale of our interests in the DJ Basin, possible increased recoverable resources from optimized well spacing in the Eagle Ford resource play, possible decreased averageplans, exploration drilling times in the Eagle Ford resource play, central batteries and pipeline construction projects, the filing of a plan of development for the Atrush Block, anticipated exploration activity in the Gulf of Mexico, Ethiopia, Gabon, Norway, and the Kurdistan Region of Iraq and Kenya, the developmenttiming of our in-situ assets, plans to exit Polandfirst production for the Atrush Block, the award of one block in Gabon, planned turnarounds at Foinaven, Brae, and oil sands mining, the possible sale of the U.K. and Norway businesses, and the goalcommon stock repurchase program. The reported average number of divesting between $1.5 to $3.0 billion of other assets over the period of 2011 through 2013. The average timesdays to drill a well and expectations asmay not be indicative of the number of days to future drilling timesdrill a well in the future. The current or initial production rates may not be indicative of future drilling times.production rates. Factors that could potentially affect anticipatedfuture drilling activity, possible increased recoverable resources from optimized well spacing in the Eagle Ford resource play, possible decreased averageplans, exploration drilling times in the Eagle Ford resource play, central batteries and pipeline construction projects and anticipated exploratory activity in the Gulf of Mexico, Ethiopia, Gabon, Norway, and the Kurdistan Region of Iraq and Kenya, and the timing of first production for the Atrush Block include pricing, supply and demand for liquid hydrocarbons and natural gas, the amount of capital available for exploration and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, availability of materials and labor, other associated risks with construction projects, the inability to obtain or delay in obtaining necessary government and third-party approvals and permits, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto, and other geological, operating and economic considerations. The timingaward of closing the sale of our interestsblock in the DJ BasinGabon is subject to the satisfactiongovernment approval and negotiation of customary closing conditions. Plans to exit Poland, the timing of filing the plan of development for the Atrush Blockan exploration and the projected asset dispositions through 2013production sharing contract. The planned turnarounds at Foinaven, Brae, and oil sands mining are based on current expectations estimates, and good faith projections and are not guarantees of future performance. The developmentpossible sale of the U.K. and Norway businesses is subject to the identification of one or more buyers, board approval, successful negotiations, and execution of definitive agreements. The common stock repurchase program could be affected by changes in the prices of and demand for liquid hydrocarbons and natural gas, actions of competitors, disruptions or interruptions of our in-situ assets is dependent on obtaining regulatory approvalexploration or production operations, unforeseen hazards such as weather conditions or acts of war or terrorist acts and future development plans.other operating and economic considerations. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and difficult to predict. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.
Market Conditions
 Prevailing prices for the various qualities of crude oil and natural gas that we produce significantly impact our revenues and cash flows.  Worldwide prices have been volatile in recent years.  The following table lists benchmark crude oil and natural gas price averages relative to our North America E&P and International E&P segments in the first quarters of 20132014 and 20122013.
Three Months Ended March 31,Three Months Ended March 31,
Benchmark2013 201220142013
West Texas Intermediate ("WTI") crude oil (Dollars per barrel)

$94.36
 
$103.03

$98.62

$94.36
Brent (Europe) crude oil (Dollars per barrel)

$112.49
 
$118.49

$108.17

$112.49
Henry Hub natural gas (Dollars per million British thermal units ("mmbtu"))(a)

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

$4.94

$3.34
(a) 
Settlement date average.

21


North America E&P
Liquid hydrocarbons – The quality, location, and composition of our liquid hydrocarbon production mix willcan cause our U.S. liquid hydrocarbonNorth America E&P price realizations to differ from the WTI benchmark.
Quality – Light sweet crude contains less sulfur and tends to be lighter than sour crude oil so that refining it is less costly and produceshas historically produced higher value products; therefore, light sweet crude is considered of higher quality and typically sellshas historically sold 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.increasing. In the first quarter of20132014, the percentage of our U.S. crude oil and condensate production that was sweet averaged 7479 percent compared to 5374 percent in the same period of 20122013.

20


Location – In recent years, crude oil sold along the United StatesU.S. Gulf Coast, such as that from the Eagle Ford, shale, has been priced based on the Louisiana Light Sweet ("LLS") benchmark which has historically priced at a premium to WTI because the Louisiana Light Sweet benchmarkand has been trackinghistorically tracked closely to Brent, while production from inland areas farther from large refineries has been at apriced lower. The average WTI discount to WTI.Brent has narrowed in 2014. In first quarter of2014, the WTI discount to Brent was $9.55 compared to $18.13 in the same period of 2013. As a result of significant increases in U.S. production of light sweet crude oil, the historical relationship between WTI, Brent and LLS pricing may not be indicative of future periods.
Composition – The proportion of our liquid hydrocarbon sales that are NGLs continues to increase due to our development of United States unconventional liquids-rich plays. NGLs were 1415 percent of our North America E&P liquid hydrocarbon sales volumes in the first quarter of20132014 compared to 814 percent in the same period of 20122013.
Natural gas – A significant portion of our natural gas production in the lower 48 states of the United StatesU.S. is sold at bid-week prices, or first-of-month indices relative to our specific producing areas.  Average Henry Hub settlement prices for natural gas were 2248 percent higher for the first quarter of2014 quarter of 2013 compared tothan in the same period of the prior year.2013. 
International E&P
Liquid hydrocarbons – Our international crude oil production is relatively sweet and is generally sold in relation to the Brent crude benchmark, which was 54 percent lower in the first quarter of2014 quarterthan in the same period of 2013 than the same quarter of 2012.
Natural gas – Our major international natural gas-producing regions are Europe and Equatorial Guinea.  Natural gas prices in Europe have been considerably higher than in the U.S. in recent years.  In the case of Equatorial Guinea, our natural gas sales are subject to term contracts, making realized prices in these areas less volatile.  The natural gas sales from Equatorial Guinea are at fixed prices; therefore, our reported average natural gas realized prices may not fully track market price movements.
Oil Sands Mining
 The Oil Sands Mining segment produces and sells various qualities of synthetic crude oil. Output mix can be impacted by operational problemsreliability or planned unit outages at the mines or upgrader. Sales prices for roughly two-thirds of the normal output mix will trackhave historically tracked movements in WTI and one-third will trackhas historically tracked movements in the Canadian heavy sour crude oil marker, primarily Western Canadian Select ("WCS"). The decrease in benchmark pricing coupled with the increased WCS discount fromto WTI in the first quarter of 20132014 decreased 28 percent when compared to the same period of 2012, combined to create downward pressure on our average realizations.2013.
The operating cost structure of theour Oil Sands Mining operations is predominantly fixed and therefore many of the costs incurred in times of full operation continue during production downtime. Per-unit costs are sensitive to production rates. Key variable costs are natural gas and diesel fuel, which track commodity markets such as the Canadian Alberta Energy Company ("AECO") natural gas sales index and crude oil prices, respectively.prices.
The table below shows benchmark prices that impacted both our revenues and variable costs for the first quarters of 20132014 and 20122013:
Three Months Ended March 31,Three Months Ended March 31,
Benchmark2013 201220142013
WTI crude oil (Dollars per barrel)

$94.36
 
$103.03
$98.62$94.36
WCS crude oil (Dollars per barrel)(a)

$62.41
 
$81.51
$75.55
$62.41
AECO natural gas sales index (Dollars per mmbtu)(b)

$3.16
 
$2.18
$4.99
$3.16
(a) 
Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.
(b) 
Monthly average AECO day ahead index.

22


Results of Operations
Consolidated Results of Operation
ConsolidatedNet income before income taxesper diluted share was $1.65 in the first quarter of 2014, up over 200 percent from the same period of 2013 primarily due to the $0.83 per diluted share after-tax gain on the sale of our Angola assets and a reduction in exploration expenses. The effective tax rate for continuing operations was 52 percent in the first quarter of2014 compared to 72 percent in the first quarter of2013. This decrease was primarily due to higher projected 2014 annual ordinary income from our North American operations, which are in a lower tax jurisdiction, and pretax losses in Libya in the first quarter of 2013 was 5 percent higher than2014, compared to pretax income in Libya during the same period of 20122013, where the tax rates are in excess of 90 percent. Income from continuing operations per diluted share was $0.77, an increase of 43 percent from the first quarter of 2013, primarily relateddue to the 22 percent increasereduction in sales volumes on a boe basis. The effective tax rate was 73 percentexploration expenses and the change in the first quarter of 2013 comparedincome mix to 69 percent in the first quarter of 2012, with the increase related to higher income from operations in higherlower tax jurisdictions, primarily Norway and Libya.jurisdictions.

21


Sales and other operating revenues, including related partyare summarized by segment in the following table:
Three Months Ended March 31,Three Months Ended March 31,
(In millions)2013 20122014 2013
Sales and other operating revenues, including related party:   
Sales and other operating revenues, including related party   
North America E&P$1,215
 $912
$1,392
 $1,215
International E&P1,887
 1,663
1,061
 1,801
Oil Sands Mining388
 379
377
 388
Segment sales and other operating revenues, including related party$3,490
 $2,954
2,830
 3,404
Unrealized loss on crude oil derivative instruments(50) —
—
 (50)
Total sales and other operating revenues, including related party$3,440
 $2,954
Sales and other operating revenues, including related party$2,830
 $3,354
 
TotalNorth America E&P sales and other operating revenuesincreased $486$177 million in the first quarter of2014 quartercompared to the same period of 2013 from the comparable prior-year period, with increases in each segment. The $303 million increase in the North America E&P segment was primarily due to higher net liquid hydrocarbon net sales volumes which increased 57 percent overresulting from the same quarter of 2012. Most of this net sales volume increase is a result of ongoing development programs in the Eagle Ford and Bakken shalecontinued growth across our three U.S. resource plays. Partially offsetting this increase wereplays partially offset by slightly lower liquid hydrocarbon and natural gas realizations. price realizations compared to the same period of 2013.
The following table gives details of net sales volumes and average price realizations of our North America E&P segment.segment:
Three Months Ended March 31, Three Months Ended March 31,
2013 2012 2014 2013
North America E&P Operating Statistics       
Net liquid hydrocarbon sales volumes (mbbld) (a)
141
 90
 163
 141
Liquid hydrocarbon average realizations (per bbl) (b) (c)

$86.14
 
$93.63
Liquid hydrocarbon average price realizations (per bbl) (b) (c)
 $84.79 $86.14
Net crude oil and condensate sales volumes (mbbld)
121
 83
 138
 121
Crude oil and condensate average realizations (per bbl) (b)

$94.68
 
$97.28
Crude oil and condensate average price realizations (per bbl) (b)
 $92.48 $94.68
Net natural gas liquids sales volumes (mbbld)
20
 7
 25
 20
Natural gas liquids average realizations (per bbl) (b)

$35.48
 
$51.55
   
Natural gas liquids average price realizations (per bbl) (b)
 $43.11 $35.48
Net natural gas sales volumes (mmcfd)
340
 344
 300
 340
Natural gas average realizations (per mcf)(b)

$3.86
 
$4.13
Natural gas average price realizations (per mcf)(b)
 $5.28 $3.86
(a) 
Includes crude oil, condensate and natural gas liquids.
(b) 
Excludes gains and losses on derivative instrumentsinstruments.
(c) 
Inclusion of realized gains (losses)losses on crude oil derivative instruments would have increased (decreased)decreased average liquid hydrocarbon price realizations by ($0.37)$0.31 per bbl for the first quarterthree months of 2013.2013. There were no realized gains (losses) on crude oil derivative instruments infor the first quarterthree months of 2012.2014.
The $224 million increase inInternational E&P sales and other operating revenues decreased $740 million in the International E&P segmentfirst quarter of 2014 from the comparable prior-year period. The decrease in the first quarter of 2014 was primarily a result of increaseddue to lower liquid hydrocarbon and natural gas sales volumes, from our African operationsprimarily in Libya and Norway as previously discussed.  Lowerdiscussed, and lower liquid hydrocarbon realizations partially offset the volume impact.price realizations.

23


The following table gives details of net sales volumes and average price realizations of our International E&P segment.segment:
 Three Months Ended March 31,
 2013 2012
International E&P Operating Statistics   
     Net liquid hydrocarbon sales volumes (mbbld)(a)
   
Europe100
 97
Africa80
 52
Total International E&P180
 149
     Liquid hydrocarbon average realizations (per bbl)(b)
   
Europe
$116.13
 
$123.76
Africa
$97.13
 
$94.41
Total International E&P
$107.68
 
$113.55
    
Net natural gas sales volumes (mmcfd)
   
           Europe(c)
95
 104
Africa473
 418
Total International E&P568
 522
     Natural gas average realizations (per mcf)(b)
   
Europe
$12.83
 
$9.99
Africa
$0.51
 
$0.24
Total International E&P
$2.57
 
$2.19
 Three Months Ended March 31,
 2014 2013
International E&P Operating Statistics   
   Net liquid hydrocarbon sales volumes (mbbld)(a)
110
 171
   Liquid hydrocarbon average price realizations (per bbl)
$96.49 $107.79
Net natural gas sales volumes (mmcfd) (b)
518
 568
   Natural gas average price realizations (per mcf)
$1.98 $2.57
(a) 
Includes crude oil, condensate and natural gas liquids. The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.
(b) 
Excludes gains and losses on derivative instruments.
(c)
Includes natural gas acquired for injection and subsequent resale of 117 mmcfd and 1411 mmcfd for the first quarter quarterss of 20132014 and 20122013.

22


Oil Sands Mining sales and other operating revenues increased $9 million. Synthetic crude oil sales volumes were 16 percent higher thandecreased $11 million in the first quarter of 2012, reflecting increased reliability of2014 from the mines and upgrader in the first quarter of 2013.  However, an increase in the discount of WCS to WTI resulted in decreases in average realizations during the comparable prior-year period.first quarter of 2013, partially offsetting the positive volume impact.  
The following table gives details of net sales volumes and average price realizations of our Oil Sands Mining segment.segment:
Three Months Ended March 31, Three Months Ended March 31, 
2013 2012 2014 2013
Oil Sands Mining Operating Statistics       
Net synthetic crude oil sales volumes (mbbld) (a)
51
 44
 47
 51
Synthetic crude oil average realizations (per bbl)

$79.98
 
$90.88
Synthetic crude oil average price realizations (per bbl)
 $88.50 $79.98
(a) 
Includes blendstocks.
Unrealized gains and losses on crude oil derivative instruments are included in total sales and other operating revenues but are not allocated to the segments. In the first quarter of 2013, theThese crude oil derivatives resulted in a net unrealized loss onof $50 million in the first quarter of 2013. There were no crude oil derivative instruments was $50 million with no comparable crude oil derivative activity in the same periodfirst quarter of 2012. See Note 12 to the consolidated financial statements and Item 3. Quantitative and Qualitative Disclosures About Market Risk for additional information about our derivative positions.2014.
Marketing revenues decreasedincreased $409110 million in the first quarter of20132014 from the comparable prior-year period. The increase related primarily to North America E&P segment marketing activities, formerly referred to as supply optimization activities, which include the purchase of commodities from third parties for resale, have been decreasing in 2013 due to market dynamics. Related commodity prices have also been lower in 2013 than in 2012.  These activities serve to aggregate volumes in order to satisfy transportation commitments andas well as to achieve flexibility within product types and delivery points.  points, and which increased in 2014 as a result of market dynamics.
 Income from equity method investmentsincreased $40$19 million in the first quarter of2014 versus the first quarter of2013 from the comparable prior-year period,2013 primarily due to higher LNG realizations and partially due to higher sales volumes since turnarounds at our facilities in Equatorial Guinea reduced sale volumes in the first quarter ofaverage price realizations.  2012.  

24


Net gain on disposal of assets in the first quarter of2013 includesincluded a $98 million pretax gain on the sale of our interest in the Neptune gas plant, a $46 million pretax gain on the sale of our remaining assets in Alaska and a $43 million pretax loss on the conveyance of our interest in the Marcellus natural gas shale play to the operator. The net gain on disposal of assets in the first quarter of 2012 consists of the $166 million gain on the sale of our interests in several Gulf of Mexico crude oil pipeline systems. See Note 5 to the consolidated financial statements for information about these dispositions.
Production expensesincreased$6449 million in the first quarter of2014 compared to the same quarter ofin 2013 from the comparable period of 2012. The increase isNorth America E&P production expenses increased $27 million primarily related to increased net sales volumes in the U.S. resource plays. International E&P production expenses increased $62 million, including $40 million for non-recurring workover activity in Norway and $11 million for non-recurring riser repairs in Equatorial Guinea. These one-time charges combined with decreased net sales volumes substantially increased the production expense rate for the International E&P segment below. OSM production expenses decreased $40 million primarily due to lower contract services and contract labor in the first quarter of 2014 and higher turnaround costs in the same quarter of 2013, however lower net sales volumes caused the production expense rate to increase slightly.
The following table provides production expense rates for each segment.segment:
  Three Months Ended March 31, 
($ per boe) 2014 2013
North America E&P 
$11.02
 
$10.35
International E&P 
$9.67
 
$4.57
Oil Sands Mining (a)
 $47.54 $46.29
(a)
Production expense per synthetic crude oil barrel (before royalties) includes production costs, shipping and handling, taxes other than income and insurance costs and excludes pre-development costs.
Marketing expenses decreasedincreased $413111 million in the first quarter of20132014 from the same period of 20122013, consistent with the marketing revenue declinerevenues change discussed above.
 Exploration expenses were higher$387 million lower in the first quarter of20132014 than in the same quarter ofin 20122013, primarily due to larger unproved property impairments. The first quarter of 2013 included $340 million inhigher non-cash unproved property impairments onin our North America E&P segment in the first quarter of 2013 related to Eagle Ford shale leases that either havehad expired or that we do not expect to drill or extend.

23


The following table summarizes the components of exploration expenses.expenses:
Three Months Ended March 31, Three Months Ended March 31,
(In millions)2013 2012 2014 2013
Unproved property impairments$383
 $35
 $41
 $383
Dry well costs21
 23
 2
 21
Geological and geophysical27
 45
 11
 28
Other34
 32
 22
 31
Total exploration expenses$465
 $135
 $76
 $463
Depreciation, depletion and amortization(“DD&A”) increaseddecreased $17323 million in the first quarter of20132014 from the comparable prior-year period.  Our segments apply the units-of-production method to the majority of their assets; therefore,assets, including capitalized asset retirement costs. Decreased DD&A in the previously discussed increases infirst quarter of2014 primarily reflects the impact of lower International E&P and OSM net sales volumes generally result in similar changes in DD&A. partially offset by higher North America E&P net sales volumes.
The DD&A rate (expense per barrel of oil equivalent)boe), which is impacted by changes in reserves and capitalized costs, can also cause changes into our DD&A. A lowerThe DD&A rates for the International E&P DD&A rateand Oil Sands Mining segments decreased in the first quarter of 2014 from the same quarter of 2013, primarily due to reserve increases atadditions in Norway and Canada in the endlatter half of 2012 for Norway, compared to the same period in 2012 partially offset the impact of higher sales volumes.2013. The following table provides DD&A rates for each segment.segment:
Three Months Ended March 31,Three Months Ended March 31,
($ per boe)2013 20122014 2013
DD&A rate      
North America E&P
$27
 
$23
$26.88
 $26.83
International E&P
$8
 
$9
$7.04
 $7.50
Oil Sands Mining
$12
 
$13
$11.70
 $12.13
Impairmentsin the first quarter of 2013 related primarily to the Powder River Basin and to the Ozona development in the Gulf of Mexico. Impairments in the first quarter of 2012 were also primarily2014 included $17 million related to the Ozona development in the Gulf of Mexico. See Note 11 toThe first quarter of 2013 included a $21 million impairment for the consolidated financial statementsOzona development and a $15 million impairment for information about these impairments.the Power River Basin.
Taxes other than income include production, severance and ad valorem taxes in the United States which tend to increase or decrease in relation to sales volumes and revenues.revenue. With the increase in North America E&P revenues and net sales volumes, taxes other than income increased $14 million in the first quarter of2014 from the first quarter of2013.
General and administrative expensesincreased$20 million in the first quarter of2014 from the same period in 2013. The increase is primarily due to a $63 million charge related to partial settlements of our U.S. pension plans, partially offset by lower employee related costs.
Net interest and other increaseddecreased $2220 million in the first quarter of20132014 from the comparable period of 20122013 primarily due to lowera dividend received from a mutual insurance company of which we are an owner, and increased capitalized interest in 2013.interest.
Provision for income taxes increased decreased$98397 million in the first quarter of20132014 from the comparable period of 20122013 primarily due to the increase inas a result of lower pretax income, primarily in high tax rate jurisdictions.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.income, and foreign currency remeasurement, net of any foreign currency hedge effects. The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments. The difference between the total provision and the sum of the amounts allocated to segments and to items not allocated to segments is shown in corporate and other unallocated itemsreported in the segment income table below.“Not Allocated to Segments” column of the tables in Note 6 to the consolidated financial statements.

25


Our effective income tax rates inon continuing operations for the first three months of 20132014 and 20122013 were 7352 percent and 6972 percent.  These rates are higher than the U.S. statutory rate of 35 percent due to earnings from foreign jurisdictions, primarily Norway in 2014 and 2013 and Libya in 2013, where the tax rates are in excess of the U.S. statutory rate.  The decrease in the effective tax rate on continuing operations in the first three months of 2014 is due to higher projected annual ordinary income from our North American operations, which are in a lower tax jurisdiction, and pretax losses in Libya.
The tax provision (benefit) applicable to Libyan ordinary income (loss) was recorded as a discrete item in the first three months of 2014 and 2013.  Excluding Libya, the effective tax rates on continuing operations would be 53 percent and 64 percent for the first three months of 2014 and 2013. In Libya, where the statutory tax rate is in excess of 90 percent, we have had no oil liftings since July 2013 due to third-party labor strikes at the Es Sider oil terminal and there remains uncertainty around sustained future

24


production and sales levels. Reliable estimates of 2014 and 2013 and 2012Libyan annual ordinary income from our Libyan operations could not be made and the range of possible scenarios when including ordinary income from our Libyan operations in the worldwide annual effective tax rate calculation demonstrates significant variability.  As such, for the first three months of 20132014 and 2012, an2013, estimated annual effective tax rate wasrates were calculated excluding Libya and applied to consolidated ordinary income excluding Libya andLibya.
Discontinued operations are presented net of tax. In the tax provision applicablefirst quarter of 2014, we closed the sale of our Angola assets. Our Angola operations are reflected as discontinued operations in all periods presented. See Note 5 to Libyan ordinary income was recorded as a discrete item in the period.  Excluding Libya, the effective tax rate would be 65 percent and 64 percent for the first three months of 2013 and 2012.consolidated financial statements.
 Segment Income (Loss)
Segment income represents income from continuing operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments.
Three Months Ended March 31, Three Months Ended March 31,
(In millions)2013 2012 2014 2013
North America E&P$(59) $104
 $242
 $(59)
International E&P453
 407
 331
 454
Oil Sands Mining38
 38
 64
 38
Segment income432
 549
 637
 433
Items not allocated to segments, net of income taxes: 
  
Corporate and other unallocated items(71) (71)
Unrealized loss on crude oil derivative instruments(32) —
Impairments(10) (167)
Net gain on dispositions64
 106
Items not allocated to segments, net of income taxes (97) (53)
Income from continuing operations 540
 380
Discontinued operations (a)
 609
 3
Net income$383
 $417
 $1,149
 $383
(a)
In the first quarter of 2014, we closed the sale of our Angola assets. The Angola business is reflected as discontinued operations in all periods presented.
 North America E&P segment income decreased $163increased $301 million after-tax in the first quarter of20132014 compared to the same period of 20122013. The decrease wasincrease is primarily due to lower exploration expenses and higher net sales volumes from our U.S. resource plays. In the resultfirst quarter of 2014, exploration expenses were $57 million, compared to $435 million in the same period of 2013, primarily related to unproved property impairments, higher DD&A and lower liquid hydrocarbon realizations, partially offset by higher liquid hydrocarbon sales volumes, as discussed above.previously discussed.
 International E&P segment income increased $46decreased $123 million after-tax in the first quarter of20132014 compared to the same period of 2012.2013. The decrease is primarily a result of lower net sales volumes in Libya, Norway and the U.K. and higher production expenses in Norway and Equatorial Guinea, partially offset by reduced DD&A associated with the lower volumes and lower income taxes, primarily in Libya. Production expenses were higher in the first quarter of 2014 by approximately $40 million due to non-recurring workover activity in Norway, and by $11 million due to non-recurring riser repairs in Equatorial Guinea.
 Oil Sands Mining segment incomeincreased $26 million after-tax in the first quarter of2014 compared to the same period of 2013. The increase was primarily related toa result of lower contract services and contract labor in the first quarter of 2014 and higher liquid hydrocarbonturnaround costs in the same quarter of 2013. The favorable impacts of higher price realizations and lower DD&A in the first quarter of 2014 were mostly offset by lower net sales volumes due to lower mine reliability and increased income from equity method investments, partially offset by higher income taxes.  nine days of planned mine maintenance.
Critical Accounting Estimates
There have been no changes to our critical accounting estimates subsequent to December 31, 2012.2013.
Accounting Standards Not Yet Adopted
In February 2013,April 2014, FASB issued an amendment to accounting standards update was issued to provide guidancethat changes the criteria for reporting discontinued operations while enhancing related disclosures.  Under 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 suchamendment, only disposals representing a strategic shift in operations should be presented as asset retirement and environmental obligations, contingencies, guarantees, income taxes and retirement benefits, which are separately addressed within 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 paydiscontinued operations. Those strategic shifts should have a major effect on the basisorganization’s operations and financial results. Examples include disposal of its arrangement among its co-obligorsa major geographic area, a major line of business, or a major equity method investment.  Expanded disclosures about the assets, liabilities, income, and 2) any amount the entity expects to pay on behalfexpenses 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 isdiscontinued operations will be required.  In addition, disclosure of the total outstanding amount underpretax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting will be made in order to provide users with information about the arrangement, not reduced by the effect of any amounts that may be recoverableongoing trends in an organization’s results from other entities, plus the carrying amount of any liability or receivable recognized must be disclosed. This accounting standards update iscontinuing operations.  The amendments are effective for us beginning in the first quarter of 20142015 and should be applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that exist at the beginning of 2014. Earlyearly adoption is permitted. We are currently evaluating the potential impactprovisions of this accounting standards updateamendment and assessing the impact, if any, it may have on our consolidated results of operations, financial position andor cash flows.


2625


Cash Flows and Liquidity
 Cash Flows
 Net cash provided by operating activitiescontinuing operations was $1,5281,392 million in the first three months of 2014, compared to $1,503 million in the first three months of 2013, compared to $973. The $111 million in the first three months of 2012 decrease primarily reflectingreflects the impact of increased liquid hydrocarbon, natural gas and synthetic crude oillower International E&P sales volumes on operating income.
 Net cash used inprovided by investing activities totaledrelated to continuing operations was $1,0371,097 million in the first three months of 2014, compared to net cash used of $983 million in the first three months of 2013, compared.  The increase in the first quarter of 2014 is primarily due to disposals of assets of $8062,123 million, which reflects the net proceeds of the sales of our interests in the first three monthsAngola Blocks 31 and 32. In 2013, net proceeds of 2012.  Significant investing activities are additions to property, plant and equipment and disposal of assets.  Additions in both periods primarily related to spending on U.S. unconventional resource plays, particularly the Eagle Ford shale. Disposals of assets totaled $312 million and $208 million in first three months of 2013 and 2012, with 2013 net proceedswere primarily related to the sales of our Alaska assets and our interest in the Neptune gas plant. In 2012, net proceeds resulted primarily from the sale of our interests in several Gulf of Mexico crude oil pipeline systems.
 For further information regarding capital expenditures by segment, see Supplemental Statistics.
 Net cash used in financing activities related to continuing operations was$810 million in the first three months of 2014, compared to $413 million in the first three months of 2013.  During the first three months of 2014, compared to $157we repurchased $551 million of our common stock under our authorized share repurchase program. We repaid a net $135 million of commercial paper in the first three months of 20122014 compared to $200 million in the first three months of 2013.  Repayments of debt at maturity were $114 million in the first three months of 2013 and $53 million in the first three months of 2012. We also repaid all $200 million of our outstanding commercial paper during the first three months of 2013.   Dividends paid of approximately $120 millionDividend payments were a significant useuses of cash in both periods.
 Liquidity and Capital Resources
 Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, the issuance of notes, our committed revolving credit facility and sales of non-strategic assets. Our working capital requirements are supported by these sources and we may issue commercial paper backed by our $2.5 billion revolving credit facility to meet short-term cash requirements.  Because of the alternatives available to us as discussed above, and our access to capital markets through the shelf registration discussed below, 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 March 31, 20132014, we had no borrowings against our revolving credit facility orand no amounts outstanding under our U.S. commercial paper program that is backed by the revolving credit facility. During the first quarter of 2013, $200 million of commercial paper was issued and $400 million of commercial paper was repaid.
At March 31, 20132014, we had $6,544$6,460 million in long-term debt outstanding, $68$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.
Shelf Registration
We have a universal shelf registration statement filed with the SEC under which we, as a "well-known seasoned issuer" for purposes of SEC rules, have the ability to issue and sell an indeterminate amount of various types of equity and debt and equity securities.

2726


Cash-Adjusted-Debt-To-CapitalCash-Adjusted Debt-To-Capital Ratio
 Our cash-adjusted debt-to-capital ratio (total debt-minus-cash and cash equivalents to total debt-plus-equity-minus-cash)debt-plus-equity-minus-cash and cash equivalents) was 2419 percent at March 31, 20132014, compared to 25 percent at December 31, 20122013.
March 31, December 31,March 31, December 31,
(In millions)2013 20122014 2013
Commercial paper$—
 $200
$—
 $135
Long-term debt due within one year68
 184
68
 68
Long-term debt6,476
 6,512
6,392
 6,394
Total debt$6,544
 $6,896
$6,460
 $6,597
Cash$768
 $684
Cash and cash equivalents$1,964
 $264
Equity$18,588
 $18,283
$19,805
 $19,344
Calculation: 
  
 
  
Total debt$6,544
 $6,896
$6,460
 $6,597
Minus cash768
 684
Minus cash and cash equivalents1,964
 264
Total debt minus cash5,776
 6,212
$4,496
 $6,333
Total debt6,544
 6,896
$6,460
 $6,597
Plus equity18,588
 18,283
19,805
 19,344
Minus cash768
 684
Total debt plus equity minus cash$24,364
 $24,495
Minus cash and cash equivalents1,964
 264
Total debt plus equity minus cash and cash equivalents$24,301
 $25,677
Cash-adjusted debt-to-capital ratio24% 25%19% 25%
 Capital Requirements
 On April 24, 2013,30, 2014, our Board of Directors approved a dividend of 1719 cents per share for the first quarter of 20132014, payable June 10, 20132014 to stockholders of record at the close of business on May 16, 2013.21, 2014.
As of March 31, 2013,2014, we plan to make contributions of up to $55$57 million to our funded pension plans during the remainder of 2014.
In 2013, our Board of Directors increased the authorization for repurchases of our common stock by $1.2 billion, bringing the total authorized to $6.2 billion. As of March 31, 2014, we had repurchased 108 million common shares at a total cost of $4,273 million, with 16 million shares acquired at a cost of $551 million in 2013, $17the first quarter of 2014. In March of 2014, we began an additional $500 million share repurchase phase, which is substantially complete. Upon completion of which were madethis additional phase there will be $1.5 billion remaining on the Company's share repurchase authorization. Purchases under the repurchase program may be in April 2013.either open market transactions, including block purchases, or in privately negotiated transactions. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. The program’s authorization does not include specific price targets or timetables. The timing of purchases under the program will be influenced by cash generated from operations, proceeds from potential asset sales, cash from available borrowings and market conditions.
Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance (as measured by various factors including cash provided from operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies.  The discussion of liquidity above also contains forward-looking statements regarding planned funding of pension plans, which are based on current expectations, estimates and projections and are not guarantees of actual performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict.  Some factors that could cause actual results to differ materially include prices of and demand for liquid hydrocarbons and natural gas, and synthetic crude oil, actions of competitors, disruptions or interruptions of our production or oil sands mining and bitumen upgrading operations due to unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto, and other operating and economic considerations.
Contractual Cash Obligations
As of March 31, 2013,2014, our total contractual cash obligations were consistent with December 31, 2012.2013.
          

27


Environmental Matters 
We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations.  If these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected.  We believe that substantially all of our competitors must comply with similar environmental laws and regulations.  However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes.
There have been no significant changes to our environmental matters subsequent to December 31, 2012.2013.

28


Other Contingencies
We are a defendant in a number of lawsuits arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims.  While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.  
 See Part II Item 1. Legal Proceedings for updated information about ongoing litigation.
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 20122013 Annual Report on Form 10-K. Additional disclosures regarding our open derivative positions, such asincluding underlying notional quantities, how they are reported in our consolidated financial statements and how their fair values are measured, may be found in Notes 11 and 12 to the consolidated financial statements.
Sensitivity analysis of the incremental effects on income from operations (“IFO”) of hypothetical 10 percent and 25 percent increases and decreases in commodity prices on our open commodity derivative instruments, by contract type as of March 31, 2013 is provided in the following table.
 
Incremental Change in IFO from a Hypothetical Price Increase of

 
Incremental Change in IFO from a Hypothetical Price Decrease of

 10% 25% 10% 25%
Crude oil       
Swaps$(127) $(317) $127
 $317
Option Collars(52) (160) 47
 155
Total crude oil(179) (477) 174
 472
Natural gas       
Futures(1) (1) 1
 1
Total natural gas(1) (1) 1
 1
Total$(180) $(478) $175
 $473
Sensitivity analysis of the projected incremental effect of a hypothetical 10 percent change in interest rates on financial assets and liabilities as of March 31, 20132014 is provided in the following table.
  Incremental  Incremental
  Change in  Change in
(In millions) Fair Value Fair ValueFair Value Fair Value
Financial assets (liabilities): (a)
      
Interest rate swap agreements$18
(b) 
$2
$7
(b) 
$5
Long-term debt, including amounts due within one year$(7,347)
(b) 
$(231)$(7,020)
(b)(c) 
$(225)
(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.
(c)
Excludes capital leases.
The aggregate cash flow effect onincremental change in fair value of our foreign currency derivative contracts of a hypothetical 10 percent change in exchange rates at March 31, 20132014 would be $6171 million.
Item 4. Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in RuleRules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer.  Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our company's design and operation of disclosure controls and procedures were effective for the period ending as of March 31, 2013.  2014.  
InDuring the first quarter of 2013, we completed the update of our existing Enterprise Resource Planning ("ERP") system. This update included a new general ledger, consolidations system and reporting tools. There2014, 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.

28

MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)


 Three Months Ended
 March 31,
(In millions)2014 2013
Segment Income (Loss)   
North America E&P$242
 $(59)
International E&P331
 454
Oil Sands Mining64
 38
Segment income637
 433
Items not allocated to segments, net of income taxes(97) (53)
Income from continuing operations540
 380
Discontinued operations (a)
609
 3
Net income$1,149
 $383
Capital Expenditures (b)
 
  
North America E&P$867
 $970
International E&P171
 171
Oil Sands Mining68
 45
Corporate3
 30
Discontinued operations (a)
44
 54
Total$1,153
 $1,270
Exploration Expenses 
  
North America E&P$57
 $435
International E&P19
 28
Total$76
 $463
(a)
In the first quarter of 2014, we closed the sale of our Angola assets. The Angola business is reflected as discontinued operations in all periods presented.
(b)
Capital expenditures include changes in accruals.



29

MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)


 Three Months Ended
 March 31,
(In millions)2013 2012
Segment Income (Loss)   
North America E&P$(59) $104
International E&P453
 407
Oil Sands Mining38
 38
Segment income432
 549
Items not allocated to segments, net of income taxes(49) (132)
Net income$383
 $417
Capital Expenditures(a)
   
North America E&P$970
 $829
International E&P225
 138
Oil Sands Mining45
 52
Corporate30
 44
Total$1,270
 $1,063
Exploration Expenses   
North America E&P$435
 $106
International E&P30
 29
Total$465
 $135
(a)
Capital expenditures include changes in accruals.

 Three Months Ended
 March 31,
Net Sales Volumes2014 2013
North America E&P   
Crude Oil and Condensate (mbbld)
   
Bakken38 33
Eagle Ford62 46
Oklahoma resource basins2 1
Other North America36 41
Total Crude Oil and Condensate138 121
Natural Gas Liquids (mbbld)
   
Bakken2 2
Eagle Ford16 12
Oklahoma resource basins4 4
Other North America3 2
Total Natural Gas Liquids25 20
Total Liquid Hydrocarbons (mbbld)
   
Bakken40 35
Eagle Ford78 58
Oklahoma resource basins6 5
Other North America39 43
Total Liquid Hydrocarbons163 141
Natural Gas (mmcfd)
   
Bakken16 13
Eagle Ford107 83
Oklahoma resource basins54 50
Alaska0 31
Other North America123 163
Total Natural Gas300 340
Total North America E&P (mboed)
213 198


30

MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)


Three Months EndedThree Months Ended
March 31,March 31,
Net Sales Volumes2013 20122014 2013
North America E&P 
  
Crude Oil and Condensate (mbbld)
121
 83
Natural Gas Liquids (mbbld)
20
 7
International E&P 
Total Liquid Hydrocarbons (mbbld)
 
Equatorial Guinea35 37
Norway62 79
United Kingdom13 21
Libya0 34
Total Liquid Hydrocarbons141
 90
110 171
Natural Gas (mmcfd)
340
 344
 
Total North America E&P (mboed)
198
 147
   
International E&P 
  
Liquid Hydrocarbons (mbbld)
   
Europe100
 97
Africa80
 52
Total Liquid Hydrocarbons180
 149
Natural Gas (mmcfd)
 
  
Europe(b)
95
 104
Africa473
 418
Equatorial Guinea435 447
Norway50 54
United Kingdom(c)
30 41
Libya3 26
Total Natural Gas568
 522
518 568
Total International E&P (mboed)
274
 236
197 265
   
Oil Sands Mining    
Synthetic Crude Oil (mbbld)(c)
51
 44
   
Synthetic Crude Oil (mbbld)(d)
47 51
Total Continuing Operations (mboed)
457 514
Discontinued Operations (mboed)(a)
6 9
Total Company (mboed)
523
 427
463 523
Net Sales Volumes of Equity Method Investees 
  
 
LNG (mtd)
6,787
 6,291
6,579 6,787
Methanol (mtd)
1,410
 1,312
1,153 1,410
(b)(c) 
Includes natural gas acquired for injection and subsequent resale of 117 mmcfd and 1411 mmcfd for the first quartersquarters of 20132014 and 20122013.
(c)(d) 
Includes blendstocks.




31

MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)


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

$94.68
 
$97.28
Natural Gas Liquids (per bbl)

$35.48
 
$51.55
Total Liquid Hydrocarbons(e)

$86.14
 
$93.63
Natural Gas (per mcf)

$3.86
 
$4.13
    
International E&P   
Liquid Hydrocarbons (per bbl)
   
Europe
$116.13
 
$123.76
Africa
$97.13
 
$94.41
Total Liquid Hydrocarbons
$107.68
 
$113.55
Natural Gas (per mcf)
   
Europe
$12.83
 
$9.99
Africa(f)

$0.51
 
$0.24
Total Natural Gas
$2.57
 
$2.19
    
Oil Sands Mining   
    Synthetic Crude Oil (per bbl)

$79.98
 
$90.88
 Three Months Ended
 March 31,
Average Price Realizations (e)
2014 2013
North America E&P   
Crude Oil and Condensate (per bbl)
   
Bakken$89.46 $91.22
Eagle Ford96.10
 103.78
Oklahoma resource basins94.38
 90.07
Other North America89.25
 87.30
Total Crude Oil and Condensate92.48
 94.68
Natural Gas Liquids (per bbl)
   
Bakken$57.62 $41.05
Eagle Ford37.50
 28.16
Oklahoma resource basins44.58
 41.27
Other North America61.83
 56.58
Total Natural Gas Liquids43.11
 35.48
Total Liquid Hydrocarbons (per bbl) (f)
   
Bakken$87.60 $88.60
Eagle Ford84.16
 88.06
Oklahoma resource basins58.75
 52.86
Other North America87.40
 85.41
Total Liquid Hydrocarbons84.79
 86.14
Natural Gas (per mcf)
   
Bakken$8.41 $3.61
Eagle Ford4.89
 3.35
Oklahoma resource basins5.50
 3.56
Alaska—
 7.90
Other North America5.10
 3.49
Total Natural Gas5.28
 3.86
(d)(e) 
Excludes gains andor losses on derivative instruments.
(e)(f) 
Inclusion of realized gains (losses)losses on crude oil derivative instruments would have increased (decreased)decreased average liquid hydrocarbon price realizations by ($0.37)$0.31 per bbl for the first quarterthree months of 2013.2013. There were no realized gains (losses) on crude oil derivative instruments infor the first quarterthree months of 2012.2014.
(f)


Primarily represents fixed prices under long-term contracts with Alba Plant LLC, Atlantic Methanol Production Company LLC and Equatorial Guinea LNG Holdings Limited, which are equity method investees.  We include our share of income from each of these equity method investees in our International E&P segment.

32

MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)


 Three Months Ended
 March 31,
Average Price Realizations (e)
2014 2013
International E&P   
Total Liquid Hydrocarbons (per bbl)
   
Equatorial Guinea$62.37 $65.89
Norway112.94
 117.13
United Kingdom109.53
 112.25
Libya—
 129.56
Total Liquid Hydrocarbons96.49
 107.79
Natural Gas (per mcf)
   
Equatorial Guinea(g)
$0.24 $0.24
Norway12.01
 14.00
United Kingdom10.02
 11.27
Libya6.65
 5.04
Total Natural Gas1.98
 2.57
Oil Sands Mining   
Synthetic Crude Oil (per bbl)
$88.50 $79.98
Discontinued Operations (per bbl)(a)
$99.82 $105.95
(g) Primarily represents fixed prices under long-term contracts with Alba Plant LLC, Atlantic Methanol Production Company LLC and Equatorial Guinea LNG Holdings Limited, which are equity method investees.  We include our share of income from each of these equity method investees in our International E&P segment.


33


Part II – OTHER INFORMATION
Item 1. Legal Proceedings
We are a defendant in a number of lawsuits arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims.  While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.  Certain of thosethese matters are discussed below.
LitigationEnvironmental Proceedings
InBased on currently available information, which is in many cases preliminary and incomplete, we believe as of March 2011, Noble Drilling (U.S.) LLC (“Noble”) filed a lawsuit against us in31, 2014 that total clean-up and remediation costs connected with ongoing remediation sites will be approximately $25 million, the District Courtmajority of Harris County, Texas, alleging, among other things, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation, relating to a multi-year drilling contract for a newly constructed drilling rig to be deployed in the U.S. Gulf of Mexico.  We filed an answer in April 2011, contending, among other things, failure to perform, failure to comply with material obligations, failure to mitigate alleged damages and that Noble failed to provide the rig according to the operating, performance and safety requirements specified in the drilling contract. In April 2013, we filed a counterclaim against Noble alleging, among other things, breach of contract and breach of the duty of good faith relating to the multi-year drilling contract. The counterclaim also included a breach of contract claim for reimbursement for the value of fuel used by Noble under an offshore daywork drilling contract. We are vigorously defending this litigation.  The ultimate outcome of this lawsuit, including any financial effect on us, remains uncertain.  We do not believe an estimate of a reasonably probable loss (or range of loss) can be made for this lawsuit at this time.
Environmental
 We continue to work with the North Dakota Department of Health to resolve voluntary disclosures we made in 2009 relating to potential Clean Air Act violations relating to our operations on state lands in the Bakken shale. The proposed settlement of the fine is $169,800 and is expected to be executed by the parties in the second quarter of 2013.which have already been incurred.
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 20122013 Annual Report on Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table provides information about purchases by Marathon Oil during the quarter ended March 31, 20132014, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities Exchange Act of 1934.
 Column (a) Column (b) Column (c) Column (d)
 Total Number of Average Price 
Total Number of
Shares Purchased
as Part of
Publicly Announced
 
Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Period
Shares Purchased (a)(b)
 Paid per Share 
 Plans or Programs(c)
 
Plans or Programs(c)
01/01/13 – 01/31/135,910
 $31.34 —
 $1,780,609,536
02/01/13 – 02/28/13107,389
 $33.74 —
 $1,780,609,536
03/01/13 – 03/31/1334,051
 $33.56 —
 $1,780,609,536
Total147,350
 $33.60 —
  
 Column (a) Column (b) Column (c) Column (d)
 Total Number of Average Price 
Total Number of
Shares Purchased
as Part of
Publicly Announced
 
Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Period
Shares Purchased (a)(b)
 Paid per Share 
 Plans or Programs(c)
 
Plans or Programs(c)
01/01/14 - 01/31/14

5,324
 $35.03 —
 $2,500,000,000
02/01/14 - 02/28/144,814,974
 $33.30 4,803,356
 $2,340,045,464
03/01/14 - 03/31/1411,670,823
 $33.76 11,576,645
 $1,949,161,815
Total16,491,121
 $33.63 16,380,001
  
(a) 
120,43183,556 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.
(b) 
In March 2013, 26,9192014, 27,564 shares were repurchased in open-market transactions to satisfy the requirements for dividend reinvestment under the Marathon Oil Corporation Dividend Reinvestment and Direct Stock Purchase Plan (the “Dividend Reinvestment Plan”) by the administrator of the Dividend Reinvestment Plan. Shares needed to meet the requirements of the Dividend Reinvestment Plan are either purchased in the open market or issued directly by Marathon Oil.
(c) 
We announced a share repurchase program in January 2006, and amended it several times in 2007 for a total authorized program of $5 billion. As of March 31, 20132014, 78we had repurchased 108 million split-adjusted common shares had been acquired at a cost of $3,222$4,273 million, which includes transaction fees and commissions that are not reported in the table above. Of this total, 6616 million shares had beenwere acquired at a cost of $2,922$551 million prior toduring the spin-offfirst quarter of the downstream business.2014.

Item 4. Mine Safety Disclosures
 Not applicable.

3334


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
10.1 Form of Performance Unit Award Agreement (2013-20152014 - 2016 Performance Cycle)Cycle for Section 16 Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan         X  
10.2 Form of Performance Unit Award Agreement (2013-20152014 - 2016 Performance Cycle)Cycle for Officers granted under X
10.3Marathon Oil Corporation's 2012 IncentiveCorporation Deferred Compensation Plan for Non-Employee Directors (Amended and Restated as of January 1, 2012)         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.PREXBRL Taxonomy Extension Presentation Linkbase.X
101.CAL XBRL Taxonomy Extension Calculation Linkbase.         X  
101.DEF XBRL Taxonomy Extension Definition Linkbase.         X  
101.LAB XBRL Taxonomy Extension Label Linkbase.         X  
101.PREXBRL Taxonomy Extension Presentation Linkbase.X


3435



SIGNATURES

 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
May 10, 20137, 2014 MARATHON OIL CORPORATION
   
 By:/s/ Michael K. Stewart  /s/ John R. Sult
   Michael K. StewartJohn R. Sult
  
Executive Vice President Finance and Accounting,
Controller and Treasurer
Chief Financial Officer

3536



Exhibit Index

    Incorporated by Reference    
Exhibit Number Exhibit Description Form Exhibit Filing Date SEC File No. Filed Herewith Furnished Herewith
10.1 Form of Performance Unit Award Agreement (2013-20152014 - 2016 Performance Cycle)Cycle for Section 16 Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan         X  
10.2 Form of Performance Unit Award Agreement (2013-20152014 - 2016 Performance Cycle)Cycle for Officers granted under X
10.3Marathon Oil Corporation's 2012 IncentiveCorporation Deferred Compensation Plan for Non-Employee Directors (Amended and Restated as of January 1, 2012)         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.PREXBRL Taxonomy Extension Presentation Linkbase.X
101.CAL XBRL Taxonomy Extension Calculation Linkbase.         X  
101.DEF XBRL Taxonomy Extension Definition Linkbase.         X  
101.LAB XBRL Taxonomy Extension Label Linkbase.         X  
101.PREXBRL Taxonomy Extension Presentation Linkbase.X