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 JuneSeptember 30, 2015
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 R No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes R No £
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer     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 677,184,913677,260,116 shares of Marathon Oil Corporation common stock outstanding as of JulyOctober 31, 2015.




MARATHON OIL CORPORATION
 
Unless the context otherwise indicates, references to “Marathon Oil,” “we,” “our,” or “us” in this Form 10-Q 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).
For certain industry specific terms used in this Form 10-Q, please see "Definitions" in our 2014 Annual Report on Form 10-K.

 Table of Contents 
  Page
 
 
 
 
 
 
 
 
 
 


1



Part I - Financial Information
Item 1. Financial Statements

MARATHON OIL CORPORATION
Consolidated Statements of Income (Unaudited)
Three Months Ended Six Months EndedThree Months Ended Nine Months Ended
June 30, June 30,September 30, September 30,
(In millions, except per share data)2015 2014 2015 20142015 2014 2015 2014
Revenues and other income:              
Sales and other operating revenues, including related party$1,307
 $2,270
 $2,587
 $4,419
$1,300
 $2,316
 $3,887
 $6,735
Marketing revenues183
 618
 387
 1,159
84
 554
 471
 1,713
Income from equity method investments26
 120
 62
 257
36
 89
 98
 346
Net gain (loss) on disposal of assets
 (87) 1
 (85)
Net loss on disposal of assets(109) (3) (108) (88)
Other income15
 20
 26
 40
12
 15
 38
 55
Total revenues and other income1,531
 2,941
 3,063
 5,790
1,323
 2,971
 4,386
 8,761
Costs and expenses: 
  
    
 
  
    
Production450
 562
 894
 1,104
406
 593
 1,300
 1,697
Marketing, including purchases from related parties182
 614
 387
 1,156
84
 554
 471
 1,710
Other operating81
 101
 188
 204
93
 99
 281
 303
Exploration111
 145
 201
 218
585
 96
 786
 314
Depreciation, depletion and amortization751
 680
 1,572
 1,323
717
 737
 2,289
 2,060
Impairments44
 4
 44
 21
337
 109
 381
 130
Taxes other than income78
 109
 145
 204
46
 115
 191
 319
General and administrative168
 139
 339
 326
125
 160
 464
 486
Total costs and expenses1,865
 2,354
 3,770
 4,556
2,393
 2,463
 6,163
 7,019
Income (loss) from operations(334) 587
 (707) 1,234
(1,070) 508
 (1,777) 1,742
Net interest and other(58) (76) (105) (125)(75) (55) (180) (180)
Income (loss) from continuing operations before income taxes(392) 511
 (812) 1,109
(1,145) 453
 (1,957) 1,562
Provision (benefit) for income taxes(6) 151
 (150) 351
(396) 149
 (546) 500
Income (loss) from continuing operations(386) 360
 (662) 758
(749) 304
 (1,411) 1,062
Discontinued operations
 180
 
 931

 127
 
 1,058
Net income (loss)$(386) $540
 $(662) $1,689
$(749) $431
 $(1,411) $2,120
Per basic share: 
  
  
  
 
  
  
  
Income (loss) from continuing operations$(0.57) $0.53
 $(0.98) $1.11
$(1.11) $0.45
 $(2.09) $1.56
Discontinued operations$
 $0.27
 $
 $1.36
$
 $0.19
 $
 $1.55
Net income (loss)$(0.57) $0.80
 $(0.98) $2.47
$(1.11) $0.64
 $(2.09) $3.11
Per diluted share:              
Income (loss) from continuing operations
$(0.57) $0.53
 $(0.98) $1.10
$(1.11) $0.45
 $(2.09) $1.55
Discontinued operations$
 $0.27
 $
 $1.36
$
 $0.19
 $
 $1.55
Net income (loss)$(0.57) $0.80
 $(0.98) $2.46
$(1.11) $0.64
 $(2.09) $3.10
Dividends per share$0.21
 $0.19
 $0.42
 $0.38
$0.21
 $0.21
 $0.63
 $0.59
Weighted average common shares outstanding: 
  
  
  
 
  
  
  
Basic677
 676
 676
 684
677
 675
 677
 681
Diluted677
 679
 676
 688
677
 678
 677
 684
 The accompanying notes are an integral part of these consolidated financial statements.

2



MARATHON OIL CORPORATION
Consolidated Statements of Comprehensive Income (Unaudited)
Three Months Ended Six Months EndedThree Months Ended Nine Months Ended
June 30, June 30,September 30, September 30,
(In millions)2015 2014 2015 20142015 2014 2015 2014
Net income (loss)$(386) $540
 $(662) $1,689
$(749) $431
 $(1,411) $2,120
Other comprehensive income (loss) 
  
  
  
 
  
  
  
Postretirement and postemployment plans 
  
  
  
 
  
  
  
Change in actuarial loss and other86
 (13) 162
 (43)(2) 3
 160
 (40)
Income tax benefit (provision)(30) 5
 (57) 15
(1) (2) (58) 13
Postretirement and postemployment plans, net of tax56
 (8) 105
 (28)(3) 1
 102
 (27)
Comprehensive income (loss)$(330) $532
 $(557) $1,661
$(752) $432
 $(1,309) $2,093
 The accompanying notes are an integral part of these consolidated financial statements.


3



MARATHON OIL CORPORATION
Consolidated Balance Sheets (Unaudited)
June 30, December 31,September 30, December 31,
(In millions, except per share data)2015 20142015 2014
Assets      
Current assets:      
Cash and cash equivalents$1,572
 $2,398
$1,680
 $2,398
Short-term investments925
 
700
 
Receivables, less reserve of $4 and $31,195
 1,729
991
 1,729
Inventories336
 357
324
 357
Other current assets102
 109
163
 109
Total current assets4,130
 4,593
3,858
 4,593
Equity method investments1,045
 1,113
1,012
 1,113
Property, plant and equipment, less accumulated depreciation, 
  
 
  
depletion and amortization of $23,395 and $21,88429,121
 29,040
depletion and amortization of $23,713 and $21,88427,920
 29,040
Goodwill459
 459
457
 459
Other noncurrent assets1,015
 806
1,427
 806
Total assets$35,770
 $36,011
$34,674
 $36,011
Liabilities 
  
 
  
Current liabilities: 
  
 
  
Accounts payable$1,507
 $2,545
$1,246
 $2,545
Payroll and benefits payable119
 191
138
 191
Accrued taxes156
 285
143
 285
Other current liabilities235
 290
286
 290
Long-term debt due within one year1,035
 1,068
1,035
 1,068
Total current liabilities3,052
 4,379
2,848
 4,379
Long-term debt7,321
 5,323
7,323
 5,323
Deferred tax liabilities2,531
 2,486
2,542
 2,486
Defined benefit postretirement plan obligations438
 598
436
 598
Asset retirement obligations1,963
 1,917
1,965
 1,917
Deferred credits and other liabilities247
 288
225
 288
Total liabilities15,552
 14,991
15,339
 14,991
Commitments and contingencies

 



 

Stockholders’ Equity 
  
 
  
Preferred stock – no shares issued or outstanding (no par value,      
26 million shares authorized)
 

 
Common stock: 
  
 
  
Issued – 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 – 93 million and 95 million shares(3,555) (3,642)(3,553) (3,642)
Additional paid-in capital6,484
 6,531
6,493
 6,531
Retained earnings16,691
 17,638
15,800
 17,638
Accumulated other comprehensive loss(172) (277)(175) (277)
Total stockholders' equity20,218
 21,020
19,335
 21,020
Total liabilities and stockholders' equity$35,770
 $36,011
$34,674
 $36,011
 The accompanying notes are an integral part of these consolidated financial statements.

4



MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows (Unaudited)
Six Months EndedNine Months Ended
June 30,September 30,
(In millions)2015 20142015 2014
Increase (decrease) in cash and cash equivalents      
Operating activities: 
  
 
  
Net income (loss)$(662) $1,689
$(1,411) $2,120
Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
  
 
  
Discontinued operations
 (931)
 (1,058)
Deferred income taxes(185) 173
(590) 337
Depreciation, depletion and amortization1,572
 1,323
2,289
 2,060
Impairments44
 21
381
 130
Pension and other postretirement benefits, net14
 26
9
 (27)
Exploratory dry well costs and unproved property impairments148
 156
708
 220
Net (gain) loss on disposal of assets(1) 85
Net loss on disposal of assets108
 88
Equity method investments, net37
 (10)41
 51
Changes in:   
   
Current receivables534
 (266)738
 (270)
Inventories21
 (58)30
 (32)
Current accounts payable and accrued liabilities(770) (31)(954) (115)
All other operating, net(35) (59)(136) (28)
Net cash provided by continuing operations717
 2,118
1,213
 3,476
Net cash provided by discontinued operations
 440

 856
Net cash provided by operating activities717
 2,558
1,213
 4,332
Investing activities: 
  
 
  
Acquisitions, net of cash acquired
 (12)
Additions to property, plant and equipment(2,320) (2,230)(2,948) (3,639)
Disposal of assets2
 2,232
105
 2,237
Investments - return of capital31
 27
61
 46
Purchases of short-term investments(925) 
(925) 
Maturities of short-term investments225
 
Investing activities of discontinued operations
 (233)
 (356)
All other investing, net(1) 
22
 (24)
Net cash used in investing activities(3,213) (204)(3,460) (1,748)
Financing activities: 
  
 
  
Commercial paper, net
 (135)
 (135)
Borrowings1,996
 
1,996
 
Debt issuance costs(19) 
(19) 
Debt repayments(34) (34)(34) (34)
Purchases of common stock
 (1,000)
 (1,000)
Dividends paid(285) (260)(427) (401)
All other financing, net11
 86
14
 150
Net cash provided by (used in) financing activities1,669
 (1,343)1,530
 (1,420)
Effect of exchange rate on cash and cash equivalents:      
Continuing operations1
 
(1) (1)
Discontinued operations
 (10)
 (11)
Cash held for sale
 (96)
 (655)
Net increase (decrease) in cash and cash equivalents(826) 905
(718) 497
Cash and cash equivalents at beginning of period2,398
 264
2,398
 264
Cash and cash equivalents at end of period$1,572
 $1,169
$1,680
 $761
 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")SEC and do not include all of the information and disclosures required by accounting principles generally accepted in the United States ("U.S. GAAP")GAAP for complete financial statements.
As a result of the sale of our Angola assets and our Norway business in 2014, both are reflected as discontinued operations. The disclosures in this report related to results of operations and 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 Corporationour 2014 Annual Report on Form 10-K.  The results of operations for the secondthird quarter and first sixnine months of 2015 are not necessarily indicative of the results to be expected for the full year.
2.   Accounting Standards
Not Yet Adopted
In May 2015, the FASB issued an update that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The amendment also removes certain disclosure requirements regarding all investments that are eligible to be measured using the net asset value per share practical expedient and only requires certain disclosures on those investments for which an entity elects to use the net asset value per share expedient. This standard is effective for us in the first quarter of 2016 and will be applied on a retrospective basis. Early adoption is permitted. This standard only modifies disclosure requirements; as such, there will be no impact on our consolidated results of operations, financial position or cash flows.
In April 2015, the FASB issued an update that requires debt issuance costs to be presented in the balance sheet as a direct reduction from the associated debt liability. This standard is effective for us in the first quarter of 2016 and will be applied on a retrospective basis. Early adoption is permitted, including in interim periods.permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In February 2015, the FASB issued an amendment to the guidance for determining whether an entity is a variable interest entity ("VIE"). The standard does not add or remove any of the five characteristics that determine if an entity is a VIE. However, it does change the manner inby which a reporting entity assesses one of the characteristics. In particular, when decision-making over the entity’s most significant activities has been outsourced, the standard changes how a reporting entity assesses ifwhether the equity holders at risk lack decision making rights.rights if the decision-making over the subject entity’s most significant activities was outsourced. This standard is effective for us in the first quarter of 2016 and early adoption is permitted, including in interim periods.permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In August 2014, the FASB issued an update that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in United States ("U.S.") auditing standards.  This standard is effective for us in the first quarter of 2017 and early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.
In May 2014, the FASB issued an update that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance, requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively, and improves guidance for multiple-element arrangements. This standard is effective for us in the first quarter of 2018 and should be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. Early adoption is permitted with an effective date no earlier than first quarter of 2017. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.

6


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Recently Adopted
In April 2014, the 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. Expanded disclosures about the assets, liabilities, income and expenses of discontinued operations are 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 were effective for us in the first quarter of 2015 and apply to dispositions or classifications as held for sale thereafter. Adoption of this standard did not impact 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% undivided interest, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton, Alberta, Canada.  Costs under this contract are accrued and recorded on a monthly basis, with current liabilities of $2 million recorded at JuneSeptember 30, 2015 and $3 million at December 31, 2014.  This contract qualifies as a variable interest contractual arrangement, and the Corridor Pipeline qualifies as a VIE.  We hold a variable interest but are not the primary beneficiary because our shipments are only 20% 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 $508$471 million as of JuneSeptember 30, 2015.  The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term.
4.Income (Loss) per Common Share
Basic income (loss) per share is based on the weighted average number of common shares outstanding.  Diluted income (loss) per share assumes exercise of stock options, provided the effect is not antidilutive. The per share calculations below exclude 13 million and 52 million stock options for the secondthird quarters of 2015 and 2014 and 13 million and 4 million stock options for the first sixnine months of 2015 and 2014 that were antidilutive.
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended September 30, Nine Months Ended September 30,
(In millions, except per share data)2015 2014 2015 20142015 2014 2015 2014
Income (loss) from continuing operations$(386) $360
 $(662) $758
$(749) $304
 $(1,411) $1,062
Discontinued operations
 180
 
 931

 127
 
 1,058
Net income (loss)$(386) $540
 $(662) $1,689
$(749) $431
 $(1,411) $2,120
              
Weighted average common shares outstanding677
 676
 676
 684
677
 675
 677
 681
Effect of dilutive securities
 3
 
 4

 3
 
 3
Weighted average common shares, diluted677
 679
 676
 688
677
 678
 677
 684
Per basic share:              
Income (loss) from continuing operations$(0.57) $0.53
 $(0.98) $1.11
$(1.11) $0.45
 $(2.09) $1.56
Discontinued operations$
 $0.27
 $
 $1.36
$
 $0.19
 $
 $1.55
Net income (loss)$(0.57) $0.80
 $(0.98) $2.47
$(1.11) $0.64
 $(2.09) $3.11
Per diluted share:              
Income (loss) from continuing operations$(0.57) $0.53
 $(0.98) $1.10
$(1.11) $0.45
 $(2.09) $1.55
Discontinued operations$
 $0.27
 $
 $1.36
$
 $0.19
 $
 $1.55
Net income (loss)$(0.57) $0.80
 $(0.98) $2.46
$(1.11) $0.64
 $(2.09) $3.10

7


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


5.Acquisitions
2014 - North America E&P Segment
In the third quarter of 2014, we acquired acreage in the Oklahoma Resource Basins at a cost of $68 million after final settlement adjustments.
6.Dispositions
2015 - North America E&P Segment
In JulyAugust 2015, we closed the sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets for proceeds of approximately $100 million and recorded a pretax loss of $1 million. During the second quarter of 2015, we recorded a non-cash impairment charge of $44 million related to these assets (See Note 15).
2015 - International E&P Segment
In September 2015, we entered into an agreement to sell our East Texas/North LouisianaAfrica exploration acreage in Ethiopia and Wilburton, Oklahoma natural gas assets forKenya. A pretax loss of $109 million was recorded in the third quarter of 2015. This transaction is expected proceeds of $102 million, excluding closing adjustments. We expect the transaction to close during the thirdfourth quarter of 2015.
2014 - North America E&P Segment
In Junethe second quarter of 2014, we closed the sale of non-core acreage located in the far northwest portion of Williston Basin for proceeds of $90 million. Amillion and recorded a pretax loss of $91 million was recorded in the second quarter of 2014.million.
2014 - International E&P Segment
In the second quarter of 2014, we entered into an agreement to sell our Norway business, including the operated Alvheim floating production, storage and offloading vessel, 10 operated licenses and a number of non-operated licenses on the Norwegian Continental Shelf in the North Sea.  The transaction closed during the fourth quarter of 2014.
Our Norway business was reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for 2014. Select amounts reported in discontinued operations follow:were as follows:
Three Months Ended June 30,Six Months Ended June 30,Three Months Ended September 30,Nine Months Ended September 30, 
(In millions) 2014 2014 2014 2014 
Revenues applicable to discontinued operations $693
 $1,373
 $528
 $1,901
 
Pretax income from discontinued operations $598
 $1,130
 $487
 $1,617
 
After-tax income from discontinued operations (a)
 $180
 $322
 $127
 $449
(a) 
(a)    Includes a tax benefit of $26 million related to a decrease in the valuation allowance on U.S. foreign tax credits from the Norway operations.
  
In the first quarter of 2014, we closed the sales of our non-operated 10% working interests in the Production Sharing Contracts and Joint Operating Agreements for Angola Blocks 31 and 32 for aggregate proceeds of approximately $2 billion and recorded a $576 million after-tax gain on sale. Included in the after-tax gain is a deferred tax benefit reflecting our ability to utilize foreign tax credits that otherwise would have 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 the prior period. Select amounts reported in discontinued operations follow:were as follows:
Six Months Ended June 30,Nine Months Ended September 30,
(In millions)20142014
Revenues applicable to discontinued operations$58
$58
Pretax income from discontinued operations, before gain$51
$51
Pretax gain on disposition of discontinued operations$470
$470
After-tax income from discontinued operations$609
$609
  

8

6.

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


7.    Segment Information
  We are a global energy company with operations in North America, Europe and Africa. Each of our three reportable operating segments is organized and managed based upon both geographic location and the nature of the products and services it offers.
North AmericaN.A. E&P ("N.A. E&P") – explores for, produces and markets crude oil and condensate, natural gas liquids ("NGLs")NGLs and natural gas in North America;
InternationalInt'l E&P ("Int'l E&P") – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North America and produces and markets products manufactured from natural gas, such as liquefied natural gas ("LNG")LNG and methanol, in Equatorial Guinea ("E.G."); 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.

8


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


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, 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. Gains or losses on dispositions, certain impairments, change in tax expense associated with a tax rate change, unrealized gains or losses on crude oil derivative instruments, or other items that affect comparability also are not allocated to operating segments.
As discussed in Note 5,6, as a result of the sale of our Angola assets and our Norway business in 2014, both are reflected as discontinued operations and excluded from the InternationalInt'l E&P segment for 2014.
Three Months Ended June 30, 2015Three Months Ended September 30, 2015
  Not Allocated    Not Allocated  
(In millions)N.A. E&P Int'l E&P OSM to Segments TotalN.A. E&P Int'l E&P OSM to Segments Total
Sales and other operating revenues$993
 $211
 $147
 $(44)
(c) 
$1,307
$796
 $182
 $242
 $80
(c) 
$1,300
Marketing revenues110
 30
 43
 
 183
57
 25
 2
 
 84
Total revenues1,103
 241
 190
 (44) 1,490
853
 207
 244
 80
 1,384
Income from equity method investments
 26
 
 
 26
Net gain on disposal of assets and other income11
 4
 
 
 15
Income (loss) from equity method investments
 48
 
 (12)
(d) 
36
Net gain (loss) on disposal of assets and other income6
 6
 
 (109)
(e) 
(97)
Less:                  
Production expenses179
 64
 207
 
 450
179
 61
 166
 
 406
Marketing costs112
 29
 41
 
 182
56
 25
 3
 
 84
Exploration expenses91
 20
 
 
 111
22
 10
 
 553
(f) 
585
Depreciation, depletion and amortization634
 71
 35
 11
 751
549
 79
 76
 13
 717
Impairments
 
 
 44
(d) 
44

 
 4
 333
(g) 
337
Other expenses (a)
99
 19
 9
 122
(e) 
249
106
 25
 8
 79
(h) 
218
Taxes other than income67
 
 5
 6
 78
42
 
 5
 (1) 46
Net interest and other
 
 
 58
 58

 
 
 75
 75
Income tax provision (benefit)(23) 27
 (30) 20
(f) 
(6)(34) 32
 (7) (387) (396)
Segment income (loss) /Loss from continuing operations$(45) $41
 $(77) $(305) $(386)$(61) $29
 $(11) $(706) $(749)
Capital expenditures (b)
$551
 $99
 $16
 $12
 $678
$564
 $30
 $(11) $12
 $595
(a) 
Includes other operating expenses and general and administrative expenses.
(b) 
Includes accruals.
(c) 
Unrealized lossgain on crude oil derivative instruments.
(d) 
Partial impairment of investment in equity method investee (See Note 15).
(e)
Includes loss on sale of East Africa exploration acreage (See Note 6).
(f)
Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (See Note 14).
(g)
Proved property impairments (See Note 14).
(h)
Includes pension settlement loss of $18 million and severance related expenses associated with workforce reductions of $4 million (See Note 8).


9


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


 Three Months Ended September 30, 2014
   Not Allocated  
(In millions)N.A. E&P Int'l E&P OSM to Segments Total
Sales and other operating revenues$1,586
 $273
 $457
 $
 $2,316
Marketing revenues506
 46
 2
 
 554
Total revenues2,092
 319
 459
 
 2,870
Income from equity method investments
 89
 
 
 89
Net gain (loss) on disposal of assets and other income(1) 12
 
 1
 12
Less:         
Production expenses233
 108
 252
 
 593
Marketing costs507
 45
 2
 
 554
Exploration expenses55
 41
 
 
 96
Depreciation, depletion and amortization609
 55
 62
 11
 737
Impairments
 
 
 109
(c) 
109
Other expenses (a)
118
 26
 14
 101
(d) 
259
Taxes other than income109
 
 5
 1
 115
Net interest and other
 
 
 55
 55
Income tax provision (benefit)168
 39
 31
 (89) 149
Segment income/Income from continuing operations$292
 $106
 $93
 $(187) $304
Capital expenditures (b)
$1,277
 $166
 $49
 $16
 $1,508
(a)
Includes other operating expenses and general and administrative expenses.
(b)
Includes accruals.
(c)
Proved property impairment (See Note 12)14).
(d)
Includes pension settlement loss of $22 million (See Note 8).
 Nine Months Ended September 30, 2015
   Not Allocated  
(In millions)N.A. E&P Int'l E&P OSM to Segments Total
Sales and other operating revenues$2,639
 $575
 $614
 $59
(c) 
$3,887
Marketing revenues345
 81
 45
 
 471
Total revenues2,984
 656
 659
 59
 4,358
Income (loss) from equity method investments
 110
 
 (12)
(d) 
98
Net gain (loss) on disposal of assets and other income17
 20
 1
 (108)
(e) 
(70)
Less:         
Production expenses560
 192
 548
 
 1,300
Marketing costs348
 79
 44
 
 471
Exploration expenses148
 85
 
 553
(f) 
786
Depreciation, depletion and amortization1,866
 214
 173
 36
 2,289
Impairments
 
 4
 377
(g) 
381
Other expenses (a)
322
 67
 26
 330
(h) 
745
Taxes other than income170
 
 15
 6
 191
Net interest and other
 
 
 180
 180
Income tax provision (benefit)(146) 56
 (43) (413)
(i) 
(546)
Segment income (loss) /Loss from continuing operations$(267) $93
 $(107) $(1,130) $(1,411)
Capital expenditures (b)
$2,048
 $275
 $26
 $26
 $2,375
(a)
Includes other operating expenses and general and administrative expenses.
(b)
Includes accruals.
(c)
Unrealized gain on crude oil derivative instruments.
(d)
Partial impairment of investment in equity-method investee (See Note 15).
(e) 
Includes pension settlement loss on sale of $64 million (seeEast Africa exploration acreage (See Note 7)6).
(f)
Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (See Note 14).
(g)
Proved property impairments (See Note 14).
(h)
Includes pension settlement loss of $99 million and severance related expenses associated with workforce reductions of $47 million (See Note 8).
(i) 
Includes $135 million of deferred tax expense related to Alberta provincial corporate tax rate increase (see(See Note 8)9).


910


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)



Three Months Ended June 30, 2014Nine Months Ended September 30, 2014
  Not Allocated    Not Allocated  
(In millions)N.A. E&P Int'l E&P OSM to Segments TotalN.A. E&P Int'l E&P OSM to Segments Total
Sales and other operating revenues$1,540
 $347
 $383
 $
 $2,270
$4,518
 $1,000
 $1,217
 $
 $6,735
Marketing revenues540
 61
 17
 
 618
1,486
 177
 50
 
 1,713
Total revenues2,080
 408
 400
 
 2,888
6,004
 1,177
 1,267
 
 8,448
Income from equity method investments
 120
 
 
 120

 346
 
 
 346
Net gain (loss) on disposal of assets and other income15
 15
 1
 (98)
(c) 
(67)17
 44
 3
 (97)
(c) 
(33)
Less:                  
Production expenses217
 99
 246
 
 562
661
 307
 729
 
 1,697
Marketing costs537
 60
 17
 
 614
1,484
 176
 50
 
 1,710
Exploration expenses82
 63
 
 
 145
194
 120
 
 
 314
Depreciation, depletion and amortization550
 75
 45
 10
 680
1,674
 201
 152
 33
 2,060
Impairments4
 
 
 
 4
21
 
 
 109
(d) 
130
Other expenses (a)
126
 34
 13
 67
(d) 
240
354
 98
 40
 297
(e) 
789
Taxes other than income102
 
 6
 1
 109
301
 
 16
 2
 319
Net interest and other
 
 
 76
 76

 
 
 180
 180
Income tax provision (benefit)175
 52
 19
 (95) 151
496
 178
 71
 (245) 500
Segment income/Income from continuing operations$302
 $160
 $55
 $(157) $360
Segment income /Income from continuing operations$836
 $487
 $212
 $(473) $1,062
Capital expenditures (b)
$1,102
 $115
 $55
 $10
 $1,282
$3,246
 $386
 $172
 $29
 $3,833
(a) 
Includes other operating expenses and general and administrative expenses.
(b) 
Includes accruals.
(c) 
Primarily related to the sale of non-core acreage (see(See Note 5)6).
(d)
Includes pension settlement loss of $8 million (see Note 7).
 Six Months Ended June 30, 2015
   Not Allocated  
(In millions)N.A. E&P Int'l E&P OSM to Segments Total
Sales and other operating revenues$1,843
 $393
 $372
 $(21)
(c) 
$2,587
Marketing revenues288
 56
 43
 
 387
Total revenues2,131
 449
 415
 (21) 2,974
Income from equity method investments
 62
 
 
 62
Net gain on disposal of assets and other income11
 14
 1
 1
 27
Less:         
Production expenses381
 131
 382
 
 894
Marketing costs292
 54
 41
 
 387
Exploration expenses126
 75
 
 
 201
Depreciation, depletion and amortization1,317
 135
 97
 23
 1,572
Impairments
 
 
 44
(d) 
44
Other expenses (a)
216
 42
 18
 251
(e) 
527
Taxes other than income128
 
 10
 7
 145
Net interest and other
 
 
 105
 105
Income tax provision (benefit)(112) 24
 (36) (26)
(f) 
(150)
Segment income (loss) /Loss from continuing operations$(206) $64
 $(96) $(424) $(662)
Capital expenditures (b)
$1,484
 $245
 $37
 $14
 $1,780
(a)
Includes other operating expenses and general and administrative expenses.
(b)
Includes accruals.
(c)
Unrealized loss on crude oil derivative instruments.
(d) 
Proved property impairmentimpairments (See Note 12)14).
(e) 
Includes $43 million of severance related expenses associated with a workforce reduction and a pension settlement loss of $81$93 million (see Note 7).
(f)
Includes $135 million of deferred tax expense related to Alberta provincial corporate tax rate increase (see(See Note 8).



10


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


 Six Months Ended June 30, 2014
   Not Allocated  
(In millions)N.A. E&P Int'l E&P OSM to Segments Total
Sales and other operating revenues$2,932
 $727
 $760
 $
 $4,419
Marketing revenues980
 131
 48
 
 1,159
Total revenues3,912
 858
 808
 
 5,578
Income from equity method investments
 257
 
 
 257
Net gain (loss) on disposal of assets and other income18
 32
 3
 (98)
(c) 
(45)
Less:         
Production expenses428
 199
 477
 
 1,104
Marketing costs977
 131
 48
 
 1,156
Exploration expenses139
 79
 
 
 218
Depreciation, depletion and amortization1,065
 146
 90
 22
 1,323
Impairments21
 
 
 
 21
Other expenses (a)
236
 72
 26
 196
(d) 
530
Taxes other than income192
 
 11
 1
 204
Net interest and other
 
 
 125
 125
Income tax provision (benefit)328
 139
 40
 (156) 351
Segment income /Income from continuing operations$544
 $381
 $119
 $(286) $758
Capital expenditures (b)
$1,969
 $220
 $123
 $13
 $2,325
(a)
Includes other operating expenses and general and administrative expenses.
(b)
Includes accruals.
(c)
Primarily related to the sale of non-core acreage (see Note 5).
(d)
Includes pension settlement loss of $71 million (see Note 7).
7.8.    Defined Benefit Postretirement Plans
The following summarizes the components of net periodic benefit cost (credit):cost:
Three Months Ended June 30,Three Months Ended September 30,
Pension Benefits Other BenefitsPension Benefits Other Benefits
(In millions)2015 2014 2015 20142015 2014 2015 2014
Service cost$12
 $11
 $1
 $1
$11
 $12
 $
 $
Interest cost13
 15
 2
 3
12
 15
 3
 4
Expected return on plan assets(17) (14) 
 
(17) (16) 
 
Amortization: 
  
  
  
 
  
  
  
– prior service cost (credit)(2) 2
 (1) (1)(3) 1
 (1) (1)
– actuarial loss7
 10
 
 
5
 7
 1
 
Net settlement loss (a)
64
 8
 
 
18
 22
 
 
Net curtailment loss (b)

 
 2
 
4
 
 
 
Net periodic benefit cost$77
 $32
 $4
 $3
$30
 $41
 $3
 $3

11


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Six Months Ended June 30,Nine Months Ended September 30,
Pension Benefits Other BenefitsPension Benefits Other Benefits
(In millions)2015 2014 2015 20142015 2014 2015 2014
Service cost24
 23
 2
 2
$35
 $35
 $2
 $2
Interest cost27
 31
 5
 6
39
 46
 8
 10
Expected return on plan assets(36) (32) 
 
(53) (48) 
 
Amortization: 
  
  
  
 
  
  
  
– prior service cost (credit)(1) 3
 (2) (2)(4) 4
 (3) (3)
– actuarial loss14
 16
 
 
19
 23
 1
 
Net settlement loss(a)
81
 71
 
 
99
 93
 
 
Net curtailment loss (gain) (b)
1
 
 (4) 
5
 
 (4) 
Net periodic benefit cost$110

$112

$1

$6
$140

$153

$4

$9
(a) 
Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan's total service and interest cost for that year.
(b) 
Related to the workforce reduction,reductions, which reduced the future expected years of service for employees participating in the plans.plans and the impact of discontinuing accruals for future benefits under the U.K. pension plan effective December 31, 2015.
During the first sixnine months of 2015, we recorded the effects of a workforce reduction, and a U.S. pension plan amendment.amendment and the discontinuation of accruals for future benefits under the U.K. pension plan. The U.S. pension plan amendment freezes the final average pay used to calculate the benefit under the legacy final average pay formula benefit and iswas effective July 6, 2015. For the U.K. pension plan, a final decision was reached with the plan trustees to close the plan to future benefit accruals effective December 31, 2015. Additionally, during the first sixnine months of 2015 and 2014, we recorded the effects of partial settlements of our U.S. pension plans. As required, we remeasured the plans' assets and liabilities as of the applicable balance sheet dates. The cumulative effects of these events are included in the remeasurement and reflected in both the pension liability and net periodic benefit cost (credit).cost.
During the first sixnine months of 2015, we made contributions of $46$65 million to our funded pension plans.  We expect to make additional contributions up to an estimated $42$18 million to our funded pension plans over the remainder of 2015.  During the first sixnine months of 2015, we made payments of $42$57 million and $8$13 million related to unfunded pension plans and other postretirement benefit plans, respectively.
8.9.    Income Taxes
Effective Tax Rate
The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The difference between the total provision (benefits)(benefit) and the sum of the amounts allocated to segments is reported in the “Not Allocated to Segments” column of the tables in Note 6.7.
Our effective income tax rates on continuing operations for the first sixnine months of 2015 and 2014 were 18%28% and 32%.  The tax provision (benefit) applicable to Libyan ordinary income (loss) was recorded as a discrete item in the first sixnine months of 2015 and 2014.  Excluding Libya, the effective tax rates on continuing operations, would be 15%27% and 34%32% for the first sixnine months of 2015 and 2014. In Libya, uncertainty remains around the timing of future production and sales levels. Reliable estimates of 2015 and 2014 Libyan annual ordinary income from our operations could not be made and the range of possible scenarios in the worldwide annual effective tax rate calculation demonstrates significant variability.  Thus, for the first sixnine months of 2015 and 2014, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss).
Change in Tax Law
On June 29, 2015, the Alberta government enacted legislation to increase the provincial corporate tax rate from 10% to 12%. As a result of this legislation, we recorded additional non-cash deferred tax expense of $135 million in the second quarter of 2015.

Indefinite Reinvestment Assertion
In the second quarter of 2015, we reviewed our operations and concluded that we do not have the same level of capital needs outside the U.S. as previously expected. Therefore, we no longer intend for previously unremitted foreign earnings of

12


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


approximately $1 billion associated with our Canadian operations to be permanently reinvested outside the U.S. As such, none of Marathon Oil’s foreign earnings remain permanently reinvested abroad. We anticipate foreign tax credits associated with these Canadian earnings would be sufficient to offset any incremental U.S. tax liabilities, and therefore, no additional net deferred taxes have beenwere recorded in the second quarter of 2015.


12


Deferred Tax Assets
MARATHON OIL CORPORATION
NotesIn connection with our assessment of the realizability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of our deferred tax assets will not be realized.  In the event it is more likely than not that some portion or all of our deferred taxes will not be realized, such assets are reduced by a valuation allowance. Future increases to Consolidated Financial Statements (Unaudited)our valuation allowance are possible if our estimates and assumptions (particularly as they relate to downward revisions of our long-term commodity price forecast) are revised such that they reduce estimates of future taxable income during the carryforward period.


9.10.    Short-term Investments
As of JuneSeptember 30, 2015, our short-term investments are comprised of bank time deposits with original maturities of greater than three months and remaining maturities of less than twelve months. The maturity dates range from September 2015 to October 2015. These short-term investmentsThey are classified as held-to-maturity investments, which are recorded at amortized cost. The carrying values of our short-term investments approximate fair value. These short-term investments matured during October 2015.
10.11.   Inventories
 Inventories of liquid hydrocarbons, natural gas and bitumen are carried at the lower of cost or market value. Materials and supplies are valued at weighted average cost and reviewed for obsolescence or impairment when market conditions indicate.
June 30, December 31,September 30, December 31,
(In millions)2015 20142015 2014
Liquid hydrocarbons, natural gas and bitumen$50
 $58
$39
 $58
Supplies and other items286
 299
285
 299
Inventories, at cost$336
 $357
$324
 $357
11.12.  Property, Plant and Equipment, net of Accumulated Depreciation, Depletion and Amortization
June 30, December 31,September 30, December 31,
(In millions)2015 20142015 2014
North America E&P$16,757
 $16,717
$15,875
 $16,717
International E&P2,848
 2,741
2,604
 2,741
Oil Sands Mining9,401
 9,455
9,334
 9,455
Corporate115
 127
107
 127
Net property, plant and equipment$29,121

$29,040
$27,920

$29,040
Our Libya operations continue to be impacted by civil unrest and, in December 2014, Libya’s National Oil Corporation once again declared force majeure at the Es Sider oil terminal, as disruptions from civil unrest continue. Considerable uncertainty remains around the timing of future production and sales levels.
As of JuneSeptember 30, 2015, our net property, plant and equipment investment in Libya is $775 million, and total proved reserves (unaudited) in Libya as of December 31, 2014 are 243 million barrels of oil equivalent ("mmboe").boe. We and our partners in the Waha concessions continue to assess the situation and the condition of our assets in Libya. Our periodic assessment of the carrying value of our net property, plant and equipment in Libya specifically considers the net investment in the assets, the duration of our concessions and the reserves anticipated to be recoverable in future periods. The undiscounted cash flows related to our Libya assets continuescontinue to exceed the carrying value of $775 million by a material amount.
Exploratory well costs capitalized greater than one year after completion of drilling were $88 million and $126 million as of JuneSeptember 30, 2015 and December 31, 2014. This $38 million net decrease was associated with a write-down of our Canadian in-situ assets at Birchwood.Birchwood in the second quarter of 2015. After further evaluation of the estimated recoverable

13


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


resources and our development plans, we withdrew our regulatory application for the proposed steam assisted gravity drainage ("SAGD") demonstration project.project at Birchwood.
13. Other Noncurrent Assets
 September 30, December 31,
(in millions)2015 2014
Deferred tax assets$1,115
 $525
Intangible assets95
 96
Other217
 185
Other noncurrent assets$1,427
 $806
14. Impairments and Exploration Expenses
The continued decline of commodity prices resulted in a downward revision of our long-term commodity price assumptions and was a triggering event which required us to reassess long-lived assets related to oil and gas producing properties for impairment as of September 30, 2015. Further changes in management's forecast assumptions may cause us to reassess our long-lived assets for impairment, and could result in non-cash impairment charges in the future.
The following table summarizes impairment charges of proved properties:
 Three Months Ended September 30, Nine Months Ended September 30,
(in millions)2015 2014 2015 2014
Total impairments$337
 $109
 $381
 $130
Impairments for the three and nine months ended September 30, 2015 consisted primarily of proved properties in Colorado and the Gulf of Mexico as a result of lower forecasted commodity prices.
Impairments for the three and nine months ended September 30, 2014 consisted primarily of proved properties in the Gulf of Mexico, Texas and North Dakota as a result of revisions to estimated abandonment costs and lower forecasted commodity prices. See Note 7 for relevant detail regarding segment presentation and Note 15 for fair value measurements related to impairments of proved properties.
The following table summarizes the components of exploration expenses:
 Three Months Ended September 30, Nine Months Ended September 30,
(In millions)2015 2014 2015 2014
Exploration Expenses       
Unproved property impairments$563
 $39
 $612
 $140
Dry well costs(3) 25
 96
 80
Geological and geophysical8
 10
 23
 27
Other17
 22
 55
 67
Total exploration expenses$585
 $96
 $786
 $314
Included in the unproved property impairments for the three and nine months ended September 30, 2015 are non-cash charges of $553 million as a result of changes in our conventional exploration strategy (Gulf of Mexico and Harir block in the Kurdistan Region of Iraq) and lower forecasted commodity prices (Colorado).
Unproved property impairments for the three and nine months ended September 30, 2014 primarily consist of leases in Texas and North Dakota that either expired or we decided not to drill or extend. See Note 7 for relevant detail regarding segment presentation.

1314


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


12.15.  Fair Value Measurements
 Fair Values - Recurring
The following tables present assets and liabilities accounted for at fair value on a recurring basis as of JuneSeptember 30, 2015 and December 31, 2014 by fair value hierarchy level.
June 30, 2015September 30, 2015
(In millions)Level 1 Level 2 Level 3 TotalLevel 1 Level 2 Level 3 Total
Derivative instruments, assets              
Commodity (a)
$
 $5
 $
 $5
$
 $61
 $
 $61
Interest rate
 11
 
 11

 15
 
 15
Derivative instruments, assets$
 $16
 $
 $16
$
 $76
 $
 $76
Derivative instruments, liabilities              
Commodity (a)
$
 $26
 $
 $26
$
 $3
 $
 $3
Derivative instruments, liabilities$
 $26
 $
 $26
$
 $3
 $
 $3
(a)  
Derivative instruments are recorded on a net basis in the company's balance sheet (see Note 13)16).
 December 31, 2014
(In millions)Level 1 Level 2 Level 3 Total
Derivative instruments, assets       
Interest rate$
 $8
 $
 $8
Derivative instruments, assets$
 $8
 $
 $8
Commodity derivatives include three-way collars, swaptions, extendable three-way collars and call options. These instruments are measured at fair value using either the Black-Scholes Model or Black Model. Inputs to both models include prices, interest rates, and implied volatility. The inputs to these models are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.
Interest rate swaps are measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs.
See Note 1316 for additional discussion of the types of derivative instruments we use.
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 June 30,Three Months Ended September 30,
2015 20142015 2014
(In millions)Fair Value Impairment Fair Value ImpairmentFair Value Impairment Fair Value Impairment
Long-lived assets held for use$17
 $44
 $
 $4
$41
 $337
 $43
 $109
Six Months Ended June 30,Nine Months Ended September 30,
2015 20142015 2014
(In millions)Fair Value Impairment Fair Value ImpairmentFair Value Impairment Fair Value Impairment
Long-lived assets held for use$17
 $44
 $
 $21
$58
 $381
 $43
 $130

Commodity prices began declining in the second half of 2014 and remain substantially lower through 2015 as compared to the first six months of 2014. As this period of sustained reduced2015. The prolonged decline in commodity prices, continues, itand the resulting change in management's future commodity price assumptions, was a triggering event which required us to reassess long-lived assets related to oil and gas producing properties for impairment as of September 30, 2015. Further changes in management's forecast assumptions may cause us to reassess our long-lived assets for impairment, and could result in non-cash impairment charges related to long-lived assets in future periods.

All long-livedthe future. Long-lived assets held for use that were impaired inare discussed below. The fair values of each 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, unless otherwise noted.  Inputs to the first six months of 2015fair value measurement include reserve and 2014 were heldproduction estimates made by our North America E&P segment.reservoir engineers, estimated future commodity prices

1415


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


In July adjusted for quality and location differentials, and forecasted operating expenses for the remaining estimated life of the reservoir.
2015 we entered into an agreement to sell our East Texas/- North Louisiana and Wilburton, Oklahoma natural gas assets. We expect the transaction to close duringAmerica E&P
In the third quarter of 2015.2015, impairments of $333 million were recorded primarily related to certain producing assets in Colorado and the Gulf of Mexico as a result of lower forecasted commodity prices, to an aggregate fair value of $41 million.
    During the second quarter of 2015, we recorded a non-cash impairment charge of $44 million related to theseour East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets as a result of the anticipated sale.sale (see Note 6). The fair values were measured using a probability weighted income approach based on both the anticipated sales price and a held-for-use model. The held-for-use model contained internal estimates
2015 - International E&P
In the third quarter of future production levels,2015, a partial impairment of $12 million was recorded to an investment in an equity method investee as a result of lower forecasted commodity prices, and discount rate. All such inputs were classified as Level 3.to a fair value of $604 million. This impairment was reflected in income from equity method investments in our consolidated statements of income.
2014 - North America E&P
The Ozona development in the Gulf of Mexico ceased producing in 2013, at which time those long-lived assets were fully impaired. In the first and second quartersnine months of 2014, we recorded additional impairments of $17 million and $4$30 million as a result of estimated abandonment cost revisions.
In the third quarter of 2014, impairments of $53 million were recorded to certain other Gulf of Mexico properties as a result of estimated abandonment cost and other revisions, to an aggregate fair value of $19 million. In addition, two additional on-shore fields were impaired a total of $47 million to an aggregate fair value of $24 million primarily due to lower forecasted commodity prices.
Fair Values – Goodwill
Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. After we performed our annual goodwill impairment test in April 2015, a triggering event (downward revision of forecasted commodity price assumptions) required us to reassess our goodwill for impairment as of September 30, 2015. Based on the results of this assessment, we concluded no impairment was required. The fair value was measured using an income approach based upon forecasted future abandonment costs, which are Level 3 inputs. of the North America E&P and International E&P reporting units exceeded their respective book values by a significant margin. Changes in management's forecast commodity price assumptions may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.
Fair Values – Financial Instruments
Our current assets and liabilities include financial instruments, the most significant of which are receivables, short-term investments, long-term debt due within one year, and payables. We believe the carrying values of our receivables, short-term investments 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 insignificant bad debt expense, which includes an evaluation of counterparty credit risk.

16


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


The following table summarizes financial instruments, excluding receivables, short-term investments, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at JuneSeptember 30, 2015 and December 31, 2014.
June 30, 2015 December 31, 2014September 30, 2015 December 31, 2014
Fair Carrying Fair CarryingFair Carrying Fair Carrying
(In millions)Value Amount Value AmountValue Amount Value Amount
Financial assets              
Other noncurrent assets$134
 $133
 $132
 $129
$109
 $116
 $132
 $129
Total financial assets 134
 133
 132
 129
109
 116
 132
 129
Financial liabilities 
  
  
  
 
  
  
  
Other current liabilities13
 13
 13
 13
15
 14
 13
 13
Long-term debt, including current portion (a)
8,720
 8,324
 6,887
 6,360
8,302
 8,324
 6,887
 6,360
Deferred credits and other liabilities73
 67
 69
 68
69
 64
 69
 68
Total financial liabilities $8,806
 $8,404
 $6,969
 $6,441
$8,386
 $8,402
 $6,969
 $6,441
(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. 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.
13.16. Derivatives
For further information regarding the fair value measurement of derivative instruments, see Note 12.15. 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. The following tables present the gross fair values of derivative instruments and the reported net amounts where they appear on the consolidated balance sheets as of JuneSeptember 30, 2015 and December 31, 2014.
 September 30, 2015  
(In millions)Asset Liability Net Asset Balance Sheet Location
Fair Value Hedges       
     Interest rate$15
 $
 $15
 Other noncurrent assets
Total Designated Hedges15
 
 15
  
        
Not Designated as Hedges       
     Commodity55
 2
 53
 Other current assets
     Commodity6
 1
 5
 Other noncurrent assets
Total Not Designated as Hedges61
 3
 58
  
     Total$76

$3

$73
  
 December 31, 2014  
(In millions)Asset Liability Net Asset Balance Sheet Location
Fair Value Hedges       
     Interest rate$8
 $
 $8
 Other noncurrent assets
     Total$8
 $
 $8
  

1517


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


 June 30, 2015  
(In millions)Asset Liability Net Asset Balance Sheet Location
Fair Value Hedges       
     Interest rate$11
 $
 $11
 Other noncurrent assets
     Total$11

$

$11
  
        
 June 30, 2015  
(In millions)Asset Liability Net Liability Balance Sheet Location
Not Designated as Hedges       
     Commodity$5
 $17
 $12
 Other current liabilities
     Commodity
 9
 9
 Other noncurrent liabilities
     Total$5
 $26
 $21
  
 December 31, 2014  
(In millions)Asset Liability Net Asset Balance Sheet Location
Fair Value Hedges       
     Interest rate$8
 $
 $8
 Other noncurrent assets
     Total$8
 $
 $8
  
Derivatives Designated as Fair Value Hedges
The following table presents, by maturity date, information about our interest rate swap agreements as of JuneSeptember 30, 2015 and December 31, 2014, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.
June 30, 2015 December 31, 2014September 30, 2015 December 31, 2014
Aggregate Notional AmountWeighted Average, LIBOR-Based, Aggregate Notional AmountWeighted Average, LIBOR-Based,Aggregate Notional AmountWeighted Average, LIBOR-Based, Aggregate Notional AmountWeighted Average, LIBOR-Based,
Maturity Dates(in millions)Floating Rate (in millions)Floating Rate(in millions)Floating Rate (in millions)Floating Rate
October 1, 2017$600
4.67% $600
4.64%$600
4.68% $600
4.64%
March 15, 2018$300
4.52% $300
4.49%$300
4.54% $300
4.49%
The pretax effects of derivative instruments designated as hedges of fair value in our consolidated statements of income are summarized in the table below. The foreign currency forwards were used to hedge the current Norwegian tax liability of our Norway business that was sold in the fourth quarter of 2014. Those instruments outstanding were transferred to the purchaser of the Norway business upon closing of the sale. There is no ineffectiveness related to the fair value hedges.
 Gain (Loss) Gain (Loss)
 Three Months Ended June 30, Six Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
(In millions)Income Statement Location2015 2014 2015 2014Income Statement Location2015 2014 2015 2014
Derivative                
Interest rateNet interest and other$(2) $4
 $3
 $3
Net interest and other$4
 $(6) $7
 $(3)
Foreign currencyDiscontinued operations$
 $(14) $
 $(11)Discontinued operations$
 $(18) $
 $(29)
Hedged Item  
  
  
  
  
  
  
  
Long-term debtNet interest and other$2
 $(4) $(3) $(3)Net interest and other$(4) $6
 $(7) $3
Accrued taxesDiscontinued operations$
 $14
 $
 $11
Discontinued operations$
 $18
 $
 $29
 Derivatives not Designated as Hedges
During the first sixnine months of 2015, we entered into multiple crude oil derivatives indexed to New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI"),WTI related to a portion of our forecasted North America E&P sales through December 2016. These commodity derivatives primarily consist of three-way collars, extendable three-way collars and call options and threeoptions. Three way-collars which consist of a sold call (ceiling), a purchased put (floor) and a sold put. The ceiling price is the maximum we will receive for the contract crude oil volumes, the floor is the minimum price we will receive, unless the market price falls below the sold put strike price.

16


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


In this case, we receive the NYMEX WTI price plus the difference between the floor and the sold put price. These commodity derivatives were not designated as hedges and are shown in the table below:

18


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


Financial InstrumentWeighted Average PriceBarrels per dayRemaining TermWeighted Average PriceBarrels per dayRemaining Term
Three-Way Collars  
Ceiling$70.3435,000
July- December 2015 (a)
$70.3435,000October- December 2015
Floor$55.57 $55.57 
Sold put$41.29 $41.29 
  
Ceiling$71.8412,000January- December 2016$60.002,000
October 2015- March 2016 (a)
Floor$60.48 $50.00 
Sold put$50.00 $40.00 
  
Ceiling$73.132,000
January- June 2016 (b)
$71.8412,000       January- December 2016
Floor$65.00 $60.48 
Sold put$50.00 $50.00 
 
Ceiling$73.132,000
January- June 2016 (b)
Floor$65.00 
Sold put$50.00 
Call Options
$72.3910,000
January- December 2016 (c)
$72.3910,000
January- December 2016 (c)
(a) 
Counterparties have the option, exercisable on March 31, 2016, to execute fixed-price swaps (swaptions)extend these collars through September of 2016 at athe same volume and weighted average price of $71.67 per barrel indexed to NYMEX WTI, which is exercisable on October 30, 2015. If counterparties exercise,as the term of the fixed price swaps would be for calendar year 2016 and, if all such are exercised, 25,000 barrels per day.underlying three-way collars.
(b) 
Counterparty has the option, exercisable on June 30, 2016, to extend these collars through the remainder of 2016 at the same volume and weighted average price as the underlying three-way collars.
(c) 
Call options settle monthly.
The impact of these crude oil derivative instruments appears in sales and other operating revenues in our consolidated statements of income and was a net lossgain of $43$108 million and $17$91 million in the secondthird quarter and first sixnine months of 2015. There were no crude oil derivative instruments in the first sixnine months of 2014.
On June 1, 2015, we entered into Treasury rate locks, which expired on the same day, to hedge against timing differences as it related to our Notes offering (see Note 15)18). Following the execution of the Treasury locks, corresponding interest rates increased during the day of June 1. As a result, the settlement of the Treasury rate locks resulted in a gain of $6 million, which was recognized in net interest and other in our consolidated statements of income.
14.17.    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 sixnine months of 2015: 
Stock Options Restricted StockStock Options Restricted Stock
Number of
Shares
 
Weighted
Average
Exercise Price
 Awards 
Weighted
Average Grant
Date Fair Value
Number of
Shares
 
Weighted
Average
Exercise Price
 Awards 
Weighted
Average Grant
Date Fair Value
Outstanding at December 31, 201413,427,836
 
$29.68
 3,448,353
 
$34.04
13,427,836
 
$29.68
 3,448,353
 
$34.04
Granted724,082
(a) 

$29.06
 2,668,357
 
$30.53
724,082
(a) 

$29.06
 2,674,987
 
$30.52
Options Exercised/Stock Vested(480,458) 
$16.47
 (921,404) 
$34.29
(549,926) 
$16.84
 (1,135,635) 
$33.25
Canceled(455,855) 
$34.48
 (491,739) 
$33.70
(605,760) 
$34.11
 (708,380) 
$33.20
Outstanding at June 30, 201513,215,605
 
$29.97
 4,703,567
 
$32.04
Outstanding at September 30, 201512,996,232
 
$29.99
 4,279,325
 
$32.17
(a)    The weighted average grant date fair value of stock option awards granted was $6.84 per share.
Stock-based performance unit awards
 During the first sixnine months of 2015, we granted 382,335 stock-based performance units to certain officers. The grant date fair value per unit was $31.77.

1719


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


15.18.  Debt
Revolving Credit Facility As of JuneSeptember 30, 2015, we had no borrowings against our revolving credit facility (as amended, the "Credit Facility"), as described below.
In May 2015, we amended our $2.5 billion unsecured Credit Facility to increase the facility size by $500 million to a total of $3 billion and extendextended the maturity date by an additional year such that the Credit Facility now matures in May 2020.  The amendment additionally provides us the ability to request two one-year extensions to the maturity date and an option to increase the commitment amount by up to an additional $500 million, subject to the consent of any increasing lenders.  The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively.  Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unchanged.
The Credit Facility includes a covenant requiring that our ratio of total debt to total capitalization not exceed 65% as of the last day of each fiscal quarter. If an event of default occurs, the lenders holding more than half of the commitments may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility. As of JuneSeptember 30, 2015, we were in compliance with this covenant with a debt-to-capitalization ratio of 29%30%.
Debt Issuance On June 10, 2015, we issued $2 billion aggregate principal amount of unsecured senior notes which consist of the following series:
$600 million of 2.70% senior notes due June 1, 2020
$900 million of 3.85% senior notes due June 1, 2025
$500 million of 5.20% senior notes due June 1, 2045
Interest on each series of senior notes is payable semi-annually beginning December 1, 2015. We will use the aggregate net proceeds to repay our $1 billion 0.90% senior notes due 2015, which mature on November 1, 2015, and for general corporate purposes. We may redeem some or all of the senior notes at any time at the applicable redemption price, plus accrued interest, if any. The aggregate net proceeds were used to repay our $1 billion 0.90% senior notes that matured in November 2015, and the remainder for general corporate purposes. As of JuneSeptember 30, 2015, we were in compliance with the covenants under the indenture governing the senior notes.
16.19.  Reclassifications Out of Accumulated Other Comprehensive Income (Loss)
The following table presents a summary of amounts reclassified from accumulated other comprehensive income (loss) to income (loss) from continuing operations in their entirety:
Three Months Ended June 30, Six Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30, 
(In millions)2015 2014 2015 2014 Income Statement Line2015 2014 2015 2014 Income Statement Line
    
Postretirement and postemployment plansPostretirement and postemployment plans       Postretirement and postemployment plans       
Amortization of actuarial loss$(7) $(10) $(14) $(16) General and administrative$(6) $(7) $(20) $(23) General and administrative
Net settlement loss(64) (8) (81) (71) General and administrative(18) (22) (99) (93) General and administrative
Net curtailment gain (loss)(2) 
 3
 
 General and administrative(4) 
 (1) 
 General and administrative
(73) (18) (92) (87) Income (loss) from operations(28) (29) (120) (116) Income (loss) from operations
25
 7
 32
 30
 Benefit for income taxes10
 10
 44
 38
 Benefit for income taxes
Other insignificant, net of tax
 
 
 (1) 
 
 
 (1) 
Total reclassifications$(48) $(11) $(60) $(58) Income (loss) from continuing operations$(18) $(19) $(76) $(79) Income (loss) from continuing operations

1820


MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)


17.20.  Supplemental Cash Flow Information
Six Months Ended June 30,Nine Months Ended September 30,
(In millions)2015 20142015 2014
Net cash used in operating activities:      
Interest paid (net of amounts capitalized)$(143) $(149)$(200) $(201)
Income taxes paid to taxing authorities (a)
(165) (1,336)(174) (1,514)
Net cash provided by (used in) financing activities:      
Commercial paper, net: 
  
 
  
Issuances$
 $2,285
$
 $2,285
Repayments
 (2,420)
 (2,420)
Commercial paper, net$
 $(135)$
 $(135)
Noncash investing activities, related to continuing operations: 
  
 
  
Asset retirement costs capitalized, net of revisions$6
 $42
$12
 $240
Asset retirement obligations assumed by buyer
 52
23
 52
Receivable for disposal of assets
 44

 44
(a) 
The first sixnine months of 2014 included $1.076 billion$1,195 million related to discontinued operations.
18.21.   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.  







1921




Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
Executive Overview
Outlook
Operations
Market Conditions
Results of Operations
Critical Accounting Estimates
Cash Flows and Liquidity
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the preceding consolidated financial statements and notes in Item 1.
Executive Overview
We are aan independent global energyexploration and production company withbased in Houston, Texas. Our operations are primarily located in North America, Europe and Africa. EachAfrica with a focus on our North American unconventional shale plays. Total proved reserves were 2.2 billion boe at December 31, 2014 and total assets were $35 billion at September 30, 2015.
Our significant financial results, operating activities and strategic actions include the following:
Increased company-wide net sales volumes from continuing operations by 7% to 445 mboed in the third quarter of our three reportable operating segments is organized2015 from 417 mboed in the third quarter of 2014
Net sales volumes from our three U.S. resource plays increased 9% to 210 mboed in the third quarter of 2015 from 192 mboed in the third quarter of 2014
Maintained focus on cost discipline and managed based upon both geographic locationefficiencies
Reduced third quarter cash capital expenditures to $628 million, a 28% decrease compared to the previous quarter, reflecting continued capital discipline and benefits from operating efficiencies
Reduced company-wide production expenses per boe in the third quarter of 2015 compared to the same period last year
North America E&P - 27% reduction to $7.43 per boe
International E&P - 47% reduction to $5.53 per boe
Oil Sands Mining - 30% reduction to $26.01 per boe
Achieved 97% average operational availability for our operated assets in the third quarter of 2015
Active management of liquidity and capital structure
At the end of the third quarter, we had $5.4 billion of liquidity, including $2.4 billion in cash and short-term investments, $1 billion of which was used to repay our senior notes that matured in November
Cash and short-term investments-adjusted debt-to-capital ratio of 24% at September 30, 2015, as compared with 16% at December 31, 2014
Portfolio management activities
We continue to make progress advancing our goal to divest at least $500 million of non-core asset sales
Closed on the sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets in August 2015 for proceeds of approximately $100 million
Signed agreement for sale of our East Africa exploration acreage
Financial results
Loss from continuing operations per diluted share of $1.11 in the third quarter of 2015 as compared to income from continuing operations of $0.45 per diluted share in the same period last year
Included in the loss for the third quarter are $611 million ($949 million pre-tax) of non-cash charges comprised largely of losses and asset impairments resulting from lower forecasted commodity prices and changes in our conventional exploration strategy (refer to Exploration Update below)
Operating cash flow provided by continuing operations for the first nine months of 2015 was $1.2 billion, compared to $3.5 billion in the same period last year, reflecting the lower commodity price environment

Subsequent to the natureend of the productsthird quarter, we reduced our quarterly dividend from $0.21 to $0.05 per share to address the uncertainty of a lower for longer commodity price environment, to align with our priority of maintaining a strong balance sheet through the cycle and services it offers.
North America E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in North America;
International E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North America and produces and markets products manufacturedto provide us with additional capital flexibility to support growth from natural gas, such as LNG and methanol, in 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.U.S. resource plays when commodity prices improve.

As a result of the sale of our Angola assets and our Norway business in 2014, both are reflected as discontinued operations. The disclosures in this report related to results of operations and cash flows are presented on the basis of continuing operations, unless otherwise noted.
22


Executive OverviewOutlook
Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows and their subsequent reinvestmentthe amount of capital available to reinvest into our business. Commodity prices began declining in the second half of 2014 and remain substantially lower through 2015 as compared to the first six months of 2014.2015. We believe we can manage in this lower commodity price cycle through a continued focus on development in our three U.S. resource plays, operational execution, efficiency improvements, cost reductions, capital discipline and portfolio optimization, all while maintaining financial flexibility.
Our significant financial results, operating activities and strategic actions include the following:
Increased company-wide net sales volumes from continuing operations by 4% to 411 thousand barrels of oil equivalent per day ("mboed") in the second quarter of 2015 from 394 mboed in the second quarter of 2014
Net sales volumes from our three U.S. resource plays increased 29% to 220 mboed in the second quarter of 2015 from 170 mboed in the second quarter of 2014
Maintained focus on cost discipline and efficiencies
Reduced North America E&P production expenses per boe by 31% in the second quarter of 2015 compared to the same period last year
Achieved 96% average operational availability for our operated assets in the second quarter of 2015
Reallocated an additional $35 million of capital to Oklahoma Resource Basins to leverage higher non-operated activity and to further advance subsurface knowledge and resource delineation
Active management of liquidity and capital structure
$5.5 billion of liquidity at the end of the second quarter, comprised of $3.0 billion in the unused revolving credit facility and $2.5 billion in cash and short-term investments
Cash and short-term investments-adjusted debt-to-capital ratio of 22% at June 30, 2015, as compared with 16% at December 31, 2014
Issued $2 billion of senior notes in June 2015; plan to use $1 billion of proceeds to satisfy scheduled debt maturities in the fourth quarter of 2015 and the remainder for general corporate purposes
Increased the capacity of the revolving credit facility to $3.0 billion from $2.5 billion while also extending the maturity date to May 2020
Repatriated Canadian earnings in tax efficient manner, providing $250 million of cash available for use in U.S. operations
Executed additional derivative instruments to reduce commodity price uncertainty for a portion of our forecasted North America E&P crude oil volumes
Portfolio management activities
We are targeting to generate at least $500 million from select non-core asset sales
Signed definitive sales agreement in July 2015 related to non-core assets for expected proceeds of $102 million, excluding closing-adjustments
Financial results
Loss from continuing operations per diluted share of $0.57 in the second quarter of 2015 as compared to income from continuing operations of $0.53 per diluted share in the same period last year

20


Recognized additional non-cash deferred tax expense of $135 million in the second quarter of 2015 related to the increase in Alberta's provincial corporate income tax rate
Operating cash flow provided by continuing operations for the first six months of 2015 was $717 million, compared to $2.1 billion in the same period last year, reflecting the lower commodity price environment
We continue to optimize our resource allocation given the current price environment. We expect our full-year 2015 capital, investment and exploration budget to be at or below $3.3$3.1 billion. We estimate our full-year North America E&P and International E&P production volumes (excluding Libya) to be 375380 - 390 net mboed and OSM's synthetic crude oil production to be 40 - 45 net mboed. In addition, based on our current outlook and preliminary plan discussions, we would anticipate a 2016 capital, investment and exploration program of up to $2.2 billion which would give us the flexibility to deliver 2016 annual average production in the U.S. resource plays flat to the 2015 exit rate.
Exploration Update
In September 2015, we announced our intention to scale back our conventional exploration program with an anticipated 2016 program of approximately $100 million, a reduction of 60% as compared to the 2015 budget, subject to approval by our Board of Directors.  Our conventional exploration focus will be redirected to existing commitments in the Gulf of Mexico and Gabon.  As a result, we recorded non-cash impairments related to unproved properties in the Gulf of Mexico and the Harir block in the Kurdistan Region of Iraq in the third quarter.
Operations
The following table presents a summary of our sales volumes for each of our segments. Refer to the Results of Operations for a price-volume analysis for each of the segments.
 Three Months Ended September 30, Nine Months Ended September 30,
Net Sales Volumes2015 2014 Increase
(Decrease)
 2015 2014 Increase
(Decrease)
North America E&P (mboed)
261 250 4% 273 230 19%
International E&P (mboed)
119 112 6% 115 121 (5)%
Oil Sands Mining (mbbld) (a)
65 55 18% 51 49 4%
Total Continuing Operations (mboed)
445 417 7% 439 400 10%
(a)    Includes blendstocks





Operations
North America E&P--Production&P--Net Sales Volumes
Net sales volumes in the North America E&P segment average net sales volumes in the second quarter and first six monthsincreased as a result of 2015 increased 21% and 26% compared to the second quarter and first six months of 2014.  Net liquid hydrocarbon sales volumes increased 35 thousand barrels per day ("mbbld") and 47 mbbld, and net natural gas sales volumes increased 67 million cubic feet per day ("mmcfd") and 63 mmcfd in the second quarter and first six months of 2015 compared to the second quarter and first six months of 2014, reflecting continued growth from the combined U.S. resource plays. The following table provides net sales volumes for our significant operational areas within this segment.

Three Months Ended June 30, Six Months Ended June 30,
2015 2014 2015 2014Three Months Ended September 30, Nine Months Ended September 30,
Net Sales Volumes       2015 2014 Increase
(Decrease)
 2015 2014 Increase
(Decrease)
Crude Oil and Condensate (mbbld)
 
Bakken54 44 53 41
Equivalent Barrels (mboed)
 
Eagle Ford82 67 87 65126 117 8% 137 105 30%
Oklahoma Resource Basins5 2 5 223 19 21% 24 17 41%
Other North America (a)
35 38 35 36
Total Crude Oil and Condensate176 151 180 144
Natural Gas Liquids (mbbld)
 
Bakken3 3 3 261 56 9% 59 50 18%
Eagle Ford26 16 26 16
Oklahoma Resource Basins6 6 6 5
Other North America(a)
2 2 3 4
Total Natural Gas Liquids37 27 38 27
Total Liquid Hydrocarbons (mbbld)
 
Bakken57 47 56 43
Eagle Ford108 83 113 81
Oklahoma Resource Basins11 8 11 7
Other North America(a)
37 40 38 40
Total Liquid Hydrocarbons213 178 218 171
Natural Gas (mmcfd)
 
Bakken22 18 20 17
Eagle Ford164 111 167 109
Oklahoma Resource Basins81 61 79 58
Other North America(a)
94 104 94 113
Total Natural Gas361 294 360 297
Equivalent Barrels (mboed)
 
Bakken61 50 59 46
Eagle Ford135 102 141 99
Oklahoma Resource Basins24 18 24 17
Other North America(a)
54 57 54 5851 58 (12)% 53 58 (9)%
Total North America E&P274 227 278 220261 250 4% 273 230 19%
(a)     Includes Gulf of Mexico and other conventional onshore U.S. production.
(a)
Includes Gulf of Mexico and other conventional onshore U.S. production.




The following table provides our sales mix for each of our U.S. resource plays.
22


 Three Months Ended September 30,
 2015
 Eagle Ford Oklahoma Resource Basins Bakken
Crude oil and condensate59% 18% 87%
Natural gas liquids20% 28% 8%
Natural gas21% 54% 5%
The following table presents a summary of our operated drilling activity in the U.S. resource plays:
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended September 30, Nine Months Ended September 30,
2015 2014 2015 20142015 2014 2015 2014
Gross Operated    
Eagle Ford:  
Wells drilled to total depth59 88 147 17151 93 198 264
Wells brought to sales52 76 143 12557 87 200 212
Oklahoma Resource Basins: 
Wells drilled to total depth4 4 17 15
Wells brought to sales8 6 16 14
Bakken:  
Wells drilled to total depth5 19 25 225 25 30 60
Wells brought to sales22 19 46 165 18 51 52
Oklahoma Resource Basins: 
Wells drilled to total depth5 6 13 11
Wells brought to sales3 4 8 8
Eagle Ford – Of the 57 gross wells brought to sales during this quarter, 11 were in the Austin Chalk, 6 were in the Upper Eagle Ford, – Average net sales volumes from Eagle Ford were 135 mboed and 141 mboed40 in the second quarter and first six months of 2015 compared to 102 mboed and 99 mboed in the same periods of 2014, for increases of 32% and 42%. Approximately 61% of second quarter sales was crude oil and condensate, 19% was NGLs and 20% was natural gas.Lower Eagle Ford. Our average time to drill an Eagle Ford well in secondthe third quarter 2015, spud-to-total depth, was 11decreased to 10 days. Also, during
Oklahoma Resource Basins – During the secondthird quarter, of 2015, we spud our first Springer well and brought online 8 Upper Eagle Ford, 33 Lower Eagle Ford and 11 Austin Chalk gross operated wells (6 in SCOOP and 2 in STACK), with one of the SCOOP wells being an extended-reach lateral. In addition to the 8 wells mentioned above, we completed and brought online three "stack-and-frac" pilots with wells in three horizons.
Bakken – Average net sales volumes from the Bakken shale were 61 mboed and 59 mboed in the second quarter and first six months of 2015 compared to 50 mboed and 46 mboed in the same period for 2014, for increases of 22% and 28%. Our Bakken production averaged approximately 89% crude oil, 5% NGLs and 6% natural gas. Our time to drill a Bakken well, spud-to-total depth, averaged 13 days in the second quarter of 2015.
Application of the enhanced completion design continues to provide promising results, with outperformance of historical type curves after 180 days of cumulative production. The enhanced completion design optimizes proppant loading, frac fluid volumes and stage density. Three high-density pilots (six wells per horizon) were completed through the second quarter. Also in the second quarter, our first Three Forks second benchan additional Smith infill pilot well in the MyrmidonSCOOP which was completed.
Oklahoma Resource Basins – Net sales volumes from the Oklahoma Resource Basins averaged 24 mboed in both the second quarter and first six months of 2015 compared to 18 mboed and 17 mboed in the comparable 2014 periods, for increases of 33% and 41%. Our second quarter 2015 production was approximately 20% crude, 25% NGLs and 55% natural gas. Of the three gross operated wells brought to sales this quarter, two were SCOOPon October 1. These wells and one was a STACK Osage well.are all in the very early stages of production. We also finished drilling five operated Smith infill pilot wells this quarter.
Additionally, we continue to leverage the benefit of participation in outside-operated wells and plan to participate in approximately 8555-70 gross outside-operated wells in 2015 in the SCOOP Woodford, SCOOP Springer and STACK areas. In the first six months of 2015, we participated in fourareas, with 17 outside-operated high-density spacing pilots in the SCOOP area; three in the Woodford (80-128 acre spacing) and one in the emerging Springer shale (105-128 acre spacing) overlaying the Woodford. Two outside-operated STACK Meramec XL wells were brought to sales during the quarter.
Bakken – The 5 gross wells brought to sales this quarter were in the East Myrmidon area. Despite the lower number of wells to sales this quarter, sales volumes were driven by continued strong performance from the Doll pad wells (West Myrmidon) which came online in late June as well as sustained improvement in production uptime. We expect reduced completions activity during the fourth quarter.
Gulf of Mexico – Development work continues in the Gunflint field located on Mississippi Canyon Blocks 948, 949, 992 (N/2) and 993 (N/2). We expect the two-well subsea tieback to be complete by the end of 2015 with first oil in the second half of 2015.mid-2016. We hold an 18% non-operated working interest in the Gunflint field.
North America E&P--Exploration
Gulf of MexicoDuring the second quarter, we spud the Solomon exploration prospect on Walker Ridge Block 225 and farmed down our operated working interest to 58%.
The third appraisal well on the Shenandoah prospect was spud in May 2015 and is still drilling.reached total depth in October, finding more than 620 feet of net oil pay. The operator completed logging operations and will obtain a whole core across the reservoir interval. The well is located in Walker Ridge Block 52,51, in which we hold a 10% non-operated working interest.

23


International E&P--Production
International E&P segment average net sales volumes in the second quarter and first six months of 2015 decreased 12% and 10% compared to the second quarter and first six months of 2014, reflecting field decline and a planned turnaround in Equatorial Guinea in The Solomon exploration prospect located on Walker Ridge Block 225 was spud during the second quarter of 2015 which also reducedand is expected to reach total depth in the fourth quarter. We hold a 58% operated working interest in this prospect.

24


International E&P--Net Sales Volumes
The following table provides net sales to the AMPCO and LNG facilities. In addition, the AMPCO methanol facility completed a planned turnaround in first quarter 2015.volumes for our significant operational areas within this segment.
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended September 30, Nine Months Ended September 30,
2015 2014 2015 20142015 2014 
Increase
(Decrease)
 2015 2014 Increase
(Decrease)
Net Sales Volumes        
Crude Oil and Condensate (mbbld)
       
Equatorial Guinea19
 20
 18
 22
United Kingdom14
 13
 14
 13
Total Crude Oil and Condensate33
 33
 32
 35
Natural Gas Liquids (mbbld)
       
Equatorial Guinea9
 11
 10
 11
United Kingdom
 
 
 
Total Natural Gas Liquids9
 11
 10
 11
Total Liquid Hydrocarbons (mbbld)
       
Equatorial Guinea28
 31
 28
 33
United Kingdom14
 13
 14
 13
Total Liquid Hydrocarbons42
 44
 42
 46
Natural Gas (mmcfd)
       
Equivalent Barrels (mboed)
 
Equatorial Guinea365
 446
 390
 441
101 97 4% 96 104 (8)%
United Kingdom(a)
31
 28
 32
 29
18 9 100% 19 15 27%
Libya
 
 
 1
 6 (100)%  2 (100)%
Total Natural Gas396
 474
 422
 471
Equivalent Barrels (mboed)
       
Equatorial Guinea89
 105
 93
 107
United Kingdom(a)
19
 18
 19
 18
Total International E&P (mboed)
108
 123
 112
 125
119 112 6% 115 121 (5)%
Net Sales Volumes of Equity Method Investees        
 
LNG (mtd)
4,991
 6,624
 5,629
 6,601
5,700 6,265 (9)% 5,653 6,488 (13)%
Methanol (mtd)
673
 980
 778
 1,066
1,125 1,103 2% 895 1,078 (17)%
(a) 
Includes natural gas acquired for injection and subsequent resale of 78 mmcfd and 3 mmcfd for the third quarters of 2015 and 2014, and 8 mmcfd and 5 mmcfd for the second quarters of 2015 and 2014, and 9 mmcfd and 6 mmcfd for the first sixnine months of 2015 and 2014.
Equatorial GuineaAverageThird quarter net sales volumes were 89 mboed and 93 mboed in the second quarter and first six months of 2015 compared to 105 mboed and 107 mboed in the same periods of 2014. Planned turnaround and maintenance activities at the Alba field and EG LNG facilities reducedincreased as production rates during the second quarter of 2015. The Alba turnaround subsequently reduced sales to our equity method investees, Alba Plant LLC, EGHoldings and AMPCO. Additionally, there was a planned turnaround at AMPCO in the first quarter of 2015.
During the second quarter of 2015,from the Alba C21 development well reached total depthcame online with higher than expected yields, combined with a successful wire-line intervention program on five existing Alba wells. The ongoing Alba field compression project, designed to maintain the production plateau two additional years and extend field life up to eight years, achieved mechanical completion activities are underway. To date, well performance results are consistent with pre-drill estimates.at the fabrication yard in the Netherlands during the third quarter and is on schedule to be operational in mid-2016.
United Kingdom Average net sales volumes were 19 mboed for each of the second quarter and first six months of 2015, relatively flat as compared to 18 mboed in the same periods of 2014. Net sales volumes benefited from improved production as two subsea development wells at West Brae began producing during the first2015. Overall, operating availability was higher for all U.K. assets in 2015 as compared to comparative 2014 periods which included planned and second quarters of 2015. This completed the last of the planned five-well Brae infill drilling program begun in 2014. In addition, as fullcompression was reinstated during the second quarter of 2015 at the non-operated Foinaven field, this contributed to improved reliability.
unplanned maintenance activities. During the third quarter of 2015, planned maintenance activities are scheduledwere completed at the East Brae field and continue at the non-operated Foinaven field. The activity at Foinaven will impact production volumes during the fourth quarter of 2015.
Libya – We had no sales during the first sixnine months of 2015 as a result of continued civil unrest.unrest, as compared to one lifting in the third quarter of 2014. In December 2014, Libya’s National Oil Corporation reinstated force majeure at the Es Sider oil terminal, as disruptions from civil unrest continue.terminal. Considerable uncertainty remains around the timing of future production and sales levels.

24


International E&P--Exploration
Kurdistan Region of Iraq – On the Harir Block, testing was completed on the Mirawa-2 appraisal well during the second quarter of 2015. The well has been temporarily suspended as a potential future producer and the drilling rig has been de-mobilized. We hold a 45% operated working interest in the block.
Oil Sands Mining
 Our net synthetic crude oil sales volumes were 2965 mbbld and 4451 mbbld in the secondthird quarter and first sixnine months of 2015 compared to 4455 mbbld and 4549 mbbld in the same periods of 2014. Production declinedNet sales volumes increased in the secondthird quarter of 2015 primarily due to the planned turnaroundsimproved mine reliability and no major maintenance activities. Planned maintenance at the base upgrader and Muskeg River Mine and unplanned downtime at the expansion upgrader. Production was relatively flatboth mines in the first six months of 2015 compared to the same period in 2014 as the planned turnarounds and unplanned downtime during the secondfourth quarter of 2015 were mostly offset by higher production driven by improved mine reliability during the first quarter of 2015.is expected to impact production. We hold a 20% non-operated working interest in the AOSP.Athabasca Oil Sands Project. 

 

25



Market Conditions
Prevailing prices for the crude oil, NGLs and natural gas that we produce significantly impact our revenues and cash flows. The benchmark prices for crude oil, NGLs and natural gas were significantly lower in the secondthird quarter and first sixnine months of 2015 as compared to the same periods in 2014; as a result, we experienced significant declines in our price realizations associated with those benchmarks. Additional detail on market conditions, including our average price realizations and benchmarks for crude oil, NGLs and natural gas relative to our operating segments, follows.
North America E&P
 The following table presents our average price realizations and the related benchmarks for crude oil, NGLs and natural gas for the secondthird quarter and first sixnine months of 2015 and 2014.
 Three Months Ended June 30, Six Months Ended June 30,
 2015 2014 2015 2014
Average Price Realizations (a)
       
Crude Oil and Condensate (per bbl) (b)
       
Bakken
$51.36
 
$93.08
 
$45.84
 
$91.43
Eagle Ford53.47
 99.08
 47.81
 97.65
Oklahoma Resource Basins51.00
 101.12
 48.34
 98.05
Other North America (c)
52.83
 93.45
 47.10
 91.40
Total Crude Oil and Condensate52.63
 95.95
 47.11
 94.30
Natural Gas Liquids (per bbl)
       
Bakken
$11.63
 
$45.13
 
$7.19
 
$51.04
Eagle Ford14.08
 30.20
 13.90
 33.76
Oklahoma Resource Basins14.45
 33.04
 15.83
 38.21
Other North America (c)
25.65
 54.13
 26.03
 57.65
Total Natural Gas Liquids14.77
 34.80
 14.60
 38.75
Total Liquid Hydrocarbons (per bbl)
       
Bakken
$49.29
 
$90.47
 
$43.72
 
$89.16
Eagle Ford44.05
 85.36
 40.01
 84.78
Oklahoma Resource Basins30.29
 52.00
 29.24
 55.04
Other North America (c)
50.89
 90.45
 45.52
 88.97
Total Liquid Hydrocarbons45.96
 86.43
 41.37
 85.65
Natural Gas (per mcf)
       
Bakken
$2.62
 
$4.12
 
$2.76
 
$6.14
Eagle Ford2.71
 4.76
 2.79
 4.83
Oklahoma Resource Basins2.64
 4.57
 2.63
 5.01
Other North America (c)
2.98
 5.65
 3.29
 5.35
Total Natural Gas2.76
 5.00
 2.88
 5.14
Benchmarks       
WTI crude oil (per bbl)(d)

$57.95
 
$102.99
 
$53.34
 
$100.84
Louisiana Light Sweet ("LLS") crude oil (per bbl)(e)
62.94
 105.55
 57.97
 104.97
Mont Belvieu NGLs (per bbl) (f)
17.65
 34.54
 18.02
 36.42
Henry Hub natural gas(g) (per mmbtu)(h)  
2.64
 4.67
 2.81
 4.80
 Three Months Ended September 30, Nine Months Ended September 30,
 2015 2014 Decrease 2015 2014 Decrease
Average Price Realizations (a)
           
Crude Oil and Condensate (per bbl) (b)
$41.37 $89.65 (54)% $45.27 $92.59 (51)%
Natural Gas Liquids (per bbl)
11.88 33.93 (65)% 13.67 36.96 (63)%
Total Liquid Hydrocarbons (per bbl)
35.75 80.89 (56)% 39.55 83.89 (53)%
Natural Gas (per mcf)
2.75 4.21 (35)% 2.84 4.81 (41)%
Benchmarks           
WTI crude oil (per bbl)
$46.50 $97.25 (52)% $51.01 $99.62 (49)%
LLS crude oil (per bbl)
50.22 101.03 (50)% 55.33 103.63 (47)%
Mont Belvieu NGLs (per bbl) (c)
15.86 32.69 (51)% 17.28 35.15 (51)%
Henry Hub natural gas (per mmbtu)
2.77 4.06 (32)% 2.80 4.55 (38)%
(a) 
Excludes gains or losses on derivative instruments.
(b) 
Inclusion of realized gains on crude oil derivative instruments would have increased average crude oil price realization by $0.06$1.87 per bbl and $0.14$0.69 per bbl for the secondthird quarter and first sixnine months of 2015. There were no crude oil derivative instruments in 2014.
(c) 
Includes Gulf of Mexico and other conventional onshore U.S. production.
(d)
NYMEX.
(e)
Bloomberg Finance LLP: LLS St. James.
(f)
Bloomberg Finance LLP: Y-grade Mix NGL of 50% ethane, 25% propane, 10% butane, 5% isobutane and 10% natural gasoline.
(g)
Settlement date average.
(h)
Million British thermal units.
Crude oil and condensate – Our crude oil and condensate price realizations may differ from the benchmark due to the quality and location of the product.
Natural gas liquids – The majority of our NGL volumes are sold at reference to Mont Belvieu prices.

26



Natural gas A significant portion of our natural gas production in the U.S. is sold at bid-week prices, or first-of-month indices relative to our specific producing areas.  
International E&P
The following table presents our average price realizations and the related benchmark for crude oil, NGLs, and natural gas for the secondthird quarter and first sixnine months of 2015 and 2014.
 Three Months Ended June 30, Six Months Ended June 30,
 2015 2014 2015 2014
Average Price Realizations       
Crude Oil and Condensate (per bbl)
       
Equatorial Guinea
$52.27
 
$90.91
 
$47.55
 
$90.66
United Kingdom62.97
 111.76
 60.19
 111.38
Total Crude Oil and Condensate56.70
 99.36
 52.92
 98.51
Natural Gas Liquids (per bbl)
       
Equatorial Guinea (a)

$1.00
 
$1.00
 
$1.00
 
$1.00
United Kingdom36.49
 64.37
 34.82
 69.56
Total Natural Gas Liquids3.10
 3.02
 3.29
 3.64
Total Liquid Hydrocarbons (per bbl)
       
Equatorial Guinea
$35.74
 
$59.72
 
$31.81
 
$61.12
United Kingdom61.93
 110.51
 58.96
 110.02
Total Liquid Hydrocarbons44.70
 75.41
 41.06
 75.48
Natural Gas (per mcf)
       
Equatorial Guinea (a)

$0.24
 
$0.24
 
$0.24
 
$0.24
United Kingdom6.98
 8.04
 7.34
 9.07
Libya
 
 
 5.45
Total Natural Gas0.78
 0.69
 0.78
 0.80
Benchmark       
Brent (Europe) crude oil (per bbl)(b)

$61.69
 
$109.70
 
$57.81
 
$108.93
 Three Months Ended September 30, Nine Months Ended September 30,
 2015 2014 Increase
(Decrease)
 2015 2014 Increase
(Decrease)
Average Price Realizations           
Crude Oil and Condensate (per bbl)
$46.18 $89.07 (48)% $50.51 $95.71 (47)%
Natural Gas Liquids (per bbl)
2.69 1.00 169% 3.08 2.83 9%
Liquid Hydrocarbons (per bbl)
35.88 66.80 (46)% 39.21 72.88 (46)%
Natural Gas (per mcf)
0.59 0.56 5% 0.71 0.73 (3)%
Benchmark    
     
Brent (Europe) crude oil (per bbl) (a)
$50.23 $101.82 (51%) $55.28 $106.56 (48%)
(a) 
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.
(b)
Average of monthly prices obtained from Energy Information Administration ("EIA")EIA website.
Liquid hydrocarbons – Our United Kingdom ("U.K.") liquid hydrocarbon production is generally sold in relation to the Brent crude benchmark. Our production from Equatorial Guinea is condensate, which receives lower prices than crude oil.

NGLs
26



Our NGL and natural gas sales in the International E&P segment originate primarily from our E.G. operations and are subjectsold to our equity method investees under fixed-price, term contracts; therefore, our reported average NGL realized prices within the International E&P segmentfor NGLs and natural gas will not fully track market price movements.
Natural gasOur The equity affiliates then utilize, process and sell the NGLs and natural gas salesat market prices, with our share of their income/loss reflected in the Income from E.G. are subject to fixed-price, term contracts, making realized prices in this area less volatile; therefore, our reported average natural gas realized prices withinequity method investments line item on the International E&P segment will not fully track market price movements.Consolidated Statements of Income.
Oil Sands Mining
The Oil Sands Mining segment produces and sells various qualities of synthetic crude oil. Output mix can be impacted by operational reliability or planned unit outages at the mines or upgrader. Sales prices for roughly two-thirds of the normal output mix have historically tracked movements in WTI and one-third have historically tracked movements in the Canadian heavy crude oil marker, primarily Western Canadian Select ("WCS").WCS.
The operating cost structure of our 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.

27



The following table presents our average price realizations and the related benchmarks that impacted both our revenues and variable costs for the secondthird quarter and first sixnine months of 2015 and 2014.
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended September 30, Nine Months Ended September 30,
2015 2014 2015 20142015 2014 Decrease 2015 2014 Decrease
Average Price Realizations        
Synthetic Crude Oil (per bbl)

$52.46
 
$94.17
 
$44.33
 
$91.27
$39.49 $88.22 (55%) $42.26 $90.11 (53%)
Benchmark       
Benchmarks 
WTI crude oil (per bbl)(a)

$57.95
 
$102.99
 
$53.34
 
$100.84
$46.50 $97.25 (52%) $51.01 $99.62 (49%)
WCS crude oil (per bbl)(b)

$46.35
 
$82.95
 
$40.13
 
$79.25
AECO natural gas sales index (per mmbtu)(c)

$2.05
 
$4.46
 
$2.07
 
$4.72
WCS crude oil (per bbl)(a)
33.16 76.99 (57%) 37.80 78.50 (52%)
(a)
NYMEX.
(b) 
Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.
(c)
Monthly average AECO day ahead index.

27



Results of Operations
Consolidated Results of OperationThree Months Ended September 30, 2015 vs. Three Months Ended September 30, 2014
Sales and other operating revenues, including related party are presented by segment in the table below:
 Three Months Ended June 30, Six Months Ended June 30,
(In millions)2015 2014 2015 2014
Sales and other operating revenues, including related party       
North America E&P$993
 $1,540
 $1,843
 $2,932
International E&P211
 347
 393
 727
Oil Sands Mining147
 383
 372
 760
Segment sales and other operating revenues, including related party$1,351
 $2,270
 $2,608
 $4,419
Unrealized loss on crude oil derivative instruments(44) 
 (21) 
Sales and other operating revenues, including related party$1,307
 $2,270
 $2,587
 $4,419
 Three Months Ended September 30,
(In millions)2015 2014
Sales and other operating revenues, including related party   
North America E&P$796
 $1,586
International E&P182
 273
Oil Sands Mining242
 457
Segment sales and other operating revenues, including related party$1,220
 $2,316
Unrealized gain on crude oil derivative instruments80
 
Sales and other operating revenues, including related party$1,300
 $2,316
Below is a price/volume analysis for each segment. Refer to the preceding Operations and Market Conditions sections for additional detail related to our net sales volumes and average price realizations.
North America E&P
  Three Months Ended Increase (Decrease) Related to Three Months Ended
(In millions) June 30, 2014 Price Realizations Net Sales Volumes June 30, 2015
North America E&P Price-Volume Analysis
Liquid hydrocarbons $1,403
 $(786) $276
 $893
Natural gas 133
 (73) 30
 90
Realized gain on crude oil        
    derivative instruments 
 1
 

 1
Other sales 4
 

 

 9
Total $1,540
     $993
  Six Months Ended Increase (Decrease) Related to Six Months Ended
(In millions) June 30, 2014 Price Realizations Net Sales Volumes June 30, 2015
North America E&P Price-Volume Analysis
Liquid hydrocarbons $2,647
 $(1,748) $734
 $1,633
Natural gas 276
 (147) 59
 188
Realized gain on crude oil        
    derivative instruments 
 5
   5
Other sales 9
     17
Total $2,932
     $1,843

28



International E&P
  Three Months Ended Increase (Decrease) Related to Three Months Ended
(In millions) June 30, 2014 Price Realizations Net Sales Volumes June 30, 2015
International E&P Price-Volume Analysis
Liquid hydrocarbons $305
 $(118) $(15) $172
Natural gas 30
 3
 (5) 28
Other sales 12
     11
Total $347
     $211
  Six Months Ended Increase (Decrease) Related to Six Months Ended
(In millions) June 30, 2014 Price Realizations Net Sales Volumes June 30, 2015
International E&P Price-Volume Analysis
Liquid hydrocarbons $634
 $(261) $(63) $310
Natural gas 69
 (2) (7) 60
Other sales 24
     23
Total $727
     $393
Oil Sands Mining
  Three Months Ended Increase (Decrease) Related to Three Months Ended
(In millions) June 30, 2014 Price Realizations Net Sales Volumes June 30, 2015
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil $377
 $(110) $(130) $137
Other sales 6
 

 

 10
Total $383
     $147
 Six Months Ended Increase (Decrease) Related to Six Months Ended Three Months Ended Increase (Decrease) Related to Three Months Ended
(In millions) June 30, 2014 Price Realizations Net Sales Volumes June 30, 2015 September 30, 2014 Price Realizations Net Sales Volumes September 30, 2015
North America E&P Price-Volume AnalysisNorth America E&P Price-Volume Analysis
Liquid hydrocarbons $1,464
 $(850) $60
 $674
Natural gas 123
 (45) 7
 85
Realized gain on crude oil        
derivative instruments 
 28
 

 28
Other sales (1) 

 

 9
Total $1,586
     $796
International E&P Price-Volume AnalysisInternational E&P Price-Volume Analysis
Liquid hydrocarbons $240
 $(130) $42
 $152
Natural gas 22
 2
 
 24
Other sales 11
     6
Total $273
     $182
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil $750
 $(376) $(19) $355
 $445
 $(294) $85
 $236
Other sales 10
     17
 12
 

 

 6
Total $760
     $372
 $457
     $242
Marketing revenues decreased $435 million and $772$470 million in the secondthird quarter and first six months of 2015 from the comparable prior-year periods.period. Marketing activities include the purchase of commodities from third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points. BecauseSince the volume of marketing activity is based on market dynamics, it can fluctuate from period to period. The decreases are related primarily to lower marketed volumes in North America, which were further compounded by a lower commodity price environment.
Income from equity method investments decreased $94 million and $195$53 million in the secondthird quarter and first six months of 2015 from the comparable 2014 period. The decrease in the second quarter of 2015 is primarily due to lower price realizations for Liquified Natural Gas ("LNG")LPG at our Alba plant, LNG at our LNG facility, Liquified Petroleum Gas ("LPG") at our Alba plant, and lower methanol prices at our AMPCO methanol facility, all of which are located in E.G. Also contributing toimpacting the decreasequarter was a partial impairment of our investment in 2015 were lower sales volumes due to the previously mentioned planned turnaround and maintenance activities at the AMPCO methanol plant, the Alba field and the LNG facility.an equity method investee.
Production expenses decreased $112 million in the second quarter of 2015 compared to the second quarter of 2014.$187 million. North America E&P declined $38$54 million due to lower operational, maintenance and labor costs. International E&P declined $35$47 million primarily becausethe result of higher project costs in 2014, such as the non-operated Foinaven subsea power project. Also contributing were lower production costs related to lower sales volumes, whilein Libya during 2015 as the secondthird quarter of 2014 included $5 million of turnaround costs at Brae and subsea maintenance costs at the non-operated Foinaven field in the U.K.had one lifting. OSM decreased $39$86 million primarily due to lower feedstock purchases (due to planned turnarounds and unplanned downtime as previously discussed) and continued cost management, especially staffing and contract labor. Also contributing to the OSM decrease was a more favorable exchange rate on expenses denominated in the Canadian Dollar. These declines were partially offset by costs incurred from the turnaround.
Production expenses for the first six months of 2015 decreased by $210 million compared to the same period of 2014. North America E&P declined $47 million due toDollar and lower operational, maintenance and labor costs. International E&P declinedfeedstock purchases given increased reliability.

2928



$68 million due to lower repair, maintenance and turnaround costs as well as lower production volumes. The previous six month period included $11 million of non-recurring riser repair costs in E.G., $5 million of expenses from a Brae turnaround and costs related to reliability issues and subsea maintenance at the non-operated Foinaven field in the U.K. OSM decreased $95 million due to the same reasons as described in the preceding paragraph.
The secondthird quarter of 2015 production expense rate (expense per boe) for North America E&P declined relative to the same quarter in 2014 due to overall cost reductions, as previously discussed, and leveraging efficiencies as production volumes increased. The expense rate for International E&P declined due to reduced maintenance and project costs and lower operational costs in second quarter of 2015 as compared to 2014.Libya. The OSM expense rate decreased as production volume increased, due tocoupled with the turnarounds and unplanned downtime in the second quarter of 2015, which resulted in lower sales volumes and higher costs.increased cost focus discussed above.
The expense rate during the first six months of 2015 compared the same period in 2014 decreased for North America E&P due to overall cost reductions as discussed in the preceding paragraph. The International E&P expense rate decreased in the first six months of 2015 due to lower project costs as discussed in the preceding paragraphs. The OSM expense rate remained relatively flat in the six months of 2015 as the lower feedstock purchases, cost management and a favorable exchange rate were offset by the aforementioned higher turnaround costs. The following table provides production expense rates for each segment:
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended September 30,
($ per boe)2015 2014 2015 20142015 2014
Production Expense Rate        
North America E&P
$7.19
 
$10.47
 
$7.57
 
$10.74
$7.43 $10.16
International E&P
$6.51
 
$8.87
 
$6.45
 
$8.82
$5.53 $10.48
Oil Sands Mining (a)

$78.24
 
$51.53
 
$50.06
 
$49.54
$26.01 $37.38
(a) 
Production expense per synthetic crude oil barrel (before royalties) includes direct production costs (less pre-development), shipping and handling and taxes other than income and insurance costs and excludes pre-development costs.income.
Marketing costs decreased $432 million and $769$470 million in the secondthird quarter and first six months of 2015 from the comparable 2014 periods,period, consistent with the marketing revenues changes discussed above.
 Exploration expenses declined $34 million inincreased $489 million. We made a strategic decision to reduce the second quarteroverall level of 2015 compared to the second quarter of 2014 due to lower unproved property impairments and dry well costs. Unproved property impairments declined primarilyour conventional exploration program; as a result, we impaired certain of fewer Eagle Ford and Bakkenour leases that either expired or that we decided not to drill or extend. The second quarter of 2014 included dry well costs associated with our exploration programs in Kurdistan, Ethiopia and Kenya. Included in the dry well costs for the second quarter of 2015 is $38 million of previously suspended well costs that were written off. The well costs are associated with our Canadian in-situ assets at Birchwood. See Note 11 to the consolidated financial statements for further discussion.
Exploration expenses were $17 million lower in the first six months of 2015 than in the comparable 2014 period due to lower unproved property impairments, which were partially offset by higher dry well costs. Unproved property impairments were higher in 2014 primarily as a result of Eagle Ford and Bakken leases that either expired or that we decided not to drill or extend. Dry well costs increased for the first six months of 2015 due to costs associated with the Sodalita West #1 well in E.G., the Key Largo well in the Gulf of Mexico and the aforementioned suspended well costs relatedHarir block in the Kurdistan Region of Iraq. Further contributing to Birchwood in-situ. Dry well costs for the first six monthsincrease was an impairment of 2014 primarily consist ofunproved property in Colorado, which we deemed uneconomic given our exploration programs in Kurdistan, Ethiopia and Kenya.forecasted natural gas prices. The following table summarizes the components of exploration expenses:
Three Months Ended Six Months Ended June 30,Three Months Ended September 30,
(In millions)2015 2014 2015 20142015 2014
Exploration Expenses          
Unproved property impairments$40
 $60
 $49
 $101
$563
 $39
Dry well costs41
 53
 99
 55
(3) 25
Geological and geophysical12
 6
 15
 17
8
 10
Other18
 26
 38
 45
17
 22
Total exploration expenses$111
 $145
 $201
 $218
$585
 $96

30



Depreciation, depletion and amortization (“DD&A”) increased $71decreased $20 million and $249 million in the second quarter and first six months of 2015 from the comparable 2014 periods primarily as a result of a higher North America E&P net sales volumesproved reserve base in Eagle Ford, the effects of which more than offset additional DD&A resulting from our three U.S. resource plays, partially offset by lowerproduction volume increases in the International E&P sales volumes.and OSM net sales volumes also declined in the second quarter of 2015, as previously discussed, also contributing to that quarter's decrease.segments. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, proved reserve and production volumes have an impact on DD&A expense.
The DD&A rate (expense per boe), which is impacted by field-level changes in sales volumes, proved reserves and capitalized costs, can also cause changes to our DD&A. The following table provides DD&A rates for each segment. The DD&A rate for North America E&P decreased primarily as a result of a higher proved reserve base in Eagle Ford. The International E&P rate increased primarily due to higher sales volumes from the Brae infill drilling program.
Three Months Ended Six Months Ended June 30,Three Months Ended September 30,
($ per boe)2015 2014 2015 20142015 2014
DD&A Rate     
  
   
North America E&P
$25.45
 
$26.58
 
$26.16
 
$26.72

$22.84
 
$26.54
International E&P
$7.17
 
$6.64
 
$6.62
 
$6.45

$7.32
 
$5.30
Oil Sands Mining
$12.87
 
$11.78
 
$12.58
 
$11.74

$12.62
 
$12.75
Impairments are discussed in Note 1214 to the consolidated financial statements.

29



Taxes other than income include production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. With the decrease in North America E&P revenues due to lower price realizations, taxes other than income decreased $31 million and $59$69 million in the secondthird quarter and first six months of 2015 from the comparable 2014 periods.2015. This decrease was partially offset by an increase in sales volumes in North America E&P. The following table summarizes the components of taxes other than income:
Three Months Ended Six Months Ended June 30,Three Months Ended September 30,
(In millions)2015 2014 2015 20142015 2014
Production and severance$40
 $68
 $74
 $122
$28
 $69
Ad valorem15
 19
 31
 38
2
 20
Other23
 22
 40
 44
16
 26
Total$78
 $109
 $145
 $204
$46
 $115
General and administrative expenses increased $29decreased $35 million in the second quarter of 2015 compared to the same period in 2014 primarily due to higher pension settlement charges. Settlement charges in the second quarter of 2015 totaled $64 million, compared to settlement charges of $8 million in the prior year quarter. This increase in pension settlement costs was partially offset by costscost savings realized from the workforce reductions that occurred in the first quarter of 2015.
General and administrative expenses increased $13 Pension settlement charges in the three months of 2015 totaled $18 million compared to $22 million in the first six months of 2015 compared to the same period in 2014. This increase was primarily due to $43 million ofprior year. In addition, we incurred severance related expenses in the first quarter of 2015 and $10 million of increased pension settlement expense (first sixthree months of 2015 totaled $81 million as compared to $71 million for the previous year). These increased costs were partially offset by costs savings realized in the second quarterassociated with workforce reductions of 2015 resulting from the workforce reductions.$4 million.
Provision (benefit) for income taxes reflectreflects an effective tax ratesrate of 2% and 18%35% in the secondthird quarter and first six months of 2015, as compared to 30% and 32% from the comparable 2014 periods. The effective rates for 2015 reflect $135 million of non-cash additional deferred tax expense recorded33% in the secondthird quarter of 2015 as a result of enacted corporate tax changes in Alberta, Canada.2014. See Note 89 to the consolidated financial statements for discussion of the effective tax rate.
Discontinued operations presented in 2014 are net of tax. See Note 56 to the consolidated financial statements for financial information about discontinued operations.
Segment Income(Loss)
Segment income (loss) represents income (loss) from continuing operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments, unrealized gains or losses on crude oil derivative instruments, or other items that affect comparability also are not allocated to operating segments.
The following table reconciles segment income (loss) to net income (loss):
 Three Months Ended September 30,
(In millions)2015 2014
North America E&P$(61) $292
International E&P29
 106
Oil Sands Mining(11) 93
Segment income (loss)(43) 491
Items not allocated to segments, net of income taxes(706) (187)
Income (loss) from continuing operations(749) 304
Discontinued operations (a)

 127
Net income (loss)$(749) $431
(a)
As a result of the sale of our Angola assets and our Norway business, both are reflected as discontinued operations in 2014.
 North America E&P segment income (loss) decreased $353 million after-tax primarily due to lower price realizations, which was partially offset by the impacts from the increased net sales volumes from the U.S. resource plays and lower production and operating costs.
International E&P segment incomedecreased $77 million after-tax primarily due to lower liquid hydrocarbon price realizations as well as reduced income from equity investments. These declines were partially offset by increased sales volumes and lower production and exploration expenses.
Oil Sands Mining segment income (loss)decreased $104 million after-tax primarily due to lower price realizations, partially offset by higher volumes and reduced production expenses.

30



Results of Operations
Nine Months Ended September 30, 2015 vs. Nine Months Ended September 30, 2014
Sales and other operating revenues, including related party are presented by segment in the table below:
 Nine Months Ended September 30,
(In millions)2015 2014
Sales and other operating revenues, including related party   
North America E&P$2,639
 $4,518
International E&P575
 1,000
Oil Sands Mining614
 1,217
Segment sales and other operating revenues, including related party$3,828
 $6,735
Unrealized gain on crude oil derivative instruments59
 
Sales and other operating revenues, including related party$3,887
 $6,735
Below is a price/volume analysis for each segment. Refer to the preceding Operations and Market Conditions sections for additional detail related to our net sales volumes and average price realizations.
  Nine Months Ended Increase (Decrease) Related to Nine Months Ended
(In millions) September 30, 2014 Price Realizations Net Sales Volumes September 30, 2015
North America E&P Price-Volume Analysis
Liquid hydrocarbons $4,112
 $(2,586) $781
 $2,307
Natural gas 398
 (190) 65
 273
Realized gain on crude oil        
    derivative instruments 
 33
   33
Other sales 8
     26
Total $4,518
     $2,639
International E&P Price-Volume Analysis
Liquid hydrocarbons $873
 $(396) $(15) $462
Natural gas 92
 (2) (7) 83
Other sales 35
     30
Total $1,000
     $575
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil $1,195
 $(672) $69
 $592
Other sales 22
     22
Total $1,217
     $614
Marketing revenues decreased $1,242 million. Marketing activities include the purchase of commodities from third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points. Since the volume of marketing activity is based on market dynamics, it can fluctuate from period to period. The decreases are related primarily to lower marketed volumes in North America, which were further compounded by a lower commodity price environment.
Income from equity method investmentsdecreased $248 million primarily due to lower price realizations for LPG at our Alba Plant, LNG at our LNG facility and lower methanol prices at our AMPCO methanol facility, all of which are located in E.G. Also contributing to the decrease in 2015 were lower sales volumes due to the planned turnaround and maintenance activities at the AMPCO methanol plant, the Alba field and the LNG facility.
Production expenses for the first nine months of 2015 decreased by $397 million. North America E&P declined $101 million due to lower operational, maintenance and labor costs. International E&P declined $115 million due to lower project work, repair, maintenance and turnaround costs as well as slightly lower production volumes. OSM declined $181 million primarily due to continued cost management, especially staffing and contract labor. Also contributing to the OSM decrease are lower feedstock purchases given increased reliability and a more favorable exchange rate on expenses denominated in the Canadian Dollar.

31



The expense rates during the first nine months of 2015 decreased for each of our segments as total production costs declined due to the reasons described in the preceding paragraph. The North America E&P and OSM segments also experienced volume increases, which further contributed to the expense rate decline. The following table provides production expense rates for each segment:
 Nine Months Ended September 30,
($ per boe)2015 2014
Production Expense Rate   
North America E&P
$7.52
 
$10.52
International E&P
$6.13
 
$9.34
Oil Sands Mining (a)

$39.58
 
$44.73
(a)
Production expense per synthetic crude oil barrel (before royalties) includes direct production costs (less pre-development), shipping and handling and taxes other than income.
Marketing costs decreased $1,239 million in the first nine months of 2015 from the comparable 2014 period, consistent with the marketing revenues changes discussed above.
Exploration expensesincreasedby$472 million as a result of unproved property impairments recognized during the third quarter of 2015. See the preceding three month period discussion for further information on our unproved property impairments. Unproved property impairments in 2014 primarily were a result of Eagle Ford and Bakken leases that either expired or that we decided not to drill or extend. Dry well costs for the first nine months of 2015 include the Sodalita West #1 well in E.G., the Key Largo well in the Gulf of Mexico, and suspended well costs related to Birchwood in-situ that were expensed during the second quarter of 2015. Dry well costs for the first nine months of 2014 primarily consist of our exploration programs in Kurdistan, Ethiopia and Kenya. The following table summarizes the components of exploration expenses:
 Nine Months Ended September 30,
(In millions)2015 2014
Exploration Expenses   
Unproved property impairments$612
 $140
Dry well costs96
 80
Geological and geophysical23
 27
Other55
 67
Total exploration expenses$786
 $314
Depreciation, depletion and amortization(“DD&A”) increased $229 million primarily as a result of higher North America E&P net sales volumes from our three U.S. resource plays. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, proved reserve and production volumes have an impact on DD&A expense.
The DD&A rate (expense per boe), which is impacted by field-level changes in sales volumes, proved reserves and capitalized costs, can also cause changes to our DD&A. The following table provides DD&A rates for each segment.
 Nine Months Ended September 30,
($ per boe)2015 2014
DD&A Rate 
  
North America E&P
$25.09
 
$26.65
International E&P
$6.87
 
$6.09
Oil Sands Mining
$12.60
 
$12.14
Impairments are discussed in Note 14 to the consolidated financial statements.

32



Taxes other than incomeinclude production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. With the decrease in North America E&P revenues due to lower price realizations, taxes other than income decreased $128 million in the first nine months of 2015. This decrease was partially offset by an increase in sales volumes in North America E&P. The following table summarizes the components of taxes other than income:
 Nine Months Ended September 30,
(In millions)2015 2014
Production and severance$102
 $191
Ad valorem33
 58
Other56
 70
Total$191
 $319
General and administrative expenses decreased $22 million primarily due to cost savings realized from the workforce reductions that occurred in the first quarter of 2015. This decrease was partially offset by $47 million of severance related expenses. The first nine months of 2015 include $99 million of pension settlement expense as compared to $93 million for the previous year.
Provision (benefit) for income taxes reflects an effective tax rate of 28% in the first nine months of 2015, as compared to 32% in the comparable 2014 period. The effective rate for 2015 reflects a $135 million non-cash deferred tax expense recorded in the second quarter of 2015 as a result of enacted corporate tax changes in Alberta, Canada. See Note 9 to the consolidated financial statements for discussion of the effective tax rate.
Discontinued operations presented in 2014 are net of tax. See Note 6 to the consolidated financial statements for financial information about discontinued operations.
Segment Income (Loss)
Segment income (loss) represents income (loss) from continuing operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments, change in tax expense associated with a tax rate change, unrealized gains or losses on crude oil derivative instruments, or other items that affect comparability also are not allocated to operating segments.
The following table reconciles segment income (loss) to net income (loss):
Three Months Ended Six Months Ended June 30,Nine Months Ended September 30,
(In millions)2015 2014 2015 20142015 2014
North America E&P$(45) $302
 $(206) $544
$(267) $836
International E&P41
 160
 64
 381
93
 487
Oil Sands Mining(77) 55
 (96) 119
(107) 212
Segment income (loss)(81) 517
 (238) 1,044
(281) 1,535
Items not allocated to segments, net of income taxes(305) (157) (424) (286)(1,130) (473)
Income (loss) from continuing operations(386) 360
 (662) 758
(1,411) 1,062
Discontinued operations (a)

 180
 
 931

 1,058
Net income (loss)$(386) $540
 $(662) $1,689
$(1,411) $2,120
(a) 
As a result of the sale of our Angola assets and our Norway business, both are reflected as discontinued operations in 2014.
 North America E&P segment income (loss) decreased $347 million and $750$1,103 million after-tax in the second quarter and first sixnine months of 2015 from the comparable 2014 periods. The decrease is primarily due to lower price realizations, which wasrealizations; these were partially offset by the impacts from the increased net sales volumes from the U.S. resource plays.plays and lower production costs.
International E&P segment income decreased $119$394 million and $317 million after-tax in the second quarter and first six months of 2015 from the comparable 2014 periods. The decreases are primarily due to lower liquid hydrocarbon price realizations and net sales volumes, as well as reduced income from equity investments. These declines were partially offset by lower production and exploration expenses.
Oil Sands Mining segment income (loss) decreased $132$319 million and $215 million after-tax in the second quarter and first six months of 2015 from the comparable 2014 periods primarily due to lower price realizations, partially offset by reduced production expenses.

33



Critical Accounting Estimates
There have been no material changes or developments in the evaluation of the accounting estimates and the underlying assumptions or methodologies pertaining to our critical accounting estimates subsequent to Critical Accounting Estimates disclosed in our Form 10-K for the year ended December 31, 2014,. except as discussed below.
Fair Value Estimates - Impairment Assessments of Long-Lived Assets and Goodwill
The continued decline of commodity prices resulted in a downward revision of our long-term commodity price assumptions and was a triggering event which required us to reassess long-lived assets related to oil and gas producing properties for impairment as of September 30, 2015. We estimated the fair values using an income approach and concluded that impairments of $337 million were required (See Notes 14 & 15 ). Changes in management's forecast assumptions may cause us to reassess our long-lived assets for impairment, and could result in non-cash impairment charges in the future.
Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. After we performed our annual goodwill impairment test in April 2015, a triggering event (downward revision to forecasted commodity price assumptions) required us to reassess our goodwill for impairment as of September 30, 2015. Based on the results of this assessment, we concluded no impairment was required. The fair value of the North America E&P and International E&P reporting units exceeded their respective book values by a significant margin. Changes in management's forecast commodity price assumptions may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.
Income Tax Estimates - Deferred Tax Assets
In connection with our assessment of the realizability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of our deferred tax assets will not be realized.  In the event it is more likely than not that some portion or all of our deferred taxes will not be realized, such assets are reduced by a valuation allowance. Future increases to our valuation allowance are possible if our estimates and assumptions (particularly as they relate to downward revisions of our long-term commodity price forecast) are revised such that they reduce estimates of future taxable income during the carryforward period.
Accounting Standards Not Yet Adopted
See Note 2 to the consolidated financial statements.

3234



Cash Flows and Liquidity
 Cash Flows
 The following table presents sources and uses of cash and cash equivalents:equivalents
Six Months Ended June 30,Nine Months Ended September 30,
(In millions)2015201420152014
Sources of cash and cash equivalents 
 
 
 
Continuing operations$717
$2,118
Discontinued operations
440
Operating activities of continued operations$1,213
$3,476
Operating activities of discontinued operations
856
Borrowings1,996

1,996

Disposals of assets2
2,232
105
2,237
Maturities of short-term investments225

Other43
113
97
196
Total sources of cash and cash equivalents$2,758
$4,903
$3,636
$6,765
Uses of cash and cash equivalents  
Cash additions to property, plant and equipment$(2,320)$(2,230)$(2,948)$(3,639)
Investing activities of discontinued operations
(233)
(356)
Purchases of short-term investments(925)
(925)
Debt issuance costs(19)
(19)
Debt repayments(34)(34)(34)(34)
Dividends paid(285)(260)(427)(401)
Purchases of common stock
(1,000)
(1,000)
Commercial paper, net
(135)
(135)
Other(1)(10)(1)(48)
Cash held for sale
(96)
(655)
Total uses of cash and cash equivalents$(3,584)$(3,998)$(4,354)$(6,268)
Commodity prices began declining in the second half of 2014 and remain substantially lower through 2015 as compared to the first six months of 2014.2015. This lower price trend adversely impacted our cash flows in 2015. Partially offsetting the decline in prices were increased net sales volumes in the North America E&P segment.and OSM segments. While we are unable to predict future commodity price movements, if this lower price environment continues, it would continue to negatively impact our cash flows from operating activities as compared to the previous year.
Borrowings reflect net proceeds received from the issuance of senior notes in June 2015. See Liquidity and Capital Resources below for additional information.
Cash flows from discontinued operations are primarily related to our Norway business, which we disposed of in the fourth quarter of 2014. Disposal of assets in 2015 pertain to the August 2015 sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets. Disposals of assets in the first six months of 2014 primarily reflect the net proceeds from the sales of our Angola assets. Disposition transactions are discussed in further detail in Note 56 to the consolidated financial statements.
In October, 2015, we announced an adjustment to our quarterly dividend. See Capital Requirements below for additional information.
Certain of our short-term investments matured in September 2015. Purchases of short-term investments in 2015 were made from proceeds received from the senior notes issuance in June 2015. The investments consistconsisted of time deposits with maturity dates ranging from September - October 2015.

3335



Additions to property, plant and equipment are our most significant use of cash and cash equivalents. The following table shows capital expenditures by segment and reconciles to additions to property, plant and equipment in continuing operations as presented in the consolidated statements of cash flows:
Six Months Ended June 30,Nine Months Ended September 30,
(In millions)2015 20142015 2014
North America E&P$1,484
 $1,969
$2,048
 $3,246
International E&P245
 220
275
 386
Oil Sands Mining37
 123
26
 172
Corporate14
 13
26
 29
Total capital expenditures1,780
 2,325
2,375
 3,833
(Increase) decrease in capital expenditure accrual540
 (95)573
 (194)
Total use of cash and cash equivalents for property, plant and equipment$2,320
 $2,230
$2,948
 $3,639
During the first sixnine months of 2014, we acquired 29 million common shares at a cost of $1 billion under our share repurchase program, 13 million of whichprogram. There were acquired in the second quarter of 2014 at a cost of $449 million.no stock repurchases during 2015.
Liquidity and Capital Resources
On June 10, 2015, we issued $2 billion aggregate principal amount of unsecured senior notes which consist of the following series:
$600 million of 2.70% senior notes due June 1, 2020
$900 million of 3.85% senior notes due June 1, 2025
$500 million of 5.20% senior notes due June 1, 2045
Interest on each series of senior notes is payable semi-annually beginning December 1, 2015. We will useused the aggregate net proceeds to repay our $1 billion 0.90% senior notes due 2015, which mature on November 1,2, 2015, and the remainder for general corporate purposes.
In May 2015, we amended our $2.5 billion unsecured revolving credit facility (as so amended, the "Credit Facility")Credit Facility to increase the facility size by $500 million to a total of $3 billion and extend the maturity date by an additional year such that the Credit Facility now matures in May 2020.  The amendment additionally provides us the ability to request two one-year extensions to the maturity date and an option to increase the commitment amount by up to an additional $500 million, subject to the consent of any increasing lenders.  The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively.  Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unchanged.
Our main sources of liquidity are cash and cash equivalents, short-term investments, internally generated cash flow from operations, the issuance of notes, our $3 billion Credit Facility and sales of non-core assets. Our working capital requirements are supported by these sources and we may also issue commercial paper, which is backed by our revolving credit facility. Furthermore, we actively manage our capital spending program, including the level and timing of activities associated with our drilling programs. Because of the alternatives available to us as discussed above, and access to capital markets through the shelf registration discussed below, we believe that our liquidity is adequate to fund not only our current operations, but also our funding requirements for the foreseeable future, including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, and other amounts that may ultimately be paid in connection with contingencies.
Outlook
We expect our capital, investment and exploration spending budget for full-year 2015 to be at or below $3.3 billion and estimate full-year North America E&P and International E&P production volumes (excluding Libya) to be 375-390 net mboed.


3436



Capital Resources
Credit Arrangements and Borrowings
At JuneSeptember 30, 2015, we had no borrowings against our revolving credit facility and no amounts outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.
At JuneSeptember 30, 2015, we had $8.4 billion in long-term debt outstanding, of which approximately $1.0 billion maturesmatured and was repaid in November 2015. We utilized cash on hand and proceeds from the fourth quartermaturities of 2015.our short-term investments to fund the debt payment. 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 securities. 
Asset Disposals
We are targeting to generate at least $500 million from select non-core asset sales. During the third quarter of 2015, we closed the sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets for proceeds of approximately $100 million and announced the sale of our Kenya and Ethiopia exploration acreage. See Note 6 to the consolidated financial statements for additional discussion of these dispositions.        
Cash and Short-Term Investments-Adjusted Debt-To-Capital Ratio
 Our cash and short-term investments-adjusted debt-to-capital ratio (total debt-minus-cash and cash equivalents and short-term investments to total debt-plus-equity-minus-cash and cash equivalents and short-term investments) was 22%24% at JuneSeptember 30, 2015, compared to 16% at December 31, 2014.
June 30, December 31,September 30, December 31,
(In millions)2015 20142015 2014
Long-term debt due within one year$1,035
 $1,068
$1,035
 $1,068
Long-term debt7,321
 5,323
7,323
 5,323
Total debt$8,356
 $6,391
$8,358
 $6,391
Cash and cash equivalents$1,572
 $2,398
$1,680
 $2,398
Short-term investments$925
 $
$700
 $
Equity$20,218
 $21,020
$19,335
 $21,020
Calculation: 
  
 
  
Total debt$8,356
 $6,391
$8,358
 $6,391
Minus cash and cash equivalents1,572
 2,398
1,680
 2,398
Minus short-term investments925
 
700
 
Total debt minus cash, cash equivalents and short-term investments$5,859
 $3,993
$5,978
 $3,993
Total debt$8,356
 $6,391
$8,358
 $6,391
Plus equity20,218
 21,020
19,335
 21,020
Minus cash and cash equivalents1,572
 2,398
1,680
 2,398
Minus short-term investments925
 
700
 
Total debt plus equity minus cash, cash equivalents and short-term investments$26,077
 $25,013
$25,313
 $25,013
Cash and short-term investments-adjusted debt-to-capital ratio22% 16%24% 16%
Capital Requirements
As noted above in "Outlook," weWe expect our revised total capital, investment and exploration spending budget for full-year 2015 to be at or below $3.3 billion.$3.1 billion which is $200 million less than our previous budget.
On July 29,October 28, 2015, our Board of Directors approved a dividend of $0.21$0.05 per share for the secondthird quarter of 2015 payable SeptemberDecember 10, 2015 to stockholders of record at the close of business on August 19,November 18, 2015. This dividend represents a reduction from the previous quarterly dividend of $0.21 per share as we continue to address the uncertainty of a lower for longer commodity price environment, align with our priority of maintaining a strong balance sheet through the cycle, and provide additional capital flexibility to support growth from the U.S. resource plays when commodity prices improve.
As of JuneSeptember 30, 2015, we plan to make contributions of up to $42$18 million to our funded pension plans during the remainder of 2015.

37



Contractual Cash Obligations
As of JuneSeptember 30, 2105,2015, there are no material changes to our consolidated cash obligations to make future payments under existing contracts, as disclosed in our 2014 Annual Report on Form 10-K, except for our issuance of $2 billion aggregate principal amount of unsecured senior notes, as more fully described in Note 1518.
          

35



Environmental Matters 
We have incurred and will continue to incur 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, 2014.
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.  
Forward-Looking Statements
This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the "Exchange Act"). All statements other than statements of historical fact included or incorporated by reference in this report are forward-looking statements, including without limitation statements regardingregarding: our operational, financial and growth strategies, including planned projects, drilling plans, maintenance activities, asset sales, productivity improvements, and drilling and completion efficiencies; our ability to effect those strategies and the expected timing and results thereof, planned capital expenditures and the impact thereof, future drilling plans, timing and expectations, maintenance activities and the timing and impact thereof, well spud timing and expectations,thereof; our financial and operational outlook and ability to fulfill that outlook,outlook; expectations regarding future economic and market conditions and their effects on our business; our 2015 and 2016 capital, investment and exploration programs, including planned allocation and reductions, and the expected benefits thereof; our declared dividend and the expected benefits thereof; our financial position, liquidity and capital resources, our 2015 budget and planned allocation,resources; production guidance; and the plans and objectives of our management for our future operations. In addition, many forward-looking statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “estimate,” “expect,” “target,” “plan,” “project,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. While we believe that our assumptions concerning future events are reasonable, a number of factors could cause results to differ materially from those indicated by such forward-looking statements including, but not limited to:
conditions in the oil and gas industry, including supply/demand levels and the resulting impact on price;
changes in expected reserve or production levels;
changes in political or economic conditions in key operating markets, including international markets;
capital available for exploration and development;
well production timing;
availability of drilling rigs, materials and labor;
difficulty in obtaining necessary approvals and permits;
non-performance by third parties of contractual obligations;
unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto;
cyber-attacks;
changes in safety, health, environmental and other regulations;
other geological, operating and economic considerations; and
the risk factors, forward-looking statements and challenges and uncertainties described in our 2014 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and those set forth from time to time in ourother filings with the SEC.
All forward-looking statements included in this report are based on information available to us on the date of this report. Except as required by law, we assume no duty or obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.

3638



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 2014 Annual Report on Form 10-K. Additional disclosures regarding our open derivative positions, including underlying notional quantities, how they are reported in our consolidated financial statements and how their fair values are measured, may be found in Notes 1215 and 1316 to the consolidated financial statements.
Commodity Price Risk During the first sixnine months of 2015, we entered into crude oil derivatives, indexed to NYMEX WTI, related to a portion of our forecasted North America E&P sales. The table below provides a summary of open positions as of JuneSeptember 30, 2015:
Financial InstrumentWeighted Average PriceBarrels per dayRemaining TermWeighted Average PriceBarrels per dayRemaining Term
Three-Way Collars  
Ceiling$70.3435,000
July- December 2015 (a)
$70.3435,000October- December 2015
Floor$55.57 $55.57 
Sold put$41.29 $41.29 
  
Ceiling$71.8412,000January- December 2016$60.002,000
October 2015- March 2016 (a)
Floor$60.48 $50.00 
Sold put$50.00 $40.00 
  
Ceiling$73.132,000
January- June 2016 (b)
$71.8412,000January- December 2016
Floor$65.00 $60.48 
Sold put$50.00 $50.00 
 
Ceiling$73.132,000
January- June 2016 (b)
Floor$65.00 
Sold put$50.00 
Call Options
$72.3910,000
January- December 2016 (c)
$72.3910,000
January- December 2016 (c)
(a) 
Counterparties have the option, exercisable on March 31, 2016, to execute fixed-price swaps (swaptions)extend these collars through September of 2016 at athe same volume and weighted average price of $71.67 per barrel indexed to NYMEX WTI, which is exercisable on October 30, 2015. If counterparties exercise,as the term of the fixed price swaps would be for calendar year 2016 and, if all such are exercised, 25,000 barrels per day.underlying three-way collars.
(b) 
Counterparty has the option, exercisable on June 30, 2016, to extend these collars through the remainder of 2016 at the same volume and weighted average price as the underlying three-way collars.
(c) 
Call options settle monthly.
The following table provides a sensitivity analysis of the projected incremental effect on income (loss) from operations of a hypothetical 10% change in NYMEX WTI prices on our open commodity derivative instruments as of JuneSeptember 30, 2015.
(In millions)Hypothetical Price Increase of 10%Hypothetical Price Decrease of 10%Hypothetical Price Increase of 10%Hypothetical Price Decrease of 10%
Crude oil commodity derivatives$(67)$51
$(46)$6

Interest Rate Risk Sensitivity analysis of the incremental effect of a hypothetical 10 percent change in interest rates on financial assets and liabilities as of JuneSeptember 30, 2015, is provided in the following table.
(In millions)Fair Value Incremental Change in Fair ValueFair Value Incremental Change in Fair Value
Financial assets (liabilities):      
Long term debt, including amounts due within one year$(8,720)
(a)(b) 
$(288)$(8,302)
(a)(b) 
$(295)
(a) 
Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.
(b) 
Excludes capital leases.
    

3739



Item 4. Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer.  As of the end of the period covered by this Report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as of JuneSeptember 30, 2015.  
During the secondthird quarter of 2015, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

38


MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)


 Three Months Ended Six Months Ended
 June 30, June 30,
(In millions)2015 2014 2015 2014
Segment Income (Loss)       
North America E&P$(45) $302
 $(206) $544
International E&P41
 160
 64
 381
Oil Sands Mining(77) 55
 (96) 119
Segment income (loss)(81) 517
 (238) 1,044
Items not allocated to segments, net of income taxes(305) (157) (424) (286)
Income (loss) from continuing operations(386) 360
 (662) 758
Discontinued operations (a)

 180
 
 931
Net income (loss)$(386) $540
 $(662) $1,689
Capital Expenditures (b)
     
  
North America E&P$551
 $1,102
 $1,484
 $1,969
International E&P99
 115
 245
 220
Oil Sands Mining16
 55
 37
 123
Corporate12
 10
 14
 13
Discontinued operations (a)

 141
 
 251
Total$678
 $1,423
 $1,780
 $2,576
Exploration Expenses     
  
North America E&P$91
 $82
 $126
 $139
International E&P20
 63
 75
 79
Total$111
 $145
 $201
 $218
(a)
As a result of the sale of our Angola assets and our Norway business, both are reflected as discontinued operations in 2014.
(b)
Includes accruals.




39


MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)


 Three Months Ended Six Months Ended
 June 30, June 30,
Net Sales Volumes2015 2014 2015 2014
North America E&P 
    
  
Crude Oil and Condensate (mbbld)
       
Bakken54
 44 53
 41
Eagle Ford82
 67 87
 65
Oklahoma Resource Basins5
 2 5
 2
Other North America (c)
35
 38 35
 36
Total Crude Oil and Condensate176
 151 180
 144
Natural Gas Liquids (mbbld)
       
Bakken3
 3 3
 2
Eagle Ford26
 16 26
 16
Oklahoma Resource Basins6
 6 6
 5
Other North America (c)
2
 2 3
 4
Total Natural Gas Liquids37
 27 38
 27
Total Liquid Hydrocarbons (mbbld)
       
Bakken57
 47 56
 43
Eagle Ford108
 83 113
 81
Oklahoma Resource Basins11
 8 11
 7
Other North America (c)
37
 40 38
 40
Total Liquid Hydrocarbons213
 178 218
 171
Natural Gas (mmcfd)
       
Bakken22
 18 20
 17
Eagle Ford164
 111 167
 109
Oklahoma Resource Basins81
 61 79
 58
Other North America (c)
94
 104 94
 113
Total Natural Gas361
 294 360
 297
Equivalent Barrels (mboed)
       
Bakken61
 50 59
 46
Eagle Ford135
 102 141
 99
Oklahoma Resource Basins24
 18 24
 17
Other North America (c)
54
 57 54
 58
Total North America E&P274
 227 278
 220
(c)
Includes Gulf of Mexico and other conventional onshore U.S. production.


40


MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)


 Three Months Ended Six Months Ended
 June 30, June 30,
Net Sales Volumes2015 2014 2015 2014
International E&P       
Crude Oil and Condensate (mbbld)
       
Equatorial Guinea19
 20
 18
 22
United Kingdom14
 13
 14
 13
Total Crude Oil and Condensate33
 33
 32
 35
Natural Gas Liquids (mbbld)
       
Equatorial Guinea9
 11
 10
 11
Total Natural Gas Liquids9
 11
 10
 11
Total Liquid Hydrocarbons (mbbld)
       
Equatorial Guinea28
 31
 28
 33
United Kingdom14
 13
 14
 13
Total Liquid Hydrocarbons42
 44
 42
 46
Natural Gas (mmcfd)
       
Equatorial Guinea365
 446
 390
 441
United Kingdom (d)
31
 28
 32
 29
Libya
 
 
 1
Total Natural Gas396
 474
 422
 471
Equivalent Barrels (mboed)
       
Equatorial Guinea89
 105
 93
 107
United Kingdom (d)
19
 18
 19
 18
Total International E&P108
 123
 112
 125
Oil Sands Mining       
Synthetic Crude Oil (mbbld) (e)
29
 44
 44
 45
Total Continuing Operations (mboed)
411
 394
 434
 390
Discontinued Operations - Angola (mboed) (a)

 
 
 3
Discontinued Operations - Norway (mboed) (a)

 70
 
 70
Total Company (mboed)
411
 464
 434
 463
Net Sales Volumes of Equity Method Investees       
LNG (mtd)
4,991
 6,624
 5,629
 6,601
Methanol (mtd)
673
 980
 778
 1,066
(d)
Includes natural gas acquired for injection and subsequent resale of 7 mmcfd and 5 mmcfd for the second quarters of 2015 and 2014, and 9 mmcfd and 6 mmcfd for the first six months of 2015 and 2014.
(e)
Includes blendstocks.




41


MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)


 Three Months Ended Six Months Ended
 June 30, June 30,
Average Price Realizations (f)
2015 2014 2015 2014
North America E&P       
Crude Oil and Condensate (per bbl) (g)
       
Bakken$51.36 $93.08 $45.84 $91.43
Eagle Ford53.47 99.08 47.81 97.65
Oklahoma Resource Basins51.00 101.12 48.34 98.05
Other North America (c)
52.83 93.45 47.10 91.40
Total Crude Oil and Condensate52.63 95.95 47.11 94.30
Natural Gas Liquids (per bbl)
       
Bakken$11.63 $45.13 $7.19 $51.04
Eagle Ford14.08 30.20 13.90 33.76
Oklahoma Resource Basins14.45 33.04 15.83 38.21
Other North America (c)
25.65 54.13 26.03 57.65
Total Natural Gas Liquids14.77 34.80 14.60 38.75
Total Liquid Hydrocarbons (per bbl)
       
Bakken$49.29 $90.47 $43.72 $89.16
Eagle Ford44.05 85.36 40.01 84.78
Oklahoma Resource Basins30.29 52.00 29.24 55.04
Other North America (c)
50.89 90.45 45.52 88.97
Total Liquid Hydrocarbons45.96 86.43 41.37 85.65
Natural Gas (per mcf)
       
Bakken$2.62 $4.12 $2.76 $6.14
Eagle Ford2.71 4.76 2.79 4.83
Oklahoma Resource Basins2.64 4.57 2.63 5.01
Other North America (c)
2.98 5.65 3.29 5.35
Total Natural Gas2.76 5.00 2.88 5.14
(f)
Excludes gains or losses on derivative instruments.
(g)
Inclusion of realized gains on crude oil derivative instruments would have increased average crude oil price realizations by $0.06 and $0.14 per bbl for the second quarter and first six months of 2015. There were no crude oil derivative instruments in 2014.



42


MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)


 Three Months Ended Six Months Ended
 June 30, June 30,
Average Price Realizations2015 2014 2015 2014
International E&P       
Crude Oil and Condensate (per bbl)
       
Equatorial Guinea$52.27 $90.91 $47.55 $90.66
United Kingdom62.97 111.76 60.19 111.38
Total Crude Oil and Condensate56.70 99.36 52.92 98.51
Natural Gas Liquids (per bbl)
       
Equatorial Guinea (h)
$1.00 $1.00 $1.00 $1.00
United Kingdom36.49 64.37 34.82 69.56
Total Natural Gas Liquids3.10 3.02 3.29 3.64
Total Liquid Hydrocarbons (per bbl)
       
Equatorial Guinea$35.74 $59.72 $31.81 $61.12
United Kingdom61.93 110.51 58.96 110.02
Total Liquid Hydrocarbons44.70 75.41 41.06 75.48
Natural Gas (per mcf)
       
Equatorial Guinea (h)
$0.24 $0.24 $0.24 $0.24
United Kingdom6.98 8.04 7.34 9.07
Libya
 
 
 5.45
Total Natural Gas0.78 0.69 0.78 0.80
Oil Sands Mining       
Synthetic Crude Oil (per bbl)
$52.46 $94.17 $44.33 $91.27
Discontinued Operations - Angola (per boe) (a)

 
 
 $99.82
Discontinued Operations - Norway (per boe) (a)

 $108.11 
 $108.09
(h)
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.


43



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.  
Item 1A. Risk Factors
We are subject to various risks and uncertainties in the course of our business.  There have been no material changes to the risk factors under Item 1A. Risk Factors in our 2014 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 JuneSeptember 30, 2015, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Exchange Act of 1934.
 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)
 Paid per Share  Plans or Programs Plans or Programs
04/01/15 - 04/30/15151,874
 27.61
 
 $1,500,285,529
05/01/15 - 05/31/156,614
 29.85
 
 $1,500,285,529
06/01/15 - 06/30/153,231
 27.11
 
 $1,500,285,529
Total161,719
 27.69
 
  
 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)
 Paid per Share  Plans or Programs Plans or Programs
07/01/15 - 07/31/153,333
 25.58
 
 $1,500,285,529
08/01/15 - 08/31/1546,543
 18.50
 
 $1,500,285,529
09/01/15 - 09/30/155,444
 15.01
 
 $1,500,285,529
Total55,320
 18.59
 
  
(a) 
161,71955,320 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

Item 5. Other Information
As we previously disclosed in a Form 8-K filed with the SEC on August 28, 2015, our Board of Directors amended and restated our By-laws, effective September 1, 2015, to modify the existing proxy access provisions of the By-laws to coincide with the stockholder proposal that was approved at our 2015 annual meeting of stockholders.
Pursuant to these amendments, the required ownership percentage needed to use the proxy access provisions was decreased to 3% of Marathon Oil’s outstanding common stock, owned continuously for at least three years. Additionally, the maximum number of stockholder nominees that may be included in the proxy statement pursuant to these provisions was increased to 25% of the number of directors in office as of the last day on which notice requesting proxy access may be delivered by an eligible stockholder.
Item 6.  Exhibits
The information required by this Item 6 is set forth in the Exhibit Index accompanying this quarterly report on Form 10-Q.

4441



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.
August 6,November 5, 2015 MARATHON OIL CORPORATION
   
 By:/s/ Gary E. Wilson
  Gary E. Wilson
  Vice President, Controller and Chief Accounting Officer
  (Duly Authorized Officer)

4542



Exhibit Index
   Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
Exhibit Number Exhibit DescriptionForm Exhibit Filing Date 
2.1++ Separation and Distribution Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Oil Company and Marathon Petroleum Corporation8-K 2.1 5/26/2011 
3.1 Restated Certificate of Incorporation of Marathon Oil Corporation10-Q 3.1 8/8/2013 
3.2 Marathon Oil Corporation By-laws (Amended and restated as of April 9, 2015)8-K 3.1 4/10/2015 
3.3 Specimen of Common Stock Certificate10-K 3.3 2/28/2014 
4.1 Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the SEC upon its request10-K 4.1 2/28/2014 
10.1 First Amendment, dated as of May 5, 2015, to the Amended and Restated Credit Agreement dated as of May 28, 2014, by and among Marathon Oil Corporation, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions named therein10-Q 10.1 5/07/2015 
12.1 Computation of Ratio of Earnings to Fixed Charges*      
31.1 Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934*      
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*      
32.1 Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350*      
32.2 Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350*      
101.INS XBRL Instance Document*      
101.SCH XBRL Taxonomy Extension Schema*      
101.CAL XBRL Taxonomy Extension Calculation Linkbase*      
101.DEF XBRL Taxonomy Extension Definition Linkbase*      
101.LAB XBRL Taxonomy Extension Label Linkbase*      
101.PRE XBRL Taxonomy Extension Presentation Linkbase*      
* Filed herewith.      
++ Marathon Oil agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request.
   Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
Exhibit Number Exhibit DescriptionForm Exhibit Filing Date 
2.1++ Separation and Distribution Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Oil Company and Marathon Petroleum Corporation8-K 2.1 5/26/2011 
3.1 Restated Certificate of Incorporation of Marathon Oil Corporation10-Q 3.1 8/8/2013 
3.2 Marathon Oil Corporation By-laws (Amended and restated as of September 1, 2015)8-K 3.1 8/28/2015 
3.3 Specimen of Common Stock Certificate10-K 3.3 2/28/2014 
4.1 Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the SEC upon its request10-K 4.1 2/28/2014 
12.1 Computation of Ratio of Earnings to Fixed Charges*      
31.1 Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934*      
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*      
32.1 Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350*      
32.2 Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350*      
101.INS XBRL Instance Document*      
101.SCH XBRL Taxonomy Extension Schema*      
101.CAL XBRL Taxonomy Extension Calculation Linkbase*      
101.DEF XBRL Taxonomy Extension Definition Linkbase*      
101.LAB XBRL Taxonomy Extension Label Linkbase*      
101.PRE XBRL Taxonomy Extension Presentation Linkbase*      
* Filed herewith.      
++ Marathon Oil agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request.