UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended September 30, ~~2014~~2015



[ ]	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 ~~674,897,005~~677,260,116 shares of Marathon Oil Corporation common stock outstanding as of October 31, ~~2014.~~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).

~~Quarter Ended~~ ~~September 30,~~For certain industry specific terms used in this Form 10-Q, please see "Definitions" in our 2014

Annual Report on Form 10-K.

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

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)


	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
(In millions, except per share data)	2014			2013			2014			2013			2015			2014			2015			2014
Revenues and other income:
Sales and other operating revenues, including related party	$	2,316		$	2,334		$	6,735		$	7,295		$	1,300		$	2,316		$	3,887		$	6,735
Marketing revenues	554			666			1,713			1,595			84			554			471			1,713
Income from equity method investments	89			114			346			309			36			89			98			346
Net loss on disposal of assets	(3		)	(6		)	(88		)	(4		)	(109		)	(3		)	(108		)	(88		)
Other income	15			19			55			38			12			15			38			55
Total revenues and other income	2,971			3,127			8,761			9,233			1,323			2,971			4,386			8,761
Costs and expenses:
Production	593			540			1,697			1,625			406			593			1,300			1,697
Marketing, including purchases from related parties	554			663			1,710			1,590			84			554			471			1,710
Other operating	99			115			303			283			93			99			281			303
Exploration	96			83			314			665			585			96			786			314
Depreciation, depletion and amortization	737			657			2,060			1,914			717			737			2,289			2,060
Impairments	109			11			130			49			337			109			381			130
Taxes other than income	115			89			319			264			46			115			191			319
General and administrative	160			143			486			465			125			160			464			486
Total costs and expenses	2,463			2,301			7,019			6,855			2,393			2,463			6,163			7,019
Income from operations	508			826			1,742			2,378
Income (loss) from operations													(1,070		)	508			(1,777		)	1,742
Net interest and other	(55		)	(71		)	(180		)	(211		)	(75		)	(55		)	(180		)	(180		)
Income from continuing operations before income taxes	453			755			1,562			2,167
Provision for income taxes	149			359			500			1,372
Income from continuing operations	304			396			1,062			795
Income (loss) from continuing operations before income taxes													(1,145		)	453			(1,957		)	1,562
Provision (benefit) for income taxes													(396		)	149			(546		)	500
Income (loss) from continuing operations													(749		)	304			(1,411		)	1,062
Discontinued operations	127			173			1,058			583			—			127			—			1,058
Net income	$	431		$	569		$	2,120		$	1,378
Net income (loss)													$	(749	)	$	431		$	(1,411	)	$	2,120
Per basic share:
Income from continuing operations	$0.45			$0.56			$1.56			$1.13
Income (loss) from continuing operations													$	(1.11	)	$	0.45		$	(2.09	)	$	1.56
Discontinued operations	$0.19			$0.24			$1.55			$0.82			$	—		$	0.19		$	—		$	1.55
Net income	$0.64			$0.80			$3.11			$1.95
Net income (loss)													$	(1.11	)	$	0.64		$	(2.09	)	$	3.11
Per diluted share:
Income from continuing operations	$0.45			$0.56			$1.55			$1.12
Income (loss) from continuing operations													$	(1.11	)	$	0.45		$	(2.09	)	$	1.55
Discontinued operations	$0.19			$0.24			$1.55			$0.82			$	—		$	0.19		$	—		$	1.55
Net income	$0.64			$0.80			$3.10			$1.94
Net income (loss)													$	(1.11	)	$	0.64		$	(2.09	)	$	3.10
Dividends per share	$0.21			$0.19			$0.59			$0.53			$	0.21		$	0.21		$	0.63		$	0.59
Weighted average common shares outstanding:
Basic	675			707			681			708			677			675			677			681
Diluted	678			711			684			712			677			678			677			684

The accompanying notes are an integral part of these consolidated financial statements.

MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income (Unaudited)


	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
(In millions)	2014			2013			2014			2013			2015			2014			2015			2014
Net income	$	431		$	569		$	2,120		$	1,378
Net income (loss)													$	(749	)	$	431		$	(1,411	)	$	2,120
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	3			34			(40		)	180			(2		)	3			160			(40		)
Income tax benefit (provision)	(2		)	(13		)	13			(67		)	(1		)	(2		)	(58		)	13
Postretirement and postemployment plans, net of tax	1			21			(27		)	113			(3		)	1			102			(27		)
Foreign currency translation and other
Unrealized gain (loss)	—			1			1			(3		)
Income tax benefit (provision)	—			—			(1		)	1
Foreign currency translation and other, net of tax	—			1			—			(2		)
Other comprehensive income (loss)	1			22			(27		)	111
Comprehensive income	$	432		$	591		$	2,093		$	1,489
Comprehensive income (loss)													$	(752	)	$	432		$	(1,309	)	$	2,093

The accompanying notes are an integral part of these consolidated financial statements.

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)


	September 30,			December 31,			September 30,			December 31,
(In millions, except per share data)	2014			2013			2015			2014
Assets
Current assets:
Cash and cash equivalents	$	761		$	264		$	1,680		$	2,398
Receivables	2,048			2,134
Short-term investments							700			—
Receivables, less reserve of $4 and $3							991			1,729
Inventories	379			364			324			357
Other current assets	143			172			163			109
Current assets held for sale	873			41
Total current assets	4,204			2,975			3,858			4,593
Equity method investments	1,103			1,201			1,012			1,113
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $21,024 and $21,895	28,658			28,145
depletion and amortization of $23,713 and $21,884							27,920			29,040
Goodwill	457			499			457			459
Other noncurrent assets	988			1,153			1,427			806
Noncurrent assets held for sale	1,290			1,647
Total assets	$	36,700		$	35,620		$	34,674		$	36,011
Liabilities
Current liabilities:
Commercial paper	$	—		$	135
Accounts payable	2,430			2,206			$	1,246		$	2,545
Payroll and benefits payable	149			240			138			191
Accrued taxes	181			1,445			143			285
Other current liabilities	184			214			286			290
Long-term debt due within one year	68			68			1,035			1,068
Current liabilities held for sale	1,164			25
Total current liabilities	4,176			4,333			2,848			4,379
Long-term debt	6,355			6,394			7,323			5,323
Deferred tax liabilities	2,570			2,492			2,542			2,486
Defined benefit postretirement plan obligations	611			604			436			598
Asset retirement obligations	2,003			2,009			1,965			1,917
Deferred credits and other liabilities	405			401			225			288
Noncurrent liabilities held for sale	354			43
Total liabilities	16,474			16,276			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 and 770 million shares (par value $1 per share,
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 – 95 million and 73 million shares	(3,644		)	(2,903		)
Held in treasury, at cost – 93 million and 95 million shares							(3,553		)	(3,642		)
Additional paid-in capital	6,523			6,592			6,493			6,531
Retained earnings	16,854			15,135			15,800			17,638
Accumulated other comprehensive loss	(277		)	(250		)	(175		)	(277		)
Total stockholders' equity	20,226			19,344			19,335			21,020
Total liabilities and stockholders' equity	$	36,700		$	35,620		$	34,674		$	36,011

The accompanying notes are an integral part of these consolidated financial statements.

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)


	Nine Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2014			2013			2015			2014
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	2,120		$	1,378
Adjustments to reconcile net income to net cash provided by operating activities:
Net income (loss)							$	(1,411	)	$	2,120
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations	(1,058		)	(583		)	—			(1,058		)
Deferred income taxes	337			(2		)	(590		)	337
Depreciation, depletion and amortization	2,060			1,914			2,289			2,060
Impairments	130			49			381			130
Pension and other postretirement benefits, net	(27		)	41			9			(27		)
Exploratory dry well costs and unproved property impairments	220			553			708			220
Net loss on disposal of assets	88			4			108			88
Equity method investments, net	51			12			41			51
Changes in:
Current receivables	(270		)	(133		)	738			(270		)
Inventories	(32		)	(11		)	30			(32		)
Current accounts payable and accrued liabilities	(115		)	(20		)	(954		)	(115		)
All other operating, net	(28		)	98			(136		)	(28		)
Net cash provided by continuing operations	3,476			3,300			1,213			3,476
Net cash provided by discontinued operations	856			741			—			856
Net cash provided by operating activities	4,332			4,041			1,213			4,332
Investing activities:
Acquisitions, net of cash acquired	(12		)	(74		)	—			(12		)
Additions to property, plant and equipment	(3,639		)	(3,383		)	(2,948		)	(3,639		)
Disposal of assets	2,237			402			105			2,237
Investments - return of capital	46			45			61			46
Purchases of short-term investments							(925		)	—
Maturities of short-term investments							225			—
Investing activities of discontinued operations	(356		)	(435		)	—			(356		)
All other investing, net	(24		)	34			22			(24		)
Net cash used in investing activities	(1,748		)	(3,411		)	(3,460		)	(1,748		)
Financing activities:
Commercial paper, net	(135		)	—			—			(135		)
Borrowings							1,996			—
Debt issuance costs							(19		)	—
Debt repayments	(34		)	(148		)	(34		)	(34		)
Purchases of common stock	(1,000		)	(500		)	—			(1,000		)
Dividends paid	(401		)	(376		)	(427		)	(401		)
All other financing, net	150			70			14			150
Net cash used in financing activities	(1,420		)	(954		)
Net cash provided by (used in) financing activities							1,530			(1,420		)
Effect of exchange rate on cash and cash equivalents:
Continuing operations	(1		)	(3		)	(1		)	(1		)
Discontinued operations	(11		)	(3		)	—			(11		)
Cash held for sale	(655		)	—			—			(655		)
Net increase (decrease) in cash and cash equivalents	497			(330		)	(718		)	497
Cash and cash equivalents at beginning of period	264			684			2,398			264
Cash and cash equivalents at end of period	$	761		$	354		$	1,680		$	761

The accompanying notes are an integral part of these consolidated financial statements.

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 of America ("~~U.S. ~~GAAP")~~GAAP for complete financial statements.

As ~~the~~a result of the sale of our Angola assets ~~in the first quarter of 2014~~ and ~~the sale~~ our Norway business ~~which closed October 15,~~in 2014, ~~(see Note 6), these businesses~~both are reflected as discontinued ~~operations in all periods presented.~~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. ~~Assets and liabilities are presented as held for sale in the consolidated balance sheets as of December 31, 2013 for our Angola business and September 30, 2014 for our Norway business.~~

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in ~~the Marathon Oil Corporation 2013~~our 2014 Annual Report on Form 10-K. The results of operations for the third quarter and first nine months of~~2014~~ 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. 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 by which a reporting entity assesses whether the equity holders at risk lack decision making 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. 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 ~~Financial Accounting Standards Board ("FASB")~~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 ~~2017~~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 ~~not permitted.~~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.

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. Those strategic shifts should have a major effect on the organization’s operations and financial results. Examples include disposal of a major geographic area, a major line of business, or a major equity method investment. Expanded disclosures about the assets, liabilities, income and expenses of discontinued operations ~~will be~~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 ~~are~~were effective for us in the first quarter of 2015 and ~~early adoption is permitted. We did not elect early adoption of this amendment and do not expect its future adoption~~apply to ~~have a significant impact on our consolidated results of operations, financial position~~dispositions or ~~cash flows.~~

~~Recently Adopted~~

~~In June 2013, the FASB ratified the Emerging Issues Task Force consensus which requires that an unrecognized tax benefit (or a portion thereof) be presented~~classifications as ~~a reduction to a deferred tax asset~~held for an available net operating loss carryforward, a similar tax loss or tax credit carryforward. This accounting standards update was effective for us beginning in the first quarter of 2014 and is required to be applied prospectively.sale thereafter. Adoption of this standard did not ~~have a significant~~ impact ~~on our consolidated results of operations, financial position or cash flows.~~

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

In February 2013, an accounting standards update was issued to provide guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations such as asset retirement and environmental obligations, contingencies, guarantees, income taxes and retirement benefits, which are separately addressed within U.S. GAAP. This accounting standards update was effective for us beginning in the first quarter of 2014 and is required to be applied retrospectively. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

3. Variable Interest Entity

The owners of the Athabasca Oil Sands Project, in which we hold a ~~20 percent~~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.~~Edmonton, Alberta, Canada. Costs under this contract are accrued and recorded on a monthly basis, with current liabilities of $3$2 million recorded at September 30, ~~2014, consistent with~~ 2015 and $3 million at December 31, ~~2013~~.2014. This contract qualifies as a variable interest contractual arrangement, and the Corridor Pipeline qualifies as a ~~variable interest entity (“VIE”).~~VIE. We hold a variable interest but are not the primary beneficiary because our shipments are only ~~20 percent~~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 ~~$586~~$471 million as of September 30, ~~2014~~.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

~~4. Income per Common Share~~

Basic income (loss) per share is based on the weighted average number of common shares outstanding. Diluted income per share assumes exercise of stock options, provided the effect is not antidilutive. The per share calculations below exclude 13 million and 2 million stock options for the third quarters of 2015 and 2014 and 13 million and 4 million stock options for the ~~third quarters of~~ ~~2014~~ ~~and~~ ~~2013~~ ~~and 4 million and 5 million stock options for the~~ first nine months of~~2014~~ 2015 and ~~2013~~ ~~as they~~2014 that were antidilutive.


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,					Nine Months Ended September 30,
(In millions, except per share data)	2014		2013		2014		2013		2015			2014		2015			2014
Income from continuing operations	$	304	$	396	$	1,062	$	795
Income (loss) from continuing operations									$	(749	)	$	304	$	(1,411	)	$	1,062
Discontinued operations	127		173		1,058		583		—			127		—			1,058
Net income	$	431	$	569	$	2,120	$	1,378
Net income (loss)									$	(749	)	$	431	$	(1,411	)	$	2,120

Weighted average common shares outstanding	675		707		681		708		677			675		677			681
Effect of dilutive securities	3		4		3		4		—			3		—			3
Weighted average common shares, including
dilutive effect	678		711		684		712
Weighted average common shares, diluted									677			678		677			684
Per basic share:
Income from continuing operations		$0.45		$0.56		$1.56		$1.13
Income (loss) from continuing operations									$	(1.11	)	$	0.45	$	(2.09	)	$	1.56
Discontinued operations		$0.19		$0.24		$1.55		$0.82	$	—		$	0.19	$	—		$	1.55
Net income		$0.64		$0.80		$3.11		$1.95
Net income (loss)									$	(1.11	)	$	0.64	$	(2.09	)	$	3.11
Per diluted share:
Income from continuing operations		$0.45		$0.56		$1.55		$1.12
Income (loss) from continuing operations									$	(1.11	)	$	0.45	$	(2.09	)	$	1.55
Discontinued operations		$0.19		$0.24		$1.55		$0.82	$	—		$	0.19	$	—		$	1.55
Net income		$0.64		$0.80		$3.10		$1.94
Net income (loss)									$	(1.11	)	$	0.64	$	(2.09	)	$	3.10

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~5. Acquisitions~~


5.	Acquisitions

2014 ~~- North America Exploration and Production ("E&P") Segment~~

~~In an asset acquisition that closed August 2014, we added acreage to our Oklahoma resource position at a cost of approximately $80 million before final settlement adjustments.~~

~~2013~~ - North America E&P Segment

In ~~July 2013,~~the third quarter of 2014, we acquired ~~additional~~ acreage in the ~~Eagle Ford~~Oklahoma Resource Basins at a cost of $68 million after final settlement adjustments.


6.	Dispositions

2015 - North America E&P Segment

In August 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 Africa exploration acreage in ~~a transaction valued at $97~~Ethiopia and Kenya. A pretax loss of $109 million ~~including a carried interest~~was recorded in the third quarter of ~~$23 million which was fully satisfied as of September 30, 2014. The pro forma impact of this~~2015. This transaction is ~~not material~~expected to ~~our consolidated statements~~close during the fourth quarter of ~~income for any periods presented.~~2015.

~~The transaction was accounted for as a business combination with~~2014 - North America E&P Segment

In the ~~fair values~~second quarter of assets acquired and liabilities assumed measured primarily using an income approach, specifically utilizing a discounted cash flow model. The estimated fair values were based on significant inputs not observable2014, we closed the sale of non-core acreage located in the ~~market,~~far northwest portion of Williston Basin for proceeds of $90 million and therefore represent Level 3 measurements. Significant inputs included estimated reserve volumes, the expected future production profile, estimated commodity prices, assumptions regarding future operating and development costs andrecorded a ~~discount rate~~pretax loss of ~~approximately 10 percent. The entire up-front cash consideration of $74 million was allocated to property, plant and equipment at the acquisition date.~~

~~6. Dispositions~~$91 million.

2014 - International E&P Segment

In ~~June~~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, with an effective date of January 1, 2014.~~Sea. The transaction closed on October 15, 2014. After adjustment for debt, net working capital and interest on the net purchase price, we received proceeds of approximately $2.1 billion and expect to record a pretax gain of approximately $1.4 billion induring the fourth quarter of 2014.

Our Norway business iswas reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for ~~all periods presented.~~2014. Select amounts reported in discontinued operations were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended September 30,			Nine Months Ended September 30,
(In millions)	2014		2013		2014			2013			2014			2014
Revenues applicable to discontinued operations	$	528	$	699	$	1,901		$	2,431		$	528		$	1,901
Pretax income from discontinued operations	$	487	$	523	$	1,617		$	1,945		$	487		$	1,617
After-tax income from discontinued operations	$	127	$	122	$	449	^(a)	$	502		$	127		$	449	^(a)


^(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.~~

~~Assets and liabilities presented as held for sale~~ in the ~~September 30, 2014 consolidated balance sheet reflect~~valuation allowance on U.S. foreign tax credits from the Norway ~~business.~~operations.

In the first quarter of 2014, we closed the sales of our non-operated ~~10 percent~~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.~~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.

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

Our Angola operations are reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for ~~all periods presented.~~the prior period. Select amounts reported in discontinued operations were as follows:

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2014 2013 2014 2013
Revenues applicable to discontinued operations $ —
$ 89
$ 58
$ 254
Pretax income from discontinued operations, before gain $ —
$ 78
$ 51
$ 156
Pretax gain on disposition of discontinued operations $ —
$ —
$ 470
$ —
After-tax income from discontinued operations $ —
$ 51
$ 609
^(a)
$ 81


^(a)	~~Includes an after-tax gain on disposition of discontinued operations of $576 million~~.

~~Assets and liabilities presented as held for sale in the December 31, 2013 consolidated balance sheet reflect the Angola business.~~



	Nine Months Ended September 30,
(In millions)	2014
Revenues applicable to discontinued operations	$	58
Pretax income from discontinued operations, before gain	$	51
Pretax gain on disposition of discontinued operations	$	470
After-tax income from discontinued operations	$	609

~~2014 - North America E&P Segment~~

In June 2014, we closed the sale of non-core acreage located in the far northwest portion of the Williston Basin for proceeds of $90 million. A pretax loss of $91 million was recorded in the second quarter of 2014.MARATHON OIL CORPORATION

~~2013 - North America E&P Segment~~Notes to Consolidated Financial Statements (Unaudited)

~~In June 2013, we closed the sale of our interests in the DJ Basin for proceeds of $19 million. A pretax loss of $114 million was recorded in the second quarter of 2013.~~

~~In February 2013, we conveyed our interests in the Marcellus natural gas shale play to the operator. A $43 million pretax loss on this transaction was recorded in the first quarter of 2013.~~

In February 2013, we closed the sale of our interest in the Neptune gas plant, located onshore Louisiana, for proceeds of $166 million. A $98 million pretax gain on this sale was recorded in the first quarter of 2013.

In January 2013, we closed the sale of our remaining assets in Alaska, for proceeds of $195 million, subject to a six-month escrow of $50 million which was collected in July 2013. After closing adjustments were made in the second quarter of 2013, the pretax gain on this sale was $55 million.

7. Segment Information

We ~~have~~are a global energy company with operations in North America, Europe and Africa. Each of our three reportable operating ~~segments. Each of these~~ segments is organized and managed based upon both geographic location and the nature of the products and services it offers.

~~North America~~N.A. E&P ~~("N.A. E&P")~~ – explores for, produces and markets ~~liquid hydrocarbons~~crude oil and condensate, NGLs and natural gas in North America;

~~International~~Int'l E&P ~~("Int'l E&P")~~ – explores for, produces and markets ~~liquid hydrocarbons~~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.

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. ~~Unrealized~~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, ~~certain impairments, gains or losses on dispositions~~ or other items that affect comparability ~~(as determined by the CODM)~~ also are not allocated to operating segments.

As discussed in Note ~~5, we sold~~6, as a result of the sale of our Angola assets ~~in the first quarter of 2014~~ and our Norway business ~~on October 15, 2014. The Angola and Norway businesses~~in 2014, both are reflected as discontinued operations and ~~are~~ excluded from the ~~International~~Int'l E&P segment ~~in all periods presented.~~for 2014.



	Three 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	$	796		$	182	$	242		$	80		^(c)	$	1,300
Marketing revenues	57			25		2			—				84
Total revenues	853			207		244			80				1,384
Income (loss) from equity method investments	—			48		—			(12		)	^(d)	36
Net gain (loss) on disposal of assets and other income	6			6		—			(109		)	^(e)	(97		)
Less:
Production expenses	179			61		166			—				406
Marketing costs	56			25		3			—				84
Exploration expenses	22			10		—			553			^(f)	585
Depreciation, depletion and amortization	549			79		76			13				717
Impairments	—			—		4			333			^(g)	337
Other expenses ^(a)	106			25		8			79			^(h)	218
Taxes other than income	42			—		5			(1		)		46
Net interest and other	—			—		—			75				75
Income tax provision (benefit)	(34		)	32		(7		)	(387		)		(396		)
Segment income (loss) /Loss from continuing operations	$	(61	)	$	29	$	(11	)	$	(706	)		$	(749	)
Capital expenditures ^(b)	$	564		$	30	$	(11	)	$	12			$	595


^(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 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).

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 revenues	506			46		2		—				554
Total revenues	2,092			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 expenses	233			108		252		—				593
Marketing costs	507			45		2		—				554
Exploration expenses	55			41		—		—				96
Depreciation, depletion and amortization	609			55		62		11				737
Impairments	—			—		—		109			^(c)	109
Other expenses ^(a)	118			26		14		101			^(d)	259
Taxes other than income	109			—		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 ~~impairments (see~~impairment (See Note ~~13)~~14).


^(d)	Includes pension settlement loss of $22 ~~million.~~million (See Note 8).


	Three Months Ended September 30, 2013												Nine Months Ended September 30, 2015
							Not Allocated														Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		to Segments				Total		N.A. E&P			Int'l E&P		OSM			to Segments				Total
Sales and other operating revenues	$	1,321	$	611	$	463	$	(61	)	^(c)	$	2,334	$	2,639		$	575	$	614		$	59		^(c)	$	3,887
Marketing revenues	607		56		3		—				666		345			81		45			—				471
Total revenues	1,928		667		466		(61		)		3,000		2,984			656		659			59				4,358
Income from equity method investments	—		114		—		—				114
Income (loss) from equity method investments													—			110		—			(12		)	^(d)	98
Net gain (loss) on disposal of assets and other income	9		7		2		(5		)		13		17			20		1			(108		)	^(e)	(70		)
Less:
Production expenses	205		108		227		—				540		560			192		548			—				1,300
Marketing costs	605		55		3		—				663		348			79		44			—				471
Exploration expenses	48		35		—		—				83		148			85		—			553			^(f)	786
Depreciation, depletion and amortization	490		116		54		(3		)		657		1,866			214		173			36				2,289
Impairments	11		—		—		—				11		—			—		4			377			^(g)	381
Other expenses ^(a)	111		35		38		74			^(d)	258		322			67		26			330			^(h)	745
Taxes other than income	82		—		5		2				89		170			—		15			6				191
Net interest and other	—		—		—		71				71		—			—		—			180				180
Income tax provision (benefit)	143		247		35		(66		)		359		(146		)	56		(43		)	(413		)	⁽ⁱ⁾	(546		)
Segment income/Income from continuing operations	$	242	$	192	$	106	$	(144	)		$	396
Segment income (loss) /Loss from continuing operations													$	(267	)	$	93	$	(107	)	$	(1,130	)		$	(1,411	)
Capital expenditures ^(b)	$	832	$	120	$	66	$	7			$	1,025	$	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 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 $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 Note 9).

~~(a)Includes other operating expenses and general and administrative expenses.~~

~~(b)Includes accruals.~~

~~(c)Unrealized loss on crude oil derivative instruments.~~

~~(d)Includes pension settlement loss of $15 million.~~

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


	Nine Months Ended September 30, 2014													Nine Months Ended September 30, 2014
							Not Allocated													Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		to Segments				Total			N.A. E&P		Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	4,518	$	1,000	$	1,217	$	—			$	6,735		$	4,518	$	1,000	$	1,217	$	—			$	6,735
Marketing revenues	1,486		177		50		—				1,713			1,486		177		50		—				1,713
Total revenues	6,004		1,177		1,267		—				8,448			6,004		1,177		1,267		—				8,448
Income from equity method investments	—		346		—		—				346			—		346		—		—				346
Net gain (loss) on disposal of assets and other income	17		44		3		(97		)	^(c)	(33		)	17		44		3		(97		)	^(c)	(33		)
Less:
Production expenses	661		307		729		—				1,697			661		307		729		—				1,697
Marketing costs	1,484		176		50		—				1,710			1,484		176		50		—				1,710
Exploration expenses	194		120		—		—				314			194		120		—		—				314
Depreciation, depletion and amortization	1,674		201		152		33				2,060			1,674		201		152		33				2,060
Impairments	21		—		—		109			^(d)	130			21		—		—		109			^(d)	130
Other expenses ^(a)	354		98		40		297			^(e)	789			354		98		40		297			^(e)	789
Taxes other than income	301		—		16		2				319			301		—		16		2				319
Net interest and other	—		—		—		180				180			—		—		—		180				180
Income tax provision (benefit)	496		178		71		(245		)		500			496		178		71		(245		)		500
Segment income/Income from continuing operations	$	836	$	487	$	212	$	(473	)		$	1,062
Segment income /Income from continuing operations														$	836	$	487	$	212	$	(473	)		$	1,062
Capital expenditures ^(b)	$	3,246	$	386	$	172	$	29			$	3,833		$	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 ~~located in the far northwest portion of the Williston Basin (see~~(See Note 6).


^(d)	Proved property impairments ~~(see~~(See Note ~~13)~~14).


^(e)	Includes pension settlement loss of $93 ~~million.~~

Nine Months Ended September 30, 2013
Not Allocated
(In millions) N.A. E&P Int'l E&P OSM to Segments Total
Sales and other operating revenues $ 3,820
$ 2,332
$ 1,204
$ (61 )
^(c)
$ 7,295
Marketing revenues 1,391
192
12
—
1,595
Total revenues 5,211
2,524
1,216
(61 ) 8,890
Income from equity method investments —
309
—
—
309
Net gain (loss) on disposal of assets and other income 15
30
5
(16 ) 34
Less:
Production expenses 584
269
772
—
1,625
Marketing costs 1,390
188
12
—
1,590
Exploration expenses 559
106
—
—
665
Depreciation, depletion and amortization 1,458
284
154
18
1,914
Impairments 34
—
—
15
^(d)
49
Other expenses ^(a)
311
99
48
290
^(e)
748
Taxes other than income 244
—
16
4
264
Net interest and other —
—
—
211
211
Income tax provision (benefit) 242
1,282
55
(207 ) 1,372
Segment income/Income from continuing operations $ 404
$ 635
$ 164
$ (408 ) $ 795
Capital expenditures ^(b)
$ 2,706
$ 314
$ 209
$ 47
$ 3,276


^(a)	~~Includes other operating expenses and general and administrative expenses.~~


^(b)	~~Includes accruals.~~


^(c)	~~Unrealized loss on crude oil derivative instruments.~~


^(d)	~~Proved property impairments (see~~million (See Note ~~13)~~8).


^(e)	~~Includes pension settlement loss of $32 million.~~

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

8. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:


	Three Months Ended September 30,												Three Months Ended September 30,
	Pension Benefits						Other Benefits						Pension Benefits						Other Benefits
(In millions)	2014			2013			2014			2013			2015			2014			2015			2014
Service cost	$	12		$	12		$	—		$	1		$	11		$	12		$	—		$	—
Interest cost	15			16			4			3			12			15			3			4
Expected return on plan assets	(16		)	(17		)	—			—			(17		)	(16		)	—			—
Amortization:
– prior service cost (credit)	1			2			(1		)	(2		)	(3		)	1			(1		)	(1		)
– actuarial loss	7			9			—			—			5			7			1			—
Net settlement loss^(a)	22			15			—			—			18			22			—			—
Net curtailment loss^(b)													4			—			—			—
Net periodic benefit cost	$	41		$	37		$	3		$	2		$	30		$	41		$	3		$	3

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Nine Months Ended September 30,

Pension Benefits Other Benefits
(In millions) 2014 2013 2014 2013
Service cost $ 35
$ 38
$ 2
$ 3
Interest cost 46
47
10
9
Expected return on plan assets (48 ) (50 ) —
—
Amortization:

– prior service cost (credit) 4
5
(3 ) (5 )
– actuarial loss 23
38
—
—
Net settlement loss^(a)
93
32
—
—
Net periodic benefit cost $ 153
$ 110
$ 9
$ 7

^(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.~~



	Nine Months Ended September 30,
	Pension Benefits						Other Benefits
(In millions)	2015			2014			2015			2014
Service cost	$	35		$	35		$	2		$	2
Interest cost	39			46			8			10
Expected return on plan assets	(53		)	(48		)	—			—
Amortization:
– prior service cost (credit)	(4		)	4			(3		)	(3		)
– actuarial loss	19			23			1			—
Net settlement loss^(a)	99			93			—			—
Net curtailment loss (gain)^(b)	5			—			(4		)	—
Net periodic benefit cost	$	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 workforce reductions, which reduced the future expected years of service for employees participating in the plans and the impact of discontinuing accruals for future benefits under the U.K. pension plan effective December 31, 2015.

During the first nine months of ~~2014 and 2013,~~2015, we recorded the effects of ~~partial~~a workforce reduction, a U.S. pension plan 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 and was 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 nine months of 2015 and 2014, we recorded the effects of settlements of our U.S. pension ~~plans and~~plans. As required, we remeasured the ~~plans’~~plans' assets and liabilities as of the applicable balance sheet dates. ~~As a result, we recognized a pretax increase~~The cumulative effects of ~~$10 million~~these events are included in the remeasurement and ~~a pretax decrease of $22 million~~reflected in ~~actuarial losses in other comprehensive income for~~both the ~~third quarter~~pension liability and net periodic benefit cost.

During the first nine months of ~~2014 and a pretax decrease of $24 million and $163 million in actuarial losses in other comprehensive income for the third quarter and first nine months of 2013.~~

~~During the~~ ~~first nine months of 2014~~,2015, we made contributions of ~~$94~~$65 million to our funded pension plans. We expect to make additional contributions up to an estimated ~~$24~~$18 million to our funded pension plans over the remainder of ~~2014. Current benefit~~2015. During the first nine months of 2015, we made payments of $57 million and $13 million related to unfunded pension plans ~~were~~ ~~$83 million~~, and ~~payments related to~~ other postretirement benefit plans, ~~were~~ ~~$11 million~~ ~~during the~~ ~~first nine months of 2014~~.respectively.

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 (benefit) and the sum of the amounts allocated to segments is reported in the “Not Allocated to Segments” column of the tables in Note 7.7.

Our effective income tax rates on continuing operations for the first nine months of 2015 and 2014 were 28% and ~~2013 were~~ ~~32 percent~~ ~~and~~ ~~63 percent~~32%. ~~The decrease in the effective tax rate on continuing operations in the~~ ~~first nine months of 2014~~ ~~is primarily due to a decrease in pretax income from Libya operations, where the tax rate is in excess of 90 percent.~~

The tax provision (benefit) applicable to Libyan ordinary income (loss) was recorded as a discrete item in the first nine months of ~~2014~~2015 and ~~2013.~~2014. Excluding Libya, the effective tax rates on continuing operations, would be ~~32 percent~~27% and ~~36 percent~~32% for the first nine months of ~~2014~~2015 and ~~2013.~~2014. In Libya, ~~there~~uncertainty remains ~~uncertainty~~ around the timing of future production and sales levels. Reliable estimates of ~~2014~~2015 and ~~2013~~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 nine 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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

scenarios in the worldwide annual effective tax rate calculation demonstrates significant variability. Thus, for the first nine months of 2014 and 2013, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income.

In the second quarter of 2014, we reviewed our foreign operations, including the disposition of Norway, and concluded that our foreign operations do not have the same level of immediate capital needs as previously expected. Therefore, we no longer intend for previously unremitted foreign earnings of $746 millionapproximately $1 billion associated with our ~~United Kingdom ("U.K.")~~Canadian operations to be permanently reinvested outside the U.S. ~~Foreign~~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. The remaining undistributed~~liabilities, and therefore, no additional net deferred taxes were recorded in the second quarter of 2015.

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 of certain consolidated foreign subsidiaries for which no U.S. deferred income tax provision has been recorded because we intend to permanently reinvest such income in our foreign operations amounted to ~~$994 million~~ at September 30, 2014. If such income were not permanently reinvested, income tax expense of approximately $348 million would be recorded, not including potential utilization of foreign tax credits.during the carryforward period.

10. Short-term Investments

As of September 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. They 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.

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.


	September 30,		December 31,		September 30,		December 31,
(In millions)	2014		2013		2015		2014
Liquid hydrocarbons, natural gas and bitumen	$	80	$	55	$	39	$	58
Supplies and other items	299		309		285		299
Inventories, at cost	$	379	$	364	$	324	$	357

~~11.~~12. Property, Plant and Equipment, net of Accumulated Depreciation, Depletion and Amortization


	September 30,		December 31,		September 30,		December 31,
(In millions)	2014		2013		2015		2014
North America E&P	$	16,298	$	14,973	$	15,875	$	16,717
International E&P^(a)	2,754		3,590		2,604		2,741
Oil Sands Mining	9,486		9,447		9,334		9,455
Corporate	120		135		107		127
Net property, plant and equipment	$	28,658	$	28,145	$	27,920	$	29,040


^(a)	~~International E&P decrease is due to Norway assets reflected as held for sale in the September 30, 2014 consolidated balance sheet.~~

~~In the third quarter of 2013, our production~~Our Libya operations continue to be impacted by civil unrest and, in ~~Libya was interrupted by third-party labor strikes at the port facilities, which later resulted in a blockade of the Es Sider terminal from which we export oil. In July~~December 2014, ~~Libya's~~Libya’s National Oil Corporation ~~rescinded~~once again declared force majeure ~~associated with these third-party labor strikes~~ at the Es Sider ~~terminal. Our first 2014 lifting occurred in August, and was sourced~~oil terminal, as disruptions from ~~existing inventory at the terminal. Production from the Waha concessions resumed in August 2014; however, considerable~~civil unrest continue. Considerable uncertainty remains around the timing of future production and sales levels.

As of September 30, ~~2014,~~2015, our net property, plant and equipment investment in Libya is ~~approximately $771 million.~~$775 million, and total proved reserves (unaudited) in Libya as of December 31, 2014 are 243 million 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 continue 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 ~~$155~~$88 million and $126 million as of September 30, ~~2014 (including $29 million related to Norway project costs which are reflected in noncurrent assets held for sale)~~2015 and ~~$281 million as of~~ December 31, ~~2013 (including $70 million related to Norway project costs).~~2014. This ~~$126~~$38 million net decrease was associated with a write-down of our Canadian in-situ assets at Birchwood in the second quarter of 2015. After further evaluation of the estimated recoverable

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 demonstration project at Birchwood.

13. Other Noncurrent Assets



	September 30,		December 31,
(in millions)	2015		2014
Deferred tax assets	$	1,115	$	525
Intangible assets	95		96
Other	217		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 ~~a $153 million reduction due to~~lower forecasted commodity prices.

Impairments for the ~~sale~~three and nine months ended September 30, 2014 consisted primarily of our interests in Angola Blocks 31 and 32 and a decrease of $39 million due to the commencement of drilling at the Boyla development and sanction of the Viper project offshore Norway, partially offset by an increase of $66 million for Diaba License G4-223 offshore Gabon where the Diaman-1B well reached total depthproved properties in the ~~third quarter~~Gulf of ~~2013. We are analyzing new 3D seismic, integrated with existing technical data, in order~~Mexico, Texas and North Dakota as a result of revisions to ~~finalize~~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 ~~next steps~~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 geophysical	8			10		23		27
Other	17			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 ~~program on~~strategy (Gulf of Mexico and Harir block in the ~~Diaba License.~~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. Asset Retirement Obligations~~

~~The following summarizes the changes in asset retirement obligations during the first nine months of 2014:~~

(In millions)
Beginning balance^(a)
$ 2,096
Incurred, including acquisitions 39
Settled, including dispositions (110 )
Accretion expense (included in depreciation, depletion and amortization) 87
Revisions to previous estimates^(b)
231
Held for sale (309 )
Ending balance^(a)
$ 2,034


^(a)	~~Includes asset retirement obligations of $87 million and $31 million classified as short-term at December 31, 2013 and September 30, 2014.~~


^(b)	~~Estimated abandonment and other costs increased for Gulf of Mexico and U.K. assets.~~

~~13.~~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 September 30, ~~2014~~2015 and December 31, ~~2013~~2014 by fair value hierarchy level.


	September 30, 2014								September 30, 2015
(In millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity^(a)									$	—	$	61	$	—	$	61
Interest rate	$	—	$	5	$	—	$	5	—		15		—		15
Derivative instruments, assets	$	—	$	5	$	—	$	5	$	—	$	76	$	—	$	76
Derivative instruments, liabilities
Foreign currency	$	—	$	17	$	—	$	17
Commodity^(a)									$	—	$	3	$	—	$	3
Derivative instruments, liabilities	$	—	$	17	$	—	$	17	$	—	$	3	$	—	$	3


^(a)	Derivative instruments are recorded on a net basis in the company's balance sheet (see Note 16).


	December 31, 2013								December 31, 2014
(In millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Interest rate	$	—	$	8	$	—	$	8	$	—	$	8	$	—	$	8
Foreign currency	—		2		—		2
Derivative instruments, assets	$	—	$	10	$	—	$	10	$	—	$	8	$	—	$	8
Derivative instruments, liabilities
Foreign currency	$	—	$	4	$	—	$	4
Derivative instruments, liabilities	$	—	$	4	$	—	$	4

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. ~~Foreign currency forwards are measured at fair value with a market approach using third-party pricing services, such as Bloomberg L.P., which have been corroborated with data from active markets~~See Note 16 for ~~similar assets or liabilities, and are Level 2 inputs.~~additional discussion of the types of derivative instruments we use.

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

Fair Values - Nonrecurring

The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.


	Three Months Ended September 30,								Three Months Ended September 30,
	2014				2013				2015				2014
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	43	$	109	$	5	$	11	$	41	$	337	$	43	$	109


	Nine Months Ended September 30,								Nine Months Ended September 30,
	2014				2013				2015				2014
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	43	$	130	$	5	$	49	$	58	$	381	$	43	$	130

~~All~~

Commodity prices began declining in the second half of 2014 and remain substantially lower through 2015. The prolonged decline in commodity prices, and 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 in the future. Long-lived assets held for use that were impaired ~~in the first nine months of~~ ~~2014~~ ~~and~~ ~~2013~~ ~~were held by our North America E&P segment.~~are 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.~~inputs, unless otherwise noted. Inputs to the fair value measurement ~~included~~include reserve and production estimates made by our reservoir engineers, estimated future commodity prices

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

adjusted for quality and location differentials, and forecasted operating expenses for the remaining estimated life of the reservoir.

2015 - North America E&P

In the third quarter of 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 our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets as a result of the anticipated 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.

2015 - International E&P

In the third quarter of 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, 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 ~~the first quarter of~~ 2013, ~~and a $21 million impairment was recorded.~~at which time those long-lived assets were fully impaired. In the first nine months of 2014, we recorded additional impairments of $30 million ~~at Ozona~~ 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.

~~Also in the third quarter of 2014,~~ 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.

~~In the first quarter of 2013, as a result of our decision to wind down operations in the Powder River Basin due to poor economics, an impairment of~~ ~~$15 million~~ ~~was recorded.~~Fair Values – Goodwill

~~Other impairments of~~Unlike long-lived assets, ~~held~~goodwill must be tested for ~~use by~~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 of the North America E&P ~~segment~~and International E&P reporting units exceeded their respective book values by a significant margin. Changes in ~~the first nine months of~~ ~~2013~~ ~~were a result of reduced drilling expectations, reductions of estimated reserves or declining~~management's forecast commodity ~~prices.~~

~~Crude oil prices began declining in the third quarter of 2014~~price assumptions may cause us to reassess our goodwill for impairment, and ~~continued to decrease in October 2014. A period of sustained low commodity prices~~ could result in ~~additional~~ non-cash impairment charges ~~related to our assets~~ in ~~future periods.~~the future.

Fair Values – Financial Instruments

Our current assets and liabilities include financial instruments, the most significant of which are receivables, ~~commercial paper~~short-term investments, long-term debt due within one year, and payables. We believe the carrying values of our receivables, ~~commercial paper~~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 ~~insignificance of~~insignificant bad debt expense, which includes an evaluation of counterparty credit risk.

1516

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The following table summarizes financial instruments, excluding ~~current~~ receivables, ~~commercial paper, current~~short-term investments, payables ~~capital leases~~ and derivative financial instruments, and their reported fair value by individual balance sheet line item at September 30, ~~2014~~2015 and December 31, ~~2013~~.2014.


	September 30, 2014				December 31, 2013				September 30, 2015				December 31, 2014
	Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount		Value		Amount		Value		Amount
Financial assets
Other noncurrent assets	$	194	$	189	$	154	$	147	$	109	$	116	$	132	$	129
Total financial assets	194		189		154		147		109		116		132		129
Financial liabilities
Other current liabilities	13		13		13		13		15		14		13		13
Long-term debt, including current portion^(a)	7,057		6,394		6,922		6,427		8,302		8,324		6,887		6,360
Deferred credits and other liabilities	94		150		149		147		69		64		69		68
Total financial liabilities	$	7,164	$	6,557	$	7,084	$	6,587	$	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. Most~~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.

~~14.~~16. Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note 13.15. 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. ~~Netting is assessed by counterparty, and as of~~ ~~September 30, 2014~~ ~~and~~ ~~December 31, 2013, there were no offsetting amounts. Positions by contract were all either assets or liabilities.~~

The following tables present the gross fair values of derivative instruments ~~excluding cash collateral,~~ and the reported net amounts ~~along with~~ where they appear on the consolidated balance sheets as of September 30, ~~2014~~2015 and December 31, ~~2013~~.2014.

September 30, 2014
(In millions) Asset Liability Net Asset Balance Sheet Location
Fair Value Hedges
Interest rate $ 5
$ —
$ 5
Other noncurrent assets
Total Designated Hedges $ 5
$ —
$ 5


	September 30, 2014							September 30, 2015
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Foreign currency	$	—	$	17	$	17	Current liabilities held for sale
Interest rate								$	15	$	—	$	15	Other noncurrent assets
Total Designated Hedges	$	—	$	17	$	17		15		—		15

Not Designated as Hedges
Commodity								55		2		53		Other current assets
Commodity								6		1		5		Other noncurrent assets
Total Not Designated as Hedges								61		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

1617

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

December 31, 2013
(In millions) Asset Liability Net Asset Balance Sheet Location
Fair Value Hedges
     Interest rate $ 8
$ —
$ 8
Other noncurrent assets
     Foreign currency 2
—
2
Other current assets
Total Designated Hedges $ 10
$ —
$ 10

December 31, 2013
(In millions) Asset Liability Net Liability Balance Sheet Location
Fair Value Hedges
     Foreign currency $ —
$ 4
$ 4
Current liabilities
Total Designated Hedges $ —
$ 4
$ 4

Derivatives Designated as Fair Value Hedges

The following table presents, by maturity date, information about our interest rate swap agreements as of September 30, ~~2014~~2015 and December 31, ~~2013,~~2014, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.

September 30, 2014 December 31, 2013
Aggregate Notional Amount Weighted Average, LIBOR-Based, Aggregate Notional Amount Weighted Average, LIBOR-Based,
Maturity Dates (in millions) Floating Rate (in millions) Floating Rate
October 2, 2017 $ 600
4.64 % $ 600
4.65 %
March 15, 2018 $ 300
4.49 % $ 300
4.50 %

As of September 30, 2014 and December 31, 2013, our foreign currency forwards had an aggregate notional amount of 2,246 million and 2,387 million Norwegian Kroner at weighted average forward rates of 6.149 and 6.060. These forwards hedge the current Norwegian tax liability of the subsidiary that holds our Norway business. Those outstanding at September 30, 2014 have settlement dates through February 2015 and were transfered to the purchaser of our Norway business upon closing of the sale on October 15, 2014.



	September 30, 2015				December 31, 2014
	Aggregate Notional Amount		Weighted Average, LIBOR-Based,		Aggregate Notional Amount		Weighted Average, LIBOR-Based,
Maturity Dates	(in millions)		Floating Rate		(in millions)		Floating Rate
October 1, 2017	$	600	4.68	%	$	600	4.64	%
March 15, 2018	$	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 September 30,						Nine Months Ended September 30,							Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	Income Statement Location	2014			2013			2014			2013			Income Statement Location	2015			2014			2015			2014
Derivative
Interest rate	Net interest and other	$	(6	)	$	5		$	(3	)	$	(9	)	Net interest and other	$	4		$	(6	)	$	7		$	(3	)
Foreign currency	Discontinued operations	$	(18	)	$	5		$	(29	)	$	(41	)	Discontinued operations	$	—		$	(18	)	$	—		$	(29	)
Hedged Item
Long-term debt	Net interest and other	$	6		$	(5	)	$	3		$	9		Net interest and other	$	(4	)	$	6		$	(7	)	$	3
Accrued taxes	Discontinued operations	$	18		$	(5	)	$	29		$	41		Discontinued operations	$	—		$	18		$	—		$	29

Derivatives not Designated as Hedges

During the first nine months of 2015, we entered into multiple crude oil derivatives indexed to New York Mercantile Exchange ("NYMEX") WTI related to a portion of our forecasted North America E&P sales through December 2016. These commodity derivatives consist of three-way collars, extendable three-way collars and call options. Three way-collars consist of a sold call (ceiling), a purchased put (floor) and a sold put. The ~~impact of all~~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. In this case, we receive the NYMEX WTI price plus the difference between the floor and the sold put price. These commodity ~~derivative instruments~~derivatives were not designated as hedges ~~appears in sales~~ and ~~other operating revenues in our consolidated statements of income and were net losses of $86 million and $73 million~~are shown in the ~~third quarter and first nine months of 2013. There were no crude oil derivatives in the third quarter and first nine months of 2014.~~table below:

1718

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~15.~~



Financial Instrument	Weighted Average Price	Barrels per day	Remaining Term
Three-Way Collars
Ceiling	$70.34	35,000	October- December 2015
Floor	$55.57
Sold put	$41.29

Ceiling	$60.00	2,000	October 2015- March 2016 ^(a)
Floor	$50.00
Sold put	$40.00

Ceiling	$71.84	12,000	January- December 2016
Floor	$60.48
Sold put	$50.00

Ceiling	$73.13	2,000	January- June 2016 ^(b)
Floor	$65.00
Sold put	$50.00
Call Options	$72.39	10,000	January- December 2016 ^(c)


^(a)	Counterparties have the option, exercisable on March 31, 2016, to extend these collars through September of 2016 at the same volume and weighted average price as the 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 gain of $108 million and $91 million in the third quarter and first nine months 2015. There were no crude oil derivative instruments in the first nine 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 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.

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 nine months of ~~2014:~~2015:


	Stock Options					Restricted Stock				Stock 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, 2013	18,104,887				$27.27	4,031,888			$31.80
Outstanding at December 31, 2014										13,427,836				$29.68	3,448,353			$34.04
Granted	1,935,423		^(a)		$34.48	1,935,888			$34.96	724,082		^(a)		$29.06	2,674,987			$30.52
Options Exercised/Stock Vested	(5,882,065	)			$23.45	(1,557,101	)		$30.06	(549,926	)			$16.84	(1,135,635	)		$33.25
Canceled	(559,254	)			$33.97	(448,358	)		$32.02	(605,760	)			$34.11	(708,380	)		$33.20
Outstanding at September 30, 2014	13,598,991				$29.67	3,962,317			$34.00
Outstanding at September 30, 2015										12,996,232				$29.99	4,279,325			$32.17

^(a) The weighted average grant date fair value of stock option awards granted was ~~$10.50~~$6.84 per share.

Stock-based performance unit awards

During the first nine months of ~~2014,~~2015, we granted ~~221,491~~382,335 stock-based performance units to certain officers. The grant date fair value per unit was ~~$34.28.~~$31.77.

~~16.~~

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

18. Debt

Revolving Credit FacilityAs of September 30, ~~2014,~~2015, we had no borrowings against our revolving credit facility (as amended, the "Credit Facility"), as described ~~below, or under our U.S. commercial paper program that is backed by the revolving credit facility.~~below.

In May ~~2014,~~2015, we amended our $2.5 billion unsecured ~~revolving credit~~Credit Facility to increase the facility ~~(the "Credit Facility"),~~size by $500 million to a total of $3 billion and extended the maturity ~~to May 2019. Terms of this amended~~date by an additional year such that the Credit Facility ~~include~~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 ~~$1.0 billion,~~$500 million, subject to the consent of any increasing ~~lenders, and~~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.~~million, respectively. Fees on the unused commitment of each lender, ~~range from 8 basis points to 22.5 basis points depending on our credit ratings. Borrowings~~as well as the borrowing options under the Credit Facility, bear interest, at our option, at either (a) an adjusted LIBOR rate plus a margin ranging from 87.5 basis points to 150 basis points depending on our credit ratings or (b) the Base Rate plus a margin ranging from 0 basis points to 50 basis points depending on our credit ratings. Base Rate is defined as a per annum rate equal to the greatest of (a) the prime rate, (b) the federal funds rate plus one-half of one percent or (c) LIBOR for a one-month interest period plus 1 percent.remain unchanged.

The ~~agreement contains~~Credit Facility includes a covenant requiring that ~~requires~~ our ratio of total debt to total capitalization not to exceed ~~65 percent~~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 September 30, 2015, we were in compliance with this covenant with a debt-to-capitalization ratio of 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 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 September 30, 2015, we were in compliance with the covenants under the indenture governing the senior notes.

~~17.~~19. Reclassifications Out of Accumulated Other Comprehensive ~~Loss~~Income (Loss)

The following table presents a summary of amounts reclassified from accumulated other comprehensive ~~loss~~income (loss) to ~~net~~ income (loss) from continuing operations in their entirety:


	Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2014			2013			2014			2013			Income Statement Line	2015			2014			2015			2014			Income Statement Line
Accumulated Other Comprehensive Loss Components
	Income (Expense)
Postretirement and postemployment plans	Postretirement and postemployment plans													Postretirement and postemployment plans
Amortization of actuarial loss	$	(7	)	$	(9	)	$	(23	)	$	(38	)	General and administrative	$	(6	)	$	(7	)	$	(20	)	$	(23	)	General and administrative
Net settlement loss	(22		)	(15		)	(93		)	(32		)	General and administrative	(18		)	(22		)	(99		)	(93		)	General and administrative
Net curtailment gain (loss)														(4		)	—			(1		)	—			General and administrative
	(29		)	(24		)	(116		)	(70		)	Income from operations	(28		)	(29		)	(120		)	(116		)	Income (loss) from operations
	10			9			38			26			Provision for income taxes	10			10			44			38			Benefit for income taxes
Other insignificant, net of tax	—			—			(1		)	(1		)		—			—			—			(1		)
Total reclassifications	$	(19	)	$	(15	)	$	(79	)	$	(45	)	Income from continuing operations	$	(18	)	$	(19	)	$	(76	)	$	(79	)	Income (loss) from continuing operations

1820

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~18. Stockholders' Equity~~

~~During the first nine months of 2014, we acquired 29 million common shares at a cost of $1 billion under our share repurchase program.~~

~~19.~~20. Supplemental Cash Flow Information


	Nine Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2014			2013			2015			2014
Net cash provided by operating activities:
Net cash used in operating activities:
Interest paid (net of amounts capitalized)	$	201		$	216		$	(200	)	$	(201	)
Income taxes paid to taxing authorities ^(a)	1,514			3,218			(174		)	(1,514		)
Net cash provided by (used in) financing activities:
Commercial paper, net:
Issuances	$	2,285		$	4,975		$	—		$	2,285
Repayments	(2,420		)	(4,975		)	—			(2,420		)
Commercial paper, net	(135		)	—			$	—		$	(135	)
Noncash investing activities, related to continuing operations:
Asset retirement costs capitalized	$	240		$	309
Change in capital expenditure accrual	194			(107		)
Asset retirement costs capitalized, net of revisions							$	12		$	240
Asset retirement obligations assumed by buyer	52			92			23			52
Receivable for disposal of assets	44			—			—			44


^(a)	~~Income taxes paid to taxing authorities included $1,195 million and $1,690 million related to discontinued operations in the~~The first nine months of 2014 ~~and 2013.~~included $1,195 million related to discontinued operations.

~~20.~~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.

~~Contractual commitments~~– At ~~September 30, 2014, Marathon’s contractual commitments to acquire property, plant and equipment were $1,051 million.~~

1921

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

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 ~~energy~~exploration and production company based in Houston, ~~Texas, with~~Texas. Our operations are primarily located in North America, Europe and Africa ~~and the Middle East. We have three reportable operating segments. Each of these segments is organized based upon both geographic location and the nature of the products and services it offers.~~

with a focus on our North ~~America E&P – explores for, produces and markets liquid hydrocarbons and natural gas in North America;~~

International E&P – explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in Equatorial Guinea; and

~~Oil Sands Mining – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.~~

As discussed in Note 6 to the consolidated financial statements, our Angola and Norway businesses are reflected as discontinued operations and are excluded from the International E&P segment in all periods presented. We sold our Angola assets in the first quarter ofAmerican unconventional shale plays. Total proved reserves were 2.2 billion boe at December 31, 2014 and ~~our Norway business on October 15, 2014. Assets and liabilities are presented as held for sale in the consolidated balance sheets as of December 31, 2013 for our Angola business and~~total assets were $35 billion at September 30, ~~2014 for our Norway business.~~

~~Executive Summary~~2015.

Our significant financial results, operating activities and strategic actions include the following:

~~Our~~Increased company-wide net sales volumes from continuing operations ~~for the~~ ~~third quarter and first nine months of2014~~ ~~averaged 417~~ ~~thousand barrels of oil equivalent per day ("mboed") and 400~~by 7% to 445 mboed ~~compared to 403 mboed and 412 mboed for the third quarter and first nine months of 2013. As we had only one oil lifting from Libya~~ in the third quarter ~~and first nine months~~ of ~~2014, a more representative comparison is net sales volumes~~2015 from ~~continuing operations excluding Libya. Excluding Libya, our net sales volumes from continuing operations increased 8 percent and 6 percent~~417 mboed in the third quarter ~~and first nine months~~ of ~~2014. The continued ramp up of production~~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 efficiencies


◦	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 end of the third 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 to provide us with additional capital flexibility to support growth from the U.S. resource plays ~~was~~when commodity prices improve.

Outlook

Commodity prices are the most significant ~~contributor~~factor impacting our revenues, profitability, operating cash flows and the amount of capital available to reinvest into our business. Commodity prices began declining in the 2014 increases when comparing results excluding Libya, partially offset by decreases from the U.K. and Equatorial Guinea. Net sales volumes related to the Angola and Norway discontinued operations for the third quarter and first nine monthssecond half of 2014 ~~averaged 58 mboed~~ and ~~68 mboed compared~~remain substantially lower through 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.

We expect our full-year 2015 capital, investment and exploration budget to ~~77 mboed and 90 mboed for the third quarter and first nine months of 2013, ranging from 12 to 18 percent of total company net sales volumes in those periods.~~

~~Income from continuing operations per diluted share was $0.45 for the third quarter of 2014, a decrease of 20 percent over the same 2013 period, as a result of lower income from~~be $3.1 billion. We estimate our International E&P segment driven primarily by lower net sales volumes combined with lower liquid hydrocarbon price realizations across all segments. In the first nine months of 2014, income from continuing operations per diluted share increased by 38 percent from the comparable 2013 period to $1.56, reflecting higher income from ourfull-year North America E&P and ~~Oil Sands Mining segments driven primarily by continued growth~~International E&P production volumes (excluding Libya) to be 380 - 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 ~~net sales volumes from our~~the U.S. resource plays ~~partially offset~~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 ~~lower commodity prices. This increase in the first nine months~~our Board of 2014 also reflects the $0.84 per diluted share after-tax gain on the sale of our Angola assets in the first quarter of 2014 and the $0.48 per diluted share after-tax non-cash charge for unproved property impairments on Eagle Ford leases that either expired or that we did not expectDirectors. Our conventional exploration focus will be redirected to ~~drill or extend in the first quarter of 2013.~~

~~Key Operating and Financial Activities~~

~~In the~~ ~~third quarter of 2014, notable activities were:~~

~~Increased average net sales volumes from the three U.S. resource plays to 192 mboed, up 43 percent from same quarter of last year~~

~~Continued strong pace in the Eagle Ford with 87 gross operated wells to sales, up 14 percent from the second quarter of 2014~~

~~Eight gross operated Austin Chalk wells brought to sales during the quarter, all within previously delineated acreage; 16 additional wells being drilled, completed or awaiting first production~~

~~Nineteen gross operated Bakken wells brought to sales, of which eight are piloting enhanced completions~~

~~Incremental drilling rig added in the Bakken as of late September to provide additional capacity for high-density spacing and enhanced completion pilots~~

~~Six gross operated wells brought to sales in the Oklahoma Resource Basins, of which four were in the South Central Oklahoma Oil Province ("SCOOP") and two in the Southern Mississippi Trend~~

~~Began drilling the operated Key Largo exploration well~~existing commitments in the Gulf of Mexico

~~Brought two successful South Brae infill wells online~~ and Gabon. As a result, we recorded non-cash impairments related to unproved properties in the ~~U.K. North Sea~~Gulf of Mexico and the Harir block in the Kurdistan Region of Iraq in the third quarter.

Operations

~~Recorded 96 percent average operational availability for operated assets~~

~~Significant fourth quarter activity through~~ ~~November 4, 2014~~ ~~includes:~~

~~Closed sale~~The following table presents a summary of our ~~Norway business on October 15, 2014~~sales volumes for ~~approximately $2.1 billion in proceeds~~

~~Executed agreements in October~~each of our segments. Refer to ~~add approximately 12,000 net acres to SCOOP position, including prospective acres~~the Results of Operations for a price-volume analysis for each of the ~~Springer formation~~

~~Operations~~

~~North America E&P--Production~~segments.

Three Months Ended September 30, Nine Months Ended September 30,
2014 2013 2014 2013
Net Sales Volumes
Crude Oil and Condensate (mbbld)

Bakken 50 34 44 34
Eagle Ford 75 52 68 49
Oklahoma Resource Basins 3 2 2 1
Other North America ^(a)
38 38 37 41
Total Crude Oil and Condensate 166 126 151 125
Natural Gas Liquids (mbbld)

Bakken 3 2 3 2
Eagle Ford 20 14 18 14
Oklahoma Resource Basins 5 5 5 4
Other North America^(a)
3 3 2 2
Total Natural Gas Liquids 31 24 28 22
Total Liquid Hydrocarbons (mbbld)

Bakken 53 36 47 36
Eagle Ford 95 66 86 63
Oklahoma Resource Basins 8 7 7 5
Other North America^(a)
41 41 39 43
Total Liquid Hydrocarbons 197 150 179 147
Natural Gas (mmcfd)

Bakken 18 12 17 12
Eagle Ford 130 93 116 92
Oklahoma Resource Basins 63 47 59 49
Other North America^(a)
106 145 111 165
Total Natural Gas 317 297 303 318
Equivalent Barrels (mboed)

Bakken 56 38 50 38
Eagle Ford 117 82 105 78
Oklahoma Resource Basins 19 15 17 13
Other North America^(a)
58 65 58 71
Total North America E&P 250 200 230 200



	Three Months Ended September 30,			Nine Months Ended September 30,
Net Sales Volumes	2015	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 ~~Gulf of Mexico and other conventional onshore U.S. production, plus Alaska~~blendstocks

North America E&P--Net Sales Volumes

Net sales volumes in ~~2013.~~

the North America E&P segment ~~average net sales volumes in the~~ ~~third quarter and first nine months~~increased as a result of~~2014~~ ~~increased 25 percent and 15 percent when compared to the~~ ~~third quarter and first nine months of2013. Net liquid hydrocarbon sales volumes~~ ~~increase~~d 47 ~~thousand barrels per day ("mbbld") and 32 mbbld for the~~ ~~third quarter and first nine months of~~ ~~2014, and net natural gas sales volumes increased 20 million cubic feet per day ("mmcfd") and decreased 15 mmcfd for the third quarter and first nine months of 2014, primarily reflecting~~ continued growth from the combined U.S. resource ~~plays, partially offset by the shut-in and exit from Powder River Basin operations.~~plays. The ~~negative impact of extreme winter weather on availability and completion operations in the first quarter of 2014 is reflected in the smaller increase in~~following table provides net ~~liquid hydrocarbon~~ sales volumes for ~~the nine-month period. Reduced net natural gas~~our significant operational areas within this segment.



	Three Months Ended September 30,			Nine Months Ended September 30,
Net Sales Volumes	2015	2014	Increase (Decrease)	2015	2014	Increase (Decrease)
Equivalent Barrels (mboed)
Eagle Ford	126	117	8%	137	105	30%
Oklahoma Resource Basins	23	19	21%	24	17	41%
Bakken	61	56	9%	59	50	18%
Other North America ^(a)	51	58	(12)%	53	58	(9)%
Total North America E&P	261	250	4%	273	230	19%


^(a)	Includes Gulf of Mexico and other conventional onshore U.S. production.

The following table provides our sales ~~volumes~~mix for ~~the nine-month period were primarily related to the Powder River Basin and to the January 2013 sale~~each of ~~our Alaska assets, somewhat offset by increases in associated natural gas production from~~ our U.S. resource plays.



	Three Months Ended September 30,
	2015
	Eagle Ford	Oklahoma Resource Basins	Bakken
Crude oil and condensate	59%	18%	87%
Natural gas liquids	20%	28%	8%
Natural gas	21%	54%	5%

The following table presents a summary of our operated drilling activity in the U.S. resource plays:



	Three Months Ended September 30,		Nine Months Ended September 30,
	2015	2014	2015	2014
Gross Operated
Eagle Ford:
Wells drilled to total depth	51	93	198	264
Wells brought to sales	57	87	200	212
Oklahoma Resource Basins:
Wells drilled to total depth	4	4	17	15
Wells brought to sales	8	6	16	14
Bakken:
Wells drilled to total depth	5	25	30	60
Wells brought to sales	5	18	51	52

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~~and 40 in the Lower Eagle Ford. Our average time to drill an Eagle Ford ~~were 117 mboed and 105 mboed~~well in the third quarter ~~and first nine months of 2014 compared~~2015, spud-to-total depth, decreased to 82 mboed and 78 mboed in the same 2013 periods, for increases of 43 percent and 35 percent. Approximately 64 percent of third quarter sales was crude oil and condensate, 18 percent was natural gas liquids ("NGLs") and 18 percent was natural gas.10 days.

Enhanced completion design in the Eagle Ford continues to deliver strong results as the growing population of these wells achieving 180-day cumulative production continues to average 25 percent improvement in volumes as compared to the previous completion design.

Oklahoma Resource Basins – During the third quarter, ~~of 2014,~~ we ~~reached total depth on 93 gross~~spud our first Springer well and brought online 8 operated wells (6 in SCOOP and ~~brought 87 gross~~

~~operated~~2 in STACK), with one of the SCOOP wells being an extended-reach lateral. In addition to ~~sales, compared to 70 reaching total depth and 71~~the 8 wells mentioned above, we completed an additional Smith infill pilot well in the SCOOP which was brought to sales on October 1. These wells are all in the ~~third quarter~~very early stages of 2013. During the first nine months of 2014, we reached total depth on 264 gross operated wells and brought 221 gross operated wells to sales, compared to 228 reaching total depth and 219 brought to sales in the same 2013 period. Our third quarter of 2014 average spud-to-total depth time was 13 days compared to 12 days in the same 2013 period. Our high-density pad drilling continues to average four wells per pad in 2014. This higher pad density and the longer laterals being drilled in 2014 contribute to the slightly higher spud-to-total depth time in 2014.

Included with the Eagle Ford well counts noted above, we brought online eight Austin Chalk wells, all drilled within the previously delineated acreage. Sixteen additional Austin Chalk wells are currently being drilled, completed or awaiting first production and we expect to complete a total of 30 wells in the Austin Chalk for 2014.

Bakken – Average net sales volumes from the Bakken shale were 56 mboed and 50 mboed in the third quarter and first nine months of 2014 compared to 38 mboed in the same 2013 periods, for increases of 47 percent and 32 percent. Our Bakken production averages approximately 89 percent crude oil, six percent NGLs and five percent natural gas. During the third quarter of 2014, we reached total depth on 25 gross operated wells and brought 19 gross operated wells to sales, compared to 21 reaching total depth and 21 brought to sales in the third quarter of 2013. During the first nine months of 2014, we reached total depth on 60 gross operated wells and brought 49 gross operated wells to sales compared to 61 reaching total depth and 56 brought to sales in the same 2013 period. Our third quarter average time to drill a well was 16 days spud-to-total depth, compared to 18 days in the same 2013 period. We recompleted 16 wells in the Hector and Ajax areas during the third quarter of 2014, with 13 of these wells brought to sales.

~~Three of four high-density spacing pilots have begun drilling, with each pad comprised of six Middle Bakken and six Three Forks first bench wells.~~production. We continue to ~~execute an enhanced completion design pilot program, including elevated proppant volumes, hybrid slickwater fracs, increased stages~~leverage the benefit of participation in outside-operated wells and ~~cemented liners. Of~~plan to participate in approximately 55-70 gross outside-operated wells in 2015 in the ~~19 Bakken~~SCOOP Woodford, SCOOP Springer and STACK areas, with 17 outside-operated wells brought to sales induring the ~~quarter, eight are piloting enhanced completions. In late September an incremental drilling rig was added in the~~ quarter.

Bakken ~~to provide additional capacity for high-density spacing and enhanced completion pilots.~~

~~Oklahoma resource basins~~ – Net sales volumes from the Oklahoma resource basins averaged 19 mboed and 17 mboed in the third quarter and first nine months of 2014 compared to 15 mboed and 13 mboed in the comparable 2013 periods, for increases of 27 percent and 31 percent. Approximately 42 percent of third quarter 2014 sales was liquid hydrocarbons and 58 percent natural gas. During the third quarter of 2014, we reached total depth on fourThe 5 gross ~~operated wells and brought six gross operated wells to sales. Of the~~ wells brought to sales ~~four~~this quarter were in the ~~SCOOP and two in~~East Myrmidon area. Despite the ~~Southern Mississippi Trend. We plan to add two incremental rigs in the Oklahoma Resource Basins by year end. During the first nine months~~lower number of ~~2014, we reached total depth on 15 gross operated wells and brought ten gross operated~~ wells to sales ~~compared to eight reaching total depth and nine brought to~~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 ~~same 2013 period.~~

~~Wyoming~~ – ~~Operated production at~~Gunflint field located on Mississippi Canyon Blocks 948, 949, 992 (N/2) and 993 (N/2). We expect the ~~Powder River Basin field ceased in March 2014. Plug and abandonment activities are expected~~two-well subsea tieback to be ~~substantially~~ complete by the end of 2015 with first oil in mid-2016. We hold an 18% non-operated working interest in the ~~fourth quarter of 2014.~~Gunflint field.

North America E&P--Exploration

Gulf of Mexico ~~–The operated Key Largo~~ – The third appraisal well on the Shenandoah prospect was spud in May 2015 and 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 51, in which we hold a 10% non-operated working interest. The Solomon exploration prospect located on Walker Ridge Block ~~578,~~225 was spud during the second quarter of 2015 and is expected to reach total depth in ~~September 2014 as~~ the ~~first well of a multi-year Gulf of Mexico exploration program with a new-build deepwater drillship.~~fourth quarter. We ~~are operator and~~ hold a ~~60 percent~~58% operated working interest in ~~the~~this prospect.

~~An exploration well was spud on the Perseus prospect, located on Desoto Canyon Block 231 in September 2014. We hold a 30 percent non-operated working interest in the prospect.~~

The second appraisal well on the non-operated Shenandoah prospect was spud in late May 2014 and is still drilling. The well is located on Walker Ridge Block 52, in which we hold a 10 percent working interest.

~~North America E&P--Acquisitions~~

~~In an asset acquisition that closed August 2014, we added acreage to our Oklahoma resource position at a cost of approximately $80 million before final settlement adjustments.~~

2324

International E~~&P--Production~~&P--Net Sales Volumes

The following table provides net sales volumes for our significant operational areas within this segment.


	Three Months Ended September 30,		Nine Months Ended September 30,		Three Months Ended September 30,			Nine Months Ended September 30,
	2014	2013	2014	2013	2015	2014	Increase (Decrease)	2015	2014	Increase (Decrease)
Net Sales Volumes
Total Liquid Hydrocarbons (mbbld)
Equatorial Guinea	27	32	31	32
United Kingdom(a)	6	20	11	18
Libya	6	16	2	32
Total Liquid Hydrocarbons	39	68	44	82
Natural Gas (mmcfd)
Equatorial Guinea	420	463	434	437
United Kingdom^(a)	19	26	26	34
Libya	—	30	1	27
Total Natural Gas	439	519	461	498
Equivalent Barrels (mboed)
Equatorial Guinea	97	109	104	104	101	97	4%	96	104	(8)%
United Kingdom^(a)	9	24	15	24	18	9	100%	19	15	27%
Libya	6	21	2	37	—	6	(100)%	—	2	(100)%
Total International E&P (mboed)	112	154	121	165	119	112	6%	115	121	(5)%
Net Sales Volumes of Equity Method Investees
LNG (mtd)	6,265	7,302	6,488	6,638	5,700	6,265	(9)%	5,653	6,488	(13)%
Methanol (mtd)	1,103	1,364	1,078	1,249	1,125	1,103	2%	895	1,078	(17)%


^(a)	Includes natural gas acquired for injection and subsequent resale of 38 mmcfd and 43 mmcfd for the third quarters of 2015 and 2014, and ~~2013,~~8 mmcfd and 5 ~~mmcfd and 8~~ mmcfd for the first nine months of ~~2014~~2015 and ~~2013.~~2014.

~~International E&P segment average~~Equatorial Guinea – Third quarter net sales volumes increased as production from the Alba C21 development well came 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 at the fabrication yard in the Netherlands during the third quarter and ~~first nine months of~~is on schedule to be operational in mid-2016.

~~2014~~United Kingdom ~~decreased 27 percent and 27 percent when~~– Net sales volumes benefited from improved production as two subsea development wells at West Brae began producing during 2015. Overall, operating availability was higher for all U.K. assets in 2015 as compared to ~~the~~ ~~third quarter~~comparative 2014 periods which included planned and ~~first nine months of2013. We had lower oil sales from Libya in 2014 as a result of third party labor strikes at the Es Sider terminal. Excluding Libya, net sales volumes decreased 20 percent in~~unplanned maintenance activities. During the third quarter of ~~2014~~2015, planned maintenance activities were completed at the East Brae field and ~~decreased 7 percent in~~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 nine months of ~~2014 compared to the same 2013 periods. The third quarter of 2014 net sales volume decrease, excluding Libya, is primarily~~2015 as a result of the timing of liquid hydrocarbon liftings from the U.K., lower reliability at the non-operated methanol facility in Equatorial Guinea and planned maintenance activities at the non-operated Forties Pipeline System that lowered operational availability across the Brae complex in the U.K. The net sales volume decrease for the first nine months of 2014, excluding Libya, is primarily related to reliability issues at the non-operated U.K. Foinaven fieldcontinued civil unrest, as ~~well as natural production decline within the U.K. Brae fields, in addition to the third quarter impacts discussed above.~~

~~Equatorial Guinea – Average net sales volumes were 97 mboed and 104 mboed in the third quarter and first nine months of 2014~~ compared to 109 mboed and 104 mboed in the same 2013 periods. Third quarter of 2014 net sales volumes were lower primarily as a result of temporary production curtailments due to unplanned maintenance on the main condensate line as well as lower reliability at the non-operated methanol facility.

An outbreak of the Ebola virus has existed in certain regions of West Africa (Guinea, Liberia, Sierra Leone) for several months. Although neither Equatorial Guinea nor any other African country in which we have business activities has been impacted by Ebola to date, our business operations may be adversely affected through travel or other restrictions. We continue to monitor the situation and are working closely with appropriate external parties to maintain business continuity and the health and well-being of our staff.

United Kingdom – Average net sales volumes were 9 mboed and 15 mboed in the third quarter and first nine months of 2014 compared to 24 mboed in the same 2013 periods, for decreases of 63 percent and 38 percent, primarily due to the timing of liquid hydrocarbon liftings, planned maintenance activities on the non-operated Forties Pipeline System in the third quarter of 2014, reliability issues at the non-operated Foinaven field and natural decline within the Brae fields. Overall, operating availability was lower for all U.K. assets in 2014 due to planned and unplanned maintenance activities. We brought two South Brae infill wells onlineone lifting in the third quarter of 2014. ~~A third South Brae well and a new West Brae well are planned to come online in the first quarter of 2015.~~

~~Libya –~~ In ~~July~~December 2014, ~~Libya's~~Libya’s National Oil Corporation ~~rescinded~~reinstated force majeure ~~associated with third-party labor strikes~~ at the Es Sider oil terminal. ~~Our first 2014 lifting occurred in August, and was sourced from existing inventory at the terminal. Production from the Waha concessions resumed in August 2014; however, considerable~~Considerable uncertainty remains around the timing of future production and sales levels.

~~International E&P--Exploration~~

Kurdistan Region of Iraq – We resumed testing of the Jisik-1 exploration well on the operated Harir Block following suspension of certain operations due to security concerns in the region and continue to closely monitor the situation. In the fourth quarter of 2014, we will commence a 2D seismic program and expect to spud the Mirawa-2 appraisal well. We hold a 45 percent operated working interest in the Harir Block.

On the non-operated Sarsang Block, testing continues on the East Swara Tika-1 exploratory well which reached a total depth of approximately 13,000 feet in June 2014. The co-venturers declared the Swara Tika discovery commercial in May 2014 and filed a field development plan in June. Discussions are ongoing with the Ministry of Natural Resources to finalize the Swara Tika field development plan. Testing of the Mangesh well was finalized and the well costs were charged to dry well expense in the second quarter of 2014. Due to a contract amendment in April 2014, we hold a 20 percent non-operated working interest in the Sarsang block.

Construction of the phase one production facility on the non-operated Atrush Block continues with first oil expected in 2015. The Chiya Khere-5 development well (formerly Atrush-5) reached total depth in late June 2014. The well will be tested prior to final completion and tie-in to the phase one production facility. The Atrush-4 development well reached total depth in January 2014, completed testing in April 2014 and has been suspended as a future producer. We hold a 15 percent non-operated working interest in the Atrush Block.

~~Equatorial Guinea – An exploration well on the Sodalita West prospect is expected to spud by the end of 2014 as the first of two offshore exploration wells targeting oil-prone plays.~~

Kenya – The Sala-2 appraisal well spud in the third quarter of 2014, did not encounter commercial hydrocarbons, and the well costs were charged to dry well expense in the quarter. The Sala-1 exploration well was spud in February 2014 on the eastern side of Block 9 and made a natural gas discovery in the second quarter of 2014. The well was drilled to a total depth of approximately 10,000 feet and analysis indicated three zones of interest over a 3,280-foot gross interval which were subsequently drill-stem tested. We hold a 50 percent non-operated working interest in Block 9 with the option to operate any commercial development.

Ethiopia – Two wells were drilled on the South Omo Block: the Shimela-1 well, which reached total depth in May 2014, and the Gardim-1 well, which reached total depth in July 2014. Neither well encountered commercial hydrocarbons and the well costs were charged to dry well expense in the second quarter of 2014. We hold a 20 percent non-operated interest in the South Omo Block.

Early in 2014, we increased our acreage in Ethiopia through a farm-in to the Rift Basin Area Block with 10.5 million gross acres. We are in the process of acquiring 2D seismic and plan to drill an appraisal well in 2015. We hold a 50 percent non-operated working interest in the block with the option to operate if a discovery is made.

Gabon – In August 2014, we signed an exploration and production sharing contract for Gabon offshore Block G13, which was subsequently re-named Tchicuate. Located in the deepwater, pre-salt play, the block encompasses 275,000 acres; and, acquisition of 3D seismic is planned to commence in early November 2014. We hold a 100 percent participating interest and operatorship in the block. In the event of development, the Republic of Gabon will assume a 20 percent financed interest in the contract upon commencement of production. The State holds additional rights to participate in the block in the future as a co-investor.

~~Poland – During the first quarter of 2014, we relinquished our remaining four operated concessions to the government.~~

~~International E&P--Dispositions~~

~~In June 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,~~ ~~with an effective date of January 1, 2014. The transaction closed on October 15, 2014 for approximately $2.1 billion in proceeds.~~

~~The Norway business is excluded from the International E&P segment results and is reported as discontinued operations. Average net sales volumes from Norway were 58 mboed and 66 mboed in the~~ ~~third quarter and first nine months of2014~~ ~~compared to~~ 68 ~~mboed and~~ 81 ~~mboed in the same~~ ~~2013~~ periods. The decrease for the quarter was primarily related to a 12-day planned turnaround at Alvheim versus a planned 7-day turnaround in same quarter of 2013, as well as natural field decline. Alvheim was also impacted in the first quarter of 2014 by severe winter weather which resulted in eight days of curtailed production.

In the first quarter of 2014, we closed the sales of our non-operated 10 percent working interests in the Production Sharing Contracts and Joint Operating Agreements for Angola Blocks 31 and 32 for aggregate proceeds of approximately $2 billion. See Note 6 to the consolidated financial statements for information about these dispositions.

Oil Sands Mining

~~Our Oil Sands Mining operations consist of a 20 percent non-operated working interest in the Athabasca Oil Sands Project.~~ Our net synthetic crude oil sales volumes were 5565 mbbld and 4951 mbbld in the third quarter and first nine months of ~~2014~~2015 compared to 4955 mbbld and 4749 mbbld in the same periods of ~~2013. The increase for~~2014. Net sales volumes increased in the third quarter of ~~2014 was the result of~~2015 primarily due to improved ~~operational availability at the upgrader and mines and higher beginning bitumen inventories. Comparison of sales volumes for the nine-month periods reflects lower~~ mine reliability and ~~nine days of planned mine~~no major maintenance activities. Planned maintenance at both mines in the ~~first~~fourth quarter of ~~2014 and~~2015 is expected to impact production. We hold a ~~planned turnaround~~20% non-operated working interest in the ~~second quarter of 2013.~~Athabasca Oil Sands Project.

2625

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 third quarter and first nine 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 third quarter and first nine months of ~~2014~~2015 and ~~2013.~~2014.

Three Months Ended September 30, Nine Months Ended September 30,
2014 2013 2014 2013
Average Price Realizations ^(a)

Crude Oil and Condensate (per bbl)

Bakken
$85.28

$97.76

$89.07

$92.58
Eagle Ford 93.51
104.08
96.12
102.41
Oklahoma Resource Basins 93.78
101.82
96.23
94.80
Other North America ^(b)
87.50
99.93
90.06
92.75
Total Crude Oil and Condensate 89.65
101.05
92.59
96.54
Natural Gas Liquids (per bbl)

Bakken
$40.60

$44.08

$46.92

$40.24
Eagle Ford 30.90
30.11
32.64
28.84
Oklahoma Resource Basins 33.64
35.11
36.74
34.91
Other North America ^(b)
51.49
55.81
55.77
54.39
Total Natural Gas Liquids 33.93
35.01
36.96
34.06
Total Liquid Hydrocarbons (per bbl) ^(c)

Bakken
$82.67

$95.24

$86.66

$89.96
Eagle Ford 79.99
87.96
82.99
86.61
Oklahoma Resource Basins 56.57
51.34
55.58
50.49
Other North America ^(b)
85.28
97.12
87.71
90.30
Total Liquid Hydrocarbons 80.89
90.49
83.89
87.09
Natural Gas (per mcf)

Bakken
$4.29

$3.73

$5.49

$3.93
Eagle Ford 4.21
3.53
4.59
3.71
Oklahoma Resource Basins 3.97
3.10
4.64
3.79
Other North America^(b)
4.34
3.62
5.03
3.96
Total Natural Gas 4.21
3.51
4.81
3.86
Benchmarks
West Texas Intermediate ("WTI") crude oil (per bbl)

$97.25

$105.81
$99.62 $98.20
Louisiana Light Sweet ("LLS") crude oil (per bbl)^(d)
101.03
110.00
103.63
109.48
Mont Belvieu NGLs (per bbl)^(e)
32.69
33.46
35.15
33.05
Henry Hub natural gas^(f) (per mmbtu)^(g)
4.06
3.58
4.55
3.65



	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)	~~Includes Gulf of Mexico and other conventional onshore U.S. production, plus Alaska in 2013.~~

^(c)

Inclusion of realized ~~losses~~gains on crude oil derivative instruments would have ~~decreased~~increased average ~~liquid hydrocarbon~~crude oil price ~~realizations~~realization by ~~$1.81~~$1.87 per bbl and ~~$0.30~~$0.69 per bbl for the third quarter and first nine months of ~~2013~~.2015. There were no crude oil derivative instruments ~~for the third quarter and first nine months of~~ ~~2014~~.

in 2014.


^(d)	~~Bloomberg Finance LLP: LLS St. James.~~


^(e)(c)	Bloomberg Finance LLP: Y-grade Mix NGL of 50% ethane, 25% propane, 10% butane, 5% isobutane and 10% natural gasoline.


^(f)	~~Settlement date average.~~


^(g)	~~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. Crude oil benchmark prices decreased for third quarter and first nine months of 2014 compared to the same 2013 periods due to a decline in crude oil prices because of increased supply, weak global demand and other geopolitical factors. This price decline continued after quarter end with WTI averaging $84.34 per bbl in October 2014.

Natural gas liquids – The majority of our NGL volumes are sold at reference to Mont Belvieu prices. Average Mount Belvieu NGL prices for the third quarter of 2014 were modestly lower than for the same 2013 period. This was primarily due to softer ethane prices, due to a higher incidence of downtime in the demand driven petroleum chemical industry, and lower crude oil prices. Our net NGL sales volumes continue to grow due to development of our U.S. resource plays with increases of 29 percent and 27 percent during the third quarter and first nine months of 2014 compared to the same 2013 periods.

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. Average Henry Hub settlement prices for natural gas were higher in the third quarter of 2014 compared to the same 2013 period primarily because of incremental demand generated from significantly lower storage levels.

International E&P

The following table presents our average price realizations and the related benchmark for crude oil, NGLs, and natural gas for the third quarter and first nine months of ~~2014~~2015 and ~~2013~~2014.

Three Months Ended September 30, Nine Months Ended September 30,
2014 2013 2014 2013
Average Price Realizations
Total Liquid Hydrocarbons (per bbl)

Equatorial Guinea
$51.83

$57.35

$58.37

$59.54
United Kingdom 88.68
108.34
106.00
108.13
Libya 114.36
124.19
114.86
122.91
Total Liquid Hydrocarbons 66.80
88.47
72.88
94.41
Natural Gas (per mcf)

Equatorial Guinea^(a)

$0.24

$0.24

$0.24

$0.24
United Kingdom 7.60
10.67
8.72
10.78
Libya —
5.92
5.45
5.26
Total Natural Gas 0.56
1.10
0.73
1.24
Benchmark
Brent (Europe) crude oil (per bbl)

$101.82

$110.27

$106.56

$108.45



	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~~Average of monthly 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~~obtained from ~~each of these equity method investees in our International E&P segment.~~EIA website.

Liquid hydrocarbons – Our U.K. liquid hydrocarbon production is generally sold in relation to the Brent crude benchmark. Our ~~liquid hydrocarbon~~ production from Equatorial Guinea ~~includes~~is condensate, ~~and NGLs that receive~~which receives lower prices than crude oil. ~~During the third quarter of 2014, crude oil prices declined driven by weaker demand~~

Our NGL and ~~increased supply, along with continued global economy and geopolitical factors. This price decline continued after quarter end with Brent averaging $88.05 per bbl in October 2014.~~

~~Natural gas~~ –Our major international natural gas-producing regions are the U.K. and Equatorial Guinea. Natural gas prices in Europe have been considerably higher than in the U.S. in recent years. In the case of Equatorial Guinea, our natural gas sales in the International E&P segment originate primarily from our E.G. operations and are ~~subject~~sold to our equity method investees under fixed-price, term ~~contracts, making realized prices in this area less volatile;~~contracts; therefore, our reported average ~~natural gas~~ realized prices for ~~the International E&P segment~~NGLs and natural gas will not fully track market price movements. The equity affiliates then utilize, process and sell the NGLs and natural gas at market prices, with our share of their income/loss reflected in the Income from equity method investments line item on the 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"). Comparing the corresponding 2014 and 2013 periods, the WCS discount to WTI widened in the third quarter by $2.80 per barrel; however, in the first nine months of 2014, the WCS discount to WTI narrowed by $1.81 per barrel.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.

The following table presents our average price realizations and the related benchmarks ~~that impacted both our revenues and variable costs~~ for the third quarter and first nine months of ~~2014~~2015 and ~~2013~~2014.


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,			Nine Months Ended September 30,
	2014		2013		2014		2013		2015	2014	Decrease	2015	2014	Decrease
Average Price Realizations
Synthetic Crude Oil (per bbl)		$88.22		$102.64		$90.11		$90.65	$39.49	$88.22	(55%)	$42.26	$90.11	(53%)
Benchmark
Benchmarks
WTI crude oil (per bbl)		$97.25		$105.81		$99.62		$98.20	$46.50	$97.25	(52%)	$51.01	$99.62	(49%)
WCS crude oil (per bbl)^(a)		$76.99		$88.35		$78.50		$75.27	33.16	76.99	(57%)	37.80	78.50	(52%)
AECO natural gas sales index (per mmbtu)^(b)		$3.51		$2.35		$4.32		$2.99


^(a)	Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.


^(b)	~~Monthly average AECO day ahead index.~~

Results of Operations

~~Consolidated Results of Operation~~Three 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 September 30, Nine Months Ended September 30,
(In millions) 2014 2013 2014 2013
Sales and other operating revenues, including related party
North America E&P $ 1,586
$ 1,321
$ 4,518
$ 3,820
International E&P 273
611
1,000
2,332
Oil Sands Mining 457
463
1,217
1,204
Segment sales and other operating revenues, including related party $ 2,316
$ 2,395
$ 6,735
$ 7,356
Unrealized loss on crude oil derivative instruments —
(61 ) —
(61 )
Sales and other operating revenues, including related party $ 2,316
$ 2,334
$ 6,735
$ 7,295

~~North America E&P sales and other operating revenues~~ increased 20 percent and 18 percent in the third quarter and first nine months of 2014 from the comparable 2013 periods primarily due to the higher net sales volumes from continued growth across our three U.S. resource plays, partially offset by lower crude oil price realizations.



	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&P	182		273
Oil Sands Mining	242		457
Segment sales and other operating revenues, including related party	$	1,220	$	2,316
Unrealized gain on crude oil derivative instruments	80		—
Sales and other operating revenues, including related party	$	1,300	$	2,316

~~The following tables display changes in North America E&P segment sales and other operating revenues by product.~~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.

Three Months Ended Increase (Decrease) Related to Three Months Ended
(In millions) September 30, 2013 Price Realizations Net Sales Volumes September 30, 2014
North America E&P Price-Volume Analysis
Liquid hydrocarbons $ 1,251
$ (174 ) $ 387
$ 1,464
Natural gas 96
20
7
123
Realized loss on crude oil
derivative instruments (24 ) 24
—
Other sales (2 ) (1 )
Total $ 1,321
$ 1,586

Nine Months Ended Increase (Decrease) Related to Nine Months Ended
(In millions) September 30, 2013 Price Realizations Net Sales Volumes September 30, 2014
North America E&P Price-Volume Analysis
Liquid hydrocarbons $ 3,490
$ (156 ) $ 778
$ 4,112
Natural gas 335
78
(15 ) 398
Realized loss on crude oil
derivative instruments (12 ) 12
—
Other sales 7
8
Total $ 3,820
$ 4,518

~~International E&P sales and other operating revenues~~ decreased 55 percent and 57 percent in the third quarter and first nine months of 2014 from the comparable 2013 periods. The decreases were primarily due to the lower liquid hydrocarbon net sales volumes previously discussed, combined with lower average price realizations for both liquid hydrocarbons and natural gas.

The following tables display changes in International E&P segment sales and other operating revenues by product. Refer to the preceding Operations and Market Conditions sections for additional detail related to our net sales volumes and average price realizations.

Three Months Ended Increase (Decrease) Related to Three Months Ended
(In millions) September 30, 2013 Price Realizations Net Sales Volumes September 30, 2014
International E&P Price-Volume Analysis
Liquid hydrocarbons $ 548
$ (78 ) $ (230 ) $ 240
Natural gas 52
(22 ) (8 ) 22
Other sales 11
11
Total $ 611
$ 273

Nine Months Ended Increase (Decrease) Related to Nine Months Ended
(In millions) September 30, 2013 Price Realizations Net Sales Volumes September 30, 2014
International E&P Price-Volume Analysis
Liquid hydrocarbons $ 2,127
$ (258 ) $ (996 ) $ 873
Natural gas 168
(64 ) (12 ) 92
Other sales 37
35
Total $ 2,332
$ 1,000

~~Oil Sands Mining sales and other operating revenues~~ ~~changed slightly in the third quarter and first nine months of 2014, from the comparable 2013 periods as shown below.~~

The following tables display changes in OSM segment sales and other operating revenues by product. Refer to the preceding Operations and Market Conditions sections for additional detail related to our net sales volumes and average price realizations.

Three Months Ended Increase (Decrease) Related to Three Months Ended
(In millions) September 30, 2013 Price Realizations Net Sales Volumes September 30, 2014
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil $ 461
$ (73 ) $ 57
$ 445
Other sales 2
12
Total $ 463
$ 457

Nine Months Ended Increase (Decrease) Related to Nine Months Ended
(In millions) September 30, 2013 Price Realizations Net Sales Volumes September 30, 2014
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil $ 1,175
$ (7 ) $ 27
$ 1,195
Other sales 29
22
Total $ 1,204
$ 1,217

~~Unrealized gains and losses on crude oil derivative instruments~~ are included in total sales and other operating revenues but are not allocated to the segments. In both the third quarter and first nine months of 2013, the net unrealized loss on crude oil derivative instruments was $61 million. There were no crude oil derivative instruments in the third quarter and first nine months of 2014.



	Three Months Ended			Increase (Decrease) Related to					Three Months Ended
(In millions)	September 30, 2014			Price Realizations			Net Sales Volumes		September 30, 2015
North 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 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	$	445		$	(294	)	$	85	$	236
Other sales	12								6
Total	$	457							$	242

Marketing revenues decreased ~~$112 million and increased $118~~$470 million in the third quarter ~~and first nine months~~ of ~~2014~~2015 from the comparable prior-year periods. The decrease in the third quarter of 2014 is related primarily to lower marketing activity levels and crude oil prices in the North America E&P segment. The increase in the first nine months of 2014 is primarily due to higher marketing activity levels in both the North America E&P and OSM segments.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. 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 investments decreased $25 million and increased $37 million in the third quarter and first nine months of 2014 from the comparable 2013 periods. The decrease in the third quarter of 2014 is primarily due to reliability issues in Equatorial Guinea at the non-operated methanol facility and lower average price realizations. The increase in the first nine months of 2014 is primarily due to higher earnings from our LNG operations in Equatorial Guinea as a result of higher average price realizations and a turnaround in the second quarter of 2013.

~~Net loss on disposal of assets~~ in the first nine months of 2014 includes the loss on the sale of non-core acreage located in the far northwest portion of the Williston Basin. See Note 6 to the consolidated financial statements for further details on dispositions.

~~Production expenses~~ ~~increased~~ $53 million in the third quarter of 2015 from the comparable 2014 ~~from~~period. The decrease is 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 impacting the quarter was a partial impairment of our investment in an equity method investee.

Production expenses decreased $187 million. North America E&P declined $54 million due to lower operational, maintenance and labor costs. International E&P declined $47 million primarily the result of higher project costs in 2014, such as the non-operated Foinaven subsea power project. Also contributing were lower production costs in Libya during 2015 as the third quarter of ~~2013.~~2014 had one lifting. OSM decreased $86 million primarily due to 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 and lower feedstock purchases given increased reliability.

The third quarter of 2015 production expense rate (expense per boe) for North America E&P ~~segment~~declined due to overall cost reductions, as previously discussed, and leveraging efficiencies as production ~~expenses increased $28 million primarily related to higher net sales~~ volumes ~~in the U.S. resource plays. OSM segment production expenses increased $25 million primarily as a result of higher net sales volumes.~~

In the first nine months of 2014, production expenses increased $72 million compared to the same 2013 period. North America E&P segment production expenses increased $77 million primarily related to higher net sales volumes in the U.S. resource plays.increased. The expense rate for International E&P ~~segment production expenses increased $38 million~~declined due to reduced maintenance and ~~included $11 million for non-recurring riser repairs~~project costs and lower operational costs in Equatorial Guinea during the first quarter of 2014 and $5 million related to a turnaround at Brae in the U.K. during the second quarter of 2014. Lower sales volumes across the International E&P segment contributed to the higher productionLibya. The OSM expense rate ~~(production expense per barrel of oil equivalent, or "boe"). OSM segment~~decreased as production ~~expenses decreased $43 million in~~volume increased, coupled with the ~~first nine months of 2014 due to the 2013 turnaround and lower contract services and contract labor costs in 2014.~~increased cost focus discussed above.

The following table provides production expense rates for each segment:


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,
($ per boe)	2014		2013		2014		2013		2015	2014
Production Expense Rate	Production Expense Rate
North America E&P		$10.16		$11.18		$10.52		$10.72	$7.43	$10.16
International E&P		$10.48		$7.64		$9.34		$5.96	$5.53	$10.48
Oil Sands Mining ^(a)		$37.38		$40.47		$44.73		$47.30	$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 ~~$109 million and increased $120~~$470 million in the third quarter ~~and first nine months~~ of ~~2014~~2015 from the comparable ~~2013 periods,~~2014 period, consistent with the marketing revenues changes discussed above.

Exploration expenses ~~were $351 million lower~~increased $489 million. We made a strategic decision to reduce the overall level of our conventional exploration program; as a result, we impaired certain of our leases in the ~~first nine months~~Gulf of ~~2014 than~~Mexico and the Harir block in the ~~comparable 2013 period. The first quarter~~Kurdistan Region of ~~2013 included $340 million in non-cash~~Iraq. Further contributing to the increase was an impairment of unproved property ~~impairments on Eagle Ford leases that either expired or that~~in Colorado, which we ~~did not expect to drill or extend.~~deemed uneconomic given our forecasted natural gas prices. The following table summarizes the components of exploration expenses:


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,
(In millions)	2014		2013		2014		2013		2015			2014
Exploration Expenses	Exploration Expenses
Unproved property impairments	$	39	$	35	$	140	$	458	$	563		$	39
Dry well costs	25		24		80		95		(3		)	25
Geological and geophysical	10		8		27		44		8			10
Other	22		16		67		68		17			22
Total exploration expenses	$	96	$	83	$	314	$	665	$	585		$	96

Depreciation, depletion and amortization (“DD&A”) ~~increased $80~~decreased $20 million ~~and $146 million~~primarily as a result of a higher proved reserve base in Eagle Ford, the effects of which more than offset additional DD&A resulting from production volume increases in the ~~third quarter~~International E&P and ~~first nine months of 2014 from the comparable 2013 periods.~~OSM 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.

~~Increased~~ The following table provides DD&A ~~in the third quarter and first nine months of 2014 primarily reflects the impact of higher~~rates for each segment. The DD&A rate for North America E&P ~~net~~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 ~~our three U.S. resource plays; partially offset by lower International E&P segment sales volumes, as previously discussed.~~

~~The International E&P segment DD&A rate was lower in~~ the ~~third quarter and first nine months of 2014 because a majority of our net sales volumes in the 2014 periods were from countries with lower DD&A rates.~~Brae infill drilling program.


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,
($ per boe)	2014		2013		2014		2013		2015		2014
DD&A Rate
North America E&P		$26.54		$26.64		$26.65		$26.73		$22.84		$26.54
International E&P		$5.30		$8.18		$6.09		$6.28		$7.32		$5.30
Oil Sands Mining		$12.75		$12.43		$12.14		$12.27		$12.62		$12.75

Impairments are discussed in Note 1314 to the consolidated financial statements.

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 and revenue.~~volumes. With the ~~increase~~decrease in North America E&P revenues ~~and net sales volumes,~~due to lower price realizations, taxes other than income ~~increased $26 million and $55~~decreased $69 million in the third quarter ~~and first nine months~~ of ~~2014 from the comparable 2013 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 September 30,				Nine Months Ended September 30,				Three Months Ended September 30,
(In millions)	2014		2013		2014		2013		2015		2014
Production and severance	$	69	$	50	$	191	$	151	$	28	$	69
Ad valorem	20		16		58		52		2		20
Other	26		23		70		61		16		26
Total	$	115	$	89	$	319	$	264	$	46	$	115

General and administrative expenses ~~increased $17~~decreased $35 million primarily due to cost savings realized from the workforce reductions that occurred in the first quarter of 2015. Pension settlement charges in the three months of 2015 totaled $18 million compared to $22 million in the prior year. In addition, we incurred severance related expenses in the first three months of 2015 associated with workforce reductions of $4 million.

Provision (benefit) for income taxes reflects an effective tax rate of 35% in the third quarter of ~~2014~~2015, as compared to the same 2013 period, primarily due to higher pension settlement expense as well as higher unallocated technical and operations support costs. The increase of $21 million in the first nine months of 2014 compared to the same 2013 period is primarily due to higher pension settlement expense and higher unallocated technical and operations support costs partially offset by lower employee related costs and less contract services.

~~Net interest and other~~33% in the third quarter ~~and first nine months~~ of 2014 was a lower net expense by $16 million and $31 million compared to the same 2013 periods, primarily due to decreases in net foreign currency losses. In addition, a dividend was received in the first quarter of 2014 from a mutual insurance company of which we are an owner.

~~Provision for income taxes~~ ~~decreased $210 million and $872 million in the third quarter and first nine months of 2014 from the comparable 2013 periods, primarily as a result of reduced pretax income in Libya.~~2014. See Note 9 to the consolidated financial statements for discussion of the effective tax rate.

Discontinued operations presented in 2014 are ~~presented~~ net of tax. See ~~the preceding Operations section and~~ 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. ~~Unrealized~~Gains or losses on dispositions, certain impairments, unrealized gains or losses on crude oil derivative instruments, ~~certain impairments, gains or losses on dispositions~~ or other items that affect comparability also are not allocated to operating segments.

The following table reconciles segment income (loss) to net ~~income:~~income (loss):


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,
(In millions)	2014			2013			2014			2013			2015			2014
North America E&P	$	292		$	242		$	836		$	404		$	(61	)	$	292
International E&P	106			192			487			635			29			106
Oil Sands Mining	93			106			212			164			(11		)	93
Segment income	491			540			1,535			1,203
Segment income (loss)													(43		)	491
Items not allocated to segments, net of income taxes	(187		)	(144		)	(473		)	(408		)	(706		)	(187		)
Income from continuing operations	304			396			1,062			795
Income (loss) from continuing operations													(749		)	304
Discontinued operations ^(a)	127			173			1,058			583			—			127
Net income	$	431		$	569		$	2,120		$	1,378
Net income (loss)													$	(749	)	$	431


^(a)	~~We sold our Angola assets in the first quarter~~As a result of ~~2014 and closed~~ the sale of our Angola assets and our Norway business, ~~on October 15, 2014. The Angola and Norway businesses~~both are reflected as discontinued operations in ~~all periods presented.~~2014.

North America E&P segment income (loss)~~increased $50~~ decreased $353 million ~~and $432 million~~ after-tax ~~in the~~ ~~third quarter and first nine months of2014~~ ~~compared to the same 2013 periods. The increases in both periods are~~ primarily due to ~~higher~~lower price realizations, which was partially offset by the impacts from the increased net sales volumes from the U.S. resource plays ~~partially offset by~~and lower ~~crude oil price realizations~~production and expenses associated with the higher net sales volumes, such as production expenses and DD&A. Also impacting the comparison of the nine-month period was the previously discussed non-cash unproved property impairments in the first quarter of 2013.operating costs.

International E&P segment income decreased ~~$86 million and $148~~$77 million after-tax ~~in the third quarter and first nine months of 2014 compared~~primarily due to ~~the same 2013 periods.~~ T~~he decreases in both periods are primarily a result of~~ lower ~~net sales volumes in the U.K and Equatorial Guinea and lower commodity~~liquid hydrocarbon price realizations as well as reduced income from equity investments. These declines were partially offset by ~~reduced taxes and expenses associated with the lower sales volumes. Lower~~increased sales volumes ~~from Libya impacted the decrease when comparing the nine-month periods. In addition, the second quarter of 2014 had higher~~and lower production and exploration ~~expenses due to dry wells, partially offset by higher earnings from our equity method LNG operations in Equatorial Guinea due to a turnaround in the second quarter of 2013.~~expenses.

Oil Sands Mining segment income (loss) decreased ~~$13 million and increased $48~~$104 million after-tax ~~in the third quarter and first nine months of 2014 from the comparable 2013 periods. The third quarter 2014 decrease was~~ primarily ~~a result of~~due to lower price realizations, partially offset by higher volumes and reduced production expenses.

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&P	575		1,000
Oil Sands Mining	614		1,217
Segment sales and other operating revenues, including related party	$	3,828	$	6,735
Unrealized gain on crude oil derivative instruments	59		—
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.

The ~~increase~~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 ~~was primarily~~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 costs	96		80
Geological and geophysical	23		27
Other	55		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.

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 valorem	33		58
Other	56		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):



	Nine Months Ended September 30,
(In millions)	2015			2014
North America E&P	$	(267	)	$	836
International E&P	93			487
Oil Sands Mining	(107		)	212
Segment income (loss)	(281		)	1,535
Items not allocated to segments, net of income taxes	(1,130		)	(473		)
Income (loss) from continuing operations	(1,411		)	1,062
Discontinued operations ^(a)	—			1,058
Net income (loss)	$	(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 $1,103 million after-tax in the first nine months of 2015 primarily due to lower price realizations; these were partially offset by increased net sales volumes from the U.S. resource plays and lower production ~~expenses~~costs.

International E&P segment incomedecreased $394 million after-tax primarily due to lower liquid hydrocarbon price realizations and ~~slightly higher net sales volumes.~~reduced income from equity investments. These declines were partially offset by lower production and exploration expenses.

Oil Sands Mining segment income (loss)decreased $319 million after-tax primarily due to lower price realizations, partially offset by reduced production expenses.

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, ~~2013~~.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

Accounting Standards Not Yet Adopted

See Note 2 to the consolidated financial statements.

3334

Cash Flows and Liquidity

Cash Flows

The following table presents sources and uses of cash and cash equivalents ~~for the nine months ended September 30, 2014 and 2013:~~


	Nine Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2014			2013			2015			2014
Sources of cash and cash equivalents
Continuing operations	$	3,476		$	3,300
Discontinued operations	856			741
Operating activities of continued operations							$	1,213		$	3,476
Operating activities of discontinued operations							—			856
Borrowings							1,996			—
Disposals of assets	2,237			402			105			2,237
Maturities of short-term investments							225			—
Other	196			149			97			196
Total sources of cash and cash equivalents	$	6,765		$	4,592		$	3,636		$	6,765
Uses of cash and cash equivalents
Additions to property, plant and equipment	$	(3,639	)	$	(3,383	)
Cash additions to property, plant and equipment							$	(2,948	)	$	(3,639	)
Investing activities of discontinued operations	(356		)	(435		)	—			(356		)
Purchases of short-term investments							(925		)	—
Debt issuance costs							(19		)	—
Debt repayments							(34		)	(34		)
Dividends paid							(427		)	(401		)
Purchases of common stock	(1,000		)	(500		)	—			(1,000		)
Commercial paper, net	(135		)	—			—			(135		)
Debt repayments	(34		)	(148		)
Dividends paid	(401		)	(376		)
Other	(48		)	(80		)	(1		)	(48		)
Cash held for sale	(655		)	—			—			(655		)
Total uses of cash and cash equivalents	$	(6,268	)	$	(4,922	)	$	(4,354	)	$	(6,268	)

~~The increase~~Commodity prices began declining in the second half of 2014 and remain substantially lower through 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 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 during the first nine months of 2014 is mostly due to changes in working capital driven by substantially lower tax payments during the year as well as the timing of cash receipts from liftings. The third quarter 2014 tax payments were favorably impacted by tax synergies availableare primarily related to our Norway business, ~~as a result~~which we disposed of in the ~~pending sale.~~

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 nine months of~~ 2014 primarily reflect the net proceeds from the sales of our ~~interests~~Angola assets. Disposition transactions are discussed in ~~Angola Blocks 31 and 32. In the first nine months of 2013, net proceeds were primarily related~~further detail in Note 6 to the ~~sales~~consolidated financial statements.

In October, 2015, we announced an adjustment to our quarterly dividend. See Capital Requirements below for additional information.

Certain of our ~~Alaska assets and our interests~~short-term investments matured in September 2015. Purchases of short-term investments in 2015 were made from proceeds received from the ~~Neptune gas plant and the DJ Basin.~~senior notes issuance in June 2015. The investments consisted of time deposits with maturity dates ranging from September - October 2015.

Additions to property, plant and equipment are our most significant use of cash and cash equivalents. The following table shows capital expenditures ~~related to continuing operations~~ by segment and reconciles to additions to property, plant and equipment in continuing operations as presented in the consolidated statements of cash ~~flows for the nine months ended September 30, 2014 and 2013:~~flows:


	Nine Months Ended September 30,					Nine Months Ended September 30,
(In millions)	2014			2013		2015		2014
North America E&P	$	3,246		$	2,706	$	2,048	$	3,246
International E&P	386			314		275		386
Oil Sands Mining	172			209		26		172
Corporate	29			47		26		29
Total capital expenditures	3,833			3,276		2,375		3,833
Change in capital expenditure accrual	(194		)	107
Additions to property, plant and equipment	$	3,639		$	3,383
(Increase) decrease in capital expenditure accrual						573		(194		)
Total use of cash and cash equivalents for property, plant and equipment						$	2,948	$	3,639

~~Purchases~~During the first nine months of 2014, we acquired 29 million common shares at a cost of $1 billion under our share repurchase program. There were no stock ~~are discussed in Note 18 to the consolidated financial statements.~~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 used the aggregate net proceeds to repay our $1 billion 0.90% senior notes on November 2, 2015, and the remainder for general corporate purposes.

In May 2015, we amended our $2.5 billion 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 ~~committed revolving credit facility~~$3 billion Credit Facility and sales of ~~non-strategic~~non-core assets. Our working capital requirements are supported

by these sources and we may also issue commercial paper, which is backed by our ~~$2.5 billion~~ revolving credit ~~facility to meet short-term cash requirements.~~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 ~~short-term and long-term~~ liquidity is adequate to fund not only our current operations, but also our ~~near-term and long-term~~ funding requirements for the foreseeable future, including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, ~~share repurchase program~~ and other amounts that may ultimately be paid in connection with contingencies.

Capital Resources

Credit Arrangements and Borrowings

~~In May 2014, we amended our $2.5 billion unsecured revolving credit facility and extended the maturity to May 2019. See Note 16 to the consolidated financial statements for additional terms and rates.~~ At September 30, ~~2014~~,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 September 30, ~~2014~~,2015, we had ~~$6,423 million~~$8.4 billion in long-term debt outstanding, ~~$68 million~~ of which ~~is due within one year.~~approximately $1.0 billion matured and was repaid in November 2015. We utilized cash on hand and proceeds from the maturities of 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 ~~Disposal~~Disposals

~~On October 15, 2014,~~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 ~~Norway business~~East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets for proceeds of approximately ~~$2.1 billion. The first priority for~~$100 million and announced the ~~use~~sale of ~~proceeds is organic reinvestment in~~ our ~~deep~~Kenya and ~~growing U.S. unconventional portfolio.~~Ethiopia exploration acreage. See Note 6 to the consolidated financial statements for additional discussion of ~~the Norway disposal.~~these dispositions.

~~Cash-Adjusted~~Cash and Short-Term Investments-Adjusted Debt-To-Capital Ratio

Our ~~cash-adjusted~~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)~~equivalents and short-term investments) was ~~22 percent~~24% at September 30, ~~2014~~,2015, compared to ~~25 percent~~16% at December 31, ~~2013~~.2014.


	September 30,			December 31,			September 30,			December 31,
(In millions)	2014			2013			2015			2014
Commercial paper	$	—		$	135
Long-term debt due within one year	68			68			$	1,035		$	1,068
Long-term debt	6,355			6,394			7,323			5,323
Total debt	$	6,423		$	6,597		$	8,358		$	6,391
Cash and cash equivalents	$	761		$	264		$	1,680		$	2,398
Short-term investments							$	700		$	—
Equity	$	20,226		$	19,344		$	19,335		$	21,020
Calculation:
Total debt	$	6,423		$	6,597		$	8,358		$	6,391
Minus cash and cash equivalents	761			264			1,680			2,398
Total debt minus cash and cash equivalents	$	5,662		$	6,333
Minus short-term investments							700			—
Total debt minus cash, cash equivalents and short-term investments							$	5,978		$	3,993
Total debt	$	6,423		$	6,597		$	8,358		$	6,391
Plus equity	20,226			19,344			19,335			21,020
Minus cash and cash equivalents	761			264			1,680			2,398
Total debt plus equity minus cash and cash equivalents	$	25,888		$	25,677
Cash-adjusted debt-to-capital ratio	22		%	25		%
Minus short-term investments							700			—
Total debt plus equity minus cash, cash equivalents and short-term investments							$	25,313		$	25,013
Cash and short-term investments-adjusted debt-to-capital ratio							24		%	16		%

Capital Requirements

We expect our revised total capital, investment and exploration spending budget for full-year 2015 to be $3.1 billion which is $200 million less than our previous budget.

On October ~~29, 2014,~~28, 2015, our Board of Directors approved a dividend of ~~21 cents~~$0.05 per share for the third quarter of ~~2014~~2015 payable December 10, ~~2014~~2015 to stockholders of record at the close of business on November ~~19, 2014.~~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 September 30, ~~2014~~,2015, we plan to make contributions of up to ~~$24~~$18 million to our funded pension plans during the remainder of ~~2014.~~

~~In 2013, our Board of Directors increased the authorization for repurchases of our common stock by $1.2 billion, bringing the total authorized to $6.2 billion. As of~~ ~~September 30, 2014, we had repurchased a total of 121 million common shares at a cost~~2015.

3537

~~of $4.7 billion, including 29 million shares at a cost of $1 billion in the first six months of 2014. The remaining share repurchase authorization as of~~ ~~September 30, 2014~~ is $1.5 billion. Purchases under the repurchase program may be in either open market transactions, including block purchases, or in privately negotiated transactions. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. The program’s authorization does not include specific price targets or timetables. The timing of purchases under the program will be influenced by cash generated from operations, proceeds from potential asset sales, cash from available borrowings and market conditions.

Contractual Cash Obligations

As of September 30, ~~2014,~~2015, there are no material changes to our ~~total contractual~~consolidated cash obligations ~~were consistent with December 31, 2013.~~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 18.

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, ~~2013~~.2014.

Other Contingencies

Forward-Looking Statements

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ~~as amended,~~ and Section 21E of the Securities Exchange Act of 1934 ~~as amended~~ (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 ~~regarding~~regarding: our operational, financial and growth strategies, including planned ~~capital expenditures~~projects, drilling plans, maintenance activities, asset sales, productivity improvements, and drilling and completion efficiencies; our ability to effect those strategies and the ~~impact thereof, growth activities and expectations, future drilling plans,~~expected timing and results thereof; our financial and operational outlook and ability to fulfill that outlook; expectations ~~maintenance activities~~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 ~~timing~~expected benefits thereof; our declared dividend and ~~impact thereof, well spud timing and expectations, operational outlook, future~~the expected benefits thereof; our financial position, liquidity and capital ~~resources, the planned use of proceeds from the sale of our Norway business,~~resources; production guidance; and the plans and objectives of our management for our future ~~operations, are forward-looking statements.~~operations. In addition, many forward-looking statements may be identified by the use of forward-looking terminology such as ~~“anticipates,~~“anticipate,” ~~“believes,~~“believe,” ~~“estimates,~~“estimate,” ~~“expects,~~“expect,” ~~“targets,~~“target,” ~~“plans,~~“plan,” ~~“projects,~~“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, ~~we can give no assurance that these expectations will prove to be correct. A~~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 ~~the level of supply or~~ supply/demand ~~for liquid hydrocarbons and natural gas~~levels and the resulting impact on ~~the price of liquid hydrocarbons and natural gas;~~price;

changes in expected reserve or production levels;

changes in political or economic conditions in key operating markets, including international markets;

~~the amount of~~ capital available for exploration and development;

~~timing of commencing~~well production ~~from new wells;~~

~~drilling rig availability;~~timing;

availability of drilling rigs, materials and labor;

~~the inability to obtain or delay~~difficulty in obtaining necessary ~~government or third-party~~ approvals and permits;

non-performance by third parties of ~~their~~ 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

~~other~~the risk factors, ~~discussed~~forward-looking statements and challenges and uncertainties described in Item 1. Business, Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and elsewhere in our 2014 Annual Report on Form 10-K, ~~for the year ended December 31, 2013,~~Quarterly Reports on Form 10-Q and ~~those set forth from time to time in our~~other 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 ~~whether~~ as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.

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 ~~2013~~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 1315 and 1416 to the consolidated financial statements.

Commodity Price Risk During the first nine 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 September 30, 2015:



Financial Instrument	Weighted Average Price	Barrels per day	Remaining Term
Three-Way Collars
Ceiling	$70.34	35,000	October- December 2015
Floor	$55.57
Sold put	$41.29

Ceiling	$60.00	2,000	October 2015- March 2016 ^(a)
Floor	$50.00
Sold put	$40.00

Ceiling	$71.84	12,000	January- December 2016
Floor	$60.48
Sold put	$50.00

Ceiling	$73.13	2,000	January- June 2016 ^(b)
Floor	$65.00
Sold put	$50.00
Call Options	$72.39	10,000	January- December 2016 ^(c)



^(a)							Counterparties have the option, exercisable on March 31, 2016, to extend these collars through September of 2016 at the same volume and weighted average price as the 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 September 30, 2015.

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 September 30, ~~2014~~.2015, is provided in the following table.

Incremental
Change in
(In millions) Fair Value Fair Value
Financial assets (liabilities): ^(a)

Interest rate swap agreements $ 5
^(b)
$ 5
Long-term debt, including amounts due within one year $ (7,057 )
^(b)(c)
$ (214 )



(In millions)	Fair Value				Incremental Change in Fair Value
Financial assets (liabilities):
Long term debt, including amounts due within one year	$	(8,302	)	^(a)(b)	$	(295	)


^(a)	Fair values of cash and cash equivalents, receivables, commercial paper, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.


^(b)	Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.


^(c)(b)	Excludes capital leases.

~~The incremental change in fair value of our foreign currency derivative contracts of a hypothetical 10 percent change in exchange rates at~~ ~~September 30, 2014~~ ~~would be $35 million.~~

Item 4. Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in ~~Exchange Act~~ 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. ~~Based~~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 ~~our company's~~the design and operation of these disclosure controls and procedures were effective as of September 30, ~~2014~~. 2015.

During the third quarter of ~~2014,~~2015, there were no changes in our internal control over financial reporting (as defined in ~~Exchange Act~~ 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.

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

Three Months Ended Nine Months Ended
September 30, September 30,
(In millions) 2014 2013 2014 2013
Segment Income
North America E&P $ 292
$ 242
$ 836
$ 404
International E&P 106
192
487
635
Oil Sands Mining 93
106
212
164
Segment income 491
540
1,535
1,203
Items not allocated to segments, net of income taxes (187 ) (144 ) (473 ) (408 )
Income from continuing operations 304
396
1,062
795
Discontinued operations ^(a)
127
173
1,058
583
Net income $ 431
$ 569
$ 2,120
$ 1,378
Capital Expenditures ^(b)

North America E&P $ 1,277
$ 832
$ 3,246
$ 2,706
International E&P 166
120
386
314
Oil Sands Mining 49
66
172
209
Corporate 16
7
29
47
Discontinued operations ^(a)
125
137
376
413
Total $ 1,633
$ 1,162
$ 4,209
$ 3,689
Exploration Expenses

North America E&P $ 55
$ 48
$ 194
$ 559
International E&P 41
35
120
106
Total $ 96
$ 83
$ 314
$ 665


^(a)	~~We sold our Angola assets in the first quarter of 2014 and our Norway business on October 15, 2014. The Angola and Norway businesses are reflected as discontinued operations in all periods presented.~~


^(b)	~~Capital expenditures include changes in accruals.~~

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

Three Months Ended Nine Months Ended
September 30, September 30,
Net Sales Volumes 2014 2013 2014 2013
North America E&P
Crude Oil and Condensate (mbbld)

Bakken 50 34 44 34
Eagle Ford 75 52 68 49
Oklahoma Resource Basins 3 2 2 1
Other North America ^(c)
38 38 37 41
Total Crude Oil and Condensate 166 126 151 125
Natural Gas Liquids (mbbld)

Bakken 3 2 3 2
Eagle Ford 20 14 18 14
Oklahoma Resource Basins 5 5 5 4
Other North America ^(c)
3 3 2 2
Total Natural Gas Liquids 31 24 28 22
Total Liquid Hydrocarbons (mbbld)

Bakken 53 36 47 36
Eagle Ford 95 66 86 63
Oklahoma Resource Basins 8 7 7 5
Other North America ^(c)
41 41 39 43
Total Liquid Hydrocarbons 197 150 179 147
Natural Gas (mmcfd)

Bakken 18 12 17 12
Eagle Ford 130 93 116 92
Oklahoma Resource Basins 63 47 59 49
Other North America ^(c)
106 145 111 165
Total Natural Gas 317 297 303 318
Total North America E&P (mboed)
250 200 230 200


^(c)	~~Includes Gulf of Mexico and other conventional onshore U.S. production, plus Alaska in 2013.~~

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

Three Months Ended Nine Months Ended
September 30, September 30,
Net Sales Volumes 2014 2013 2014 2013
International E&P
Total Liquid Hydrocarbons (mbbld)

Equatorial Guinea 27
32 31
32
United Kingdom 6
20 11
18
Libya 6
16 2
32
Total Liquid Hydrocarbons 39
68 44
82
Natural Gas (mmcfd)

Equatorial Guinea 420
463 434
437
United Kingdom^(d)
19
26 26
34
Libya —
30 1
27
Total Natural Gas 439
519 461
498
Total International E&P (mboed)
112
154 121
165
Oil Sands Mining
Synthetic Crude Oil (mbbld)^(e)
55
49 49
47
Total Continuing Operations (mboed)
417
403 400
412
Discontinued Operations - Angola (mboed)^(a)
—
9 2
9
Discontinued Operations - Norway (mboed)^(a)
58
68 66
81
Total Company (mboed)
475
480 468
502
Net Sales Volumes of Equity Method Investees
LNG (mtd)
6,265
7,302 6,488
6,638
Methanol (mtd)
1,103
1,364 1,078
1,249


^(d)	~~Includes natural gas acquired for injection and subsequent resale of 3 mmcfd and 4 mmcfd for the third quarters of 2014 and 2013, and 5 mmcfd and 8 mmcfd for the first nine months of 2014 and 2013.~~


^(e)	~~Includes blendstocks.~~

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

Three Months Ended Nine Months Ended
September 30, September 30,
Average Price Realizations 2014 2013 2014 2013
North America E&P
Crude Oil and Condensate (per bbl)

Bakken $85.28 $97.76 $89.07 $92.58
Eagle Ford 93.51 104.08 96.12 102.41
Oklahoma Resource Basins 93.78 101.82 96.23 94.80
Other North America ^(c)
87.50 99.93 90.06 92.75
Total Crude Oil and Condensate 89.65 101.05 92.59 96.54
Natural Gas Liquids (per bbl)

Bakken $40.60 $44.08 $46.92 $40.24
Eagle Ford 30.90 30.11 32.64 28.84
Oklahoma Resource Basins 33.64 35.11 36.74 34.91
Other North America ^(c)
51.49 55.81 55.77 54.39
Total Natural Gas Liquids 33.93 35.01 36.96 34.06
Total Liquid Hydrocarbons (per bbl) ^(f)

Bakken $82.67 $95.24 $86.66 $89.96
Eagle Ford 79.99 87.96 82.99 86.61
Oklahoma Resource Basins 56.57 51.34 55.58 50.49
Other North America ^(c)
85.28 97.12 87.71 90.30
Total Liquid Hydrocarbons 80.89 90.49 83.89 87.09
Natural Gas (per mcf)

Bakken $4.29 $3.73 $5.49 $3.93
Eagle Ford 4.21 3.53 4.59 3.71
Oklahoma Resource Basins 3.97 3.10 4.64 3.79
Other North America^(c)
4.34 3.62 5.03 3.96
Total Natural Gas 4.21 3.51 4.81 3.86


^(f)	Excludes gains or losses on derivative instruments. Inclusion of realized losses on crude oil derivative instruments would have decreased average liquid hydrocarbon price realizations by $1.81 and $0.30 per bbl for the third quarter and first nine months of 2013. There were no crude oil derivative instruments for the third quarter and first nine months of 2014.

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

Three Months Ended Nine Months Ended
September 30, September 30,
Average Price Realizations 2014 2013 2014 2013
International E&P
Total Liquid Hydrocarbons (per bbl)

Equatorial Guinea $51.83 $57.35 $58.37 $59.54
United Kingdom 88.68 108.34 106.00 108.13
Libya 114.36 124.19 114.86 122.91
Total Liquid Hydrocarbons 66.80 88.47 72.88 94.41
Natural Gas (per mcf)

Equatorial Guinea^(g)
$0.24 $0.24 $0.24 $0.24
United Kingdom 7.60 10.67 8.72 10.78
Libya —
5.92 5.45 5.26
Total Natural Gas 0.56 1.10 0.73 1.24
Oil Sands Mining
Synthetic Crude Oil (per bbl)
$88.22 $102.64 $90.11 $90.65
Discontinued Operations - Angola (per boe)^(a)
—
$107.01 $99.82 $104.49
Discontinued Operations - Norway (per boe)^(a)
$98.62 $110.97 $105.29 $109.37


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

Part II – OTHER INFORMATION

Item 1. Legal Proceedings

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 ~~2013~~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 September 30, ~~2014,~~2015, of ~~our~~ equity securities that are registered by Marathon Oil pursuant to Section 12 of the Exchange ~~Act.~~Act of 1934.

Column (a) Column (b) Column (c) Column (d)
Total Number of Average Price
Total Number of
Shares Purchased
as Part of
Publicly Announced

Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Period
Shares Purchased ^(a)(b)
Paid per Share
Plans or Programs^(c)

Plans or Programs^(c)
07/01/14 - 07/31/14 8,314
$40.04 —
$1,500,285,529
08/01/14 - 08/31/14 4,910
$39.00 —
$1,500,285,529
09/01/14 - 09/30/14 188,262
$41.02 —
$1,500,285,529
Total 201,486
$40.93 —



	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 - 07/31/15	3,333	25.58	—	$1,500,285,529
08/01/15 - 08/31/15	46,543	18.50	—	$1,500,285,529
09/01/15 - 09/30/15	5,444	15.01	—	$1,500,285,529
Total	55,320	18.59	—


^(a)	~~176,463~~55,320 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

^(b)

In September 2014, 25,023 shares were repurchased in open-market transactions to satisfy the requirements for dividend reinvestment under the Marathon Oil Corporation Dividend Reinvestment and Direct Stock Purchase Plan (the “Dividend Reinvestment Plan”) by the administrator of the Dividend Reinvestment Plan. Shares needed to meet the requirements of the Dividend Reinvestment Plan are either purchased in the open market or issued directly by Marathon Oil.


^(c)	~~As of~~ ~~September 30, 2014, we had repurchased 121 million common shares at a cost of $4.7 billion, which includes transaction fees and commissions that are not reported in the table above.~~

Item ~~4. Mine Safety Disclosures~~5. Other Information

~~Not applicable.~~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.

4341

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



November ~~4, 2014~~5, 2015		MARATHON OIL CORPORATION

	By:	/s/ ~~John R. Sult~~Gary E. Wilson
		~~John R. Sult~~Gary E. Wilson
		~~Executive~~ Vice President, Controller and Chief ~~Financial~~Accounting Officer
		(Duly Authorized Officer)

4442

Exhibit Index

Incorporated by Reference
Exhibit Number Exhibit Description Form Exhibit Filing Date SEC File No. Filed Herewith
2.1++ Separation and Distribution Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Oil Company and Marathon Petroleum Corporation 8-K 2.1 5/26/2011 001-05153
3.1 Restated Certificate of Incorporation of Marathon Oil Corporation 10-Q 3.1 8/8/2013 001-05153
3.2 Amended By-Laws of Marathon Oil Corporation effective February 25, 2014 10-K 3.2 2/28/2014 001-05153
3.3 Specimen of Common Stock Certificate 10-K 3.3 2/28/2014 001-05153
4.2 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 percent of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon its request. 10-K 4.2 2/28/2014 001-05153
10.1 Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Non-Qualified Stock Option Award Agreement. 8-K 10.1 08/01/14 001-05153
12.1 Computation of Ratio of Earnings to Fixed Charges. X
31.1 Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934. X
31.2 Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934. X
32.1 Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350. X
32.2 Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350. X
101.INS XBRL Instance Document. X
101.SCH XBRL Taxonomy Extension Schema. X
101.CAL XBRL Taxonomy Extension Calculation Linkbase. X
101.DEF XBRL Taxonomy Extension Definition Linkbase. X
101.LAB XBRL Taxonomy Extension Label Linkbase. X
101.PRE XBRL Taxonomy Extension Presentation Linkbase. X
++ 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 Description	Form	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 Corporation	8-K	2.1	5/26/2011
3.1	Restated Certificate of Incorporation of Marathon Oil Corporation	10-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 Certificate	10-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 request	10-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.



	~~INDEX~~Table of Contents
		Page
Part I - FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Consolidated Statements of Income (Unaudited)	2
	Consolidated Statements of Comprehensive Income (Unaudited)	3
	Consolidated Balance Sheets (Unaudited)	4
	Consolidated Statements of Cash Flows (Unaudited)	5
	Notes to Consolidated Financial Statements (Unaudited)	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	2022
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3739
Item 4.	Controls and Procedures	37
	~~Supplemental Statistics (Unaudited)~~	3840
Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	4341
Item 1A.	Risk Factors	4341
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4341
Item 4.5.	~~Mine Safety Disclosures~~Other Information	4341
Item 6.	Exhibits	4341
	Signatures	4442



	Nine Months Ended September 30, 2013
							Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	3,820	$	2,332	$	1,204	$	(61	)	^(c)	$	7,295
Marketing revenues	1,391		192		12		—				1,595
Total revenues	5,211		2,524		1,216		(61		)		8,890
Income from equity method investments	—		309		—		—				309
Net gain (loss) on disposal of assets and other income	15		30		5		(16		)		34
Less:
Production expenses	584		269		772		—				1,625
Marketing costs	1,390		188		12		—				1,590
Exploration expenses	559		106		—		—				665
Depreciation, depletion and amortization	1,458		284		154		18				1,914
Impairments	34		—		—		15			^(d)	49
Other expenses ^(a)	311		99		48		290			^(e)	748
Taxes other than income	244		—		16		4				264
Net interest and other	—		—		—		211				211
Income tax provision (benefit)	242		1,282		55		(207		)		1,372
Segment income/Income from continuing operations	$	404	$	635	$	164	$	(408	)		$	795
Capital expenditures ^(b)	$	2,706	$	314	$	209	$	47			$	3,276



(In millions)
Beginning balance^(a)	$	2,096
Incurred, including acquisitions	39
Settled, including dispositions	(110		)
Accretion expense (included in depreciation, depletion and amortization)	87
Revisions to previous estimates^(b)	231
Held for sale	(309		)
Ending balance^(a)	$	2,034



					Incremental
					Change in
(In millions)	Fair Value				Fair Value
Financial assets (liabilities): ^(a)
Interest rate swap agreements	$	5		^(b)	$	5
Long-term debt, including amounts due within one year	$	(7,057	)	^(b)(c)	$	(214	)



	Column (a)	Column (b)	Column (c)	Column (d)
	Total Number of	Average Price	Total Number of Shares Purchased as Part of Publicly Announced	Approximate Dollar Value of Shares that May Yet Be Purchased Under the
Period	Shares Purchased ^(a)(b)	Paid per Share	Plans or Programs^(c)	Plans or Programs^(c)
07/01/14 - 07/31/14	8,314	$40.04	—	$1,500,285,529
08/01/14 - 08/31/14	4,910	$39.00	—	$1,500,285,529
09/01/14 - 09/30/14	188,262	$41.02	—	$1,500,285,529
Total	201,486	$40.93	—



		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.	Filed Herewith
2.1++	Separation and Distribution Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Oil Company and Marathon Petroleum Corporation	8-K	2.1	5/26/2011	001-05153
3.1	Restated Certificate of Incorporation of Marathon Oil Corporation	10-Q	3.1	8/8/2013	001-05153
3.2	Amended By-Laws of Marathon Oil Corporation effective February 25, 2014	10-K	3.2	2/28/2014	001-05153
3.3	Specimen of Common Stock Certificate	10-K	3.3	2/28/2014	001-05153
4.2	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 percent of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon its request.	10-K	4.2	2/28/2014	001-05153
10.1	Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Non-Qualified Stock Option Award Agreement.	8-K	10.1	08/01/14	001-05153
12.1	Computation of Ratio of Earnings to Fixed Charges.					X
31.1	Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.					X
31.2	Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.					X
32.1	Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.					X
32.2	Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.					X
101.INS	XBRL Instance Document.					X
101.SCH	XBRL Taxonomy Extension Schema.					X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase.					X
101.DEF	XBRL Taxonomy Extension Definition Linkbase.					X
101.LAB	XBRL Taxonomy Extension Label Linkbase.					X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase.					X
++	Marathon Oil agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request.

(In millions)

Hypothetical Price Increase of 10%

Hypothetical Price Decrease of 10%

Crude oil commodity derivatives