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 ~~June~~September 30, 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 ~~677,184,913~~677,260,116 shares of Marathon Oil Corporation common stock outstanding as of ~~July~~October 31, 2015.

MARATHON OIL CORPORATION

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

For certain industry specific terms used in this Form 10-Q, please see "Definitions" in our 2014 Annual Report on Form 10-K.

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)


	Three Months Ended						Six Months Ended						Three Months Ended						Nine Months Ended
	June 30,						June 30,						September 30,						September 30,
(In millions, except per share data)	2015			2014			2015			2014			2015			2014			2015			2014
Revenues and other income:
Sales and other operating revenues, including related party	$	1,307		$	2,270		$	2,587		$	4,419		$	1,300		$	2,316		$	3,887		$	6,735
Marketing revenues	183			618			387			1,159			84			554			471			1,713
Income from equity method investments	26			120			62			257			36			89			98			346
Net gain (loss) on disposal of assets	—			(87		)	1			(85		)
Net loss on disposal of assets													(109		)	(3		)	(108		)	(88		)
Other income	15			20			26			40			12			15			38			55
Total revenues and other income	1,531			2,941			3,063			5,790			1,323			2,971			4,386			8,761
Costs and expenses:
Production	450			562			894			1,104			406			593			1,300			1,697
Marketing, including purchases from related parties	182			614			387			1,156			84			554			471			1,710
Other operating	81			101			188			204			93			99			281			303
Exploration	111			145			201			218			585			96			786			314
Depreciation, depletion and amortization	751			680			1,572			1,323			717			737			2,289			2,060
Impairments	44			4			44			21			337			109			381			130
Taxes other than income	78			109			145			204			46			115			191			319
General and administrative	168			139			339			326			125			160			464			486
Total costs and expenses	1,865			2,354			3,770			4,556			2,393			2,463			6,163			7,019
Income (loss) from operations	(334		)	587			(707		)	1,234			(1,070		)	508			(1,777		)	1,742
Net interest and other	(58		)	(76		)	(105		)	(125		)	(75		)	(55		)	(180		)	(180		)
Income (loss) from continuing operations before income taxes	(392		)	511			(812		)	1,109			(1,145		)	453			(1,957		)	1,562
Provision (benefit) for income taxes	(6		)	151			(150		)	351			(396		)	149			(546		)	500
Income (loss) from continuing operations	(386		)	360			(662		)	758			(749		)	304			(1,411		)	1,062
Discontinued operations	—			180			—			931			—			127			—			1,058
Net income (loss)	$	(386	)	$	540		$	(662	)	$	1,689		$	(749	)	$	431		$	(1,411	)	$	2,120
Per basic share:
Income (loss) from continuing operations	$	(0.57	)	$	0.53		$	(0.98	)	$	1.11		$	(1.11	)	$	0.45		$	(2.09	)	$	1.56
Discontinued operations	$	—		$	0.27		$	—		$	1.36		$	—		$	0.19		$	—		$	1.55
Net income (loss)	$	(0.57	)	$	0.80		$	(0.98	)	$	2.47		$	(1.11	)	$	0.64		$	(2.09	)	$	3.11
Per diluted share:
Income (loss) from continuing operations	$	(0.57	)	$	0.53		$	(0.98	)	$	1.10		$	(1.11	)	$	0.45		$	(2.09	)	$	1.55
Discontinued operations	$	—		$	0.27		$	—		$	1.36		$	—		$	0.19		$	—		$	1.55
Net income (loss)	$	(0.57	)	$	0.80		$	(0.98	)	$	2.46		$	(1.11	)	$	0.64		$	(2.09	)	$	3.10
Dividends per share	$	0.21		$	0.19		$	0.42		$	0.38		$	0.21		$	0.21		$	0.63		$	0.59
Weighted average common shares outstanding:
Basic	677			676			676			684			677			675			677			681
Diluted	677			679			676			688			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						Six Months Ended						Three Months Ended						Nine Months Ended
	June 30,						June 30,						September 30,						September 30,
(In millions)	2015			2014			2015			2014			2015			2014			2015			2014
Net income (loss)	$	(386	)	$	540		$	(662	)	$	1,689		$	(749	)	$	431		$	(1,411	)	$	2,120
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	86			(13		)	162			(43		)	(2		)	3			160			(40		)
Income tax benefit (provision)	(30		)	5			(57		)	15			(1		)	(2		)	(58		)	13
Postretirement and postemployment plans, net of tax	56			(8		)	105			(28		)	(3		)	1			102			(27		)
Comprehensive income (loss)	$	(330	)	$	532		$	(557	)	$	1,661		$	(752	)	$	432		$	(1,309	)	$	2,093

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)


	June 30,			December 31,			September 30,			December 31,
(In millions, except per share data)	2015			2014			2015			2014
Assets
Current assets:
Cash and cash equivalents	$	1,572		$	2,398		$	1,680		$	2,398
Short-term investments	925			—			700			—
Receivables, less reserve of $4 and $3	1,195			1,729			991			1,729
Inventories	336			357			324			357
Other current assets	102			109			163			109
Total current assets	4,130			4,593			3,858			4,593
Equity method investments	1,045			1,113			1,012			1,113
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $23,395 and $21,884	29,121			29,040
depletion and amortization of $23,713 and $21,884							27,920			29,040
Goodwill	459			459			457			459
Other noncurrent assets	1,015			806			1,427			806
Total assets	$	35,770		$	36,011		$	34,674		$	36,011
Liabilities
Current liabilities:
Accounts payable	$	1,507		$	2,545		$	1,246		$	2,545
Payroll and benefits payable	119			191			138			191
Accrued taxes	156			285			143			285
Other current liabilities	235			290			286			290
Long-term debt due within one year	1,035			1,068			1,035			1,068
Total current liabilities	3,052			4,379			2,848			4,379
Long-term debt	7,321			5,323			7,323			5,323
Deferred tax liabilities	2,531			2,486			2,542			2,486
Defined benefit postretirement plan obligations	438			598			436			598
Asset retirement obligations	1,963			1,917			1,965			1,917
Deferred credits and other liabilities	247			288			225			288
Total liabilities	15,552			14,991			15,339			14,991
Commitments and contingencies
Stockholders’ Equity
Preferred stock – no shares issued or outstanding (no par value,
26 million shares authorized)	—			—			—			—
Common stock:
Issued – 770 million shares (par value $1 per share,
1.1 billion shares authorized)	770			770			770			770
Securities exchangeable into common stock – no shares issued or
outstanding (no par value, 29 million shares authorized)	—			—			—			—
Held in treasury, at cost – 93 million and 95 million shares	(3,555		)	(3,642		)	(3,553		)	(3,642		)
Additional paid-in capital	6,484			6,531			6,493			6,531
Retained earnings	16,691			17,638			15,800			17,638
Accumulated other comprehensive loss	(172		)	(277		)	(175		)	(277		)
Total stockholders' equity	20,218			21,020			19,335			21,020
Total liabilities and stockholders' equity	$	35,770		$	36,011		$	34,674		$	36,011

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)


	Six Months Ended						Nine Months Ended
	June 30,						September 30,
(In millions)	2015			2014			2015			2014
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income (loss)	$	(662	)	$	1,689		$	(1,411	)	$	2,120
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations	—			(931		)	—			(1,058		)
Deferred income taxes	(185		)	173			(590		)	337
Depreciation, depletion and amortization	1,572			1,323			2,289			2,060
Impairments	44			21			381			130
Pension and other postretirement benefits, net	14			26			9			(27		)
Exploratory dry well costs and unproved property impairments	148			156			708			220
Net (gain) loss on disposal of assets	(1		)	85
Net loss on disposal of assets							108			88
Equity method investments, net	37			(10		)	41			51
Changes in:
Current receivables	534			(266		)	738			(270		)
Inventories	21			(58		)	30			(32		)
Current accounts payable and accrued liabilities	(770		)	(31		)	(954		)	(115		)
All other operating, net	(35		)	(59		)	(136		)	(28		)
Net cash provided by continuing operations	717			2,118			1,213			3,476
Net cash provided by discontinued operations	—			440			—			856
Net cash provided by operating activities	717			2,558			1,213			4,332
Investing activities:
Acquisitions, net of cash acquired							—			(12		)
Additions to property, plant and equipment	(2,320		)	(2,230		)	(2,948		)	(3,639		)
Disposal of assets	2			2,232			105			2,237
Investments - return of capital	31			27			61			46
Purchases of short-term investments	(925		)	—			(925		)	—
Maturities of short-term investments							225			—
Investing activities of discontinued operations	—			(233		)	—			(356		)
All other investing, net	(1		)	—			22			(24		)
Net cash used in investing activities	(3,213		)	(204		)	(3,460		)	(1,748		)
Financing activities:
Commercial paper, net	—			(135		)	—			(135		)
Borrowings	1,996			—			1,996			—
Debt issuance costs	(19		)	—			(19		)	—
Debt repayments	(34		)	(34		)	(34		)	(34		)
Purchases of common stock	—			(1,000		)	—			(1,000		)
Dividends paid	(285		)	(260		)	(427		)	(401		)
All other financing, net	11			86			14			150
Net cash provided by (used in) financing activities	1,669			(1,343		)	1,530			(1,420		)
Effect of exchange rate on cash and cash equivalents:
Continuing operations	1			—			(1		)	(1		)
Discontinued operations	—			(10		)	—			(11		)
Cash held for sale	—			(96		)	—			(655		)
Net increase (decrease) in cash and cash equivalents	(826		)	905			(718		)	497
Cash and cash equivalents at beginning of period	2,398			264			2,398			264
Cash and cash equivalents at end of period	$	1,572		$	1,169		$	1,680		$	761

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

1. Basis of Presentation

These consolidated financial statements are unaudited; however, in the opinion of management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported. All such adjustments are of a normal recurring nature unless disclosed otherwise. These consolidated financial statements, including notes, have been prepared in accordance with the applicable rules of the ~~Securities and Exchange Commission ("SEC")~~SEC and do not include all of the information and disclosures required by ~~accounting principles generally accepted in the United States ("~~U.S. ~~GAAP")~~GAAP for complete financial statements.

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

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in ~~the Marathon Oil Corporation~~our 2014 Annual Report on Form 10-K. The results of operations for the ~~second~~third quarter and first ~~six~~nine months of 2015 are not necessarily indicative of the results to be expected for the full year.

2. Accounting Standards

Not Yet Adopted

In May 2015, the FASB issued an update that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The amendment also removes certain disclosure requirements regarding all investments that are eligible to be measured using the net asset value per share practical expedient and only requires certain disclosures on those investments for which an entity elects to use the net asset value per share expedient. This standard is effective for us in the first quarter of 2016 and will be applied on a retrospective basis. Early adoption is permitted. This standard only modifies disclosure requirements; as such, there will be no impact on our consolidated results of operations, financial position or cash flows.

In April 2015, the FASB issued an update that requires debt issuance costs to be presented in the balance sheet as a direct reduction from the associated debt liability. This standard is effective for us in the first quarter of 2016 and will be applied on a retrospective basis. Early adoption is ~~permitted, including in interim periods.~~permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

In February 2015, the FASB issued an amendment to the guidance for determining whether an entity is a variable interest entity ("VIE"). The standard does not add or remove any of the five characteristics that determine if an entity is a VIE. However, it does change the manner inby which a reporting entity assesses ~~one of the characteristics. In particular, when decision-making over the entity’s most significant activities has been outsourced, the standard changes how a reporting entity assesses if~~whether the equity holders at risk lack decision making ~~rights.~~rights if the decision-making over the subject entity’s most significant activities was outsourced. This standard is effective for us in the first quarter of 2016 and early adoption is ~~permitted, including in interim periods.~~permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

In August 2014, the FASB issued an update that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in United States ~~("U.S.")~~ auditing standards. This standard is effective for us in the first quarter of 2017 and early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

In May 2014, the FASB issued an update that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance, requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively, and improves guidance for multiple-element arrangements. This standard is effective for us in the first quarter of 2018 and should be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. Early adoption is permitted with an effective date no earlier than first quarter of 2017. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Recently Adopted

In April 2014, the FASB issued an amendment to accounting standards that changes the criteria for reporting discontinued operations while enhancing related disclosures. Under the amendment, only disposals representing a strategic shift in operations should be presented as discontinued operations. Expanded disclosures about the assets, liabilities, income and expenses of discontinued operations are required. In addition, disclosure of the pretax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting will be made in order to provide users with information about the ongoing trends in an organization’s results from continuing operations. The amendments were effective for us in the first quarter of 2015 and apply to dispositions or classifications as held for sale thereafter. Adoption of this standard did not impact our consolidated results of operations, financial position or cash flows.

3. Variable Interest Entity

The owners of the Athabasca Oil Sands Project, ~~("AOSP"),~~ in which we hold a 20% undivided interest, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton, Alberta, Canada. Costs under this contract are accrued and recorded on a monthly basis, with current liabilities of $2 million recorded at ~~June~~September 30, 2015 and $3 million at December 31, 2014. This contract qualifies as a variable interest contractual arrangement, and the Corridor Pipeline qualifies as a VIE. We hold a variable interest but are not the primary beneficiary because our shipments are only 20% of the total; therefore, the Corridor Pipeline is not consolidated by us. Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was ~~$508~~$471 million as of ~~June~~September 30, 2015. The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term.


4.	Income (Loss) per Common Share

Basic income (loss) per share is based on the weighted average number of common shares outstanding. Diluted income ~~(loss)~~ per share assumes exercise of stock options, provided the effect is not antidilutive. The per share calculations below exclude 13 million and 52 million stock options for the ~~second~~third quarters of 2015 and 2014 and 13 million and 4 million stock options for the first ~~six~~nine months of 2015 and 2014 that were antidilutive.


	Three Months Ended June 30,					Six Months Ended June 30,					Three Months Ended September 30,					Nine Months Ended September 30,
(In millions, except per share data)	2015			2014		2015			2014		2015			2014		2015			2014
Income (loss) from continuing operations	$	(386	)	$	360	$	(662	)	$	758	$	(749	)	$	304	$	(1,411	)	$	1,062
Discontinued operations	—			180		—			931		—			127		—			1,058
Net income (loss)	$	(386	)	$	540	$	(662	)	$	1,689	$	(749	)	$	431	$	(1,411	)	$	2,120

Weighted average common shares outstanding	677			676		676			684		677			675		677			681
Effect of dilutive securities	—			3		—			4		—			3		—			3
Weighted average common shares, diluted	677			679		676			688		677			678		677			684
Per basic share:
Income (loss) from continuing operations	$	(0.57	)	$	0.53	$	(0.98	)	$	1.11	$	(1.11	)	$	0.45	$	(2.09	)	$	1.56
Discontinued operations	$	—		$	0.27	$	—		$	1.36	$	—		$	0.19	$	—		$	1.55
Net income (loss)	$	(0.57	)	$	0.80	$	(0.98	)	$	2.47	$	(1.11	)	$	0.64	$	(2.09	)	$	3.11
Per diluted share:
Income (loss) from continuing operations	$	(0.57	)	$	0.53	$	(0.98	)	$	1.10	$	(1.11	)	$	0.45	$	(2.09	)	$	1.55
Discontinued operations	$	—		$	0.27	$	—		$	1.36	$	—		$	0.19	$	—		$	1.55
Net income (loss)	$	(0.57	)	$	0.80	$	(0.98	)	$	2.46	$	(1.11	)	$	0.64	$	(2.09	)	$	3.10

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


5.	Acquisitions

2014 - North America E&P Segment

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


6.	Dispositions

2015 - North America E&P Segment

In ~~July~~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 ~~Texas/North Louisiana~~Africa exploration acreage in Ethiopia and ~~Wilburton, Oklahoma natural gas assets for~~Kenya. A pretax loss of $109 million was recorded in the third quarter of 2015. This transaction is expected ~~proceeds of $102 million, excluding closing adjustments. We expect the transaction~~ to close during the ~~third~~fourth quarter of 2015.

2014 - North America E&P Segment

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

2014 - International E&P Segment

In the second quarter of 2014, we entered into an agreement to sell our Norway business, including the operated Alvheim floating production, storage and offloading vessel, 10 operated licenses and a number of non-operated licenses on the Norwegian Continental Shelf in the North Sea. The transaction closed during the fourth quarter of 2014.

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


	Three Months Ended June 30,			Six Months Ended June 30,			Three Months Ended September 30,			Nine Months Ended September 30,
(In millions)		2014			2014			2014			2014
Revenues applicable to discontinued operations		$	693		$	1,373		$	528		$	1,901
Pretax income from discontinued operations		$	598		$	1,130		$	487		$	1,617
After-tax income from discontinued operations ^(a)		$	180		$	322		$	127		$	449	^(a)

^(a)Includes a tax benefit of $26 million related to a decrease in the valuation allowance on U.S. foreign tax credits from the Norway operations.

In the first quarter of 2014, we closed the sales of our non-operated 10% working interests in the Production Sharing Contracts and Joint Operating Agreements for Angola Blocks 31 and 32 for aggregate proceeds of approximately $2 billion and recorded a $576 million after-tax gain on sale. Included in the after-tax gain is a deferred tax benefit reflecting our ability to utilize foreign tax credits that otherwise would have needed a valuation allowance.

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


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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

7. Segment Information

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

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

~~International~~Int'l E&P ~~("Int'l E&P")~~ – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North America and produces and markets products manufactured from natural gas, such as ~~liquefied natural gas ("LNG")~~LNG and methanol, in ~~Equatorial Guinea ("~~E.G."); and

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

~~MARATHON OIL CORPORATION~~

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

Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”). Segment income represents income from continuing operations excluding certain items not allocated to segments, net of income taxes attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. These costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Gains or losses on dispositions, certain impairments, change in tax expense associated with a tax rate change, unrealized gains or losses on crude oil derivative instruments, or other items that affect comparability also are not allocated to operating segments.

As discussed in Note 5,6, as a result of the sale of our Angola assets and our Norway business in 2014, both are reflected as discontinued operations and excluded from the ~~International~~Int'l E&P segment for 2014.


	Three Months Ended June 30, 2015															Three 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	$	993		$	211	$	147		$	(44	)	^(c)	$	1,307		$	796		$	182	$	242		$	80		^(c)	$	1,300
Marketing revenues	110			30		43			—				183			57			25		2			—				84
Total revenues	1,103			241		190			(44		)		1,490			853			207		244			80				1,384
Income from equity method investments	—			26		—			—				26
Net gain on disposal of assets and other income	11			4		—			—				15
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			64		207			—				450			179			61		166			—				406
Marketing costs	112			29		41			—				182			56			25		3			—				84
Exploration expenses	91			20		—			—				111			22			10		—			553			^(f)	585
Depreciation, depletion and amortization	634			71		35			11				751			549			79		76			13				717
Impairments	—			—		—			44			^(d)	44			—			—		4			333			^(g)	337
Other expenses ^(a)	99			19		9			122			^(e)	249			106			25		8			79			^(h)	218
Taxes other than income	67			—		5			6				78			42			—		5			(1		)		46
Net interest and other	—			—		—			58				58			—			—		—			75				75
Income tax provision (benefit)	(23		)	27		(30		)	20			^(f)	(6		)	(34		)	32		(7		)	(387		)		(396		)
Segment income (loss) /Loss from continuing operations	$	(45	)	$	41	$	(77	)	$	(305	)		$	(386	)	$	(61	)	$	29	$	(11	)	$	(706	)		$	(749	)
Capital expenditures ^(b)	$	551		$	99	$	16		$	12			$	678		$	564		$	30	$	(11	)	$	12			$	595


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


^(b)	Includes accruals.


^(c)	Unrealized ~~loss~~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 impairment (See Note ~~12)~~14).


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



	Nine Months Ended September 30, 2015
									Not Allocated
(In millions)	N.A. E&P			Int'l E&P		OSM			to Segments				Total
Sales and other operating revenues	$	2,639		$	575	$	614		$	59		^(c)	$	3,887
Marketing revenues	345			81		45			—				471
Total revenues	2,984			656		659			59				4,358
Income (loss) from equity method investments	—			110		—			(12		)	^(d)	98
Net gain (loss) on disposal of assets and other income	17			20		1			(108		)	^(e)	(70		)
Less:
Production expenses	560			192		548			—				1,300
Marketing costs	348			79		44			—				471
Exploration expenses	148			85		—			553			^(f)	786
Depreciation, depletion and amortization	1,866			214		173			36				2,289
Impairments	—			—		4			377			^(g)	381
Other expenses ^(a)	322			67		26			330			^(h)	745
Taxes other than income	170			—		15			6				191
Net interest and other	—			—		—			180				180
Income tax provision (benefit)	(146		)	56		(43		)	(413		)	⁽ⁱ⁾	(546		)
Segment income (loss) /Loss from continuing operations	$	(267	)	$	93	$	(107	)	$	(1,130	)		$	(1,411	)
Capital expenditures ^(b)	$	2,048		$	275	$	26		$	26			$	2,375


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


^(b)	Includes accruals.


^(c)	Unrealized gain on crude oil derivative instruments.


^(d)	Partial impairment of investment in equity-method investee (See Note 15).


^(e)	Includes ~~pension settlement~~ loss on sale of ~~$64 million (see~~East Africa exploration acreage (See Note 7)6).


^(f)	Unproved property impairments associated with lower forecasted commodity prices and change in conventional exploration strategy (See Note 14).


^(g)	Proved property impairments (See Note 14).


^(h)	Includes pension settlement loss of $99 million and severance related expenses associated with workforce reductions of $47 million (See Note 8).


⁽ⁱ⁾	Includes $135 million of deferred tax expense related to Alberta provincial corporate tax rate increase ~~(see~~(See Note 8)9).

910

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


	Three Months Ended June 30, 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	$	1,540	$	347	$	383	$	—			$	2,270		$	4,518	$	1,000	$	1,217	$	—			$	6,735
Marketing revenues	540		61		17		—				618			1,486		177		50		—				1,713
Total revenues	2,080		408		400		—				2,888			6,004		1,177		1,267		—				8,448
Income from equity method investments	—		120		—		—				120			—		346		—		—				346
Net gain (loss) on disposal of assets and other income	15		15		1		(98		)	^(c)	(67		)	17		44		3		(97		)	^(c)	(33		)
Less:
Production expenses	217		99		246		—				562			661		307		729		—				1,697
Marketing costs	537		60		17		—				614			1,484		176		50		—				1,710
Exploration expenses	82		63		—		—				145			194		120		—		—				314
Depreciation, depletion and amortization	550		75		45		10				680			1,674		201		152		33				2,060
Impairments	4		—		—		—				4			21		—		—		109			^(d)	130
Other expenses ^(a)	126		34		13		67			^(d)	240			354		98		40		297			^(e)	789
Taxes other than income	102		—		6		1				109			301		—		16		2				319
Net interest and other	—		—		—		76				76			—		—		—		180				180
Income tax provision (benefit)	175		52		19		(95		)		151			496		178		71		(245		)		500
Segment income/Income from continuing operations	$	302	$	160	$	55	$	(157	)		$	360
Segment income /Income from continuing operations														$	836	$	487	$	212	$	(473	)		$	1,062
Capital expenditures ^(b)	$	1,102	$	115	$	55	$	10			$	1,282		$	3,246	$	386	$	172	$	29			$	3,833


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


^(b)	Includes accruals.


^(c)	Primarily related to the sale of non-core acreage ~~(see~~(See Note 5)6).


^(d)	~~Includes pension settlement loss of $8 million (see Note 7).~~

Six Months Ended June 30, 2015
Not Allocated
(In millions) N.A. E&P Int'l E&P OSM to Segments Total
Sales and other operating revenues $ 1,843
$ 393
$ 372
$ (21 )
^(c)
$ 2,587
Marketing revenues 288
56
43
—
387
Total revenues 2,131
449
415
(21 ) 2,974
Income from equity method investments —
62
—
—
62
Net gain on disposal of assets and other income 11
14
1
1
27
Less:
Production expenses 381
131
382
—
894
Marketing costs 292
54
41
—
387
Exploration expenses 126
75
—
—
201
Depreciation, depletion and amortization 1,317
135
97
23
1,572
Impairments —
—
—
44
^(d)
44
Other expenses ^(a)
216
42
18
251
^(e)
527
Taxes other than income 128
—
10
7
145
Net interest and other —
—
—
105
105
Income tax provision (benefit) (112 ) 24
(36 ) (26 )
^(f)
(150 )
Segment income (loss) /Loss from continuing operations $ (206 ) $ 64
$ (96 ) $ (424 ) $ (662 )
Capital expenditures ^(b)
$ 1,484
$ 245
$ 37
$ 14
$ 1,780


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


^(b)	~~Includes accruals.~~


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


^(d)	Proved property ~~impairment~~impairments (See Note ~~12)~~14).


^(e)	Includes ~~$43 million of severance related expenses associated with a workforce reduction and a~~ pension settlement loss of ~~$81~~$93 million ~~(see Note 7).~~


^(f)	~~Includes $135 million of deferred tax expense related to Alberta provincial corporate tax rate increase (see~~(See Note 8).

~~MARATHON OIL CORPORATION~~

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

Six Months Ended June 30, 2014
Not Allocated
(In millions) N.A. E&P Int'l E&P OSM to Segments Total
Sales and other operating revenues $ 2,932
$ 727
$ 760
$ —
$ 4,419
Marketing revenues 980
131
48
—
1,159
Total revenues 3,912
858
808
—
5,578
Income from equity method investments —
257
—
—
257
Net gain (loss) on disposal of assets and other income 18
32
3
(98 )
^(c)
(45 )
Less:
Production expenses 428
199
477
—
1,104
Marketing costs 977
131
48
—
1,156
Exploration expenses 139
79
—
—
218
Depreciation, depletion and amortization 1,065
146
90
22
1,323
Impairments 21
—
—
—
21
Other expenses ^(a)
236
72
26
196
^(d)
530
Taxes other than income 192
—
11
1
204
Net interest and other —
—
—
125
125
Income tax provision (benefit) 328
139
40
(156 ) 351
Segment income /Income from continuing operations $ 544
$ 381
$ 119
$ (286 ) $ 758
Capital expenditures ^(b)
$ 1,969
$ 220
$ 123
$ 13
$ 2,325


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


^(b)	~~Includes accruals.~~


^(c)	~~Primarily related to the sale of non-core acreage (see Note 5).~~


^(d)	~~Includes pension settlement loss of $71 million (see Note 7).~~

7.8. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit ~~cost (credit):~~cost:


	Three Months Ended June 30,												Three Months Ended September 30,
	Pension Benefits						Other Benefits						Pension Benefits						Other Benefits
(In millions)	2015			2014			2015			2014			2015			2014			2015			2014
Service cost	$	12		$	11		$	1		$	1		$	11		$	12		$	—		$	—
Interest cost	13			15			2			3			12			15			3			4
Expected return on plan assets	(17		)	(14		)	—			—			(17		)	(16		)	—			—
Amortization:
– prior service cost (credit)	(2		)	2			(1		)	(1		)	(3		)	1			(1		)	(1		)
– actuarial loss	7			10			—			—			5			7			1			—
Net settlement loss ^(a)	64			8			—			—			18			22			—			—
Net curtailment loss^(b)	—			—			2			—			4			—			—			—
Net periodic benefit cost	$	77		$	32		$	4		$	3		$	30		$	41		$	3		$	3

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


	Six Months Ended June 30,												Nine Months Ended September 30,
	Pension Benefits						Other Benefits						Pension Benefits						Other Benefits
(In millions)	2015			2014			2015			2014			2015			2014			2015			2014
Service cost	24			23			2			2			$	35		$	35		$	2		$	2
Interest cost	27			31			5			6			39			46			8			10
Expected return on plan assets	(36		)	(32		)	—			—			(53		)	(48		)	—			—
Amortization:
– prior service cost (credit)	(1		)	3			(2		)	(2		)	(4		)	4			(3		)	(3		)
– actuarial loss	14			16			—			—			19			23			1			—
Net settlement loss^(a)	81			71			—			—			99			93			—			—
Net curtailment loss (gain)^(b)	1			—			(4		)	—			5			—			(4		)	—
Net periodic benefit cost	$	110		$	112		$	1		$	6		$	140		$	153		$	4		$	9


^(a)	Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan's total service and interest cost for that year.


^(b)	Related to ~~the~~ workforce ~~reduction,~~reductions, which reduced the future expected years of service for employees participating in the ~~plans.~~plans and the impact of discontinuing accruals for future benefits under the U.K. pension plan effective December 31, 2015.

During the first ~~six~~nine months of 2015, we recorded the effects of a workforce reduction, ~~and~~ a U.S. pension plan ~~amendment.~~amendment and the discontinuation of accruals for future benefits under the U.K. pension plan. The U.S. pension plan amendment freezes the final average pay used to calculate the benefit under the legacy final average pay formula ~~benefit~~ and iswas effective July 6, 2015. For the U.K. pension plan, a final decision was reached with the plan trustees to close the plan to future benefit accruals effective December 31, 2015. Additionally, during the first ~~six~~nine months of 2015 and 2014, we recorded the effects of ~~partial~~ settlements of our U.S. pension plans. As required, we remeasured the plans' assets and liabilities as of the applicable balance sheet dates. The cumulative effects of these events are included in the remeasurement and reflected in both the pension liability and net periodic benefit ~~cost (credit).~~cost.

During the first ~~six~~nine months of 2015, we made contributions of ~~$46~~$65 million to our funded pension plans. We expect to make additional contributions up to an estimated ~~$42~~$18 million to our funded pension plans over the remainder of 2015. During the first ~~six~~nine months of 2015, we made payments of ~~$42~~$57 million and $8$13 million related to unfunded pension plans and other postretirement benefit plans, respectively.

8.9. Income Taxes

Effective Tax Rate

The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The difference between the total provision ~~(benefits)~~(benefit) and the sum of the amounts allocated to segments is reported in the “Not Allocated to Segments” column of the tables in Note 6.7.

Our effective income tax rates on continuing operations for the first ~~six~~nine months of 2015 and 2014 were ~~18%~~28% and 32%. The tax provision (benefit) applicable to Libyan ordinary income (loss) was recorded as a discrete item in the first ~~six~~nine months of 2015 and 2014. Excluding Libya, the effective tax rates on continuing operations, would be ~~15%~~27% and ~~34%~~32% for the first ~~six~~nine months of 2015 and 2014. In Libya, uncertainty remains around the timing of future production and sales levels. Reliable estimates of 2015 and 2014 Libyan annual ordinary income from our operations could not be made and the range of possible scenarios in the worldwide annual effective tax rate calculation demonstrates significant variability. Thus, for the first ~~six~~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)

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

Deferred Tax Assets

~~MARATHON OIL CORPORATION~~

~~Notes~~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 ~~Consolidated Financial Statements (Unaudited)~~our valuation allowance are possible if our estimates and assumptions (particularly as they relate to downward revisions of our long-term commodity price forecast) are revised such that they reduce estimates of future taxable income during the carryforward period.

9.10. Short-term Investments

As of ~~June~~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. ~~The maturity dates range from September 2015 to October 2015. These short-term investments~~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.

~~10.~~11. Inventories

Inventories of liquid hydrocarbons, natural gas and bitumen are carried at the lower of cost or market value. Materials and supplies are valued at weighted average cost and reviewed for obsolescence or impairment when market conditions indicate.


	June 30,		December 31,		September 30,		December 31,
(In millions)	2015		2014		2015		2014
Liquid hydrocarbons, natural gas and bitumen	$	50	$	58	$	39	$	58
Supplies and other items	286		299		285		299
Inventories, at cost	$	336	$	357	$	324	$	357

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


	June 30,		December 31,		September 30,		December 31,
(In millions)	2015		2014		2015		2014
North America E&P	$	16,757	$	16,717	$	15,875	$	16,717
International E&P	2,848		2,741		2,604		2,741
Oil Sands Mining	9,401		9,455		9,334		9,455
Corporate	115		127		107		127
Net property, plant and equipment	$	29,121	$	29,040	$	27,920	$	29,040

Our Libya operations continue to be impacted by civil unrest and, in December 2014, Libya’s National Oil Corporation once again declared force majeure at the Es Sider oil terminal, as disruptions from civil unrest continue. Considerable uncertainty remains around the timing of future production and sales levels.

As of ~~June~~September 30, 2015, our net property, plant and equipment investment in Libya is $775 million, and total proved reserves (unaudited) in Libya as of December 31, 2014 are 243 million ~~barrels of oil equivalent ("mmboe").~~boe. We and our partners in the Waha concessions continue to assess the situation and the condition of our assets in Libya. Our periodic assessment of the carrying value of our net property, plant and equipment in Libya specifically considers the net investment in the assets, the duration of our concessions and the reserves anticipated to be recoverable in future periods. The undiscounted cash flows related to our Libya assets ~~continues~~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 $88 million and $126 million as of ~~June~~September 30, 2015 and December 31, 2014. This $38 million net decrease was associated with a write-down of our Canadian in-situ assets at ~~Birchwood.~~Birchwood in the second quarter of 2015. After further evaluation of the estimated recoverable

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

resources and our development plans, we withdrew our regulatory application for the proposed steam assisted gravity drainage ~~("SAGD")~~ demonstration ~~project.~~project at Birchwood.

13. Other Noncurrent Assets



	September 30,		December 31,
(in millions)	2015		2014
Deferred tax assets	$	1,115	$	525
Intangible 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 lower forecasted commodity prices.

Impairments for the three and nine months ended September 30, 2014 consisted primarily of proved properties in the Gulf of Mexico, Texas and North Dakota as a result of revisions to estimated abandonment costs and lower forecasted commodity prices. See Note 7 for relevant detail regarding segment presentation and Note 15 for fair value measurements related to impairments of proved properties.

The following table summarizes the components of exploration expenses:



	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions)	2015			2014		2015		2014
Exploration Expenses
Unproved property impairments	$	563		$	39	$	612	$	140
Dry well costs	(3		)	25		96		80
Geological and 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 strategy (Gulf of Mexico and Harir block in the Kurdistan Region of Iraq) and lower forecasted commodity prices (Colorado).

Unproved property impairments for the three and nine months ended September 30, 2014 primarily consist of leases in Texas and North Dakota that either expired or we decided not to drill or extend. See Note 7 for relevant detail regarding segment presentation.

1314

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~12.~~15. Fair Value Measurements

Fair Values - Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of ~~June~~September 30, 2015 and December 31, 2014 by fair value hierarchy level.


	June 30, 2015								September 30, 2015
(In millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity^(a)	$	—	$	5	$	—	$	5	$	—	$	61	$	—	$	61
Interest rate	—		11		—		11		—		15		—		15
Derivative instruments, assets	$	—	$	16	$	—	$	16	$	—	$	76	$	—	$	76
Derivative instruments, liabilities
Commodity^(a)	$	—	$	26	$	—	$	26	$	—	$	3	$	—	$	3
Derivative instruments, liabilities	$	—	$	26	$	—	$	26	$	—	$	3	$	—	$	3


^(a)	Derivative instruments are recorded on a net basis in the company's balance sheet (see Note ~~13)~~16).



	December 31, 2014
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Interest rate	$	—	$	8	$	—	$	8
Derivative instruments, assets	$	—	$	8	$	—	$	8

Commodity derivatives include three-way collars, swaptions, extendable three-way collars and call options. These instruments are measured at fair value using either the Black-Scholes Model or Black Model. Inputs to both models include prices, interest rates, and implied volatility. The inputs to these models are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.

Interest rate swaps are measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs.

See Note 1316 for additional discussion of the types of derivative instruments we use.

Fair Values - Nonrecurring

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


	Three Months Ended June 30,								Three Months Ended September 30,
	2015				2014				2015				2014
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	17	$	44	$	—	$	4	$	41	$	337	$	43	$	109


	Six Months Ended June 30,								Nine Months Ended September 30,
	2015				2014				2015				2014
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	17	$	44	$	—	$	21	$	58	$	381	$	43	$	130

Commodity prices began declining in the second half of 2014 and remain substantially lower through ~~2015 as compared to the first six months of 2014. As this period of sustained reduced~~2015. The prolonged decline in commodity prices, ~~continues, it~~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 ~~related to long-lived assets~~ in ~~future periods.~~

~~All long-lived~~the future. Long-lived assets held for use that were impaired inare discussed below. The fair values of each were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs, unless otherwise noted. Inputs to the ~~first six months of 2015~~fair value measurement include reserve and ~~2014 were held~~production estimates made by our ~~North America E&P segment.~~reservoir engineers, estimated future commodity prices

1415

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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

2015 ~~we entered into an agreement to sell our East Texas/~~- North ~~Louisiana and Wilburton, Oklahoma natural gas assets. We expect the transaction to close during~~America E&P

In the third quarter of ~~2015.~~2015, impairments of $333 million were recorded primarily related to certain producing assets in Colorado and the Gulf of Mexico as a result of lower forecasted commodity prices, to an aggregate fair value of $41 million.

During the second quarter of 2015, we recorded a non-cash impairment charge of $44 million related to ~~these~~our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets as a result of the anticipated ~~sale.~~sale (see Note 6). The fair values were measured using a probability weighted income approach based on both the anticipated sales price and a held-for-use model. ~~The held-for-use model contained internal estimates~~

2015 - International E&P

In the third quarter of ~~future production levels,~~2015, a partial impairment of $12 million was recorded to an investment in an equity method investee as a result of lower forecasted commodity prices, ~~and discount rate. All such inputs were classified as Level 3.~~to a fair value of $604 million. This impairment was reflected in income from equity method investments in our consolidated statements of income.

2014 - North America E&P

The Ozona development in the Gulf of Mexico ceased producing in 2013, at which time those long-lived assets were fully impaired. In the first ~~and second quarters~~nine months of 2014, we recorded additional impairments of ~~$17 million and $4~~$30 million as a result of estimated abandonment cost revisions.

In the third quarter of 2014, impairments of $53 million were recorded to certain other Gulf of Mexico properties as a result of estimated abandonment cost and other revisions, to an aggregate fair value of $19 million. In addition, two additional on-shore fields were impaired a total of $47 million to an aggregate fair value of $24 million primarily due to lower forecasted commodity prices.

Fair Values – Goodwill

Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. After we performed our annual goodwill impairment test in April 2015, a triggering event (downward revision of forecasted commodity price assumptions) required us to reassess our goodwill for impairment as of September 30, 2015. Based on the results of this assessment, we concluded no impairment was required. The fair value ~~was measured using an income approach based upon forecasted future abandonment costs, which are Level 3 inputs.~~ of the North America E&P and International E&P reporting units exceeded their respective book values by a significant margin. Changes in management's forecast commodity price assumptions may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.

Fair Values – Financial Instruments

Our current assets and liabilities include financial instruments, the most significant of which are receivables, short-term investments, long-term debt due within one year, and payables. We believe the carrying values of our receivables, short-term investments and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our investment-grade credit rating, and (3) our historical incurrence of and expected future insignificant bad debt expense, which includes an evaluation of counterparty credit risk.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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


	June 30, 2015				December 31, 2014				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	$	134	$	133	$	132	$	129	$	109	$	116	$	132	$	129
Total financial assets	134		133		132		129		109		116		132		129
Financial liabilities
Other current liabilities	13		13		13		13		15		14		13		13
Long-term debt, including current portion^(a)	8,720		8,324		6,887		6,360		8,302		8,324		6,887		6,360
Deferred credits and other liabilities	73		67		69		68		69		64		69		68
Total financial liabilities	$	8,806	$	8,404	$	6,969	$	6,441	$	8,386	$	8,402	$	6,969	$	6,441

^(a) Excludes capital leases.

Fair values of our financial assets included in other noncurrent assets, and of our financial liabilities included in other current liabilities and deferred credits and other liabilities, are measured using an income approach and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value.

Most of our long-term debt instruments are publicly-traded. A market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is used to measure the fair value of such debt. The fair value of our debt that is not publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.

~~13.~~16. Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note ~~12.~~15. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts where they appear on the consolidated balance sheets as of ~~June~~September 30, 2015 and December 31, 2014.



	September 30, 2015
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	15	$	—	$	15	Other noncurrent assets
Total Designated Hedges	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

1517

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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

$ —

$ 11

June 30, 2015
(In millions) Asset Liability Net Liability Balance Sheet Location
Not Designated as Hedges
     Commodity $ 5
$ 17
$ 12
Other current liabilities
     Commodity —
9
9
Other noncurrent liabilities
     Total $ 5
$ 26
$ 21

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

Derivatives Designated as Fair Value Hedges

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


	June 30, 2015				December 31, 2014				September 30, 2015				December 31, 2014
	Aggregate Notional Amount		Weighted Average, LIBOR-Based,		Aggregate Notional Amount		Weighted Average, LIBOR-Based,		Aggregate Notional Amount		Weighted Average, LIBOR-Based,		Aggregate Notional Amount		Weighted Average, LIBOR-Based,
Maturity Dates	(in millions)		Floating Rate		(in millions)		Floating Rate		(in millions)		Floating Rate		(in millions)		Floating Rate
October 1, 2017	$	600	4.67	%	$	600	4.64	%	$	600	4.68	%	$	600	4.64	%
March 15, 2018	$	300	4.52	%	$	300	4.49	%	$	300	4.54	%	$	300	4.49	%

The pretax effects of derivative instruments designated as hedges of fair value in our consolidated statements of income are summarized in the table below. The foreign currency forwards were used to hedge the current Norwegian tax liability of our Norway business that was sold in the fourth quarter of 2014. Those instruments outstanding were transferred to the purchaser of the Norway business upon closing of the sale. There is no ineffectiveness related to the fair value hedges.


		Gain (Loss)													Gain (Loss)
		Three Months Ended June 30,						Six Months Ended June 30,							Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	Income Statement Location	2015			2014			2015			2014			Income Statement Location	2015			2014			2015			2014
Derivative
Interest rate	Net interest and other	$	(2	)	$	4		$	3		$	3		Net interest and other	$	4		$	(6	)	$	7		$	(3	)
Foreign currency	Discontinued operations	$	—		$	(14	)	$	—		$	(11	)	Discontinued operations	$	—		$	(18	)	$	—		$	(29	)
Hedged Item
Long-term debt	Net interest and other	$	2		$	(4	)	$	(3	)	$	(3	)	Net interest and other	$	(4	)	$	6		$	(7	)	$	3
Accrued taxes	Discontinued operations	$	—		$	14		$	—		$	11		Discontinued operations	$	—		$	18		$	—		$	29

Derivatives not Designated as Hedges

During the first ~~six~~nine months of 2015, we entered into multiple crude oil derivatives indexed to New York Mercantile Exchange ("NYMEX") ~~West Texas Intermediate ("WTI"),~~WTI related to a portion of our forecasted North America E&P sales through December 2016. These commodity derivatives ~~primarily~~ consist of three-way collars, extendable three-way collars and call ~~options and three~~options. Three way-collars ~~which~~ consist of a sold call (ceiling), a purchased put (floor) and a sold put. The ceiling price is the maximum we will receive for the contract crude oil volumes, the floor is the minimum price we will receive, unless the market price falls below the sold put strike price.

~~MARATHON OIL CORPORATION~~

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

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


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

Ceiling	$71.84	12,000	January- December 2016	$60.00	2,000	October 2015- March 2016 ^(a)
Floor	$60.48			$50.00
Sold put	$50.00			$40.00

Ceiling	$73.13	2,000	January- June 2016 ^(b)	$71.84	12,000	January- December 2016
Floor	$65.00			$60.48
Sold put	$50.00			$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)	$72.39	10,000	January- December 2016 ^(c)

^(a)

Counterparties have the option, exercisable on March 31, 2016, to ~~execute fixed-price swaps (swaptions)~~extend these collars through September of 2016 at athe same volume and weighted average price ~~of $71.67 per barrel indexed to NYMEX WTI, which is exercisable on October 30, 2015. If counterparties exercise,~~as the ~~term of the fixed price swaps would be for calendar year 2016 and, if all such are exercised, 25,000 barrels per day.~~underlying three-way collars.


^(b)	Counterparty has the option, exercisable on June 30, 2016, to extend these collars through the remainder of 2016 at the same volume and weighted average price as the underlying three-way collars.


^(c)	Call options settle monthly.

The impact of these crude oil derivative instruments appears in sales and other operating revenues in our consolidated statements of income and was a net ~~loss~~gain of ~~$43~~$108 million and ~~$17~~$91 million in the ~~second~~third quarter and first ~~six~~nine months of 2015. There were no crude oil derivative instruments in the first ~~six~~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 ~~15)~~18). Following the execution of the Treasury locks, corresponding interest rates increased during the day of June 1. As a result, the settlement of the Treasury rate locks resulted in a gain of $6 million, which was recognized in net interest and other in our consolidated statements of income.

~~14.~~17. Incentive Based Compensation

Stock option and restricted stock awards

The following table presents a summary of stock option and restricted stock award activity for the first ~~six~~nine months of 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, 2014	13,427,836				$29.68	3,448,353			$34.04	13,427,836				$29.68	3,448,353			$34.04
Granted	724,082		^(a)		$29.06	2,668,357			$30.53	724,082		^(a)		$29.06	2,674,987			$30.52
Options Exercised/Stock Vested	(480,458	)			$16.47	(921,404	)		$34.29	(549,926	)			$16.84	(1,135,635	)		$33.25
Canceled	(455,855	)			$34.48	(491,739	)		$33.70	(605,760	)			$34.11	(708,380	)		$33.20
Outstanding at June 30, 2015	13,215,605				$29.97	4,703,567			$32.04
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 $6.84 per share.

Stock-based performance unit awards

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

1719

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~15.~~18. Debt

Revolving Credit Facility As of ~~June~~September 30, 2015, we had no borrowings against our revolving credit facility (as amended, the "Credit Facility"), as described below.

In May 2015, we amended our $2.5 billion unsecured Credit Facility to increase the facility size by $500 million to a total of $3 billion and ~~extend~~extended the maturity date by an additional year such that the Credit Facility now matures in May 2020. The amendment additionally provides us the ability to request two one-year extensions to the maturity date and an option to increase the commitment amount by up to an additional $500 million, subject to the consent of any increasing lenders. The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unchanged.

The Credit Facility includes a covenant requiring that our ratio of total debt to total capitalization not exceed 65% as of the last day of each fiscal quarter. If an event of default occurs, the lenders holding more than half of the commitments may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility. As of ~~June~~September 30, 2015, we were in compliance with this covenant with a debt-to-capitalization ratio of ~~29%~~30%.

Debt Issuance On June 10, 2015, we issued $2 billion aggregate principal amount of unsecured senior notes which consist of the following series:

•$600 million of 2.70% senior notes due June 1, 2020

•$900 million of 3.85% senior notes due June 1, 2025

•$500 million of 5.20% senior notes due June 1, 2045

Interest on each series of senior notes is payable semi-annually beginning December 1, 2015. ~~We will use the aggregate net proceeds to repay our $1 billion 0.90% senior notes due 2015, which mature on November 1, 2015, and for general corporate purposes.~~ We may redeem some or all of the senior notes at any time at the applicable redemption price, plus accrued interest, if any. The aggregate net proceeds were used to repay our $1 billion 0.90% senior notes that matured in November 2015, and the remainder for general corporate purposes. As of ~~June~~September 30, 2015, we were in compliance with the covenants under the indenture governing the senior notes.

~~16.~~19. Reclassifications Out of Accumulated Other Comprehensive Income (Loss)

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


	Three Months Ended June 30,						Six Months Ended June 30,							Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2015			2014			2015			2014			Income Statement Line	2015			2014			2015			2014			Income Statement Line

Postretirement and postemployment plans	Postretirement and postemployment plans													Postretirement and postemployment plans
Amortization of actuarial loss	$	(7	)	$	(10	)	$	(14	)	$	(16	)	General and administrative	$	(6	)	$	(7	)	$	(20	)	$	(23	)	General and administrative
Net settlement loss	(64		)	(8		)	(81		)	(71		)	General and administrative	(18		)	(22		)	(99		)	(93		)	General and administrative
Net curtailment gain (loss)	(2		)	—			3			—			General and administrative	(4		)	—			(1		)	—			General and administrative
	(73		)	(18		)	(92		)	(87		)	Income (loss) from operations	(28		)	(29		)	(120		)	(116		)	Income (loss) from operations
	25			7			32			30			Benefit for income taxes	10			10			44			38			Benefit for income taxes
Other insignificant, net of tax	—			—			—			(1		)		—			—			—			(1		)
Total reclassifications	$	(48	)	$	(11	)	$	(60	)	$	(58	)	Income (loss) from continuing operations	$	(18	)	$	(19	)	$	(76	)	$	(79	)	Income (loss) from continuing operations

1820

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~17.~~20. Supplemental Cash Flow Information


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


^(a)	The first ~~six~~nine months of 2014 included ~~$1.076 billion~~$1,195 million related to discontinued operations.

~~18.~~21. Commitments and Contingencies

We are a defendant in a number of lawsuits arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

1921

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

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 ~~with~~based in Houston, Texas. Our operations are primarily located in North America, Europe and ~~Africa. Each~~Africa with a focus on our North American unconventional shale plays. Total proved reserves were 2.2 billion boe at December 31, 2014 and total assets were $35 billion at September 30, 2015.

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

Increased company-wide net sales volumes from continuing operations by 7% to 445 mboed in the third quarter of ~~our three reportable operating segments is organized~~2015 from 417 mboed in the third quarter of 2014


◦	Net sales volumes from our three U.S. resource plays increased 9% to 210 mboed in the third quarter of 2015 from 192 mboed in the third quarter of 2014

Maintained focus on cost discipline and ~~managed based upon both geographic location~~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 ~~nature~~end of the ~~products~~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 ~~services it offers.~~

~~North America E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in North America;~~

~~International E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North America and produces and markets products manufactured~~to provide us with additional capital flexibility to support growth from ~~natural gas, such as LNG and methanol, in E.G.; and~~

~~Oil Sands Mining – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades~~ the ~~bitumen to produce and market synthetic crude oil and vacuum gas oil.~~U.S. resource plays when commodity prices improve.

~~Executive Overview~~Outlook

Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows and ~~their subsequent reinvestment~~the amount of capital available to reinvest into our business. Commodity prices began declining in the second half of 2014 and remain substantially lower through ~~2015 as compared to the first six months of 2014.~~2015. We believe we can manage in this lower commodity price cycle through a continued focus on development in our three U.S. resource plays, operational execution, efficiency improvements, cost reductions, capital discipline and portfolio optimization, all while maintaining financial flexibility.

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

Increased company-wide net sales volumes from continuing operations by 4% to 411 thousand barrels of oil equivalent per day ("mboed") in the second quarter of 2015 from 394 mboed in the second quarter of 2014


◦	~~Net sales volumes from our three U.S. resource plays increased 29% to 220 mboed in the second quarter of 2015 from 170 mboed in the second quarter of 2014~~

~~Maintained focus on cost discipline and efficiencies~~


◦	~~Reduced North America E&P production expenses per boe by 31% in the second quarter of 2015 compared to the same period last year~~


◦	~~Achieved 96% average operational availability for our operated assets in the second quarter of 2015~~


◦	~~Reallocated an additional $35 million of capital to Oklahoma Resource Basins to leverage higher non-operated activity and to further advance subsurface knowledge and resource delineation~~

~~Active management of liquidity and capital structure~~


◦	~~$5.5 billion of liquidity at the end of the second quarter, comprised of $3.0 billion in the unused revolving credit facility and $2.5 billion in cash and short-term investments~~


◦	~~Cash and short-term investments-adjusted debt-to-capital ratio of 22% at June 30, 2015, as compared with 16% at December 31, 2014~~


◦	~~Issued $2 billion of senior notes in June 2015; plan to use $1 billion of proceeds to satisfy scheduled debt maturities in the fourth quarter of 2015 and the remainder for general corporate purposes~~


◦	~~Increased the capacity of the revolving credit facility to $3.0 billion from $2.5 billion while also extending the maturity date to May 2020~~


◦	~~Repatriated Canadian earnings in tax efficient manner, providing $250 million of cash available for use in U.S. operations~~


◦	~~Executed additional derivative instruments to reduce commodity price uncertainty for a portion of our forecasted North America E&P crude oil volumes~~

~~Portfolio management activities~~


◦	~~We are targeting to generate at least $500 million from select non-core asset sales~~


◦	~~Signed definitive sales agreement in July 2015 related to non-core assets for expected proceeds of $102 million, excluding closing-adjustments~~

~~Financial results~~


◦	~~Loss from continuing operations per diluted share of $0.57 in the second quarter of 2015 as compared to income from continuing operations of $0.53 per diluted share in the same period last year~~


◦	~~Recognized additional non-cash deferred tax expense of $135 million in the second quarter of 2015 related to the increase in Alberta's provincial corporate income tax rate~~


◦	Operating cash flow provided by continuing operations for the first six months of 2015 was $717 million, compared to $2.1 billion in the same period last year, reflecting the lower commodity price environment

~~We continue to optimize our resource allocation given the current price environment.~~ We expect our full-year 2015 capital, investment and exploration budget to be ~~at or below $3.3~~$3.1 billion. We estimate our full-year North America E&P and International E&P production volumes (excluding Libya) to be ~~375~~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 the U.S. resource plays flat to the 2015 exit rate.

Exploration Update

In September 2015, we announced our intention to scale back our conventional exploration program with an anticipated 2016 program of approximately $100 million, a reduction of 60% as compared to the 2015 budget, subject to approval by our Board of Directors. Our conventional exploration focus will be redirected to existing commitments in the Gulf of Mexico and Gabon. As a result, we recorded non-cash impairments related to unproved properties in the Gulf of Mexico and the Harir block in the Kurdistan Region of Iraq in the third quarter.

Operations

The following table presents a summary of our sales volumes for each of our segments. Refer to the Results of Operations for a price-volume analysis for each of the segments.



	Three Months Ended September 30,			Nine Months Ended September 30,
Net Sales 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 blendstocks

~~Operations~~

North America E~~&P--Production~~&P--Net Sales Volumes

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


	Three Months Ended June 30,		Six Months Ended June 30,
	2015	2014	2015	2014	Three Months Ended September 30,			Nine Months Ended September 30,
Net Sales Volumes					2015	2014	Increase (Decrease)	2015	2014	Increase (Decrease)
Crude Oil and Condensate (mbbld)
Bakken	54	44	53	41
Equivalent Barrels (mboed)
Eagle Ford	82	67	87	65	126	117	8%	137	105	30%
Oklahoma Resource Basins	5	2	5	2	23	19	21%	24	17	41%
Other North America ^(a)	35	38	35	36
Total Crude Oil and Condensate	176	151	180	144
Natural Gas Liquids (mbbld)
Bakken	3	3	3	2	61	56	9%	59	50	18%
Eagle Ford	26	16	26	16
Oklahoma Resource Basins	6	6	6	5
Other North America^(a)	2	2	3	4
Total Natural Gas Liquids	37	27	38	27
Total Liquid Hydrocarbons (mbbld)
Bakken	57	47	56	43
Eagle Ford	108	83	113	81
Oklahoma Resource Basins	11	8	11	7
Other North America^(a)	37	40	38	40
Total Liquid Hydrocarbons	213	178	218	171
Natural Gas (mmcfd)
Bakken	22	18	20	17
Eagle Ford	164	111	167	109
Oklahoma Resource Basins	81	61	79	58
Other North America^(a)	94	104	94	113
Total Natural Gas	361	294	360	297
Equivalent Barrels (mboed)
Bakken	61	50	59	46
Eagle Ford	135	102	141	99
Oklahoma Resource Basins	24	18	24	17
Other North America^(a)	54	57	54	58	51	58	(12)%	53	58	(9)%
Total North America E&P	274	227	278	220	261	250	4%	273	230	19%

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


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

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



	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 June 30,		Six Months Ended June 30,		Three Months Ended September 30,		Nine Months Ended September 30,
	2015	2014	2015	2014	2015	2014	2015	2014
Gross Operated
Eagle Ford:
Wells drilled to total depth	59	88	147	171	51	93	198	264
Wells brought to sales	52	76	143	125	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	19	25	22	5	25	30	60
Wells brought to sales	22	19	46	16	5	18	51	52
Oklahoma Resource Basins:
Wells drilled to total depth	5	6	13	11
Wells brought to sales	3	4	8	8

Eagle Ford – Of the 57 gross wells brought to sales during this quarter, 11 were in the Austin Chalk, 6 were in the Upper Eagle Ford, ~~– Average net sales volumes from Eagle Ford were 135 mboed~~ and ~~141 mboed~~40 in the second quarter and first six months of 2015 compared to 102 mboed and 99 mboed in the same periods of 2014, for increases of 32% and 42%. Approximately 61% of second quarter sales was crude oil and condensate, 19% was NGLs and 20% was natural gas.Lower Eagle Ford. Our average time to drill an Eagle Ford well in ~~second~~the third quarter 2015, spud-to-total depth, ~~was 11~~decreased to 10 days. ~~Also, during~~

Oklahoma Resource Basins – During the ~~second~~third quarter, ~~of 2015,~~ we spud our first Springer well and brought online 8 ~~Upper Eagle Ford, 33 Lower Eagle Ford and 11 Austin Chalk gross~~ operated wells (6 in SCOOP and 2 in STACK), with one of the SCOOP wells being an extended-reach lateral. In addition to the 8 wells mentioned above, we completed ~~and brought online three "stack-and-frac" pilots with wells in three horizons.~~

Bakken – Average net sales volumes from the Bakken shale were 61 mboed and 59 mboed in the second quarter and first six months of 2015 compared to 50 mboed and 46 mboed in the same period for 2014, for increases of 22% and 28%. Our Bakken production averaged approximately 89% crude oil, 5% NGLs and 6% natural gas. Our time to drill a Bakken well, spud-to-total depth, averaged 13 days in the second quarter of 2015.

Application of the enhanced completion design continues to provide promising results, with outperformance of historical type curves after 180 days of cumulative production. The enhanced completion design optimizes proppant loading, frac fluid volumes and stage density. Three high-density pilots (six wells per horizon) were completed through the second quarter. Also in the second quarter, our first Three Forks second benchan additional Smith infill pilot well in the ~~Myrmidon~~SCOOP which was ~~completed.~~

Oklahoma Resource Basins – Net sales volumes from the Oklahoma Resource Basins averaged 24 mboed in both the second quarter and first six months of 2015 compared to 18 mboed and 17 mboed in the comparable 2014 periods, for increases of 33% and 41%. Our second quarter 2015 production was approximately 20% crude, 25% NGLs and 55% natural gas. Of the three gross operated wells brought to sales ~~this quarter, two were SCOOP~~on October 1. These wells ~~and one was a STACK Osage well.~~are all in the very early stages of production. We ~~also finished drilling five operated Smith infill pilot wells this quarter.~~

~~Additionally, we~~ continue to leverage the benefit of participation in outside-operated wells and plan to participate in approximately 8555-70 gross outside-operated wells in 2015 in the SCOOP Woodford, SCOOP Springer and STACK ~~areas. In the first six months of 2015, we participated in four~~areas, with 17 outside-operated high-density spacing pilots in the SCOOP area; three in the Woodford (80-128 acre spacing) and one in the emerging Springer shale (105-128 acre spacing) overlaying the Woodford. Two outside-operated STACK Meramec XL wells ~~were~~ brought to sales during the quarter.

Bakken – The 5 gross wells brought to sales this quarter were in the East Myrmidon area. Despite the lower number of wells to sales this quarter, sales volumes were driven by continued strong performance from the Doll pad wells (West Myrmidon) which came online in late June as well as sustained improvement in production uptime. We expect reduced completions activity during the fourth quarter.

Gulf of Mexico – Development work continues in the Gunflint field located on Mississippi Canyon Blocks 948, 949, 992 (N/2) and 993 (N/2). We expect the two-well subsea tieback to be complete by the end of 2015 with first oil in ~~the second half of 2015.~~mid-2016. We hold an 18% non-operated working interest in the Gunflint field.

North America E&P--Exploration

Gulf of Mexico – ~~During the second quarter, we spud the Solomon exploration prospect on Walker Ridge Block 225 and farmed down our operated working interest to 58%.~~

The third appraisal well on the Shenandoah prospect was spud in May 2015 and ~~is still drilling.~~reached total depth in October, finding more than 620 feet of net oil pay. The operator completed logging operations and will obtain a whole core across the reservoir interval. The well is located in Walker Ridge Block ~~52,~~51, in which we hold a 10% non-operated working interest.

~~International E&P--Production~~

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

International E&P--Net Sales Volumes

The following table provides net sales ~~to the AMPCO and LNG facilities. In addition, the AMPCO methanol facility completed a planned turnaround in first quarter 2015.~~volumes for our significant operational areas within this segment.


	Three Months Ended June 30,		Six Months Ended June 30,		Three Months Ended September 30,			Nine Months Ended September 30,
	2015	2014	2015	2014	2015	2014	Increase (Decrease)	2015	2014	Increase (Decrease)
Net Sales Volumes
Crude Oil and Condensate (mbbld)
Equatorial Guinea	19	20	18	22
United Kingdom	14	13	14	13
Total Crude Oil and Condensate	33	33	32	35
Natural Gas Liquids (mbbld)
Equatorial Guinea	9	11	10	11
United Kingdom	—	—	—	—
Total Natural Gas Liquids	9	11	10	11
Total Liquid Hydrocarbons (mbbld)
Equatorial Guinea	28	31	28	33
United Kingdom	14	13	14	13
Total Liquid Hydrocarbons	42	44	42	46
Natural Gas (mmcfd)
Equivalent Barrels (mboed)
Equatorial Guinea	365	446	390	441	101	97	4%	96	104	(8)%
United Kingdom^(a)	31	28	32	29	18	9	100%	19	15	27%
Libya	—	—	—	1	—	6	(100)%	—	2	(100)%
Total Natural Gas	396	474	422	471
Equivalent Barrels (mboed)
Equatorial Guinea	89	105	93	107
United Kingdom^(a)	19	18	19	18
Total International E&P (mboed)	108	123	112	125	119	112	6%	115	121	(5)%
Net Sales Volumes of Equity Method Investees
LNG (mtd)	4,991	6,624	5,629	6,601	5,700	6,265	(9)%	5,653	6,488	(13)%
Methanol (mtd)	673	980	778	1,066	1,125	1,103	2%	895	1,078	(17)%


^(a)	Includes natural gas acquired for injection and subsequent resale of 78 mmcfd and 3 mmcfd for the third quarters of 2015 and 2014, and 8 mmcfd and 5 mmcfd for the ~~second quarters of 2015 and 2014, and 9 mmcfd and 6 mmcfd for the~~ first ~~six~~nine months of 2015 and 2014.

Equatorial Guinea – ~~Average~~Third quarter net sales volumes were 89 mboed and 93 mboed in the second quarter and first six months of 2015 compared to 105 mboed and 107 mboed in the same periods of 2014. Planned turnaround and maintenance activities at the Alba field and EG LNG facilities reducedincreased as production rates during the second quarter of 2015. The Alba turnaround subsequently reduced sales to our equity method investees, Alba Plant LLC, EGHoldings and AMPCO. Additionally, there was a planned turnaround at AMPCO in the first quarter of 2015.

~~During the second quarter of 2015,~~from the Alba C21 development well ~~reached total depth~~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 ~~activities are underway. To date, well performance results are consistent with pre-drill estimates.~~at the fabrication yard in the Netherlands during the third quarter and is on schedule to be operational in mid-2016.

United Kingdom – ~~Average net sales volumes were 19 mboed for each of the second quarter and first six months of 2015, relatively flat as compared to 18 mboed in the same periods of 2014.~~ Net sales volumes benefited from improved production as two subsea development wells at West Brae began producing during ~~the first~~2015. Overall, operating availability was higher for all U.K. assets in 2015 as compared to comparative 2014 periods which included planned and ~~second quarters of 2015. This completed the last of the planned five-well Brae infill drilling program begun in 2014. In addition, as fullcompression was reinstated during the second quarter of 2015 at the non-operated Foinaven field, this contributed to improved reliability.~~

unplanned maintenance activities. During the third quarter of 2015, planned maintenance activities ~~are scheduled~~were completed at the East Brae field and continue at the non-operated Foinaven field. The activity at Foinaven will impact production volumes during the fourth quarter of 2015.

Libya – We had no sales during the first ~~six~~nine months of 2015 as a result of continued civil ~~unrest.~~unrest, as compared to one lifting in the third quarter of 2014. In December 2014, Libya’s National Oil Corporation reinstated force majeure at the Es Sider oil ~~terminal, as disruptions from civil unrest continue.~~terminal. Considerable uncertainty remains around the timing of future production and sales levels.

~~International E&P--Exploration~~

Kurdistan Region of Iraq – On the Harir Block, testing was completed on the Mirawa-2 appraisal well during the second quarter of 2015. The well has been temporarily suspended as a potential future producer and the drilling rig has been de-mobilized. We hold a 45% operated working interest in the block.

Oil Sands Mining

Our net synthetic crude oil sales volumes were 2965 mbbld and 4451 mbbld in the ~~second~~third quarter and first ~~six~~nine months of 2015 compared to 4455 mbbld and 4549 mbbld in the same periods of 2014. ~~Production declined~~Net sales volumes increased in the ~~second~~third quarter of 2015 primarily due to ~~the planned turnarounds~~improved mine reliability and no major maintenance activities. Planned maintenance at ~~the base upgrader and Muskeg River Mine and unplanned downtime at the expansion upgrader. Production was relatively flat~~both mines in the ~~first six months of 2015 compared to the same period in 2014 as the planned turnarounds and unplanned downtime during the second~~fourth quarter of 2015 ~~were mostly offset by higher production driven by improved mine reliability during the first quarter of 2015.~~is expected to impact production. We hold a 20% non-operated working interest in the ~~AOSP.~~Athabasca Oil Sands Project.

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 ~~second~~third quarter and first ~~six~~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 ~~second~~third quarter and first ~~six~~nine months of 2015 and 2014.

Three Months Ended June 30, Six Months Ended June 30,
2015 2014 2015 2014
Average Price Realizations ^(a)

Crude Oil and Condensate (per bbl) ^(b)

Bakken
$51.36

$93.08

$45.84

$91.43
Eagle Ford 53.47
99.08
47.81
97.65
Oklahoma Resource Basins 51.00
101.12
48.34
98.05
Other North America ^(c)
52.83
93.45
47.10
91.40
Total Crude Oil and Condensate 52.63
95.95
47.11
94.30
Natural Gas Liquids (per bbl)

Bakken
$11.63

$45.13

$7.19

$51.04
Eagle Ford 14.08
30.20
13.90
33.76
Oklahoma Resource Basins 14.45
33.04
15.83
38.21
Other North America ^(c)
25.65
54.13
26.03
57.65
Total Natural Gas Liquids 14.77
34.80
14.60
38.75
Total Liquid Hydrocarbons (per bbl)

Bakken
$49.29

$90.47

$43.72

$89.16
Eagle Ford 44.05
85.36
40.01
84.78
Oklahoma Resource Basins 30.29
52.00
29.24
55.04
Other North America ^(c)
50.89
90.45
45.52
88.97
Total Liquid Hydrocarbons 45.96
86.43
41.37
85.65
Natural Gas (per mcf)

Bakken
$2.62

$4.12

$2.76

$6.14
Eagle Ford 2.71
4.76
2.79
4.83
Oklahoma Resource Basins 2.64
4.57
2.63
5.01
Other North America^(c)
2.98
5.65
3.29
5.35
Total Natural Gas 2.76
5.00
2.88
5.14
Benchmarks
WTI crude oil (per bbl)^(d)

$57.95

$102.99

$53.34

$100.84
Louisiana Light Sweet ("LLS") crude oil (per bbl)^(e)
62.94
105.55
57.97
104.97
Mont Belvieu NGLs (per bbl)^(f)
17.65
34.54
18.02
36.42
Henry Hub natural gas^(g) (per mmbtu)^(h)
2.64
4.67
2.81
4.80



	Three Months Ended September 30,			Nine Months Ended September 30,
	2015	2014	Decrease	2015	2014	Decrease
Average Price Realizations ^(a)
Crude Oil and Condensate (per bbl) ^(b)	$41.37	$89.65	(54)%	$45.27	$92.59	(51)%
Natural Gas Liquids (per bbl)	11.88	33.93	(65)%	13.67	36.96	(63)%
Total Liquid Hydrocarbons (per bbl)	35.75	80.89	(56)%	39.55	83.89	(53)%
Natural Gas (per mcf)	2.75	4.21	(35)%	2.84	4.81	(41)%
Benchmarks
WTI crude oil (per bbl)	$46.50	$97.25	(52)%	$51.01	$99.62	(49)%
LLS crude oil (per bbl)	50.22	101.03	(50)%	55.33	103.63	(47)%
Mont Belvieu NGLs (per bbl)^(c)	15.86	32.69	(51)%	17.28	35.15	(51)%
Henry Hub natural gas (per mmbtu)	2.77	4.06	(32)%	2.80	4.55	(38)%


^(a)	Excludes gains or losses on derivative instruments.


^(b)	Inclusion of realized gains on crude oil derivative instruments would have increased average crude oil price realization by ~~$0.06~~$1.87 per bbl and ~~$0.14~~$0.69 per bbl for the ~~second~~third quarter and first ~~six~~nine months of 2015. There were no crude oil derivative instruments in 2014.


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


^(d)	~~NYMEX.~~


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


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


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


^(h)	~~Million British thermal units.~~

Crude oil and condensate – Our crude oil and condensate price realizations may differ from the benchmark due to the quality and location of the product.

Natural gas liquids – The majority of our NGL volumes are sold at reference to Mont Belvieu prices.

Natural gas – A significant portion of our natural gas production in the U.S. is sold at bid-week prices, or first-of-month indices relative to our specific producing areas.

International E&P

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

Three Months Ended June 30, Six Months Ended June 30,
2015 2014 2015 2014
Average Price Realizations
Crude Oil and Condensate (per bbl)

Equatorial Guinea
$52.27

$90.91

$47.55

$90.66
United Kingdom 62.97
111.76
60.19
111.38
Total Crude Oil and Condensate 56.70
99.36
52.92
98.51
Natural Gas Liquids (per bbl)

Equatorial Guinea ^(a)

$1.00

$1.00

$1.00

$1.00
United Kingdom 36.49
64.37
34.82
69.56
Total Natural Gas Liquids 3.10
3.02
3.29
3.64
Total Liquid Hydrocarbons (per bbl)

Equatorial Guinea
$35.74

$59.72

$31.81

$61.12
United Kingdom 61.93
110.51
58.96
110.02
Total Liquid Hydrocarbons 44.70
75.41
41.06
75.48
Natural Gas (per mcf)

Equatorial Guinea ^(a)

$0.24

$0.24

$0.24

$0.24
United Kingdom 6.98
8.04
7.34
9.07
Libya —
—
—
5.45
Total Natural Gas 0.78
0.69
0.78
0.80
Benchmark
Brent (Europe) crude oil (per bbl)^(b)

$61.69

$109.70

$57.81

$108.93



	Three Months Ended September 30,			Nine Months Ended September 30,
	2015	2014	Increase (Decrease)	2015	2014	Increase (Decrease)
Average Price Realizations
Crude Oil and Condensate (per bbl)	$46.18	$89.07	(48)%	$50.51	$95.71	(47)%
Natural Gas Liquids (per bbl)	2.69	1.00	169%	3.08	2.83	9%
Liquid Hydrocarbons (per bbl)	35.88	66.80	(46)%	39.21	72.88	(46)%
Natural Gas (per mcf)	0.59	0.56	5%	0.71	0.73	(3)%
Benchmark
Brent (Europe) crude oil (per bbl) ^(a)	$50.23	$101.82	(51%)	$55.28	$106.56	(48%)


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


^(b)	Average of monthly prices obtained from ~~Energy Information Administration ("EIA")~~EIA website.

Liquid hydrocarbons – Our ~~United Kingdom ("~~U.K.") liquid hydrocarbon production is generally sold in relation to the Brent crude benchmark. Our production from Equatorial Guinea is condensate, which receives lower prices than crude oil.

~~NGLs~~

Our NGL and 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; therefore, our reported average ~~NGL~~ realized prices ~~within the International E&P segment~~for NGLs and natural gas will not fully track market price movements.

~~Natural gas~~ –~~Our~~ The equity affiliates then utilize, process and sell the NGLs and natural gas ~~sales~~at market prices, with our share of their income/loss reflected in the Income from ~~E.G. are subject to fixed-price, term contracts, making realized prices in this area less volatile; therefore, our reported average natural gas realized prices within~~equity method investments line item on the ~~International E&P segment will not fully track market price movements.~~Consolidated Statements of Income.

Oil Sands Mining

The Oil Sands Mining segment produces and sells various qualities of synthetic crude oil. Output mix can be impacted by operational reliability or planned unit outages at the mines or upgrader. Sales prices for roughly two-thirds of the normal output mix have historically tracked movements in WTI and one-third have historically tracked movements in the Canadian heavy crude oil marker, primarily ~~Western Canadian Select ("WCS").~~WCS.

The operating cost structure of our Oil Sands Mining operations is predominantly fixed and therefore many of the costs incurred in times of full operation continue during production downtime. Per-unit costs are sensitive to production rates. Key variable costs are natural gas and diesel fuel, which track commodity markets such as the Canadian Alberta Energy Company ("AECO") natural gas sales index and crude oil prices.

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


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,			Nine Months Ended September 30,
	2015		2014		2015		2014		2015	2014	Decrease	2015	2014	Decrease
Average Price Realizations
Synthetic Crude Oil (per bbl)		$52.46		$94.17		$44.33		$91.27	$39.49	$88.22	(55%)	$42.26	$90.11	(53%)
Benchmark
Benchmarks
WTI crude oil (per bbl)^(a)		$57.95		$102.99		$53.34		$100.84	$46.50	$97.25	(52%)	$51.01	$99.62	(49%)
WCS crude oil (per bbl)^(b)		$46.35		$82.95		$40.13		$79.25
AECO natural gas sales index (per mmbtu)^(c)		$2.05		$4.46		$2.07		$4.72
WCS crude oil (per bbl)^(a)									33.16	76.99	(57%)	37.80	78.50	(52%)


^(a)	~~NYMEX.~~


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


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

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 June 30, Six Months Ended June 30,
(In millions) 2015 2014 2015 2014
Sales and other operating revenues, including related party
North America E&P $ 993
$ 1,540
$ 1,843
$ 2,932
International E&P 211
347
393
727
Oil Sands Mining 147
383
372
760
Segment sales and other operating revenues, including related party $ 1,351
$ 2,270
$ 2,608
$ 4,419
Unrealized loss on crude oil derivative instruments (44 ) —
(21 ) —
Sales and other operating revenues, including related party $ 1,307
$ 2,270
$ 2,587
$ 4,419



	Three Months Ended September 30,
(In millions)	2015		2014
Sales and other operating revenues, including related party
North America E&P	$	796	$	1,586
International E&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

Below is a price/volume analysis for each segment. Refer to the preceding Operations and Market Conditions sections for additional detail related to our net sales volumes and average price realizations.

~~North America E&P~~

Three Months Ended Increase (Decrease) Related to Three Months Ended
(In millions) June 30, 2014 Price Realizations Net Sales Volumes June 30, 2015
North America E&P Price-Volume Analysis
Liquid hydrocarbons $ 1,403
$ (786 ) $ 276
$ 893
Natural gas 133
(73 ) 30
90
Realized gain on crude oil
derivative instruments —
1

1
Other sales 4

9
Total $ 1,540
$ 993

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

~~International E&P~~

Three Months Ended Increase (Decrease) Related to Three Months Ended
(In millions) June 30, 2014 Price Realizations Net Sales Volumes June 30, 2015
International E&P Price-Volume Analysis
Liquid hydrocarbons $ 305
$ (118 ) $ (15 ) $ 172
Natural gas 30
3
(5 ) 28
Other sales 12
11
Total $ 347
$ 211

Six Months Ended Increase (Decrease) Related to Six Months Ended
(In millions) June 30, 2014 Price Realizations Net Sales Volumes June 30, 2015
International E&P Price-Volume Analysis
Liquid hydrocarbons $ 634
$ (261 ) $ (63 ) $ 310
Natural gas 69
(2 ) (7 ) 60
Other sales 24
23
Total $ 727
$ 393

~~Oil Sands Mining~~

Three Months Ended Increase (Decrease) Related to Three Months Ended
(In millions) June 30, 2014 Price Realizations Net Sales Volumes June 30, 2015
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil $ 377
$ (110 ) $ (130 ) $ 137
Other sales 6

10
Total $ 383
$ 147


	Six Months Ended		Increase (Decrease) Related to						Six Months Ended			Three Months Ended			Increase (Decrease) Related to					Three Months Ended
(In millions)	June 30, 2014		Price Realizations			Net Sales Volumes			June 30, 2015			September 30, 2014			Price Realizations			Net Sales Volumes		September 30, 2015
North America E&P Price-Volume Analysis											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											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	$	750	$	(376	)	$	(19	)	$	355		$	445		$	(294	)	$	85	$	236
Other sales	10								17			12								6
Total	$	760							$	372		$	457							$	242

Marketing revenues decreased ~~$435 million and $772~~$470 million in the ~~second~~third quarter ~~and first six months~~ of 2015 from the comparable prior-year ~~periods.~~period. Marketing activities include the purchase of commodities from third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points. ~~Because~~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 ~~$94 million and $195~~$53 million in the ~~second~~third quarter ~~and first six months~~ of 2015 from the comparable 2014 period. The decrease ~~in the second quarter of 2015~~ is primarily due to lower price realizations for ~~Liquified Natural Gas ("LNG")~~LPG at our Alba plant, LNG at our LNG facility, ~~Liquified Petroleum Gas ("LPG") at our Alba plant,~~ and lower methanol prices at our AMPCO methanol facility, all of which are located in E.G. Also ~~contributing to~~impacting the ~~decrease~~quarter was a partial impairment of our investment in ~~2015 were lower sales volumes due to the previously mentioned planned turnaround and maintenance activities at the AMPCO methanol plant, the Alba field and the LNG facility.~~an equity method investee.

Production expenses decreased ~~$112 million in the second quarter of 2015 compared to the second quarter of 2014.~~$187 million. North America E&P declined ~~$38~~$54 million due to lower operational, maintenance and labor costs. International E&P declined ~~$35~~$47 million primarily ~~because~~the result of higher project costs in 2014, such as the non-operated Foinaven subsea power project. Also contributing were lower production costs ~~related to lower sales volumes, while~~in Libya during 2015 as the ~~second~~third quarter of 2014 ~~included $5 million of turnaround costs at Brae and subsea maintenance costs at the non-operated Foinaven field in the U.K.~~had one lifting. OSM decreased ~~$39~~$86 million primarily due to ~~lower feedstock purchases (due to planned turnarounds and unplanned downtime as previously discussed) and~~ continued cost management, especially staffing and contract labor. Also contributing to the OSM decrease was a more favorable exchange rate on expenses denominated in the Canadian ~~Dollar. These declines were partially offset by costs incurred from the turnaround.~~

~~Production expenses for the first six months of 2015 decreased by $210 million compared to the same period of 2014. North America E&P declined $47 million due to~~Dollar and lower ~~operational, maintenance and labor costs. International E&P declined~~feedstock purchases given increased reliability.

2928

~~$68 million due to lower repair, maintenance and turnaround costs as well as lower production volumes.~~ The previous six month period included $11 million of non-recurring riser repair costs in E.G., $5 million of expenses from a Brae turnaround and costs related to reliability issues and subsea maintenance at the non-operated Foinaven field in the U.K. OSM decreased $95 million due to the same reasons as described in the preceding paragraph.

~~The second~~third quarter of 2015 production expense rate (expense per boe) for North America E&P declined ~~relative to the same quarter in 2014~~ due to overall cost reductions, as previously discussed, and leveraging efficiencies as production volumes increased. The expense rate for International E&P declined due to reduced maintenance and project costs and lower operational costs in ~~second quarter of 2015 as compared to 2014.~~Libya. The OSM expense rate decreased as production volume increased, ~~due to~~coupled with the ~~turnarounds and unplanned downtime in the second quarter of 2015, which resulted in lower sales volumes and higher costs.~~increased cost focus discussed above.

The expense rate during the first six months of 2015 compared the same period in 2014 decreased for North America E&P due to overall cost reductions as discussed in the preceding paragraph. The International E&P expense rate decreased in the first six months of 2015 due to lower project costs as discussed in the preceding paragraphs. The OSM expense rate remained relatively flat in the six months of 2015 as the lower feedstock purchases, cost management and a favorable exchange rate were offset by the aforementioned higher turnaround costs. The following table provides production expense rates for each segment:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,
($ per boe)	2015		2014		2015		2014		2015	2014
Production Expense Rate
North America E&P		$7.19		$10.47		$7.57		$10.74	$7.43	$10.16
International E&P		$6.51		$8.87		$6.45		$8.82	$5.53	$10.48
Oil Sands Mining ^(a)		$78.24		$51.53		$50.06		$49.54	$26.01	$37.38


^(a)	Production expense per synthetic crude oil barrel (before royalties) includes direct production costs (less pre-development), shipping and handling and taxes other than ~~income and insurance costs and excludes pre-development costs.~~income.

Marketing costs decreased ~~$432 million and $769~~$470 million in the ~~second~~third quarter ~~and first six months~~ of 2015 from the comparable 2014 ~~periods,~~period, consistent with the marketing revenues changes discussed above.

Exploration expenses ~~declined $34 million in~~increased $489 million. We made a strategic decision to reduce the ~~second quarter~~overall level of ~~2015 compared to the second quarter of 2014 due to lower unproved property impairments and dry well costs. Unproved property impairments declined primarily~~our conventional exploration program; as a result, we impaired certain of ~~fewer Eagle Ford and Bakken~~our leases that either expired or that we decided not to drill or extend. The second quarter of 2014 included dry well costs associated with our exploration programs in Kurdistan, Ethiopia and Kenya. Included in the dry well costs for the second quarter of 2015 is $38 million of previously suspended well costs that were written off. The well costs are associated with our Canadian in-situ assets at Birchwood. See Note 11 to the consolidated financial statements for further discussion.

Exploration expenses were $17 million lower in the first six months of 2015 than in the comparable 2014 period due to lower unproved property impairments, which were partially offset by higher dry well costs. Unproved property impairments were higher in 2014 primarily as a result of Eagle Ford and Bakken leases that either expired or that we decided not to drill or extend. Dry well costs increased for the first six months of 2015 due to costs associated with the Sodalita West #1 well in E.G., the Key Largo well in the Gulf of Mexico and the ~~aforementioned suspended well costs related~~Harir block in the Kurdistan Region of Iraq. Further contributing to ~~Birchwood in-situ. Dry well costs for~~ the ~~first six months~~increase was an impairment of ~~2014 primarily consist of~~unproved property in Colorado, which we deemed uneconomic given our ~~exploration programs in Kurdistan, Ethiopia and Kenya.~~forecasted natural gas prices. The following table summarizes the components of exploration expenses:


	Three Months Ended				Six Months Ended June 30,				Three Months Ended September 30,
(In millions)	2015		2014		2015		2014		2015			2014
Exploration Expenses
Unproved property impairments	$	40	$	60	$	49	$	101	$	563		$	39
Dry well costs	41		53		99		55		(3		)	25
Geological and geophysical	12		6		15		17		8			10
Other	18		26		38		45		17			22
Total exploration expenses	$	111	$	145	$	201	$	218	$	585		$	96

Depreciation, depletion and amortization (“DD&A”) ~~increased $71~~decreased $20 million ~~and $249 million in the second quarter and first six months of 2015 from the comparable 2014 periods~~ primarily as a result of a higher ~~North America E&P net sales volumes~~proved reserve base in Eagle Ford, the effects of which more than offset additional DD&A resulting from ~~our three U.S. resource plays, partially offset by lower~~production volume increases in the International E&P ~~sales volumes.~~and OSM ~~net sales volumes also declined in the second quarter of 2015, as previously discussed, also contributing to that quarter's decrease.~~segments. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, proved reserve and production volumes have an impact on DD&A expense.

The DD&A rate (expense per boe), which is impacted by field-level changes in sales volumes, proved reserves and capitalized costs, can also cause changes to our DD&A. The following table provides DD&A rates for each segment. The DD&A rate for North America E&P decreased primarily as a result of a higher proved reserve base in Eagle Ford. The International E&P rate increased primarily due to higher sales volumes from the Brae infill drilling program.


	Three Months Ended				Six Months Ended June 30,				Three Months Ended September 30,
($ per boe)	2015		2014		2015		2014		2015		2014
DD&A Rate
North America E&P		$25.45		$26.58		$26.16		$26.72		$22.84		$26.54
International E&P		$7.17		$6.64		$6.62		$6.45		$7.32		$5.30
Oil Sands Mining		$12.87		$11.78		$12.58		$11.74		$12.62		$12.75

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

Taxes other than income include production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. With the decrease in North America E&P revenues due to lower price realizations, taxes other than income decreased ~~$31 million and $59~~$69 million in the ~~second~~third quarter ~~and first six months~~ of ~~2015 from the comparable 2014 periods.~~2015. This decrease was partially offset by an increase in sales volumes in North America E&P. The following table summarizes the components of taxes other than income:


	Three Months Ended				Six Months Ended June 30,				Three Months Ended September 30,
(In millions)	2015		2014		2015		2014		2015		2014
Production and severance	$	40	$	68	$	74	$	122	$	28	$	69
Ad valorem	15		19		31		38		2		20
Other	23		22		40		44		16		26
Total	$	78	$	109	$	145	$	204	$	46	$	115

General and administrative expenses ~~increased $29~~decreased $35 million ~~in the second quarter of 2015 compared to the same period in 2014~~ primarily due to higher pension settlement charges. Settlement charges in the second quarter of 2015 totaled $64 million, compared to settlement charges of $8 million in the prior year quarter. This increase in pension settlement costs was partially offset by costscost savings realized from the workforce reductions that occurred in the first quarter of 2015.

~~General and administrative expenses increased $13~~ Pension settlement charges in the three months of 2015 totaled $18 million compared to $22 million in the ~~first six months of 2015 compared to the same period in 2014. This increase was primarily due to $43 million of~~prior year. In addition, we incurred severance related expenses in the first ~~quarter of 2015 and $10 million of increased pension settlement expense (first six~~three months of 2015 ~~totaled $81 million as compared to $71 million for the previous year). These increased costs were partially offset by costs savings realized in the second quarter~~associated with workforce reductions of ~~2015 resulting from the workforce reductions.~~$4 million.

Provision (benefit) for income taxes ~~reflect~~reflects an effective tax ~~rates~~rate of ~~2% and 18%~~35% in the ~~second~~third quarter ~~and first six months~~ of 2015, as compared to ~~30% and 32% from the comparable 2014 periods. The effective rates for 2015 reflect $135 million of non-cash additional deferred tax expense recorded~~33% in the ~~second~~third quarter of ~~2015 as a result of enacted corporate tax changes in Alberta, Canada.~~2014. See Note 89 to the consolidated financial statements for discussion of the effective tax rate.

Discontinued operations presented in 2014 are net of tax. See Note 56 to the consolidated financial statements for financial information about discontinued operations.

Segment Income(Loss)

Segment income (loss) represents income (loss) from continuing operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments, unrealized gains or losses on crude oil derivative instruments, or other items that affect comparability also are not allocated to operating segments.

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



	Three Months Ended September 30,
(In millions)	2015			2014
North America E&P	$	(61	)	$	292
International E&P	29			106
Oil Sands Mining	(11		)	93
Segment income (loss)	(43		)	491
Items not allocated to segments, net of income taxes	(706		)	(187		)
Income (loss) from continuing operations	(749		)	304
Discontinued operations ^(a)	—			127
Net income (loss)	$	(749	)	$	431


^(a)	As a result of the sale of our Angola assets and our Norway business, both are reflected as discontinued operations in 2014.

North America E&P segment income (loss) decreased $353 million after-tax primarily due to lower price realizations, which was partially offset by the impacts from the increased net sales volumes from the U.S. resource plays and lower production and operating costs.

International E&P segment incomedecreased $77 million after-tax primarily due to lower liquid hydrocarbon price realizations as well as reduced income from equity investments. These declines were partially offset by increased sales volumes and lower production and exploration expenses.

Oil Sands Mining segment income (loss)decreased $104 million after-tax primarily due to lower price realizations, partially offset by higher volumes and reduced production expenses.

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



	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 expense rates during the first nine months of 2015 decreased for each of our segments as total production costs declined due to the reasons described in the preceding paragraph. The North America E&P and OSM segments also experienced volume increases, which further contributed to the expense rate decline. The following table provides production expense rates for each segment:



	Nine Months Ended September 30,
($ per boe)	2015		2014
Production Expense Rate
North America E&P		$7.52		$10.52
International E&P		$6.13		$9.34
Oil Sands Mining ^(a)		$39.58		$44.73


^(a)	Production expense per synthetic crude oil barrel (before royalties) includes direct production costs (less pre-development), shipping and handling and taxes other than income.

Marketing costs decreased $1,239 million in the first nine months of 2015 from the comparable 2014 period, consistent with the marketing revenues changes discussed above.

Exploration expensesincreasedby$472 million as a result of unproved property impairments recognized during the third quarter of 2015. See the preceding three month period discussion for further information on our unproved property impairments. Unproved property impairments in 2014 primarily were a result of Eagle Ford and Bakken leases that either expired or that we decided not to drill or extend. Dry well costs for the first nine months of 2015 include the Sodalita West #1 well in E.G., the Key Largo well in the Gulf of Mexico, and suspended well costs related to Birchwood in-situ that were expensed during the second quarter of 2015. Dry well costs for the first nine months of 2014 primarily consist of our exploration programs in Kurdistan, Ethiopia and Kenya. The following table summarizes the components of exploration expenses:



	Nine Months Ended September 30,
(In millions)	2015		2014
Exploration Expenses
Unproved property impairments	$	612	$	140
Dry well 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.



	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):


	Three Months Ended						Six Months Ended June 30,						Nine Months Ended September 30,
(In millions)	2015			2014			2015			2014			2015			2014
North America E&P	$	(45	)	$	302		$	(206	)	$	544		$	(267	)	$	836
International E&P	41			160			64			381			93			487
Oil Sands Mining	(77		)	55			(96		)	119			(107		)	212
Segment income (loss)	(81		)	517			(238		)	1,044			(281		)	1,535
Items not allocated to segments, net of income taxes	(305		)	(157		)	(424		)	(286		)	(1,130		)	(473		)
Income (loss) from continuing operations	(386		)	360			(662		)	758			(1,411		)	1,062
Discontinued operations ^(a)	—			180			—			931			—			1,058
Net income (loss)	$	(386	)	$	540		$	(662	)	$	1,689		$	(1,411	)	$	2,120


^(a)	As a result of the sale of our Angola assets and our Norway business, both are reflected as discontinued operations in 2014.

North America E&P segment income (loss) decreased ~~$347 million and $750~~$1,103 million after-tax in the ~~second quarter and~~ first ~~six~~nine months of 2015 ~~from the comparable 2014 periods. The decrease is~~ primarily due to lower price ~~realizations, which was~~realizations; these were partially offset by ~~the impacts from the~~ increased net sales volumes from the U.S. resource ~~plays.~~plays and lower production costs.

International E&P segment income decreased ~~$119~~$394 million ~~and $317 million~~ after-tax ~~in the second quarter and first six months of 2015 from the comparable 2014 periods. The decreases are~~ primarily due to lower liquid hydrocarbon price realizations and ~~net sales volumes, as well as~~ reduced income from equity investments. These declines were partially offset by lower production and exploration expenses.

Oil Sands Mining segment income (loss) decreased ~~$132~~$319 million ~~and $215 million~~ after-tax ~~in the second quarter and first six months of 2015 from the comparable 2014 periods~~ primarily due to lower price realizations, partially offset by reduced production expenses.

Critical Accounting Estimates

There have been no material changes or developments in the evaluation of the accounting estimates and the underlying assumptions or methodologies pertaining to our ~~critical accounting estimates subsequent to~~ Critical Accounting Estimates disclosed in our Form 10-K for the year ended December 31, 2014,. except as discussed below.

Fair Value Estimates - Impairment Assessments of Long-Lived Assets and Goodwill

The continued decline of commodity prices resulted in a downward revision of our long-term commodity price assumptions and was a triggering event which required us to reassess long-lived assets related to oil and gas producing properties for impairment as of September 30, 2015. We estimated the fair values using an income approach and concluded that impairments of $337 million were required (See Notes 14 & 15 ). Changes in management's forecast assumptions may cause us to reassess our long-lived assets for impairment, and could result in non-cash impairment charges in the future.

Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. After we performed our annual goodwill impairment test in April 2015, a triggering event (downward revision to forecasted commodity price assumptions) required us to reassess our goodwill for impairment as of September 30, 2015. Based on the results of this assessment, we concluded no impairment was required. The fair value of the North America E&P and International E&P reporting units exceeded their respective book values by a significant margin. Changes in management's forecast commodity price assumptions may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.

Income Tax Estimates - Deferred Tax Assets

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

Accounting Standards Not Yet Adopted

See Note 2 to the consolidated financial statements.

3234

Cash Flows and Liquidity

Cash Flows

The following table presents sources and uses of cash and cash ~~equivalents:~~equivalents


	Six Months Ended June 30,						Nine Months Ended September 30,
(In millions)	2015			2014			2015			2014
Sources of cash and cash equivalents
Continuing operations	$	717		$	2,118
Discontinued operations	—			440
Operating activities of continued operations							$	1,213		$	3,476
Operating activities of discontinued operations							—			856
Borrowings	1,996			—			1,996			—
Disposals of assets	2			2,232			105			2,237
Maturities of short-term investments							225			—
Other	43			113			97			196
Total sources of cash and cash equivalents	$	2,758		$	4,903		$	3,636		$	6,765
Uses of cash and cash equivalents
Cash additions to property, plant and equipment	$	(2,320	)	$	(2,230	)	$	(2,948	)	$	(3,639	)
Investing activities of discontinued operations	—			(233		)	—			(356		)
Purchases of short-term investments	(925		)	—			(925		)	—
Debt issuance costs	(19		)	—			(19		)	—
Debt repayments	(34		)	(34		)	(34		)	(34		)
Dividends paid	(285		)	(260		)	(427		)	(401		)
Purchases of common stock	—			(1,000		)	—			(1,000		)
Commercial paper, net	—			(135		)	—			(135		)
Other	(1		)	(10		)	(1		)	(48		)
Cash held for sale	—			(96		)	—			(655		)
Total uses of cash and cash equivalents	$	(3,584	)	$	(3,998	)	$	(4,354	)	$	(6,268	)

Commodity prices began declining in the second half of 2014 and remain substantially lower through ~~2015 as compared to the first six months of 2014.~~2015. This lower price trend adversely impacted our cash flows in 2015. Partially offsetting the decline in prices were increased net sales volumes in the North America E&P ~~segment.~~and OSM segments. While we are unable to predict future commodity price movements, if this lower price environment continues, it would continue to negatively impact our cash flows from operating activities as compared to the previous year.

Borrowings reflect net proceeds received from the issuance of senior notes in June 2015. See Liquidity and Capital Resources below for additional information.

Cash flows from discontinued operations are primarily related to our Norway business, which we disposed of in the fourth quarter of 2014. Disposal of assets in 2015 pertain to the August 2015 sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets. Disposals of assets in ~~the first six months of~~ 2014 primarily reflect the net proceeds from the sales of our Angola assets. Disposition transactions are discussed in further detail in Note 56 to the consolidated financial statements.

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

Certain of our short-term investments matured in September 2015. Purchases of short-term investments in 2015 were made from proceeds received from the senior notes issuance in June 2015. The investments ~~consist~~consisted of time deposits with maturity dates ranging from September - October 2015.

3335

Additions to property, plant and equipment are our most significant use of cash and cash equivalents. The following table shows capital expenditures by segment and reconciles to additions to property, plant and equipment in continuing operations as presented in the consolidated statements of cash flows:


	Six Months Ended June 30,					Nine Months Ended September 30,
(In millions)	2015		2014			2015		2014
North America E&P	$	1,484	$	1,969		$	2,048	$	3,246
International E&P	245		220			275		386
Oil Sands Mining	37		123			26		172
Corporate	14		13			26		29
Total capital expenditures	1,780		2,325			2,375		3,833
(Increase) decrease in capital expenditure accrual	540		(95		)	573		(194		)
Total use of cash and cash equivalents for property, plant and equipment	$	2,320	$	2,230		$	2,948	$	3,639

During the first ~~six~~nine months of 2014, we acquired 29 million common shares at a cost of $1 billion under our share repurchase ~~program, 13 million of which~~program. There were ~~acquired in the second quarter of 2014 at a cost of $449 million.~~no stock repurchases during 2015.

Liquidity and Capital Resources

On June 10, 2015, we issued $2 billion aggregate principal amount of unsecured senior notes which consist of the following series:

•$600 million of 2.70% senior notes due June 1, 2020

•$900 million of 3.85% senior notes due June 1, 2025

•$500 million of 5.20% senior notes due June 1, 2045

Interest on each series of senior notes is payable semi-annually beginning December 1, 2015. We ~~will use~~used the aggregate net proceeds to repay our $1 billion 0.90% senior notes ~~due 2015, which mature~~ on November 1,2, 2015, and the remainder for general corporate purposes.

In May 2015, we amended our $2.5 billion ~~unsecured revolving credit facility (as so amended, the "Credit Facility")~~Credit Facility to increase the facility size by $500 million to a total of $3 billion and extend the maturity date by an additional year such that the Credit Facility now matures in May 2020. The amendment additionally provides us the ability to request two one-year extensions to the maturity date and an option to increase the commitment amount by up to an additional $500 million, subject to the consent of any increasing lenders. The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unchanged.

Our main sources of liquidity are cash and cash equivalents, short-term investments, internally generated cash flow from operations, the issuance of notes, our $3 billion Credit Facility and sales of non-core assets. Our working capital requirements are supported by these sources and we may also issue commercial paper, which is backed by our revolving credit facility. Furthermore, we actively manage our capital spending program, including the level and timing of activities associated with our drilling programs. Because of the alternatives available to us as discussed above, and access to capital markets through the shelf registration discussed below, we believe that our liquidity is adequate to fund not only our current operations, but also our funding requirements for the foreseeable future, including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, and other amounts that may ultimately be paid in connection with contingencies.

~~Outlook~~

We expect our capital, investment and exploration spending budget for full-year 2015 to be at or below $3.3 billion and estimate full-year North America E&P and International E&P production volumes (excluding Libya) to be 375-390 net mboed.

3436

Capital Resources

Credit Arrangements and Borrowings

At ~~June~~September 30, 2015, we had no borrowings against our revolving credit facility and no amounts outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.

At ~~June~~September 30, 2015, we had $8.4 billion in long-term debt outstanding, of which approximately $1.0 billion ~~matures~~matured and was repaid in November 2015. We utilized cash on hand and proceeds from the ~~fourth quarter~~maturities of ~~2015.~~our short-term investments to fund the debt payment. We do not have any triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit ratings.

Shelf Registration

We have a universal shelf registration statement filed with the SEC under which we, as a "well-known seasoned issuer" for purposes of SEC rules, have the ability to issue and sell an indeterminate amount of various types of equity and debt securities.

Asset Disposals

We are targeting to generate at least $500 million from select non-core asset sales. During the third quarter of 2015, we closed the sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets for proceeds of approximately $100 million and announced the sale of our Kenya and Ethiopia exploration acreage. See Note 6 to the consolidated financial statements for additional discussion of these dispositions.

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

Our cash and short-term investments-adjusted debt-to-capital ratio (total debt-minus-cash and cash equivalents and short-term investments to total debt-plus-equity-minus-cash and cash equivalents and short-term investments) was ~~22%~~24% at ~~June~~September 30, 2015, compared to 16% at December 31, 2014.


	June 30,			December 31,			September 30,			December 31,
(In millions)	2015			2014			2015			2014
Long-term debt due within one year	$	1,035		$	1,068		$	1,035		$	1,068
Long-term debt	7,321			5,323			7,323			5,323
Total debt	$	8,356		$	6,391		$	8,358		$	6,391
Cash and cash equivalents	$	1,572		$	2,398		$	1,680		$	2,398
Short-term investments	$	925		$	—		$	700		$	—
Equity	$	20,218		$	21,020		$	19,335		$	21,020
Calculation:
Total debt	$	8,356		$	6,391		$	8,358		$	6,391
Minus cash and cash equivalents	1,572			2,398			1,680			2,398
Minus short-term investments	925			—			700			—
Total debt minus cash, cash equivalents and short-term investments	$	5,859		$	3,993		$	5,978		$	3,993
Total debt	$	8,356		$	6,391		$	8,358		$	6,391
Plus equity	20,218			21,020			19,335			21,020
Minus cash and cash equivalents	1,572			2,398			1,680			2,398
Minus short-term investments	925			—			700			—
Total debt plus equity minus cash, cash equivalents and short-term investments	$	26,077		$	25,013		$	25,313		$	25,013
Cash and short-term investments-adjusted debt-to-capital ratio	22		%	16		%	24		%	16		%

Capital Requirements

~~As noted above in "Outlook," we~~We expect our revised total capital, investment and exploration spending budget for full-year 2015 to be ~~at or below $3.3 billion.~~$3.1 billion which is $200 million less than our previous budget.

On ~~July 29,~~October 28, 2015, our Board of Directors approved a dividend of ~~$0.21~~$0.05 per share for the ~~second~~third quarter of 2015 payable ~~September~~December 10, 2015 to stockholders of record at the close of business on ~~August 19,~~November 18, 2015. This dividend represents a reduction from the previous quarterly dividend of $0.21 per share as we continue to address the uncertainty of a lower for longer commodity price environment, align with our priority of maintaining a strong balance sheet through the cycle, and provide additional capital flexibility to support growth from the U.S. resource plays when commodity prices improve.

As of ~~June~~September 30, 2015, we plan to make contributions of up to ~~$42~~$18 million to our funded pension plans during the remainder of 2015.

Contractual Cash Obligations

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

Environmental Matters

We have incurred and will continue to incur capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes.

There have been no significant changes to our environmental matters subsequent to December 31, 2014.

Other Contingencies

Forward-Looking Statements

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the "Exchange Act"). All statements other than statements of historical fact included or incorporated by reference in this report are forward-looking statements, including without limitation statements ~~regarding~~regarding: our operational, financial and growth strategies, including planned projects, drilling plans, maintenance activities, asset sales, productivity improvements, and drilling and completion efficiencies; our ability to effect those strategies and the expected timing and results thereof, planned capital expenditures and the impact thereof, future drilling plans, timing and expectations, maintenance activities and the timing and impact thereof, well spud timing and expectations,thereof; our financial and operational outlook and ability to fulfill that ~~outlook,~~outlook; expectations regarding future economic and market conditions and their effects on our business; our 2015 and 2016 capital, investment and exploration programs, including planned allocation and reductions, and the expected benefits thereof; our declared dividend and the expected benefits thereof; our financial position, liquidity and capital ~~resources, our 2015 budget and planned allocation,~~resources; production guidance; and the plans and objectives of our management for our future operations. In addition, many forward-looking statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “estimate,” “expect,” “target,” “plan,” “project,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. While we believe that our assumptions concerning future events are reasonable, a number of factors could cause results to differ materially from those indicated by such forward-looking statements including, but not limited to:

conditions in the oil and gas industry, including supply/demand levels and the resulting impact on price;

changes in expected reserve or production levels;

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

capital available for exploration and development;

well production timing;

availability of drilling rigs, materials and labor;

difficulty in obtaining necessary approvals and permits;

non-performance by third parties of contractual obligations;

unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto;

cyber-attacks;

changes in safety, health, environmental and other regulations;

other geological, operating and economic considerations; and

the risk factors, forward-looking statements and challenges and uncertainties described in our 2014 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and ~~those set forth from time to time in 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 as a result of new information, future events or otherwise.

3638

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For a detailed discussion of our risk management strategies and our derivative instruments, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk in our 2014 Annual Report on Form 10-K. Additional disclosures regarding our open derivative positions, including underlying notional quantities, how they are reported in our consolidated financial statements and how their fair values are measured, may be found in Notes 1215 and 1316 to the consolidated financial statements.

Commodity Price Risk During the first ~~six~~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 ~~June~~September 30, 2015:


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

Ceiling	$71.84	12,000	January- December 2016	$60.00	2,000	October 2015- March 2016 ^(a)
Floor	$60.48			$50.00
Sold put	$50.00			$40.00

Ceiling	$73.13	2,000	January- June 2016 ^(b)	$71.84	12,000	January- December 2016
Floor	$65.00			$60.48
Sold put	$50.00			$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)	$72.39	10,000	January- December 2016 ^(c)

^(a)


^(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 ~~June~~September 30, 2015.


(In millions)	Hypothetical Price Increase of 10%			Hypothetical Price Decrease of 10%		Hypothetical Price Increase of 10%			Hypothetical Price Decrease of 10%
Crude oil commodity derivatives	$	(67	)	$	51	$	(46	)	$	6

Interest Rate Risk Sensitivity analysis of the incremental effect of a hypothetical 10 percent change in interest rates on financial assets and liabilities as of ~~June~~September 30, 2015, is provided in the following table.


(In millions)	Fair Value				Incremental Change in Fair Value			Fair Value				Incremental Change in Fair Value
Financial assets (liabilities):
Long term debt, including amounts due within one year	$	(8,720	)	^(a)(b)	$	(288	)	$	(8,302	)	^(a)(b)	$	(295	)


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


^(b)	Excludes capital leases.

3739

Item 4. Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this Report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as of ~~June~~September 30, 2015.

During the ~~second~~third quarter of 2015, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

Three Months Ended Six Months Ended
June 30, June 30,
(In millions) 2015 2014 2015 2014
Segment Income (Loss)
North America E&P $ (45 ) $ 302
$ (206 ) $ 544
International E&P 41
160
64
381
Oil Sands Mining (77 ) 55
(96 ) 119
Segment income (loss) (81 ) 517
(238 ) 1,044
Items not allocated to segments, net of income taxes (305 ) (157 ) (424 ) (286 )
Income (loss) from continuing operations (386 ) 360
(662 ) 758
Discontinued operations ^(a)
—
180
—
931
Net income (loss) $ (386 ) $ 540
$ (662 ) $ 1,689
Capital Expenditures ^(b)

North America E&P $ 551
$ 1,102
$ 1,484
$ 1,969
International E&P 99
115
245
220
Oil Sands Mining 16
55
37
123
Corporate 12
10
14
13
Discontinued operations ^(a)
—
141
—
251
Total $ 678
$ 1,423
$ 1,780
$ 2,576
Exploration Expenses

North America E&P $ 91
$ 82
$ 126
$ 139
International E&P 20
63
75
79
Total $ 111
$ 145
$ 201
$ 218


^(a)	~~As a result of the sale of our Angola assets and our Norway business, both are reflected as discontinued operations in 2014.~~


^(b)	~~Includes accruals.~~

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

Three Months Ended Six Months Ended
June 30, June 30,
Net Sales Volumes 2015 2014 2015 2014
North America E&P

Crude Oil and Condensate (mbbld)

Bakken 54
44 53
41
Eagle Ford 82
67 87
65
Oklahoma Resource Basins 5
2 5
2
Other North America ^(c)
35
38 35
36
Total Crude Oil and Condensate 176
151 180
144
Natural Gas Liquids (mbbld)

Bakken 3
3 3
2
Eagle Ford 26
16 26
16
Oklahoma Resource Basins 6
6 6
5
Other North America ^(c)
2
2 3
4
Total Natural Gas Liquids 37
27 38
27
Total Liquid Hydrocarbons (mbbld)

Bakken 57
47 56
43
Eagle Ford 108
83 113
81
Oklahoma Resource Basins 11
8 11
7
Other North America ^(c)
37
40 38
40
Total Liquid Hydrocarbons 213
178 218
171
Natural Gas (mmcfd)

Bakken 22
18 20
17
Eagle Ford 164
111 167
109
Oklahoma Resource Basins 81
61 79
58
Other North America ^(c)
94
104 94
113
Total Natural Gas 361
294 360
297
Equivalent Barrels (mboed)

Bakken 61
50 59
46
Eagle Ford 135
102 141
99
Oklahoma Resource Basins 24
18 24
17
Other North America ^(c)
54
57 54
58
Total North America E&P 274
227 278
220


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

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

Three Months Ended Six Months Ended
June 30, June 30,
Net Sales Volumes 2015 2014 2015 2014
International E&P
Crude Oil and Condensate (mbbld)

Equatorial Guinea 19
20
18
22
United Kingdom 14
13
14
13
Total Crude Oil and Condensate 33
33
32
35
Natural Gas Liquids (mbbld)

Equatorial Guinea 9
11
10
11
Total Natural Gas Liquids 9
11
10
11
Total Liquid Hydrocarbons (mbbld)

Equatorial Guinea 28
31
28
33
United Kingdom 14
13
14
13
Total Liquid Hydrocarbons 42
44
42
46
Natural Gas (mmcfd)

Equatorial Guinea 365
446
390
441
United Kingdom ^(d)
31
28
32
29
Libya —
—
—
1
Total Natural Gas 396
474
422
471
Equivalent Barrels (mboed)

Equatorial Guinea 89
105
93
107
United Kingdom ^(d)
19
18
19
18
Total International E&P 108
123
112
125
Oil Sands Mining
Synthetic Crude Oil (mbbld) ^(e)
29
44
44
45
Total Continuing Operations (mboed)
411
394
434
390
Discontinued Operations - Angola (mboed) ^(a)
—
—
—
3
Discontinued Operations - Norway (mboed) ^(a)
—
70
—
70
Total Company (mboed)
411
464
434
463
Net Sales Volumes of Equity Method Investees
LNG (mtd)
4,991
6,624
5,629
6,601
Methanol (mtd)
673
980
778
1,066


^(d)	~~Includes natural gas acquired for injection and subsequent resale of 7 mmcfd and 5 mmcfd for the second quarters of 2015 and 2014, and 9 mmcfd and 6 mmcfd for the first six months of 2015 and 2014.~~


^(e)	~~Includes blendstocks.~~

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

Three Months Ended Six Months Ended
June 30, June 30,
Average Price Realizations ^(f)
2015 2014 2015 2014
North America E&P
Crude Oil and Condensate (per bbl) ^(g)

Bakken $51.36 $93.08 $45.84 $91.43
Eagle Ford 53.47 99.08 47.81 97.65
Oklahoma Resource Basins 51.00 101.12 48.34 98.05
Other North America ^(c)
52.83 93.45 47.10 91.40
Total Crude Oil and Condensate 52.63 95.95 47.11 94.30
Natural Gas Liquids (per bbl)

Bakken $11.63 $45.13 $7.19 $51.04
Eagle Ford 14.08 30.20 13.90 33.76
Oklahoma Resource Basins 14.45 33.04 15.83 38.21
Other North America ^(c)
25.65 54.13 26.03 57.65
Total Natural Gas Liquids 14.77 34.80 14.60 38.75
Total Liquid Hydrocarbons (per bbl)

Bakken $49.29 $90.47 $43.72 $89.16
Eagle Ford 44.05 85.36 40.01 84.78
Oklahoma Resource Basins 30.29 52.00 29.24 55.04
Other North America ^(c)
50.89 90.45 45.52 88.97
Total Liquid Hydrocarbons 45.96 86.43 41.37 85.65
Natural Gas (per mcf)

Bakken $2.62 $4.12 $2.76 $6.14
Eagle Ford 2.71 4.76 2.79 4.83
Oklahoma Resource Basins 2.64 4.57 2.63 5.01
Other North America^(c)
2.98 5.65 3.29 5.35
Total Natural Gas 2.76 5.00 2.88 5.14


^(f)	~~Excludes gains or losses on derivative instruments.~~


^(g)	Inclusion of realized gains on crude oil derivative instruments would have increased average crude oil price realizations by $0.06 and $0.14 per bbl for the second quarter and first six months of 2015. There were no crude oil derivative instruments in 2014.

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

Three Months Ended Six Months Ended
June 30, June 30,
Average Price Realizations 2015 2014 2015 2014
International E&P
Crude Oil and Condensate (per bbl)

Equatorial Guinea $52.27 $90.91 $47.55 $90.66
United Kingdom 62.97 111.76 60.19 111.38
Total Crude Oil and Condensate 56.70 99.36 52.92 98.51
Natural Gas Liquids (per bbl)

Equatorial Guinea ^(h)
$1.00 $1.00 $1.00 $1.00
United Kingdom 36.49 64.37 34.82 69.56
Total Natural Gas Liquids 3.10 3.02 3.29 3.64
Total Liquid Hydrocarbons (per bbl)

Equatorial Guinea $35.74 $59.72 $31.81 $61.12
United Kingdom 61.93 110.51 58.96 110.02
Total Liquid Hydrocarbons 44.70 75.41 41.06 75.48
Natural Gas (per mcf)

Equatorial Guinea ^(h)
$0.24 $0.24 $0.24 $0.24
United Kingdom 6.98 8.04 7.34 9.07
Libya —
—
—
5.45
Total Natural Gas 0.78 0.69 0.78 0.80
Oil Sands Mining
Synthetic Crude Oil (per bbl)
$52.46 $94.17 $44.33 $91.27
Discontinued Operations - Angola (per boe) ^(a)
—
—
—
$99.82
Discontinued Operations - Norway (per boe) ^(a)
—
$108.11 —
$108.09


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

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

Total Number of Average Price
Total Number of
Shares Purchased
as Part of
Publicly Announced

Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Period
Shares Purchased ^(a)
Paid per Share Plans or Programs Plans or Programs
04/01/15 - 04/30/15 151,874
27.61
—
$1,500,285,529
05/01/15 - 05/31/15 6,614
29.85
—
$1,500,285,529
06/01/15 - 06/30/15 3,231
27.11
—
$1,500,285,529
Total 161,719
27.69
—



	Total Number of	Average Price	Total Number of Shares Purchased as Part of Publicly Announced	Approximate Dollar Value of Shares that May Yet Be Purchased Under the
Period	Shares Purchased ^(a)	Paid per Share	Plans or Programs	Plans or Programs
07/01/15 - 07/31/15	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)	~~161,719~~55,320 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

Item 5. Other Information

As we previously disclosed in a Form 8-K filed with the SEC on August 28, 2015, our Board of Directors amended and restated our By-laws, effective September 1, 2015, to modify the existing proxy access provisions of the By-laws to coincide with the stockholder proposal that was approved at our 2015 annual meeting of stockholders.

Pursuant to these amendments, the required ownership percentage needed to use the proxy access provisions was decreased to 3% of Marathon Oil’s outstanding common stock, owned continuously for at least three years. Additionally, the maximum number of stockholder nominees that may be included in the proxy statement pursuant to these provisions was increased to 25% of the number of directors in office as of the last day on which notice requesting proxy access may be delivered by an eligible stockholder.

Item 6. Exhibits

The information required by this Item 6 is set forth in the Exhibit Index accompanying this ~~quarterly report on~~ Form 10-Q.

4441

SIGNATURES

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



~~August 6,~~November 5, 2015		MARATHON OIL CORPORATION

	By:	/s/ Gary E. Wilson
		Gary E. Wilson
		Vice President, Controller and Chief Accounting Officer
		(Duly Authorized Officer)

4542

Exhibit Index

Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
Exhibit Number Exhibit 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 April 9, 2015) 8-K 3.1 4/10/2015
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
10.1 First Amendment, dated as of May 5, 2015, to the Amended and Restated Credit Agreement dated as of May 28, 2014, by and among Marathon Oil Corporation, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions named therein 10-Q 10.1 5/07/2015
12.1 Computation of Ratio of Earnings to Fixed Charges*
31.1 Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934*
31.2 Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934*
32.1 Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350*
32.2 Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350*
101.INS XBRL Instance Document*
101.SCH XBRL Taxonomy Extension Schema*
101.CAL XBRL Taxonomy Extension Calculation Linkbase*
101.DEF XBRL Taxonomy Extension Definition Linkbase*
101.LAB XBRL Taxonomy Extension Label Linkbase*
101.PRE XBRL Taxonomy Extension Presentation Linkbase*
* Filed herewith.
++ Marathon Oil agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request.



		Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
Exhibit Number	Exhibit 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.



	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	38
	~~Supplemental Statistics (Unaudited)~~	3940
Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	4441
Item 1A.	Risk Factors	4441
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4441
Item 5.	Other Information	41
Item 6.	Exhibits	4441
	Signatures	4542



	Six Months Ended June 30, 2015
									Not Allocated
(In millions)	N.A. E&P			Int'l E&P		OSM			to Segments				Total
Sales and other operating revenues	$	1,843		$	393	$	372		$	(21	)	^(c)	$	2,587
Marketing revenues	288			56		43			—				387
Total revenues	2,131			449		415			(21		)		2,974
Income from equity method investments	—			62		—			—				62
Net gain on disposal of assets and other income	11			14		1			1				27
Less:
Production expenses	381			131		382			—				894
Marketing costs	292			54		41			—				387
Exploration expenses	126			75		—			—				201
Depreciation, depletion and amortization	1,317			135		97			23				1,572
Impairments	—			—		—			44			^(d)	44
Other expenses ^(a)	216			42		18			251			^(e)	527
Taxes other than income	128			—		10			7				145
Net interest and other	—			—		—			105				105
Income tax provision (benefit)	(112		)	24		(36		)	(26		)	^(f)	(150		)
Segment income (loss) /Loss from continuing operations	$	(206	)	$	64	$	(96	)	$	(424	)		$	(662	)
Capital expenditures ^(b)	$	1,484		$	245	$	37		$	14			$	1,780



	Six Months Ended June 30, 2014
							Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	2,932	$	727	$	760	$	—			$	4,419
Marketing revenues	980		131		48		—				1,159
Total revenues	3,912		858		808		—				5,578
Income from equity method investments	—		257		—		—				257
Net gain (loss) on disposal of assets and other income	18		32		3		(98		)	^(c)	(45		)
Less:
Production expenses	428		199		477		—				1,104
Marketing costs	977		131		48		—				1,156
Exploration expenses	139		79		—		—				218
Depreciation, depletion and amortization	1,065		146		90		22				1,323
Impairments	21		—		—		—				21
Other expenses ^(a)	236		72		26		196			^(d)	530
Taxes other than income	192		—		11		1				204
Net interest and other	—		—		—		125				125
Income tax provision (benefit)	328		139		40		(156		)		351
Segment income /Income from continuing operations	$	544	$	381	$	119	$	(286	)		$	758
Capital expenditures ^(b)	$	1,969	$	220	$	123	$	13			$	2,325