UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended ~~March 31,~~June 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 ~~674,954,423~~677,184,913 shares of Marathon Oil Corporation common stock outstanding as of ~~April 30,~~July 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).

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)


	Three Months Ended						Three Months Ended						Six Months Ended
	March 31,						June 30,						June 30,
(In millions, except per share data)	2015			2014			2015			2014			2015			2014
Revenues and other income:
Sales and other operating revenues, including related party	$	1,280		$	2,149		$	1,307		$	2,270		$	2,587		$	4,419
Marketing revenues	204			541			183			618			387			1,159
Income from equity method investments	36			137			26			120			62			257
Net gain on disposal of assets	1			2
Net gain (loss) on disposal of assets							—			(87		)	1			(85		)
Other income	11			20			15			20			26			40
Total revenues and other income	1,532			2,849			1,531			2,941			3,063			5,790
Costs and expenses:
Production	444			542			450			562			894			1,104
Marketing, including purchases from related parties	205			542			182			614			387			1,156
Other operating	107			103			81			101			188			204
Exploration	90			73			111			145			201			218
Depreciation, depletion and amortization	821			643			751			680			1,572			1,323
Impairments	—			17			44			4			44			21
Taxes other than income	67			95			78			109			145			204
General and administrative	171			187			168			139			339			326
Total costs and expenses	1,905			2,202			1,865			2,354			3,770			4,556
Income (loss) from operations	(373		)	647			(334		)	587			(707		)	1,234
Net interest and other	(47		)	(49		)	(58		)	(76		)	(105		)	(125		)
Income (loss) from continuing operations before income taxes	(420		)	598			(392		)	511			(812		)	1,109
Provision (benefit) for income taxes	(144		)	200			(6		)	151			(150		)	351
Income (loss) from continuing operations	(276		)	398			(386		)	360			(662		)	758
Discontinued operations	—			751			—			180			—			931
Net income (loss)	$	(276	)	$	1,149		$	(386	)	$	540		$	(662	)	$	1,689
Per basic share:
Income (loss) from continuing operations	$	(0.41	)	$	0.58		$	(0.57	)	$	0.53		$	(0.98	)	$	1.11
Discontinued operations	$	—		$	1.08		$	—		$	0.27		$	—		$	1.36
Net income (loss)	$	(0.41	)	$	1.66		$	(0.57	)	$	0.80		$	(0.98	)	$	2.47
Per diluted share:
Income (loss) from continuing operations	$	(0.41	)	$	0.57		$	(0.57	)	$	0.53		$	(0.98	)	$	1.10
Discontinued operations	$	—		$	1.08		$	—		$	0.27		$	—		$	1.36
Net income (loss)	$	(0.41	)	$	1.65		$	(0.57	)	$	0.80		$	(0.98	)	$	2.46
Dividends per share	$	0.21		$	0.19		$	0.21		$	0.19		$	0.42		$	0.38
Weighted average common shares outstanding:
Basic	675			693			677			676			676			684
Diluted	675			696			677			679			676			688

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

MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income (Unaudited)


	Three Months Ended						Three Months Ended						Six Months Ended
	March 31,						June 30,						June 30,
(In millions)	2015			2014			2015			2014			2015			2014
Net income (loss)	$	(276	)	$	1,149		$	(386	)	$	540		$	(662	)	$	1,689
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	76			(30		)	86			(13		)	162			(43		)
Income tax benefit (provision)	(27		)	10			(30		)	5			(57		)	15
Postretirement and postemployment plans, net of tax	49			(20		)	56			(8		)	105			(28		)
Comprehensive income (loss)	$	(227	)	$	1,129		$	(330	)	$	532		$	(557	)	$	1,661

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)


	March 31,			December 31,			June 30,			December 31,
(In millions, except per share data)	2015			2014			2015			2014
Assets
Current assets:
Cash and cash equivalents	$	1,126		$	2,398		$	1,572		$	2,398
Short-term investments							925			—
Receivables, less reserve of $4 and $3	1,341			1,729			1,195			1,729
Inventories	379			357			336			357
Other current assets	122			109			102			109
Total current assets	2,968			4,593			4,130			4,593
Equity method investments	1,100			1,113			1,045			1,113
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $22,648 and $21,884	29,291			29,040
depletion and amortization of $23,395 and $21,884							29,121			29,040
Goodwill	459			459			459			459
Other noncurrent assets	918			806			1,015			806
Total assets	$	34,736		$	36,011		$	35,770		$	36,011
Liabilities
Current liabilities:
Accounts payable	$	1,854		$	2,545		$	1,507		$	2,545
Payroll and benefits payable	127			191			119			191
Accrued taxes	260			285			156			285
Other current liabilities	252			290			235			290
Long-term debt due within one year	1,068			1,068			1,035			1,068
Total current liabilities	3,561			4,379			3,052			4,379
Long-term debt	5,326			5,323			7,321			5,323
Deferred tax liabilities	2,437			2,486			2,531			2,486
Defined benefit postretirement plan obligations	515			598			438			598
Asset retirement obligations	1,949			1,917			1,963			1,917
Deferred credits and other liabilities	288			288			247			288
Total liabilities	14,076			14,991			15,552			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 – 95 million and 95 million shares	(3,634		)	(3,642		)
Held in treasury, at cost – 93 million and 95 million shares							(3,555		)	(3,642		)
Additional paid-in capital	6,532			6,531			6,484			6,531
Retained earnings	17,220			17,638			16,691			17,638
Accumulated other comprehensive loss	(228		)	(277		)	(172		)	(277		)
Total stockholders' equity	20,660			21,020			20,218			21,020
Total liabilities and stockholders' equity	$	34,736		$	36,011		$	35,770		$	36,011

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)


	Three Months Ended						Six Months Ended
	March 31,						June 30,
(In millions)	2015			2014			2015			2014
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income (loss)	$	(276	)	$	1,149		$	(662	)	$	1,689
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations	—			(751		)	—			(931		)
Deferred income taxes	(179		)	89			(185		)	173
Depreciation, depletion and amortization	821			643			1,572			1,323
Impairments	—			17			44			21
Pension and other postretirement benefits, net	(7		)	19			14			26
Exploratory dry well costs and unproved property impairments	67			43			148			156
Net gain on disposal of assets	(1		)	(2		)
Net (gain) loss on disposal of assets							(1		)	85
Equity method investments, net	3			(42		)	37			(10		)
Changes in:
Current receivables	388			(69		)	534			(266		)
Inventories	(22		)	(41		)	21			(58		)
Current accounts payable and accrued liabilities	(469		)	33			(770		)	(31		)
All other operating, net	(16		)	(19		)	(35		)	(59		)
Net cash provided by continuing operations	309			1,069			717			2,118
Net cash provided by discontinued operations	—			401			—			440
Net cash provided by operating activities	309			1,470			717			2,558
Investing activities:
Additions to property, plant and equipment	(1,452		)	(1,004		)	(2,320		)	(2,230		)
Disposal of assets	2			2,123			2			2,232
Investments - return of capital	10			20			31			27
Purchases of short-term investments							(925		)	—
Investing activities of discontinued operations	—			(96		)	—			(233		)
All other investing, net	(2		)	5			(1		)	—
Net cash provided by (used in) investing activities	(1,442		)	1,048
Net cash used in investing activities							(3,213		)	(204		)
Financing activities:
Commercial paper, net	—			(135		)	—			(135		)
Borrowings							1,996			—
Debt issuance costs							(19		)	—
Debt repayments							(34		)	(34		)
Purchases of common stock	—			(551		)	—			(1,000		)
Dividends paid	(142		)	(133		)	(285		)	(260		)
All other financing, net	4			9			11			86
Net cash used in financing activities	(138		)	(810		)
Net cash provided by (used in) financing activities							1,669			(1,343		)
Effect of exchange rate on cash and cash equivalents:
Continuing operations	(1		)	—			1			—
Discontinued operations	—			(8		)	—			(10		)
Cash held for sale							—			(96		)
Net increase (decrease) in cash and cash equivalents	(1,272		)	1,700			(826		)	905
Cash and cash equivalents at beginning of period	2,398			264			2,398			264
Cash and cash equivalents at end of period	$	1,126		$	1,964		$	1,572		$	1,169

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") and do not include all of the information and disclosures required by accounting principles generally accepted in the United States ("U.S. 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 2014 Annual Report on Form 10-K. The results of operations for the second quarter and first ~~quarter~~six 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. 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 in 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 the equity holders at risk lack decision making rights. This standard is effective for us in the first quarter of 2016 and early adoption is permitted, including in interim periods. 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 ~~2017~~2018 and should be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. Early adoption is ~~not permitted.~~permitted with an effective date no earlier than first quarter of 2017. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Recently Adopted

In April 2014, the FASB issued an amendment to accounting standards that changes the criteria for reporting discontinued operations while enhancing related disclosures. Under the amendment, only disposals representing a strategic shift in operations should be presented as discontinued operations. 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.

~~MARATHON OIL CORPORATION~~

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

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 $1$2 million recorded at ~~March 31,~~June 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 ~~$506~~$508 million as of ~~March 31,~~June 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 5 million stock options for the second quarters of 2015 and 2014 and 13 million and 4 million stock options for the first ~~three~~six months of 2015 and 2014 that were antidilutive.


	Three Months Ended March 31,					Three Months Ended June 30,					Six Months Ended June 30,
(In millions, except per share data)	2015			2014		2015			2014		2015			2014
Income (loss) from continuing operations	$	(276	)	$	398	$	(386	)	$	360	$	(662	)	$	758
Discontinued operations	—			751		—			180		—			931
Net income (loss)	$	(276	)	$	1,149	$	(386	)	$	540	$	(662	)	$	1,689

Weighted average common shares outstanding	675			693		677			676		676			684
Effect of dilutive securities	—			3		—			3		—			4
Weighted average common shares, diluted	675			696		677			679		676			688
Per basic share:
Income (loss) from continuing operations	$	(0.41	)	$	0.58	$	(0.57	)	$	0.53	$	(0.98	)	$	1.11
Discontinued operations	$	—		$	1.08	$	—		$	0.27	$	—		$	1.36
Net income (loss)	$	(0.41	)	$	1.66	$	(0.57	)	$	0.80	$	(0.98	)	$	2.47
Per diluted share:
Income (loss) from continuing operations	$	(0.41	)	$	0.57	$	(0.57	)	$	0.53	$	(0.98	)	$	1.10
Discontinued operations	$	—		$	1.08	$	—		$	0.27	$	—		$	1.36
Net income (loss)	$	(0.41	)	$	1.65	$	(0.57	)	$	0.80	$	(0.98	)	$	2.46

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


5.	Dispositions

2015 - North America E&P Segment

In July 2015, we entered into an agreement to sell our East Texas/North Louisiana and Wilburton, Oklahoma natural gas assets for expected proceeds of $102 million, excluding closing adjustments. We expect the transaction to close during the third quarter of 2015.

2014 - North America E&P Segment

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

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:

Three Months Ended March 31,
(In millions) 2014
Revenues applicable to discontinued operations $ 680
Pretax income from discontinued operations $ 532
After-tax income from discontinued operations $ 142



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

^(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:


	Three Months Ended March 31,		Six Months Ended June 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

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

International 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 ~~LNG~~liquefied natural gas ("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 ~~(as determined by the CODM)~~ also are not allocated to operating segments.

As discussed in Note 5, 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 E&P segment for 2014.

~~MARATHON OIL CORPORATION~~

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


	Three Months Ended March 31, 2015																Three Months Ended June 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	$	850		$	182		$	225		$	23		^(c)	$	1,280		$	993		$	211	$	147		$	(44	)	^(c)	$	1,307
Marketing revenues	178			26			—			—				204			110			30		43			—				183
Total revenues	1,028			208			225			23				1,484			1,103			241		190			(44		)		1,490
Income from equity method investments	—			36			—			—				36			—			26		—			—				26
Net gain on disposal of assets and other income	—			10			1			1				12			11			4		—			—				15
Less:
Production expenses	202			67			175			—				444			179			64		207			—				450
Marketing costs	180			25			—			—				205			112			29		41			—				182
Exploration expenses	35			55			—			—				90			91			20		—			—				111
Depreciation, depletion and amortization	683			64			62			12				821			634			71		35			11				751
Impairments																	—			—		—			44			^(d)	44
Other expenses ^(a)	117			23			9			129			^(d)	278			99			19		9			122			^(e)	249
Taxes other than income	61			—			5			1				67			67			—		5			6				78
Net interest and other	—			—			—			47				47			—			—		—			58				58
Income tax benefit	(89		)	(3		)	(6		)	(46		)		(144		)
Segment income (loss) /Income (loss) from continuing operations	$	(161	)	$	23		$	(19	)	$	(119	)		$	(276	)
Income tax provision (benefit)																	(23		)	27		(30		)	20			^(f)	(6		)
Segment income (loss) /Loss from continuing operations																	$	(45	)	$	41	$	(77	)	$	(305	)		$	(386	)
Capital expenditures ^(b)	$	933		$	146		$	21		$	2			$	1,102		$	551		$	99	$	16		$	12			$	678


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


^(b)	Includes accruals.


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


^(d)	Proved property impairment (See Note 12).


^(e)	Includes pension settlement loss of $64 million (see Note 7).


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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



	Three 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	$	1,540	$	347	$	383	$	—			$	2,270
Marketing revenues	540		61		17		—				618
Total revenues	2,080		408		400		—				2,888
Income from equity method investments	—		120		—		—				120
Net gain (loss) on disposal of assets and other income	15		15		1		(98		)	^(c)	(67		)
Less:
Production expenses	217		99		246		—				562
Marketing costs	537		60		17		—				614
Exploration expenses	82		63		—		—				145
Depreciation, depletion and amortization	550		75		45		10				680
Impairments	4		—		—		—				4
Other expenses ^(a)	126		34		13		67			^(d)	240
Taxes other than income	102		—		6		1				109
Net interest and other	—		—		—		76				76
Income tax provision (benefit)	175		52		19		(95		)		151
Segment income/Income from continuing operations	$	302	$	160	$	55	$	(157	)		$	360
Capital expenditures ^(b)	$	1,102	$	115	$	55	$	10			$	1,282


^(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 $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 (See Note 12).


^(e)	Includes $43 million of severance related expenses associated with a workforce reduction and a pension settlement loss of ~~$17 million.~~$81 million (see Note 7).

Three Months Ended March 31, 2014
Not Allocated
(In millions) N.A. E&P Int'l E&P OSM to Segments Total
Sales and other operating revenues $ 1,392
$ 380
$ 377
$ —
$ 2,149
Marketing revenues 440
70
31
—
541
Total revenues 1,832
450
408
—
2,690
Income from equity method investments —
137
—
—
137
Net gain on disposal of assets and other income 3
17
2
—
22
Less:
Production expenses 211
100
231
—
542
Marketing costs 440
71
31
—
542
Exploration expenses 57
16
—
—
73
Depreciation, depletion and amortization 515
71
45
12
643
Impairments 17
—
—
—
17
Other expenses ^(a)
110
38
13
129
^(c)
290
Taxes other than income 90
—
5
—
95
Net interest and other —
—
—
49
49
Income tax provision (benefit) 153
87
21
(61 ) 200
Segment income/Income from continuing operations $ 242
$ 221
$ 64
$ (129 ) $ 398
Capital expenditures ^(b)
$ 867
$ 105
$ 68
$ 3
$ 1,043

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

~~(b)Includes accruals.~~

^(c) ~~Includes pension settlement loss of $63 million~~



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

910

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. Defined Benefit Postretirement Plans

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


	Three Months Ended March 31,												Three Months Ended June 30,
	Pension Benefits						Other Benefits						Pension Benefits						Other Benefits
(In millions)	2015			2014			2015			2014			2015			2014			2015			2014
Service cost	$	12		$	12		$	1		$	1		$	12		$	11		$	1		$	1
Interest cost	14			16			3			3			13			15			2			3
Expected return on plan assets	(19		)	(18		)	—			—			(17		)	(14		)	—			—
Amortization:
– prior service cost (credit)	1			1			(1		)	(1		)	(2		)	2			(1		)	(1		)
– actuarial loss	7			6			—			—			7			10			—			—
Net settlement loss ^(a)	17			63			—			—			64			8			—			—
Net curtailment loss (gain)^(b)	1			—			(6		)	—
Net periodic benefit cost (credit)	$	33		$	80		$	(3	)	$	3
Net curtailment loss^(b)													—			—			2			—
Net periodic benefit cost													$	77		$	32		$	4		$	3

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



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


^(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, which reduced the future expected years of service for employees participating in the plans.

During the first ~~quarter~~six months of 2015, we recorded the effects of a workforce reduction and a pension plan amendment. The pension plan amendment freezes the final average pay used to calculate the formula benefit and is effective July 6, 2015. Additionally, during the first ~~quarter~~six 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).

During the first ~~three~~six months of 2015, we made contributions of ~~$23~~$46 million to our funded pension plans. We expect to make additional contributions up to an estimated ~~$70~~$42 million to our funded pension plans over the remainder of 2015. During the first ~~three~~six months of 2015, we made payments of ~~$12~~$42 million and $3$8 million related to unfunded pension plans and other postretirement benefit plans, respectively.

8. Income Taxes

The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The difference between the total provision (benefits) and the sum of the amounts allocated to segments is reported in the “Not Allocated to Segments” column of the tables in Note 6.

Our effective income tax rates on continuing operations for the first ~~three~~six months of 2015 and 2014 were ~~34%~~18% and ~~33%~~32%. The tax provision (benefit) applicable to Libyan ordinary income (loss) was recorded as a discrete item in the first ~~three~~six months of 2015 and 2014. Excluding Libya, the effective tax rates on continuing operations, would be ~~31%~~15% and ~~36%~~34% for the first ~~three~~six months of 2015 and 2014. In Libya, ~~there~~uncertainty remains ~~uncertainty~~ 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 ~~three~~six months of 2015 and 2014, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss).

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.

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 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 recorded in the second quarter of 2015.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

9. Short-term Investments

As of June 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 are classified as held-to-maturity investments, which are recorded at amortized cost. The carrying values of our short-term investments approximate fair value.

10. 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.


	March 31,		December 31,		June 30,		December 31,
(In millions)	2015		2014		2015		2014
Liquid hydrocarbons, natural gas and bitumen	$	54	$	58	$	50	$	58
Supplies and other items	325		299		286		299
Inventories, at cost	$	379	$	357	$	336	$	357

~~MARATHON OIL CORPORATION~~

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

~~10.~~11. Property, Plant and Equipment, net of Accumulated Depreciation, Depletion and Amortization


	March 31,		December 31,		June 30,		December 31,
(In millions)	2015		2014		2015		2014
North America E&P	$	16,954	$	16,717	$	16,757	$	16,717
International E&P	2,803		2,741		2,848		2,741
Oil Sands Mining	9,415		9,455		9,401		9,455
Corporate	119		127		115		127
Net property, plant and equipment	$	29,291	$	29,040	$	29,121	$	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 ~~March 31,~~June 30, 2015, our net property, plant and equipment investment in Libya is ~~$769~~$775 million, and total proved reserves (unaudited) in Libya as of December 31, 2014 are 243 ~~mmboe.~~million barrels of oil equivalent ("mmboe"). 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 to exceed the carrying value of ~~$769~~$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 ~~March 31,~~June 30, 2015 and December 31, 2014. This $38 million net decrease was associated with our Canadian in-situ assets at Birchwood. After further evaluation of the estimated recoverable resources and our development plans, we withdrew our regulatory application for the proposed steam assisted gravity drainage ("SAGD") demonstration project.

~~11.~~

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

12. Fair Value Measurements

Fair Values - Recurring

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


	March 31, 2015								June 30, 2015
(In millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity	$	—	$	23	$	—	$	23
Commodity^(a)									$	—	$	5	$	—	$	5
Interest rate	—		13		—		13		—		11		—		11
Derivative instruments, assets	$	—	$	36	$	—	$	36	$	—	$	16	$	—	$	16
Derivative instruments, liabilities
Commodity^(a)									$	—	$	26	$	—	$	26
Derivative instruments, liabilities									$	—	$	26	$	—	$	26


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



	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, ~~and swaptions. Three-way~~swaptions, extendable three-way collars and ~~swaptions~~call options. These instruments are measured at fair value using either the Black-Scholes Model ~~and the~~or Black ~~Model, respectively.~~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 1213 for additional discussion of the types of derivative instruments we use.

~~MARATHON OIL CORPORATION~~

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

Fair Values - Nonrecurring

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


	Three Months Ended March 31,								Three Months Ended June 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	$	17	$	44	$	—	$	4



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

~~No impairments were recorded~~

Commodity prices began declining in ~~the first three months of 2015. In~~ the second half of 2014 ~~commodity prices began a substantial decline which persisted into~~and remain substantially lower through 2015 as compared to the first ~~quarter~~six months of ~~2015.~~2014. As this period of sustained reduced commodity prices continues, it could result in non-cash impairment charges related to long-lived assets in future periods.

All long-lived assets held for use that were impaired in the first six months of 2015 and 2014 were held by our North America E&P segment.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

In July 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 the third quarter of 2015. During the second quarter of 2015, we recorded a non-cash impairment charge of $44 million related to these assets as a result of the anticipated sale. 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 of future production levels, prices and discount rate. All such inputs were classified as Level 3.

The Ozona development in the Gulf of Mexico ~~(held by our North America E&P segment)~~ ceased producing in 2013, at which time those long-lived assets were fully impaired. In the first ~~quarter~~and second quarters of 2014, we recorded an additional ~~impairment~~impairments of $17 million ~~related to Ozona~~and $4 million as a result of estimated abandonment cost revisions. The fair value was measured using an income approach based upon forecasted future abandonment costs, which are Level 3 inputs.

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.

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 ~~March 31,~~June 30, 2015 and December 31, 2014.


	March 31, 2015				December 31, 2014				June 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	$	135	$	134	$	132	$	129	$	134	$	133	$	132	$	129
Total financial assets	135		134		132		129		134		133		132		129
Financial liabilities
Other current liabilities	13		13		13		13		13		13		13		13
Long-term debt, including current portion^(a)	6,980		6,361		6,887		6,360		8,720		8,324		6,887		6,360
Deferred credits and other liabilities	68		68		69		68		73		67		69		68
Total financial liabilities	$	7,061	$	6,442	$	6,969	$	6,441	$	8,806	$	8,404	$	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.

~~MARATHON OIL CORPORATION~~

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

~~12.~~13. Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note ~~11.~~12. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. ~~Netting is assessed by counterparty, and as of March 31, 2015 and December 31, 2014, there were no offsetting amounts.~~ The following tables present the gross fair values of derivative instruments and the reported net amounts ~~along with~~ where they appear on the consolidated balance sheets as of ~~March 31,~~June 30, 2015 and December 31, 2014.

March 31, 2015
(In millions) Asset Liability Net Asset Balance Sheet Location
Fair Value Hedges
     Interest rate $ 13
$ —
$ 13
Other noncurrent assets
Total Designated Hedges 13
—
13

Not Designated as Hedges
     Commodity 23
—
23
Other current assets
Total Not Designated as Hedges 23
—
23

     Total $ 36
$ —
$ 36

15

MARATHON OIL CORPORATION

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

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 ~~March 31,~~June 30, 2015 and December 31, 2014, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.


	March 31, 2015				December 31, 2014				June 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	4.66	%	$	600	4.64	%	$	600	4.67	%	$	600	4.64	%
March 15, 2018	$	300	4.51	%	$	300	4.49	%	$	300	4.52	%	$	300	4.49	%

~~MARATHON OIL CORPORATION~~

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

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 March 31,							Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	Income Statement Location		2015			2014			Income Statement Location	2015			2014			2015			2014
Derivative
Interest rate	Net interest and other		$	5		$	(1	)	Net interest and other	$	(2	)	$	4		$	3		$	3
Foreign currency	Discontinued operations		$	—		$	3		Discontinued operations	$	—		$	(14	)	$	—		$	(11	)
Hedged Item
Long-term debt	Net interest and other		$	(5	)	$	1		Net interest and other	$	2		$	(4	)	$	(3	)	$	(3	)
Accrued taxes	Discontinued operations		$	—		$	(3	)	Discontinued operations	$	—		$	14		$	—		$	11

Derivatives not Designated as Hedges

During the first ~~quarter~~six months of 2015, we entered into multiple crude oil derivatives indexed to New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI"), related to a portion of our forecasted North America E&P sales through December ~~2015.~~2016. These commodity derivatives ~~are three-way collars~~primarily consist of call options and 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 ~~New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI")~~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:



~~Three-Way Collars~~

~~Barrels per day~~	~~25,000~~
~~Index~~	~~NYMEX WTI~~
~~Weighted average price per barrel:~~
~~Ceiling~~	~~$71.67~~
~~Floor~~	~~$55.00~~
~~Sold put~~	~~$40.00~~
~~Remaining Term~~ ^(a)	~~April - December 2015~~



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

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

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


^(a)	Counterparties have the option to execute fixed-price swaps (swaptions) at a weighted average price of $71.67 per barrel indexed to NYMEX WTI, which is exercisable on October 30, 2015. If counterparties exercise, the term of the fixed price swaps would be for calendar year 2016 and, if all such are exercised, 25,000 barrels per day.

~~of $71.67 per barrel indexed to NYMEX WTI, which is exercisable on October 30, 2015. If~~

~~counterparties exercise, the term of the fixed-price swaps would be for calendar year 2016 and, if all~~

~~such options are exercised, 25,000 barrels per day.~~


^(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 ~~commodity~~crude oil derivative instruments appears in sales and other operating revenues in our consolidated statements of income and was a net ~~gain~~loss of ~~$26~~$43 million and $17 million in the second quarter and first ~~quarter~~six months of 2015. There were no ~~commodity~~crude oil derivative instruments in the first ~~quarter~~six months of 2014.

14On 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). 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.

~~MARATHON OIL CORPORATION~~

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

~~13.~~14. 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 ~~three~~six 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	317,563			$28.93	724,082		^(a)		$29.06	2,668,357			$30.53
Options Exercised/Stock Vested	(99,441	)			$17.36	(257,390	)		$34.94	(480,458	)			$16.47	(921,404	)		$34.29
Canceled	(272,031	)			$34.07	(414,431	)		$33.78	(455,855	)			$34.48	(491,739	)		$33.70
Outstanding at March 31, 2015	13,780,446				$29.65	3,094,095			$33.48
Outstanding at June 30, 2015										13,215,605				$29.97	4,703,567			$32.04

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

~~14.~~

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

15. Debt

Revolving Credit Facility As of June 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 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 30, 2015, we were in compliance with this covenant with a debt-to-capitalization ratio of 29%.

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. As of June 30, 2015, we were in compliance with the covenants under the indenture governing the senior notes.

16. 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 March 31,							Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2015			2014			Income Statement Line	2015			2014			2015			2014			Income Statement Line

Postretirement and postemployment plans								Postretirement and postemployment plans
Amortization of actuarial loss	$	(7	)	$	(6	)	General and administrative	$	(7	)	$	(10	)	$	(14	)	$	(16	)	General and administrative
Net settlement loss	(17		)	(63		)	General and administrative	(64		)	(8		)	(81		)	(71		)	General and administrative
Net curtailment gain	5			—			General and administrative
Net curtailment gain (loss)								(2		)	—			3			—			General and administrative
	(19		)	(69		)	Income (loss) from operations	(73		)	(18		)	(92		)	(87		)	Income (loss) from operations
	7			23			Benefit for income taxes	25			7			32			30			Benefit for income taxes
Other insignificant, net of tax								—			—			—			(1		)
Total reclassifications	$	(12	)	$	(46	)	Income (loss) from continuing operations	$	(48	)	$	(11	)	$	(60	)	$	(58	)	Income (loss) from continuing operations

~~15. Supplemental Cash Flow Information~~

Three Months Ended March 31,
(In millions) 2015 2014
Net cash provided by (used in) operating activities:
Interest paid (net of amounts capitalized) $ (55 ) $ (56 )
Income taxes paid to taxing authorities ^(a)
(47 ) (453 )
Net cash provided by (used in) financing activities:
Commercial paper, net:

Issuances $ —
$ 2,235
Repayments —
(2,370 )
Commercial paper, net —
(135 )
Noncash investing activities, related to continuing operations:

Asset retirement costs capitalized $ 21
$ 37
Asset retirement obligations assumed by buyer —
43
Receivable for disposal of assets —
44


^(a)	~~Income taxes paid to taxing authorities included $357 million related to discontinued operations in the first three months of 2014 .~~

1518

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~16.~~17. Supplemental Cash Flow Information



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


^(a)	The first six months of 2014 included $1.076 billion related to discontinued operations.

18. 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.

1619

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

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 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.

Executive Overview

Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows and their subsequent reinvestment into our business. ~~The substantial decline in commodity~~Commodity prices ~~that~~ began declining in the second half of 2014 ~~persisted~~and remain substantially lower through 2015 as compared to the first ~~quarter~~six months of ~~2015.~~2014. 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, ~~and efficiencies, and~~efficiency improvements, cost reductions, capital discipline and portfolio optimization, all while maintaining financial flexibility.

Our significant ~~first quarter 2015~~ financial results, ~~and~~ operating activities and strategic actions include the following:

~~Loss from continuing operations per diluted share of $(0.41) as compared to income from continuing operations of $0.57 per diluted share in the first quarter of 2014~~

Increased company-wide net sales volumes from continuing operations by ~~19% from 386~~4% to 411 thousand barrels of oil equivalent per day ("mboed") in the ~~first~~second quarter of 2015 from 394 mboed in the second quarter of 2014 ~~to 459 mboed~~


◦	Net sales volumes from our three U.S. resource plays increased ~~49% from 154~~29% to 220 mboed in the ~~first~~second quarter of 2015 from 170 mboed in the second quarter of 2014 ~~to 229 mboed~~

~~Achieved 98% average operational availability for our operated assets~~

~~Reduced North America E&P production expenses per boe by 28% compared to the first quarter of 2014~~

~~Completed our previously announced workforce reduction, incurring severance~~Maintained focus on cost discipline and ~~related expenses of $43 million~~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

~~Operating cash flow provided by continuing operations of~~ ~~$309 million, compared to~~ ~~$1.1 billion~~ ~~for first quarter of 2014~~

~~$3.6 billion~~Active management of liquidity ~~at the end of the first quarter, comprised of $1.1 billion in cash~~ and ~~$2.5 billion in the unused revolving credit facility; credit facility capacity increased to $3 billion after quarter end~~capital structure

~~Cash-adjusted debt-to-capital ratio of 20% at March 31,~~


◦	$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 ~~and portfolio~~ given the current price environment. We ~~now~~ expect our full-year 2015 capital, investment and exploration budget to be at or below $3.3 ~~billion, a decrease of $0.2 billion from our previously announced plan.~~billion. We ~~continue to~~ estimate our full-year North America E&P and International E&P production volumes (excluding Libya) to be ~~370~~375 - 390 net mboed. We are targeting to generate at least $500 million from select non-core asset sales as we continue our ongoing portfolio management. See Cash Flows and Liquidity for further detail underlying our capital allocation.

Operations

North America E&P--Production

North America E&P segment average net sales volumes in the second quarter and first ~~quarter~~six months of 2015 increased ~~33%~~21% and 26% compared to the second quarter and first ~~quarter~~six months of 2014. Net liquid hydrocarbon sales volumes increased 6035 thousand barrels per day ("mbbld") and 47 mbbld, and net natural gas sales volumes increased 5967 million cubic feet per day ("mmcfd") and 63 mmcfd in the second quarter and first ~~quarter~~six months of 2015 compared to the second quarter and first ~~quarter~~six months of 2014, reflecting continued growth from the combined U.S. resource plays.


	Three Months Ended March 31,		Three Months Ended June 30,		Six Months Ended June 30,
	2015	2014	2015	2014	2015	2014
Net Sales Volumes
Crude Oil and Condensate (mbbld)
Bakken	51	38	54	44	53	41
Eagle Ford	92	62	82	67	87	65
Oklahoma Resource Basins	5	2	5	2	5	2
Other North America ^(a)	36	36	35	38	35	36
Total Crude Oil and Condensate	184	138	176	151	180	144
Natural Gas Liquids (mbbld)
Bakken	3	2	3	3	3	2
Eagle Ford	27	16	26	16	26	16
Oklahoma Resource Basins	7	4	6	6	6	5
Other North America^(a)	2	3	2	2	3	4
Total Natural Gas Liquids	39	25	37	27	38	27
Total Liquid Hydrocarbons (mbbld)
Bakken	54	40	57	47	56	43
Eagle Ford	119	78	108	83	113	81
Oklahoma Resource Basins	12	6	11	8	11	7
Other North America^(a)	38	39	37	40	38	40
Total Liquid Hydrocarbons	223	163	213	178	218	171
Natural Gas (mmcfd)
Bakken	20	16	22	18	20	17
Eagle Ford	169	107	164	111	167	109
Oklahoma Resource Basins	78	54	81	61	79	58
Other North America^(a)	92	123	94	104	94	113
Total Natural Gas	359	300	361	294	360	297
Equivalent Barrels (mboed)
Bakken	57	43	61	50	59	46
Eagle Ford	147	96	135	102	141	99
Oklahoma Resource Basins	25	15	24	18	24	17
Other North America^(a)	54	59	54	57	54	58
Total North America E&P	283	213	274	227	278	220

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

1822

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


	Three Months Ended March 31,		Three Months Ended June 30,		Six Months Ended June 30,
	2015	2014	2015	2014	2015	2014
Gross Operated
Eagle Ford:
Wells drilled to total depth	88	83	59	88	147	171
Wells brought to sales	91	49	52	76	143	125
Bakken:
Wells drilled to total depth	20	16	5	19	25	22
Wells brought to sales	24	15	22	19	46	16
Oklahoma Resource Basins:
Wells drilled to total depth	8	5	5	6	13	11
Wells brought to sales	5	4	3	4	8	8

Eagle Ford – Average net sales volumes from Eagle Ford were ~~147~~135 mboed and 141 mboed in the second quarter and first ~~quarter~~six months of 2015 compared to 96102 mboed and 99 mboed in the same ~~period for~~periods of 2014, for ~~an increase~~increases of ~~53%~~32% and 42%. Approximately ~~63%~~61% of ~~first~~second quarter sales was crude oil and condensate, ~~18%~~19% was NGLs and ~~19%~~20% was natural gas. Our average time to drill an Eagle Ford well in ~~first~~second quarter 2015, spud-to-total depth, was 1211 days. ~~Our high-density pad drilling continues to average four wells per pad.~~

~~Included with~~Also, during the ~~Eagle Ford well counts noted in the table above,~~second quarter of 2015, we brought online nine gross operated Austin Chalk wells, compared to one in the same quarter of 2014. Twenty-four additional Austin Chalk wells are currently being drilled, completed or awaiting first production. We brought online our first four-well "stack-and-frac" pilot which included Austin Chalk,8 Upper Eagle Ford, ~~and two~~33 Lower Eagle Ford ~~wells. Early performance from this pilot is encouraging.~~and 11 Austin Chalk gross operated wells and 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 5761 mboed and 59 mboed in the second quarter and first ~~quarter~~six months of 2015 compared to 4350 mboed and 46 mboed in the same period for 2014, for ~~an increase~~increases of ~~33%~~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 1713 days in the ~~first~~second quarter of 2015.

~~The Bakken~~Application of the enhanced completion design ~~pilot program has concluded~~continues to provide promising results, with ~~promising early results, which resulted in a revised standard well completion design for future wells. Data from the first 23 wells suggest greater than 30% improvement in~~outperformance of historical type curves after 180 days of cumulative ~~production after 90 days when compared to direct offset performance. All 24 of the wells brought to sales in the first quarter incorporated an~~production. The enhanced completion design ~~optimizing~~optimizes proppant loading, frac fluid volumes and stage density. ~~Early performance of the first~~Three high-density ~~pilot~~pilots (six wells per horizon) ~~is encouraging, and~~were completed through the second ~~high-density spacing pilot recently started flowback. Additionally, we recently completed drilling~~quarter. Also in the second quarter, our ~~third high-density spacing pilot.~~first Three Forks second bench well in the Myrmidon was completed.

Oklahoma Resource Basins – Net sales volumes from the Oklahoma Resource Basins averaged 2524 mboed in both the second quarter and first ~~quarter~~six months of 2015 compared to 1518 mboed and 17 mboed in the comparable 2014 ~~period,~~periods, for ~~an increase~~increases of ~~67%~~33% and 41%. ~~Approximately 48% of first~~Our second quarter 2015 ~~net~~ production was ~~liquids~~approximately 20% crude, 25% NGLs and ~~52% was~~55% natural gas. ~~All five~~Of the three gross operated wells brought to sales this quarter, two were ~~in the~~ SCOOP ~~with three of the~~ wells ~~in the southern SCOOP.~~and one was a STACK Osage well. We ~~plan to maintain our program of two~~also finished drilling five operated ~~rigs in the Oklahoma Resource Basins.~~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 5085 outside-operated wells in 2015 in the SCOOP Woodford, SCOOP Springer and STACK areas. In the first ~~quarter~~six months of 2015, we participated in ~~five~~four outside-operated high-density ~~outside-operated~~ spacing pilots in the SCOOP area; three in the Woodford (80-128 acre spacing) and ~~two~~one in the emerging Springer shale (105-128 acre spacing) overlaying the Woodford. ~~The Woodford pilots include one high-density 10-well pilot comprised~~Two outside-operated STACK Meramec XL wells were brought to sales during the quarter.

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

North America E&P--Exploration

Gulf of Mexico ~~- We expect to~~– During the second quarter, we spud the Solomon exploration prospect on Walker Ridge Block 225 ~~in the second quarter of 2015. We currently hold a 78%~~and farmed down our operated working interest to 58%.

The third appraisal well on the Shenandoah prospect was spud in ~~the prospect, but are~~May 2015 and is still drilling. The well is located in ~~advanced discussions to farm down our interest, and anticipate those discussions to be finalized~~Walker Ridge Block 52, in ~~the second quarter of 2015.~~

which we hold a 10% non-operated working interest.

1923

International E&P--Production

International E&P segment average net sales volumes in the second quarter and first ~~quarter~~six months of 2015 decreased 8%12% and 10% compared to the second quarter and first ~~quarter~~six months of 2014, reflecting field decline and a planned turnaround atin Equatorial Guinea in the second quarter of 2015, which also reduced sales to the AMPCO and LNG facilities. In addition, the AMPCO methanol facility completed a planned turnaround in first quarter 2015.


	Three Months Ended March 31,		Three Months Ended June 30,		Six Months Ended June 30,
	2015	2014	2015	2014	2015	2014
Net Sales Volumes
Crude Oil and Condensate (mbbld)
Equatorial Guinea	18	24	19	20	18	22
United Kingdom	13	12	14	13	14	13
Total Crude Oil and Condensate	31	36	33	33	32	35
Natural Gas Liquids (mbbld)
Equatorial Guinea	10	11	9	11	10	11
United Kingdom	—	1	—	—	—	—
Total Natural Gas Liquids	10	12	9	11	10	11
Total Liquid Hydrocarbons (mbbld)
Equatorial Guinea	28	35	28	31	28	33
United Kingdom	13	13	14	13	14	13
Total Liquid Hydrocarbons	41	48	42	44	42	46
Natural Gas (mmcfd)
Equatorial Guinea	418	435	365	446	390	441
United Kingdom^(a)	33	30	31	28	32	29
Libya	—	3	—	—	—	1
Total Natural Gas	451	468	396	474	422	471
Equivalent Barrels (mboed)
Equatorial Guinea	97	108	89	105	93	107
United Kingdom^(a)	19	18	19	18	19	18
Total International E&P (mboed)	116	126	108	123	112	125
Net Sales Volumes of Equity Method Investees
LNG (mtd)	6,275	6,579	4,991	6,624	5,629	6,601
Methanol (mtd)	884	1,153	673	980	778	1,066


^(a)	Includes natural gas acquired for injection and subsequent resale of 107 mmcfd and 75 mmcfd for the second quarters of 2015 and 2014, and 9 mmcfd and 6 mmcfd for the first ~~quarters~~six months of 2015 and 2014.

Equatorial Guinea – Average net sales volumes were 9789 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 reduced 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 compared to 108 mboed in~~2015.

During the ~~same period of 2014 due to field decline and a planned turnaround completed in the first~~second quarter of 2015, ~~at the AMPCO methanol facility. In April, drilling commenced on~~ the Alba C21 development ~~well.~~well reached total depth and completion activities are underway. To date, well performance results are consistent with pre-drill estimates.

United Kingdom – Average net sales volumes were 19 mboed infor each of the second quarter and first ~~quarter~~six months of 2015, relatively flat as compared to 18 mboed in the same ~~period~~periods of 2014. ~~Field decline was offset by the addition of South Brae infill wells brought online in late 2014 and first quarter of 2015,~~Net sales volumes benefited from improved production as ~~well as the first of~~ two subsea development wells at West Brae ~~brought online in~~began producing during the first ~~quarter~~and second quarters of 2015. ~~Drilling~~This completed the last of the planned five-well Brae infill drilling program begun in 2014. In addition, as fullcompression was ~~completed on a second West Brae well, which is expected to be online in~~reinstated during the second ~~quarter.~~quarter of 2015 at the non-operated Foinaven field, this contributed to improved reliability.

During the third quarter of 2015, planned maintenance activities are scheduled at the East Brae and non-operated Foinaven field.

Libya – We had no sales induring the first ~~quarter~~six months of 2015 as a result of continued civil unrest. In December 2014, Libya’s National Oil Corporation reinstated 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.

International E&P--Exploration

~~Equatorial Guinea - Drilling and evaluation~~Kurdistan Region of Iraq – On the ~~offshore Rodo-1 exploration well~~Harir Block, testing was completed inon the ~~first~~Mirawa-2 appraisal well during the second quarter of 2015. The well has been temporarily ~~abandoned while further studies progress to evaluate commerciality of~~suspended as a potential future producer and the ~~light oil discovery.~~

~~Kurdistan Region of Iraq – On the operated Harir Block, the Mirawa-2 appraisal well was spud in December. Testing is in progress and is expected to be completed in the second quarter.~~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 6029 mbbld and 44 mbbld in the second quarter and first ~~quarter~~six months of 2015 compared to 4744 mbbld and 45 mbbld in the same ~~period~~periods of 2014. ~~Higher net sales volumes, up 28%~~Production declined in the second quarter of 2015 primarily due to the planned turnarounds at the base upgrader and Muskeg River Mine and unplanned downtime at the expansion upgrader. Production was relatively flat in the first ~~quarter~~six months of 2015 compared to the ~~year-ago~~same period in 2014 as the planned turnarounds and unplanned downtime during the second quarter of 2015 were ~~primarily due to~~mostly offset by higher production driven by improved ~~reliability. The Quest Carbon Capture and Storage project reached mechanical completion in February and is on schedule for fourth~~mine reliability during the first quarter ~~2015 start-up. A 55-day planned turnaround at the base upgrader began in April, coupled with a planned turnaround at the Muskeg River Mine, followed by an extended pitstop at the Jackpine Mine.~~of 2015. We hold a 20% non-operated working interest in the AOSP.

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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 quarter and first ~~three~~six 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 quarter and first ~~quarter~~six months of 2015 and 2014.


	Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014		2015		2014
Average Price Realizations ^(a)
Crude Oil and Condensate (per bbl) ^(b)
Bakken		$39.92		$89.46		$51.36		$93.08		$45.84		$91.43
Eagle Ford	42.72		96.10		53.47		99.08		47.81		97.65
Oklahoma Resource Basins	45.57		94.38		51.00		101.12		48.34		98.05
Other North America ^(c)	41.39		89.25		52.83		93.45		47.10		91.40
Total Crude Oil and Condensate	41.75		92.48		52.63		95.95		47.11		94.30
Natural Gas Liquids (per bbl)
Bakken	N.M.			$57.62		$11.63		$45.13		$7.19		$51.04
Eagle Ford	13.73		37.50		14.08		30.20		13.90		33.76
Oklahoma Resource Basins	17.04		44.58		14.45		33.04		15.83		38.21
Other North America ^(c)	26.38		61.83		25.65		54.13		26.03		57.65
Total Natural Gas Liquids	14.43		43.11		14.77		34.80		14.60		38.75
Total Liquid Hydrocarbons (per bbl)
Bakken		$37.78		$87.60		$49.29		$90.47		$43.72		$89.16
Eagle Ford	36.30		84.16		44.05		85.36		40.01		84.78
Oklahoma Resource Basins	28.25		58.75		30.29		52.00		29.24		55.04
Other North America ^(c)	40.23		87.40		50.89		90.45		45.52		88.97
Total Liquid Hydrocarbons	36.92		84.79		45.96		86.43		41.37		85.65
Natural Gas (per mcf)
Bakken		$2.93		$8.41		$2.62		$4.12		$2.76		$6.14
Eagle Ford	2.88		4.89		2.71		4.76		2.79		4.83
Oklahoma Resource Basins	2.61		5.50		2.64		4.57		2.63		5.01
Other North America^(c)	3.59		5.10		2.98		5.65		3.29		5.35
Total Natural Gas	3.01		5.28		2.76		5.00		2.88		5.14
Benchmarks
WTI crude oil (per bbl)^(d)		$48.58		$98.62		$57.95		$102.99		$53.34		$100.84
Louisiana Light Sweet ("LLS") crude oil (per bbl)^(e)	52.84		104.38		62.94		105.55		57.97		104.97
Mont Belvieu NGLs (per bbl)^(f)	18.39		38.38		17.65		34.54		18.02		36.42
Henry Hub natural gas^(g) (per mmbtu)^(h)	2.98		4.94		2.64		4.67		2.81		4.80


^(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 ~~$0.21~~$0.06 per bbl and $0.14 per bbl for the second quarter and first ~~quarter~~six months of 2015. There were no crude oil derivative instruments ~~for the first quarter of~~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.


~~N.M~~.	~~Not meaningful.~~

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.

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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 for the second quarter and first ~~quarter~~six months of 2015 and 2014.


	Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014		2015		2014
Average Price Realizations
Crude Oil and Condensate (per bbl)
Equatorial Guinea	$42.55		$90.44			$52.27		$90.91		$47.55		$90.66
United Kingdom	57.19		110.99		62.97		111.76		60.19		111.38
Total Crude Oil and Condensate	48.87		97.73		56.70		99.36		52.92		98.51
Natural Gas Liquids (per bbl)
Equatorial Guinea ^(a)	$1.00		$1.00			$1.00		$1.00		$1.00		$1.00
United Kingdom	33.64		73.10		36.49		64.37		34.82		69.56
Total Natural Gas Liquids	3.46		4.52		3.10		3.02		3.29		3.64
Total Liquid Hydrocarbons (per bbl)
Equatorial Guinea		$27.85		$62.37		$35.74		$59.72		$31.81		$61.12
United Kingdom	55.81		109.53		61.93		110.51		58.96		110.02
Total Liquid Hydrocarbons	37.31		75.55		44.70		75.41		41.06		75.48
Natural Gas (per mcf)
Equatorial Guinea ^(a)		$0.24		$0.24		$0.24		$0.24		$0.24		$0.24
United Kingdom	7.68		10.02		6.98		8.04		7.34		9.07
Libya	—		6.65		—		—		—		5.45
Total Natural Gas	0.78		0.92		0.78		0.69		0.78		0.80
Benchmark
Brent (Europe) crude oil (per bbl)^(b)		$53.92		$108.17		$61.69		$109.70		$57.81		$108.93


^(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") 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 in E.G. are subject to fixed-price, term contracts; therefore, our reported average NGL realized prices within the International E&P segment will not fully track market price movements.

Natural gas – Our natural gas sales 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 the International E&P segment will not fully track market price movements.

Oil Sands Mining

The Oil Sands Mining segment produces and sells various qualities of synthetic crude oil. Output mix can be impacted by operational reliability or planned unit outages at the mines or upgrader. Sales prices for roughly two-thirds of the normal output mix have historically tracked movements in WTI and one-third have historically tracked movements in the Canadian heavy crude oil marker, primarily Western Canadian Select ("WCS"). ~~Comparing the corresponding 2015 and 2014 periods, the WCS discount to WTI narrowed in the first quarter of 2015 by $8.39 per barrel.~~

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.

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


	Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014		2015		2014
Average Price Realizations
Synthetic Crude Oil (per bbl)		$40.37		$88.50		$52.46		$94.17		$44.33		$91.27
Benchmark
WTI crude oil (per bbl)^(a)		$48.58		$98.62		$57.95		$102.99		$53.34		$100.84
WCS crude oil (per bbl)^(b)	$33.90		$75.55			$46.35		$82.95		$40.13		$79.25
AECO natural gas sales index (per mmbtu)^(c)	$2.09		$4.99			$2.05		$4.46		$2.07		$4.72


^(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

Sales and other operating revenues, including related party are presented by segment in the table below:


		Three Months Ended March 31,				Three Months Ended June 30,					Six Months Ended June 30,
(In millions)	(In millions)	2015		2014		2015			2014		2015			2014
Sales and other operating revenues, including related party	Sales and other operating revenues, including related party
North America E&P	North America E&P	$	850	$	1,392	$	993		$	1,540	$	1,843		$	2,932
International E&P	International E&P	182		380		211			347		393			727
Oil Sands Mining	Oil Sands Mining	225		377		147			383		372			760
Segment sales and other operating revenues, including related party	Segment sales and other operating revenues, including related party	$	1,257	$	2,149	$	1,351		$	2,270	$	2,608		$	4,419
Unrealized gain on crude oil derivative instruments		23		—
Unrealized loss on crude oil derivative instruments						(44		)	—		(21		)	—
Sales and other operating revenues, including related party	Sales and other operating revenues, including related party	$	1,280	$	2,149	$	1,307		$	2,270	$	2,587		$	4,419

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 ~~sales and other operating revenues~~ decreased 39% in the first quarter of 2015 from the comparable 2014 period primarily due to lower price realizations, partially offset by higher net sales volumes from the U.S. resource plays. See additional detail by product in the table that follows:


	Three Months Ended		Increase (Decrease) Related to					Three Months Ended		Three Months Ended		Increase (Decrease) Related to					Three Months Ended
(In millions)	March 31, 2014		Price Realizations			Net Sales Volumes		March 31, 2015		June 30, 2014		Price Realizations			Net Sales Volumes		June 30, 2015
North America E&P Price-Volume Analysis
Liquid hydrocarbons	$	1,245	$	(960	)	$	456	$	741	$	1,403	$	(786	)	$	276	$	893
Natural gas	142		(73		)	28		97		133		(73		)	30		90
Realized gain on crude oil
derivative instruments	—		3					3		—		1					1
Other sales	5							9		4							9
Total	$	1,392						$	850	$	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

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International E&P ~~sales and other operating revenues~~ decreased 52% in the first quarter of 2015 from the comparable 2014 period. The decrease was due to the lower price realizations and lower net sales volumes as detailed by product in the following table:

Three Months Ended Increase (Decrease) Related to Three Months Ended
(In millions) March 31, 2014 Price Realizations Net Sales Volumes March 31, 2015
International E&P Price-Volume Analysis
Liquid hydrocarbons $ 330
$ (143 ) $ (48 ) $ 139
Natural gas 38
(5 ) (1 ) 32
Other sales 12
11
Total $ 380
$ 182

~~Oil Sands Mining sales and other operating revenues~~ decreased 40% in the first quarter of 2015, from the comparable 2014 period primarily due to lower synthetic crude oil price realizations, partially offset by higher net sales volumes. The following table displays changes by product:



	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


	Three Months Ended		Increase (Decrease) Related to					Three Months Ended			Six Months Ended		Increase (Decrease) Related to						Six Months Ended
(In millions)	March 31, 2014		Price Realizations			Net Sales Volumes		March 31, 2015			June 30, 2014		Price Realizations			Net Sales Volumes			June 30, 2015
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil	$	373	$	(260	)	$	104	$	217
International E&P Price-Volume Analysis										International E&P Price-Volume Analysis
Liquid hydrocarbons											$	634	$	(261	)	$	(63	)	$	310
Natural gas											69		(2		)	(7		)	60
Other sales	4							8			24								23
Total	$	377						$	225		$	727							$	393

Oil Sands Mining

~~Unrealized gains on crude oil derivative instruments~~ are included in total sales and other operating revenues but are not allocated to the segments. In the first quarter of 2015, the net unrealized gain on crude oil derivative instruments was $23 million. There were no crude oil derivative instruments in the first quarter of 2014.



	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
(In millions)	June 30, 2014		Price Realizations			Net Sales Volumes			June 30, 2015
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil	$	750	$	(376	)	$	(19	)	$	355
Other sales	10								17
Total	$	760							$	372

Marketing revenues decreased ~~$337~~$435 million and $772 million in the second quarter and first ~~quarter~~six months of 2015 from the comparable prior-year ~~period. The decrease is related primarily to lower marketed volumes and the lower commodity price environment in North America.~~periods. 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 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 ~~$101~~$94 million and $195 million in the second quarter and first ~~quarter~~six months of 2015 from the comparable 2014 period. The decrease in the ~~first~~second quarter of 2015 is primarily due to lower price realizations for Liquified Natural Gas ("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 ~~this~~the decrease in 2015 were lower sales volumes ~~at the AMPCO methanol facility~~ due to the previously mentioned ~~turnaround.~~planned turnaround and maintenance activities at the AMPCO methanol plant, the Alba field and the LNG facility.

Production expenses decreased ~~$98~~$112 million in the ~~first~~second quarter of 2015 ~~from~~compared to the ~~first~~second quarter of 2014. North America E&P declined $38 million due to lower operational, maintenance and labor costs. International E&P declined $35 million primarily because of lower costs related to lower sales volumes, while the second quarter of 2014 ~~primarily due to decreases~~included $5 million of ~~$56 million~~turnaround costs at Brae and ~~$33 million in the OSM and International E&P segments, respectively. OSM production expenses decreased primarily as a result of lower feedstock~~subsea maintenance costs and operating expenses, namely contract labor and utilities. International E&P production expenses decreased due to lower repair costs in the first quarter of 2015, versus the previous year which included costs related to reliability issues at the non-operated Foinaven field in the U.K. OSM decreased $39 million primarily due to lower feedstock purchases (due to planned turnarounds and ~~non-recurring riser repairs~~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 ~~E.G.~~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 lower operational, maintenance and labor costs. International E&P declined

2529

$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 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 ~~in the first quarter of 2015~~ as production volumes increased. The expense rate for International E&P declined due to reduced maintenance and project costs in second quarter of 2015 as compared to 2014. The OSM expense rate increased due to the turnarounds and unplanned downtime in the second quarter of 2015, which resulted in lower sales volumes and higher costs.

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 ~~declined~~remained relatively flat in the six months of 2015 as ~~volumes increased while~~the lower feedstock purchases, cost management and ~~operating expenses decreased. OSM utilized less feedstock (at lower prices) and experienced lower contract labor costs as~~ a ~~result of~~favorable exchange rate were offset by the aforementioned higher ~~mine reliability in 2015.~~turnaround costs. The following table provides production expense rates for each segment:


		Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
($ per boe)	($ per boe)	2015		2014		2015		2014		2015		2014
Production Expense Rate	Production Expense Rate
North America E&P	North America E&P		$7.94		$11.02		$7.19		$10.47		$7.57		$10.74
International E&P	International E&P		$6.40		$8.76		$6.51		$8.87		$6.45		$8.82
Oil Sands Mining ^(a)	Oil Sands Mining ^(a)		$34.78		$47.54		$78.24		$51.53		$50.06		$49.54


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

Marketing costs decreased ~~$337~~$432 million and $769 million in the second quarter and first ~~quarter~~six months of 2015 from the comparable 2014 ~~period,~~periods, consistent with the marketing revenues changes discussed above.

Exploration expenses declined $34 million in the second quarter of 2015 compared to the second quarter of 2014 due to lower unproved property impairments and dry well costs. Unproved property impairments declined primarily as a result of fewer Eagle Ford and Bakken 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 ~~higher~~lower in the first ~~quarter~~six months of 2015 than in the comparable 2014 period ~~primarily~~ due to lower unproved property impairments, which were partially offset by higher dry well ~~costs, partially offset by lower unproved~~costs. Unproved property ~~impairments.~~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 ~~quarter~~six months of 2015 ~~include~~due to costs associated with the Sodalita West #1 well in E.G. ~~and~~, the Key Largo well in the Gulf of Mexico, ~~both of which were deemed unsuccessful in early 2015. The~~and the aforementioned suspended well costs related to Birchwood in-situ. Dry well costs for the first ~~quarter~~six months of 2014 ~~included non-cash unproved property impairments related to Eagle Ford~~primarily consist of our exploration programs in Kurdistan, Ethiopia and ~~Bakken leases that either had expired or that we did not expect to drill or extend.~~Kenya. The following table summarizes the components of exploration expenses:


		Three Months Ended March 31,				Three Months Ended				Six Months Ended June 30,
(In millions)	(In millions)	2015		2014		2015		2014		2015		2014
Exploration Expenses	Exploration Expenses
Unproved property impairments	Unproved property impairments	$	9	$	41	$	40	$	60	$	49	$	101
Dry well costs	Dry well costs	58		2		41		53		99		55
Geological and geophysical	Geological and geophysical	3		11		12		6		15		17
Other	Other	20		19		18		26		38		45
Total exploration expenses	Total exploration expenses	$	90	$	73	$	111	$	145	$	201	$	218

Depreciation, depletion and amortization (“DD&A”) increased ~~$178~~$71 million and $249 million in the second quarter and first ~~quarter~~six months of 2015 from the comparable 2014 ~~period~~periods primarily as a result of higher North America E&P net sales volumes from our three U.S. resource plays, partially offset by lower International E&P sales volumes. OSM net sales volumes also declined in the second quarter of 2015, as previously ~~discussed.~~discussed, also contributing to that quarter's decrease. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, 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, reserves and capitalized costs, can also cause changes to our DD&A. The following table provides DD&A rates for each segment.


		Three Months Ended March 31,				Three Months Ended				Six Months Ended June 30,
($ per boe)	($ per boe)	2015		2014		2015		2014		2015		2014
DD&A Rate	DD&A Rate
North America E&P	North America E&P		$26.85		$26.88		$25.45		$26.58		$26.16		$26.72
International E&P	International E&P		$6.10		$6.25		$7.17		$6.64		$6.62		$6.45
Oil Sands Mining	Oil Sands Mining		$12.44		$11.70		$12.87		$11.78		$12.58		$11.74

Impairments are discussed in Note 1112 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 ~~$28~~$31 million and $59 million in the second quarter and first ~~quarter~~six months of 2015 from the comparable 2014 ~~period.~~periods. 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 March 31,				Three Months Ended				Six Months Ended June 30,
(In millions)	(In millions)	2015		2014		2015		2014		2015		2014
Production and severance	Production and severance	$	34	$	55	$	40	$	68	$	74	$	122
Ad valorem	Ad valorem	16		19		15		19		31		38
Other	Other	17		21		23		22		40		44
Total	Total	$	67	$	95	$	78	$	109	$	145	$	204

General and administrative expenses ~~decreased $16~~increased $29 million in the ~~first~~second quarter of 2015 compared to the same period in 2014 primarily due to ~~lower~~higher pension settlement ~~expense of $17 million (compared to a $63 million settlement charge~~charges. Settlement charges in the ~~first~~second quarter of ~~2014) and lower contract service expenses.~~2015 totaled $64 million, compared to settlement charges of $8 million in the prior year quarter. This ~~decrease~~increase in pension settlement costs was partially offset by ~~$43 million of severance related expenses associated with a reduction in~~costs savings realized from the workforce reductions that occurred in the first quarter of 2015.

General and administrative expenses increased $13 million in the first six months of 2015 compared to the same period in 2014. This increase was primarily due to $43 million of severance related expenses in the first quarter of 2015 and $10 million of increased pension settlement expense (first six 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 of 2015 resulting from the workforce reductions.

Provision (benefit) for income taxes ~~decreased $344 million~~reflect effective tax rates of 2% and 18% in the second quarter and first ~~quarter~~six months of 2015, as compared to 30% and 32% from the comparable 2014 ~~period due to~~periods. The effective rates for 2015 reflect $135 million of non-cash additional deferred tax expense recorded in the ~~change~~second quarter of 2015 as a result of enacted corporate tax changes in ~~income (loss) from continuing operations.~~Alberta, Canada. See Note 8 to the consolidated financial statements for discussion of the effective tax rate.

Discontinued operations presented in 2014 are net of tax. See Note 5 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 March 31,						Three Months Ended						Six Months Ended June 30,
(In millions)	(In millions)	2015			2014			2015			2014			2015			2014
North America E&P	North America E&P	$	(161	)	$	242		$	(45	)	$	302		$	(206	)	$	544
International E&P	International E&P	23			221			41			160			64			381
Oil Sands Mining	Oil Sands Mining	(19		)	64			(77		)	55			(96		)	119
Segment income (loss)	Segment income (loss)	(157		)	527			(81		)	517			(238		)	1,044
Items not allocated to segments, net of income taxes	Items not allocated to segments, net of income taxes	(119		)	(129		)	(305		)	(157		)	(424		)	(286		)
Income (loss) from continuing operations	Income (loss) from continuing operations	(276		)	398			(386		)	360			(662		)	758
Discontinued operations ^(a)	Discontinued operations ^(a)	—			751			—			180			—			931
Net income (loss)	Net income (loss)	$	(276	)	$	1,149		$	(386	)	$	540		$	(662	)	$	1,689


^(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 ~~$403~~$347 million and $750 million after-tax in the second quarter and first ~~quarter~~six months of 2015 from the comparable 2014 ~~period.~~periods. The decrease is primarily due to lower price realizations, ~~and higher DD&A,~~ which was partially offset by the impacts from the increased net sales volumes from the U.S. resource plays.

International E&P segment income decreased ~~$198~~$119 million and $317 million after-tax in the second quarter and first ~~quarter~~six months of 2015 from the comparable 2014 ~~period.~~periods. The ~~decrease is~~decreases are primarily due to lower liquid hydrocarbon price realizations and net sales volumes, as well as reduced income from equity ~~investments in E.G., and higher exploration expenses.~~investments. These ~~decreases in first quarter 2015 segment income~~declines were partially offset by lower production ~~expenses as first quarter 2014 included costs related to reliability issues at the non-operated Foinaven field in the U.K.~~ and ~~non-recurring riser repairs in E.G.~~exploration expenses.

Oil Sands Mining segment income (loss) decreased ~~$83~~$132 million and $215 million after-tax in the second quarter and first ~~quarter~~six months of 2015 from the comparable 2014 ~~period~~periods primarily due to lower price realizations, partially offset by ~~higher net sales volumes and~~ reduced production expenses. ~~Lower production expenses pertained to lower feedstock costs and operating expenses, namely contract labor and utilities.~~

Critical Accounting Estimates

There have been no changes to our critical accounting estimates subsequent to December 31, 2014.

Accounting Standards Not Yet Adopted

See Note 2 to the consolidated financial statements.

Cash Flows and Liquidity

Cash Flows

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


	Three Months Ended March 31,						Six Months Ended June 30,
(In millions)	2015			2014			2015			2014
Sources of cash and cash equivalents
Continuing operations	$	309		$	1,069		$	717		$	2,118
Discontinued operations	—			401			—			440
Borrowings							1,996			—
Disposals of assets	2			2,123			2			2,232
Other	14			34			43			113
Total sources of cash and cash equivalents	$	325		$	3,627		$	2,758		$	4,903
Uses of cash and cash equivalents
Additions to property, plant and equipment	$	(1,452	)	$	(1,004	)
Cash additions to property, plant and equipment							$	(2,320	)	$	(2,230	)
Investing activities of discontinued operations	—			(96		)	—			(233		)
Purchases of short-term investments							(925		)	—
Debt issuance costs							(19		)	—
Debt repayments							(34		)	(34		)
Dividends paid							(285		)	(260		)
Purchases of common stock	—			(551		)	—			(1,000		)
Commercial paper, net	—			(135		)	—			(135		)
Dividends paid	(142		)	(133		)
Other	(3		)	(8		)	(1		)	(10		)
Cash held for sale							—			(96		)
Total uses of cash and cash equivalents	$	(1,597	)	$	(1,927	)	$	(3,584	)	$	(3,998	)

Commodity prices began declining in the second half of 2014 and ~~continued their decline into~~remain substantially lower through 2015 as compared to the first ~~three~~six months of ~~2015. The~~2014. This lower price trend adversely impacted our cash flows ~~from continuing operations.~~in 2015. Partially offsetting the decline in prices were increased net sales volumes in the North America E&P ~~and OSM segments.~~segment. 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. Disposals of assets in the first ~~three~~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 5 to the consolidated financial statements.

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

2833

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:


	Three Months Ended March 31,					Six Months Ended June 30,
(In millions)	2015		2014			2015		2014
North America E&P	$	933	$	867		$	1,484	$	1,969
International E&P	146		105			245		220
Oil Sands Mining	21		68			37		123
Corporate	2		3			14		13
Total capital expenditures	1,102		1,043			1,780		2,325
(Increase) decrease in capital expenditure accrual	350		(39		)	540		(95		)
Total use of cash and cash equivalents for property, plant and equipment	$	1,452	$	1,004		$	2,320	$	2,230

During the first ~~quarter~~six months of 2014, we acquired 1629 million common shares at a cost of ~~$551 million~~$1 billion under our share repurchase ~~program.~~program, 13 million of which were acquired in the second quarter of 2014 at a cost of $449 million.

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

In May 2015, we amended our $2.5 billion unsecured revolving credit facility (as so amended, the "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-strategic~~non-core assets. Our working capital requirements are supported by these sources and we may also issue commercial paper, which is backed by our 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 ~~revised~~expect our capital, investment and exploration spending budget for full-year 2015 to be at or below $3.3 billion ~~down from $3.5 billion. Despite this reduction, our estimated~~and estimate full-year North America E&P and International E&P production volumes (excluding Libya) ~~are expected~~ to be ~~370-390~~375-390 net mboed.

The budget reductions primarily impact the North America E&P segment and reflect reduced activity levels and more efficient and productive operations. Capital allocated to our three U.S. resource plays in 2015 has been reduced to $2.2 billion from $2.4 billion.

~~Eagle Ford capital reduced to $1.3 billion, reflecting a reduction to seven rigs by the end of the second quarter. We revised the number of gross operated wells to drill to sales to 227-247.~~

Bakken capital reduced to $645 million, reflecting a reduction to one rig by the end of the second quarter. The lower spend will fund the remaining downspacing pilots. We revised the number of gross operated wells to drill to sales to 53-63.

Oklahoma Resource Basins capital increased to $253 million, as a result of increased outside-operated activity. We plan to maintain a program of two operated rigs and participate in approximately 50 outside-operated wells in 2015. The number of gross operated wells to sales remains unchanged.

2934

Capital Resources

Credit Arrangements and Borrowings

At ~~March 31,~~June 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 ~~March 31,~~June 30, 2015, we had ~~$6.4~~$8.4 billion in long-term debt ~~outstanding. Approximately $1.1 billion is due within one year, most~~outstanding, of which approximately $1.0 billion matures in the fourth quarter of 2015. 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.

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

Our ~~cash-adjusted~~cash and short-term investments-adjusted debt-to-capital ratio (total debt-minus-cash and cash equivalents and short-term investments to total debt-plus-equity-minus-cash and cash ~~equivalents)~~equivalents and short-term investments) was ~~20%~~22% at ~~March 31,~~June 30, 2015, compared to 16% at December 31, 2014.


	March 31,			December 31,			June 30,			December 31,
(In millions)	2015			2014			2015			2014
Long-term debt due within one year	$	1,068		$	1,068		$	1,035		$	1,068
Long-term debt	5,326			5,323			7,321			5,323
Total debt	$	6,394		$	6,391		$	8,356		$	6,391
Cash and cash equivalents	$	1,126		$	2,398		$	1,572		$	2,398
Short-term investments							$	925		$	—
Equity	$	20,660		$	21,020		$	20,218		$	21,020
Calculation:
Total debt	$	6,394		$	6,391		$	8,356		$	6,391
Minus cash and cash equivalents	1,126			2,398			1,572			2,398
Total debt minus cash and cash equivalents	$	5,268		$	3,993
Minus short-term investments							925			—
Total debt minus cash, cash equivalents and short-term investments							$	5,859		$	3,993
Total debt	$	6,394		$	6,391		$	8,356		$	6,391
Plus equity	20,660			21,020			20,218			21,020
Minus cash and cash equivalents	1,126			2,398			1,572			2,398
Total debt plus equity minus cash and cash equivalents	$	25,928		$	25,013
Cash-adjusted debt-to-capital ratio	20		%	16		%
Minus short-term investments							925			—
Total debt plus equity minus cash, cash equivalents and short-term investments							$	26,077		$	25,013
Cash and short-term investments-adjusted debt-to-capital ratio							22		%	16		%

Capital Requirements

WeAs noted above in "Outlook," we expect ~~our capital spending to moderate over the remainder of 2015 as~~ our total capital, investment and exploration spending budget for full-year 2015 ~~is now projected~~ to be at or below $3.3 billion, a decrease of $0.2 billion from our previously announced plan. Additional details are discussed above in "Outlook." We continue to optimize our operations for efficiency improvements and to exercise capital discipline in this lower commodity price environment.billion.

On ~~April~~July 29, 2015, our Board of Directors approved a dividend of $0.21 per share for the ~~first~~second quarter of 2015 payable ~~June~~September 10, 2015 to stockholders of record at the close of business on ~~May 20,~~August 19, 2015.

As of ~~March 31,~~June 30, 2015, we plan to make contributions of up to ~~$70~~$42 million to our funded pension plans during the remainder of 2015.

Contractual Cash Obligations

As of June 30, 2105, 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 15.

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 ~~as amended,~~ and Section 21E of the Securities Exchange Act of 1934 ~~as amended~~ (the "Exchange Act"). All statements other than statements of historical fact included or incorporated by reference in this report are forward-looking statements, including without limitation statements regarding our operational, financial and growth strategies, our ability to effect those strategies and the expected timing and results thereof, planned capital expenditures and the impact thereof, ~~growth activities and expectations,~~ future drilling plans, timing and expectations, maintenance activities and the timing and impact thereof, well spud timing and expectations, our financial and operational outlook ~~future~~and ability to fulfill that outlook, our financial position, liquidity and capital resources, our 2015 budget and planned allocation, and the plans and objectives of our management for our future ~~operations, are forward-looking statements.~~operations. In addition, many forward-looking statements may be identified by the use of forward-looking terminology such as ~~“anticipates,~~“anticipate,” ~~“believes,~~“believe,” ~~“estimates,~~“estimate,” ~~“expects,~~“expect,” ~~“targets,~~“target,” ~~“plans,~~“plan,” ~~“projects,~~“project,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. While we believe that our assumptions concerning future events are reasonable, ~~we can give no assurance that these expectations will prove to be correct. A~~a number of factors could cause results to differ materially from those indicated by such forward-looking statements including, but not limited to:

conditions in the oil and gas industry, including ~~the level of supply or~~ supply/demand ~~for liquid hydrocarbons and natural gas~~levels and the resulting impact on ~~the price of liquid hydrocarbons and natural gas;~~price;

changes in expected reserve or production levels;

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

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

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

~~drilling rig availability;~~timing;

availability of drilling rigs, materials and labor;

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

non-performance by third parties of ~~their~~ contractual obligations;

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

~~cyber-attacks adversely affecting our operations;~~cyber-attacks;

changes in safety, health, environmental and other regulations;

other geological, operating and economic considerations; and

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

3136

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 1112 and 1213 to the consolidated financial statements.

Commodity Price Risk During the first ~~quarter~~six 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 which consisted of three-way collars with swaptions.~~sales. The table below provides a summary of open positions as of ~~March 31,~~June 30, 2015:



~~Crude Oil Derivative Positions~~
~~Three-way collars with swaptions~~
~~Barrels per day~~	~~25,000~~
~~Index~~	~~NYMEX WTI~~
~~Weighted average price per barrel:~~
~~Ceiling~~	~~$71.67~~
~~Floor~~	~~$55.00~~
~~Sold put~~	~~$40.00~~
~~Remaining Term~~ ^(a)	~~April - December 2015~~



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

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

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


^(a)	Counterparties have the option to ~~exercise~~execute fixed-price swaps (swaptions) at a weighted average price of $71.67 per barrel indexed to NYMEX WTI, which is exercisable on October 30, 2015. If counterparties exercise, the term of the fixed price swaps would be for calendar year 2016 and, if all such are exercised, 25,000 barrels per day.

~~of $71.67 per barrel indexed to NYMEX WTI, which is exercisable on October 30, 2015. If the~~

~~counterparties exercise, the term of the fixed-price swaps would be for calendar year 2016 and, if all~~

~~such options are exercised, for 25,000 barrels per day.~~


^(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 ~~("IFO")~~ of a hypothetical 10% change in NYMEX WTI prices on our open commodity derivative instruments as of ~~March 31,~~June 30, 2015.


	Incremental Change in IFO from a Hypothetical Price Increase of			Incremental Change in IFO from a Hypothetical Price Decrease of
(In millions)	10%					Hypothetical Price Increase of 10%			Hypothetical Price Decrease of 10%
Crude oil commodity derivatives	$	(34	)	$	27	$	(67	)	$	51

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 30, 2015, is provided in the following table.



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


^(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.

3237

Subsequent to March 31, 2015, we entered into additional crude oil derivatives related to a portion of our forecasted North America E&P sales. These derivatives consist of three-way collars with sold call options and stand-alone three-way collars. The corresponding terms of these derivative positions entered into from April 1 through May 5, 2015 are shown in the table below:



~~Crude Oil Derivative Positions~~
~~Three-way collars~~
~~Barrels per day~~	~~10,000~~
~~Index~~	~~NYMEX WTI~~
~~Weighted average price per barrel:~~
~~Ceiling~~	~~$67.00~~
~~Floor~~	~~$57.00~~
~~Sold put~~	~~$44.50~~
~~Term~~ ^(a)	~~April-December 2015~~
~~Three-way collars~~
~~Barrels per day~~	~~10,000~~
~~Index~~	~~NYMEX WTI~~
~~Weighted average price per barrel:~~
~~Ceiling~~	~~$71.81~~
~~Floor~~	~~$60.00~~
~~Sold put~~	~~$50.00~~
~~Term~~	~~January-December 2016~~

~~(a) Includes sold call options with weighted average price of $72.39 per barrel indexed to NYMEX WTI.~~

~~If executed, the term of the call options would be for calendar year 2016 and the same volume as the~~

~~underlying three-way collars.~~

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 ~~Securities~~ Exchange ~~Act of 1934)~~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 ~~March 31,~~June 30, 2015.

During the ~~first~~second 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 ~~Securities~~ Exchange ~~Act of 1934)~~Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

3338

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)


	Three Months Ended						Three Months Ended						Six Months Ended
	March 31,						June 30,						June 30,
(In millions)	2015			2014			2015			2014			2015			2014
Segment Income (Loss)
North America E&P	$	(161	)	$	242		$	(45	)	$	302		$	(206	)	$	544
International E&P	23			221			41			160			64			381
Oil Sands Mining	(19		)	64			(77		)	55			(96		)	119
Segment income (loss)	(157		)	527			(81		)	517			(238		)	1,044
Items not allocated to segments, net of income taxes	(119		)	(129		)	(305		)	(157		)	(424		)	(286		)
Income (loss) from continuing operations	(276		)	398			(386		)	360			(662		)	758
Discontinued operations ^(a)	—			751			—			180			—			931
Net income (loss)	$	(276	)	$	1,149		$	(386	)	$	540		$	(662	)	$	1,689
Capital Expenditures ^(b)
North America E&P	$	933		$	867		$	551		$	1,102		$	1,484		$	1,969
International E&P	146			105			99			115			245			220
Oil Sands Mining	21			68			16			55			37			123
Corporate	2			3			12			10			14			13
Discontinued operations ^(a)	—			110			—			141			—			251
Total	$	1,102		$	1,153		$	678		$	1,423		$	1,780		$	2,576
Exploration Expenses
North America E&P	$	35		$	57		$	91		$	82		$	126		$	139
International E&P	55			16			20			63			75			79
Total	$	90		$	73		$	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.

3439

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)


	Three Months Ended		Three Months Ended		Six Months Ended
	March 31,		June 30,		June 30,
Net Sales Volumes	2015	2014	2015	2014	2015	2014
North America E&P
Crude Oil and Condensate (mbbld)
Bakken	51	38	54	44	53	41
Eagle Ford	92	62	82	67	87	65
Oklahoma Resource Basins	5	2	5	2	5	2
Other North America ^(c)	36	36	35	38	35	36
Total Crude Oil and Condensate	184	138	176	151	180	144
Natural Gas Liquids (mbbld)
Bakken	3	2	3	3	3	2
Eagle Ford	27	16	26	16	26	16
Oklahoma Resource Basins	7	4	6	6	6	5
Other North America ^(c)	2	3	2	2	3	4
Total Natural Gas Liquids	39	25	37	27	38	27
Total Liquid Hydrocarbons (mbbld)
Bakken	54	40	57	47	56	43
Eagle Ford	119	78	108	83	113	81
Oklahoma Resource Basins	12	6	11	8	11	7
Other North America ^(c)	38	39	37	40	38	40
Total Liquid Hydrocarbons	223	163	213	178	218	171
Natural Gas (mmcfd)
Bakken	20	16	22	18	20	17
Eagle Ford	169	107	164	111	167	109
Oklahoma Resource Basins	78	54	81	61	79	58
Other North America ^(c)	92	123	94	104	94	113
Total Natural Gas	359	300	361	294	360	297
Equivalent Barrels (mboed)
Bakken	57	43	61	50	59	46
Eagle Ford	147	96	135	102	141	99
Oklahoma Resource Basins	25	15	24	18	24	17
Other North America ^(c)	54	59	54	57	54	58
Total North America E&P	283	213	274	227	278	220


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

3540

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)


	Three Months Ended		Three Months Ended		Six Months Ended
	March 31,		June 30,		June 30,
Net Sales Volumes	2015	2014	2015	2014	2015	2014
International E&P
Crude Oil and Condensate (mbbld)
Equatorial Guinea	18	24	19	20	18	22
United Kingdom	13	12	14	13	14	13
Total Crude Oil and Condensate	31	36	33	33	32	35
Natural Gas Liquids (mbbld)
Equatorial Guinea	10	11	9	11	10	11
United Kingdom	—	1
Total Natural Gas Liquids	10	12	9	11	10	11
Total Liquid Hydrocarbons (mbbld)
Equatorial Guinea	28	35	28	31	28	33
United Kingdom	13	13	14	13	14	13
Total Liquid Hydrocarbons	41	48	42	44	42	46
Natural Gas (mmcfd)
Equatorial Guinea	418	435	365	446	390	441
United Kingdom ^(d)	33	30	31	28	32	29
Libya	—	3	—	—	—	1
Total Natural Gas	451	468	396	474	422	471
Equivalent Barrels (mboed)
Equatorial Guinea	97	108	89	105	93	107
United Kingdom ^(d)	19	18	19	18	19	18
Total International E&P	116	126	108	123	112	125
Oil Sands Mining
Synthetic Crude Oil (mbbld) ^(e)	60	47	29	44	44	45
Total Continuing Operations (mboed)	459	386	411	394	434	390
Discontinued Operations - Angola (mboed) ^(a)	—	6	—	—	—	3
Discontinued Operations - Norway (mboed) ^(a)	—	71	—	70	—	70
Total Company (mboed)	459	463	411	464	434	463
Net Sales Volumes of Equity Method Investees
LNG (mtd)	6,275	6,579	4,991	6,624	5,629	6,601
Methanol (mtd)	884	1,153	673	980	778	1,066


^(d)	Includes natural gas acquired for injection and subsequent resale of 107 mmcfd and 75 mmcfd for the second quarters of 2015 and 2014, and 9 mmcfd and 6 mmcfd for the first ~~quarters~~six months of 2015 and 2014.


^(e)	Includes blendstocks.

3641

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)


	Three Months Ended		Three Months Ended		Six Months Ended
	March 31,		June 30,		June 30,
Average Price Realizations ^(f)	2015	2014	2015	2014	2015	2014
North America E&P
Crude Oil and Condensate (per bbl) ^(g)
Bakken	$39.92	$89.46	$51.36	$93.08	$45.84	$91.43
Eagle Ford	42.72	96.10	53.47	99.08	47.81	97.65
Oklahoma Resource Basins	45.57	94.38	51.00	101.12	48.34	98.05
Other North America ^(c)	41.39	89.25	52.83	93.45	47.10	91.40
Total Crude Oil and Condensate	41.75	92.48	52.63	95.95	47.11	94.30
Natural Gas Liquids (per bbl)
Bakken	N.M.	$57.62	$11.63	$45.13	$7.19	$51.04
Eagle Ford	13.73	37.50	14.08	30.20	13.90	33.76
Oklahoma Resource Basins	17.04	44.58	14.45	33.04	15.83	38.21
Other North America ^(c)	26.38	61.83	25.65	54.13	26.03	57.65
Total Natural Gas Liquids	14.43	43.11	14.77	34.80	14.60	38.75
Total Liquid Hydrocarbons (per bbl)
Bakken	$37.78	$87.60	$49.29	$90.47	$43.72	$89.16
Eagle Ford	36.30	84.16	44.05	85.36	40.01	84.78
Oklahoma Resource Basins	28.25	58.75	30.29	52.00	29.24	55.04
Other North America ^(c)	40.23	87.40	50.89	90.45	45.52	88.97
Total Liquid Hydrocarbons	36.92	84.79	45.96	86.43	41.37	85.65
Natural Gas (per mcf)
Bakken	$2.93	$8.41	$2.62	$4.12	$2.76	$6.14
Eagle Ford	2.88	4.89	2.71	4.76	2.79	4.83
Oklahoma Resource Basins	2.61	5.50	2.64	4.57	2.63	5.01
Other North America^(c)	3.59	5.10	2.98	5.65	3.29	5.35
Total Natural Gas	3.01	5.28	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 ~~$0.21~~$0.06 and $0.14 per bbl for the second quarter and first ~~three~~six months of 2015. There were no crude oil derivative instruments in 2014.


~~N.M~~.	~~Not meaningful.~~

3742

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)


	Three Months Ended		Three Months Ended		Six Months Ended
	March 31,		June 30,		June 30,
Average Price Realizations	2015	2014	2015	2014	2015	2014
International E&P
Crude Oil and Condensate (per bbl)
Equatorial Guinea	$42.55	$90.44	$52.27	$90.91	$47.55	$90.66
United Kingdom	57.19	110.99	62.97	111.76	60.19	111.38
Total Crude Oil and Condensate	48.87	97.73	56.70	99.36	52.92	98.51
Natural Gas Liquids (per bbl)
Equatorial Guinea ^(h)	$1.00	$1.00	$1.00	$1.00	$1.00	$1.00
United Kingdom	33.64	73.10	36.49	64.37	34.82	69.56
Total Natural Gas Liquids	3.46	4.25	3.10	3.02	3.29	3.64
Total Liquid Hydrocarbons (per bbl)
Equatorial Guinea	$27.85	$62.37	$35.74	$59.72	$31.81	$61.12
United Kingdom	55.81	109.53	61.93	110.51	58.96	110.02
Total Liquid Hydrocarbons	37.31	75.55	44.70	75.41	41.06	75.48
Natural Gas (per mcf)
Equatorial Guinea ^(h)	$0.24	$0.24	$0.24	$0.24	$0.24	$0.24
United Kingdom	7.68	10.02	6.98	8.04	7.34	9.07
Libya	—	6.65	—	—	—	5.45
Total Natural Gas	0.78	0.92	0.78	0.69	0.78	0.80
Oil Sands Mining
Synthetic Crude Oil (per bbl)	$40.37	$88.50	$52.46	$94.17	$44.33	$91.27
Discontinued Operations - Angola (per boe) ^(a)	—	99.82	—	—	—	$99.82
Discontinued Operations - Norway (per boe) ^(a)	—	108.08	—	$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.

3843

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 ~~March 31,~~June 30, 2015, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the ~~Securities~~ 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)(b)
Paid per Share Plans or Programs Plans or Programs
01/01/15 - 01/31/15 1,338 $28.33 —
$1,500,285,529
02/01/15 - 02/28/15 3,154 $28.06 —
$1,500,285,529
03/01/15 - 03/31/15 61,185 $27.52 —
$1,500,285,529
Total 65,677 $27.56 —



	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	—


^(a)	~~65,677~~161,719 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

^(b)

Does not include shares repurchased in open-market transactions to satisfy the requirements for dividend reinvestment under the Marathon Oil Corporation Dividend Reinvestment and Direct Stock Purchase Plan (the “Dividend Reinvestment Plan”) by the administrator of the Dividend Reinvestment Plan. On March 9, 2015, the Dividend Reinvestment Plan was terminated. Participants in the Dividend Reinvestment Plan were transferred to Computershare CIP, a Direct Stock Purchase and Dividend Reinvestment Plan, which is sponsored and administered by Computershare Trust Company, N.A.

~~Item 5. Other Information~~

~~Amended and Restated By-laws~~

As we previously disclosed in a Form 8-K filed with the SEC on April 10, 2015, our Board of Directors amended and restated our By-laws, effective April 9, 2015, to implement “proxy access,” which allows eligible stockholders to include their own nominees for director in our proxy materials along with the Board-nominated candidates.

Pursuant to these amendments, a stockholder, or group of twenty or fewer stockholders (collectively, an “eligible stockholder”), meeting specified eligibility requirements, may include a director nominee in our proxy materials for our annual meetings of stockholders. To use these proxy access provisions, an eligible stockholder must, among other requirements:

~~have owned 5 % or more of our outstanding common stock continuously for at least three years; and~~

provide us with a notice requesting the inclusion of the director nominee in our proxy materials and other required information not less than 90 days nor more than 120 days prior to the first anniversary of the date on which we first mail our proxy materials for the preceding year’s annual meeting of stockholders.

All director nominees submitted through these provisions (“stockholder nominees”) must be independent and meet specified additional criteria. The maximum number of stockholder nominees that may be included in the proxy statement pursuant to these provisions may not exceed 20% 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. In addition, an eligible stockholder may include a written statement of no more than 500 words supporting the candidacy of such stockholder nominee.

~~The proxy access process under the By-laws will first be available to stockholders in connection with our 2016 annual meeting of stockholders.~~

~~Amendment to Credit Agreement~~

On May 5, 2015, Marathon Oil Corporation entered into a First Amendment (the “Amendment”) 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 (the “Credit Agreement”).

The Amendment amends the Credit Agreement to, among other things, (i) increase the aggregate commitments by $500 million to an aggregate total amount of commitments of $3.0 billion, with an option to further increase the aggregate amount of commitments by up to an additional $500 million, subject to certain customary conditions, including obtaining the consent of any increasing lenders, and (ii) extend the maturity date by an additional year such that the Credit Agreement now matures on May 28, 2020, unless that date is extended under provisions in the Credit Agreement that allow us to request additional one-year extensions of the maturity date on up to two occasions. Any further extensions of the maturity date are subject to certain customary conditions, including the consent of lenders holding commitments representing a majority of the total commitments. If a Lender does not consent to an extension of the maturity date, then that Lender’s commitment will mature on the original maturity date of its commitment and will not be extended.

Certain lenders that are a party to the Amendment have in the past performed, and may in the future from time to time perform, investment banking, financial advisory, lending or commercial banking services for us and our subsidiaries, for which they have received, and may in the future receive, customary compensation and reimbursement of expenses.

The above description of the material terms and conditions of the Amendment does not purport to be complete and is qualified in its entirety by reference to the full text of the Amendment, which is filed as an exhibit to this report.

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.

4044

SIGNATURES

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



~~May 7,~~August 6, 2015		MARATHON OIL CORPORATION

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

4145

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 Amended By-Laws of Marathon Oil Corporation effective April 9, 2015 8-K 3.1 4/10/2015
3.3 Specimen of Common Stock Certificate 10-K 3.3 2/28/2014
4.2 Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon its request 10-K 4.2 2/28/2014
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*
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 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.



	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	1720
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3237
Item 4.	Controls and Procedures	3338
	Supplemental Statistics (Unaudited)	3439
Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	3944
Item 1A.	Risk Factors	3944
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
~~Item 5.~~	~~Other Information~~	3944
Item 6.	Exhibits	4044
	Signatures	4145



	Three Months Ended March 31, 2014
							Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	1,392	$	380	$	377	$	—			$	2,149
Marketing revenues	440		70		31		—				541
Total revenues	1,832		450		408		—				2,690
Income from equity method investments	—		137		—		—				137
Net gain on disposal of assets and other income	3		17		2		—				22
Less:
Production expenses	211		100		231		—				542
Marketing costs	440		71		31		—				542
Exploration expenses	57		16		—		—				73
Depreciation, depletion and amortization	515		71		45		12				643
Impairments	17		—		—		—				17
Other expenses ^(a)	110		38		13		129			^(c)	290
Taxes other than income	90		—		5		—				95
Net interest and other	—		—		—		49				49
Income tax provision (benefit)	153		87		21		(61		)		200
Segment income/Income from continuing operations	$	242	$	221	$	64	$	(129	)		$	398
Capital expenditures ^(b)	$	867	$	105	$	68	$	3			$	1,043