UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended June 30, ~~2015~~2016



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

Commission file number 1-5153

Marathon Oil Corporation

(Exact name of registrant as specified in its charter)



Delaware		25-0996816
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

5555 San Felipe Street, Houston, TX 77056-2723

(Address of principal executive offices)

(713) 629-6600

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes R No £

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer þ	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

There were ~~677,184,913~~847,258,512 shares of Marathon Oil Corporation common stock outstanding as of July 31, ~~2015.~~2016.

MARATHON OIL CORPORATION

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

For certain industry specific terms used in this Form 10-Q, please see "Definitions" in our 2015 Annual Report on Form 10-K.

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)


	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
(In millions, except per share data)	2015			2014			2015			2014			2016			2015			2016			2015
Revenues and other income:
Sales and other operating revenues, including related party	$	1,307		$	2,270		$	2,587		$	4,419		$	870		$	1,307		$	1,584		$	2,587
Marketing revenues	183			618			387			1,159			89			183			147			387
Income from equity method investments	26			120			62			257			37			26			51			62
Net gain (loss) on disposal of assets	—			(87		)	1			(85		)	294			—			234			1
Other income	15			20			26			40			12			15			16			26
Total revenues and other income	1,531			2,941			3,063			5,790			1,302			1,531			2,032			3,063
Costs and expenses:
Production	450			562			894			1,104			350			450			678			894
Marketing, including purchases from related parties	182			614			387			1,156			88			182			146			387
Other operating	81			101			188			204			95			81			204			188
Exploration	111			145			201			218			189			111			213			201
Depreciation, depletion and amortization	751			680			1,572			1,323			561			751			1,170			1,572
Impairments	44			4			44			21			—			44			1			44
Taxes other than income	78			109			145			204			39			78			87			145
General and administrative	168			139			339			326			132			168			283			339
Total costs and expenses	1,865			2,354			3,770			4,556			1,454			1,865			2,782			3,770
Income (loss) from operations	(334		)	587			(707		)	1,234			(152		)	(334		)	(750		)	(707		)
Net interest and other	(58		)	(76		)	(105		)	(125		)	(86		)	(58		)	(171		)	(105		)
Income (loss) from continuing operations before income taxes	(392		)	511			(812		)	1,109
Income (loss) before income taxes													(238		)	(392		)	(921		)	(812		)
Provision (benefit) for income taxes	(6		)	151			(150		)	351			(68		)	(6		)	(344		)	(150		)
Income (loss) from continuing operations	(386		)	360			(662		)	758
Discontinued operations	—			180			—			931
Net income (loss)	$	(386	)	$	540		$	(662	)	$	1,689		$	(170	)	$	(386	)	$	(577	)	$	(662	)
Per basic share:
Income (loss) from continuing operations	$	(0.57	)	$	0.53		$	(0.98	)	$	1.11
Discontinued operations	$	—		$	0.27		$	—		$	1.36
Net income (loss)	$	(0.57	)	$	0.80		$	(0.98	)	$	2.47
Per diluted share:
Income (loss) from continuing operations	$	(0.57	)	$	0.53		$	(0.98	)	$	1.10
Discontinued operations	$	—		$	0.27		$	—		$	1.36
Net income (loss)	$	(0.57	)	$	0.80		$	(0.98	)	$	2.46
Net income (loss) per share:
Basic													$	(0.20	)	$	(0.57	)	$	(0.73	)	$	(0.98	)
Diluted													$	(0.20	)	$	(0.57	)	$	(0.73	)	$	(0.98	)
Dividends per share	$	0.21		$	0.19		$	0.42		$	0.38		$	0.05		$	0.21		$	0.10		$	0.42
Weighted average common shares outstanding:
Basic	677			676			676			684			848			677			790			676
Diluted	677			679			676			688			848			677			790			676

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

MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income (Unaudited)


	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
(In millions)	2015			2014			2015			2014			2016			2015			2016			2015
Net income (loss)	$	(386	)	$	540		$	(662	)	$	1,689		$	(170	)	$	(386	)	$	(577	)	$	(662	)
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	86			(13		)	162			(43		)	19			86			(5		)	162
Income tax benefit (provision)	(30		)	5			(57		)	15
Income tax provision (benefit)													(7		)	(30		)	2			(57		)
Postretirement and postemployment plans, net of tax	56			(8		)	105			(28		)	12			56			(3		)	105
Other, net of tax													(2		)	—			(2		)	—
Other comprehensive income (loss)													10			56			(5		)	105
Comprehensive income (loss)	$	(330	)	$	532		$	(557	)	$	1,661		$	(160	)	$	(330	)	$	(582	)	$	(557	)

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)


	June 30,			December 31,			June 30,			December 31,
(In millions, except per share data)	2015			2014			2016			2015
Assets
Current assets:
Cash and cash equivalents	$	1,572		$	2,398		$	2,584		$	1,221
Short-term investments	925			—
Receivables, less reserve of $4 and $3	1,195			1,729
Receivables, less reserve of $4 and $4							822			912
Inventories	336			357			272			313
Other current assets	102			109			76			144
Total current assets	4,130			4,593			3,754			2,590
Equity method investments	1,045			1,113			944			1,003
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $23,395 and $21,884	29,121			29,040
depletion and amortization of $21,659 and $23,260							25,657			27,061
Goodwill	459			459			115			115
Other noncurrent assets	1,015			806			2,057			1,542
Total assets	$	35,770		$	36,011		$	32,527		$	32,311
Liabilities
Current liabilities:
Accounts payable	$	1,507		$	2,545		$	953		$	1,313
Payroll and benefits payable	119			191			114			133
Accrued taxes	156			285			85			132
Other current liabilities	235			290			229			150
Long-term debt due within one year	1,035			1,068			1			1
Total current liabilities	3,052			4,379			1,382			1,729
Long-term debt	7,321			5,323			7,280			7,276
Deferred tax liabilities	2,531			2,486			2,392			2,441
Defined benefit postretirement plan obligations	438			598			409			403
Asset retirement obligations	1,963			1,917			1,597			1,601
Deferred credits and other liabilities	247			288			314			308
Total liabilities	15,552			14,991			13,374			13,758
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,
Issued – 937 million shares and 770 million shares (par value $1 per share,
1.1 billion shares authorized)	770			770			937			770
Securities exchangeable into common stock – no shares issued or
outstanding (no par value, 29 million shares authorized)	—			—			—			—
Held in treasury, at cost – 93 million and 95 million shares	(3,555		)	(3,642		)
Held in treasury, at cost – 89 million and 93 million shares							(3,397		)	(3,554		)
Additional paid-in capital	6,484			6,531			7,433			6,498
Retained earnings	16,691			17,638			14,320			14,974
Accumulated other comprehensive loss	(172		)	(277		)	(140		)	(135		)
Total stockholders' equity	20,218			21,020			19,153			18,553
Total liabilities and stockholders' equity	$	35,770		$	36,011		$	32,527		$	32,311

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)


	Six Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2015			2014			2016			2015
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income (loss)	$	(662	)	$	1,689		$	(577	)	$	(662	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations	—			(931		)
Deferred income taxes	(185		)	173			(392		)	(185		)
Depreciation, depletion and amortization	1,572			1,323			1,170			1,572
Impairments	44			21			1			44
Net (gain) loss on derivative instruments							88			17
Net cash received (paid) in settlement of derivative instruments							46			4
Pension and other postretirement benefits, net	14			26			14			14
Exploratory dry well costs and unproved property impairments	148			156			166			148
Net (gain) loss on disposal of assets	(1		)	85			(234		)	(1		)
Equity method investments, net	37			(10		)	22			37
Changes in:
Current receivables	534			(266		)	88			534
Inventories	21			(58		)	30			21
Current accounts payable and accrued liabilities	(770		)	(31		)	(211		)	(770		)
All other operating, net	(35		)	(59		)	41			(56		)
Net cash provided by continuing operations	717			2,118
Net cash provided by discontinued operations	—			440
Net cash provided by operating activities	717			2,558			252			717
Investing activities:
Additions to property, plant and equipment	(2,320		)	(2,230		)	(753		)	(2,320		)
Disposal of assets	2			2,232			758			2
Investments - return of capital	31			27			37			31
Purchases of short-term investments	(925		)	—			—			(925		)
Investing activities of discontinued operations	—			(233		)
Deposit for acquisition							(89		)	—
All other investing, net	(1		)	—			2			(1		)
Net cash used in investing activities	(3,213		)	(204		)	(45		)	(3,213		)
Financing activities:
Commercial paper, net	—			(135		)
Borrowings	1,996			—			—			1,996
Debt issuance costs	(19		)	—			—			(19		)
Debt repayments	(34		)	(34		)	—			(34		)
Purchases of common stock	—			(1,000		)
Common stock issuance							1,236			—
Dividends paid	(285		)	(260		)	(77		)	(285		)
All other financing, net	11			86			—			11
Net cash provided by (used in) financing activities	1,669			(1,343		)	1,159			1,669
Effect of exchange rate on cash and cash equivalents:
Continuing operations	1			—
Discontinued operations	—			(10		)
Cash held for sale	—			(96		)
Effect of exchange rate on cash and cash equivalents							(3		)	1
Net increase (decrease) in cash and cash equivalents	(826		)	905			1,363			(826		)
Cash and cash equivalents at beginning of period	2,398			264			1,221			2,398
Cash and cash equivalents at end of period	$	1,572		$	1,169		$	2,584		$	1,572

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

1. Basis of Presentation

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

AsA reclassification between operating cash flow categories was made to the prior year's financial information to present it on a ~~result of~~basis comparable with 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~~current year's presentation with no impact on net cash ~~flows are presented on the basis of continuing operations, unless otherwise noted.~~provided by operating activities.

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in ~~the Marathon Oil Corporation 2014~~our 2015 Annual Report on Form 10-K. The results of operations for the second quarter and first six months of ~~2015~~2016 are not necessarily indicative of the results to be expected for the full year.

2. Accounting Standards

Not Yet Adopted

In June 2016, the FASB issued a new accounting standards update that changes the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. The standard requires the use of a forward-looking "expected loss" model as opposed to the current "incurred loss" model. This standard is effective for us in the first quarter of 2020 and will be adopted on a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period. Early adoption is permitted starting January 2019. 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.

In March 2016, the FASB issued a new accounting standards update that changes several aspects of accounting for share-based payment transactions, including a requirement to recognize all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This standard is effective for us in the first quarter of 2017 and varying transition methods (modified retrospective, retrospective or prospective) should be applied to different provisions of the standard. Early adoption is permitted. We continue to evaluate the provisions of this accounting standards update but do not believe it will have a material effect on our consolidated results of operations, financial position or cash flows.

In February 2016, the FASB issued a new lease accounting standard, which requires lessees to recognize most leases, including operating leases, on the balance sheet as a right of use asset and lease liability. Short-term leases can continue being accounted for off balance sheet based on a policy election. This standard is effective for us in the first quarter of 2019 and should be applied using a modified retrospective approach at the beginning of the earliest period presented in the financial statements. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it will have on our consolidated results of operations, financial position or cash flows.

In January 2016, the FASB issued an accounting standards update that addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. This standard is effective for us in the first quarter of 2018. Early adoption is allowed for certain provisions. 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 July 2015, the FASB issued an update that requires an entity to measure inventory at the lower of cost and net realizable value. This excludes inventory measured using LIFO or the retail inventory method. This standard is effective for us in the first quarter of 2017 and will be applied prospectively. Early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

In August 2014, the 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 U.S. auditing standards. This standard is effective for us for the annual period ending after December 15, 2016 and for annual periods and interim periods thereafter. 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.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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 requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for us in the first quarter of 2018 and should be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. While early adoption is permitted, we plan to adopt in the first quarter of 2018. We continue to evaluate certain provisions of this accounting standards update and are assessing the impact it will have on our consolidated results of operations, financial position or cash flows.

Recently 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~~was applied on a retrospective basis. ~~Early adoption is permitted.~~ This standard only modifies disclosure requirements; as such, there ~~will be~~was 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 ifwhether 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~~2016. The adoption of this standard todid not have a significant impact on our consolidated results of operations, financial position or cash flows.

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

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

~~MARATHON OIL CORPORATION~~

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

~~Recently Adopted~~

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

3. Variable Interest Entity

The owners of the Athabasca Oil Sands Project, ~~("AOSP"),~~ in which we hold a 20% undivided interest, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton, Alberta, Canada. Costs under this contract are accrued and recorded on a monthly basis, with current liabilities of $2 million recorded at June 30, ~~2015~~2016 and ~~$3 million at~~ December 31, ~~2014.~~2015. This contract qualifies as a variable interest contractual arrangement, and the Corridor Pipeline qualifies as a VIE. We hold a variable interest but are not the primary beneficiary because our shipments are only 20% of the total; therefore, the Corridor Pipeline is not consolidated by us. Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was ~~$508~~$468 million as of June 30, ~~2015.~~2016. 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.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


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~~14 million stock options for the ~~second quarters of 2015~~three and ~~2014~~six month periods ended June 30, 2016 and 13 ~~million and 4~~ million stock options for the ~~first~~three and six month periods ended June 30, 2015 that were antidilutive.



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions, except per share data)	2016			2015			2016			2015
Net income (loss)	$	(170	)	$	(386	)	$	(577	)	$	(662	)

Weighted average common shares outstanding	848			677			790			676
Weighted average common shares, diluted	848			677			790			676
Net income (loss) per share:
Basic	$	(0.20	)	$	(0.57	)	$	(0.73	)	$	(0.98	)
Diluted	$	(0.20	)	$	(0.57	)	$	(0.73	)	$	(0.98	)

5. Acquisitions

In June 2016, we executed a purchase agreement to acquire PayRock Energy Holdings, LLC ("PayRock"), a portfolio company of EnCap Investments, which closed on August 1, 2016 for $888 million, subject to closing adjustments. PayRock has approximately 61,000 net surface acres and current production of approximately 9,000 net barrels of oil equivalent in the oil window of the Anadarko Basin STACK play in Oklahoma. In the second quarter of 2016 an $89 million deposit was paid into escrow related to the acquisition. The purchase price was paid with cash on hand. We accounted for this transaction as an asset acquisition, with the majority of the purchase price allocated to property, plant and equipment.


6.	Dispositions

2016 - North America E&P Segment

During the quarter, we announced the sale of our Wyoming upstream and midstream assets for proceeds of $870 million, before closing adjustments, of which approximately $690 million was received in the second quarter. A pre-tax gain of $266 million was recognized in the second quarter 2016. The remaining asset sales are subject to the receipt of certain tribal consents and are expected to close before year end. These assets are classified as held for sale in the consolidated balance sheet as of June 30, 2016 with total assets of $104 million and total liabilities of $4 million. The proceeds for the remaining asset sales were deposited into an escrow account by the buyer.

In March and April 2016, we entered into separate agreements to sell our 10% working interest in the outside-operated Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Colorado and certain undeveloped acreage in West Texas for a combined total of approximately $80 million in proceeds, before closing adjustments. We closed on certain of the asset sales and recognized a net pre-tax net loss on sale of $48 million for the six months ended June 30, 2016. The remaining asset sales are expected to close by year-end.

2015 - North America E&P Segment

In the third quarter of 2015, we closed on the sale of our East Texas/North Louisiana and ~~2014 that were antidilutive.~~Wilburton, Oklahoma natural gas assets for proceeds of approximately $100 million and recorded a pretax loss of $1 million. During the second quarter of 2015, we recorded a non-cash impairment charge of $44 million related to these assets as a result of the anticipated sale (see Note 13).

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

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

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

6.7. Segment Information

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

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

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

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

~~MARATHON OIL CORPORATION~~

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

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


	Three Months Ended June 30, 2015															Three Months Ended June 30, 2016
									Not Allocated																Not Allocated
(In millions)	N.A. E&P			Int'l E&P		OSM			to Segments				Total			N.A. E&P			Int'l E&P			OSM			to Segments				Total
Sales and other operating revenues	$	993		$	211	$	147		$	(44	)	^(c)	$	1,307		$	617		$	159		$	185		$	(91	)	^(c)	$	870
Marketing revenues	110			30		43			—				183			53			23			13			—				89
Total revenues	1,103			241		190			(44		)		1,490			670			182			198			(91		)		959
Income from equity method investments	—			26		—			—				26			—			37			—			—				37
Net gain on disposal of assets and other income	11			4		—			—				15			2			7			1			296			^(d)	306
Less:
Production expenses	179			64		207			—				450			129			56			165			—				350
Marketing costs	112			29		41			—				182			52			23			13			—				88
Exploration expenses	91			20		—			—				111			37			4			7			141			^(e)	189
Depreciation, depletion and amortization	634			71		35			11				751			433			68			49			11				561
Impairments	—			—		—			44			^(d)	44
Other expenses ^(a)	99			19		9			122			^(e)	249			97			22			9			99			^(f)	227
Taxes other than income	67			—		5			6				78			35			—			4			—				39
Net interest and other	—			—		—			58				58			—			—			—			86				86
Income tax provision (benefit)	(23		)	27		(30		)	20			^(f)	(6		)
Segment income (loss) /Loss from continuing operations	$	(45	)	$	41	$	(77	)	$	(305	)		$	(386	)
Income tax benefit																(41		)	(2		)	(10		)	(15		)		(68		)
Segment income (loss) / Net income (loss)																$	(70	)	$	55		$	(38	)	$	(117	)		$	(170	)
Capital expenditures ^(b)	$	551		$	99	$	16		$	12			$	678		$	153		$	12		$	7		$	5			$	177


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


^(b)	Includes accruals.


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


^(d)	~~Proved property impairment~~Primarily related to partial sale of Wyoming upstream and midstream assets. (See ~~Note 12).~~note 6.)


^(e)	~~Includes pension settlement loss~~Impairments associated with decision to not drill remaining Gulf of ~~$64 million (see Note 7).~~Mexico undeveloped leases.


^(f)	Includes ~~$135~~pension settlement loss of $31 million ~~of deferred tax expense related to Alberta provincial corporate tax rate increase (see Note~~(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															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	$	1,843		$	393	$	372		$	(21	)	^(c)	$	2,587		$	993		$	211	$	147		$	(44	)	^(c)	$	1,307
Marketing revenues	288			56		43			—				387			110			30		43			—				183
Total revenues	2,131			449		415			(21		)		2,974			1,103			241		190			(44		)		1,490
Income from equity method investments	—			62		—			—				62			—			26		—			—				26
Net gain on disposal of assets and other income	11			14		1			1				27			11			4		—			—				15
Less:
Production expenses	381			131		382			—				894			179			64		207			—				450
Marketing costs	292			54		41			—				387			112			29		41			—				182
Exploration expenses	126			75		—			—				201			91			20		—			—				111
Depreciation, depletion and amortization	1,317			135		97			23				1,572			634			71		35			11				751
Impairments	—			—		—			44			^(d)	44			—			—		—			44			^(d)	44
Other expenses ^(a)	216			42		18			251			^(e)	527			99			19		9			122			^(e)	249
Taxes other than income	128			—		10			7				145			67			—		5			6				78
Net interest and other	—			—		—			105				105			—			—		—			58				58
Income tax provision (benefit)	(112		)	24		(36		)	(26		)	^(f)	(150		)	(23		)	27		(30		)	20			^(f)	(6		)
Segment income (loss) /Loss from continuing operations	$	(206	)	$	64	$	(96	)	$	(424	)		$	(662	)
Segment income (loss) / Net income (loss)																$	(45	)	$	41	$	(77	)	$	(305	)		$	(386	)
Capital expenditures ^(b)	$	1,484		$	245	$	37		$	14			$	1,780		$	551		$	99	$	16		$	12			$	678


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


^(b)	Includes accruals.


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


^(d)	Proved property impairment (See Note ~~12)~~13).


^(e)	Includes ~~$43 million of severance related expenses associated with a workforce reduction and a~~ pension settlement loss of ~~$81~~$64 million (see Note 7)8).


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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


	Six Months Ended June 30, 2014													Six Months Ended June 30, 2016
							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	$	2,932	$	727	$	760	$	—			$	4,419		$	1,110		$	255		$	333		$	(114	)	^(c)	$	1,584
Marketing revenues	980		131		48		—				1,159			84			38			25			—				147
Total revenues	3,912		858		808		—				5,578			1,194			293			358			(114		)		1,731
Income from equity method investments	—		257		—		—				257			—			51			—			—				51
Net gain (loss) on disposal of assets and other income	18		32		3		(98		)	^(c)	(45		)
Net gain on disposal of assets and other income														3			13			1			233			^(d)	250
Less:
Production expenses	428		199		477		—				1,104			263			109			306			—				678
Marketing costs	977		131		48		—				1,156			84			37			25			—				146
Exploration expenses	139		79		—		—				218			55			10			7			141			^(e)	213
Depreciation, depletion and amortization	1,065		146		90		22				1,323			920			118			109			23				1,170
Impairments	21		—		—		—				21			1			—			—			—				1
Other expenses ^(a)	236		72		26		196			^(d)	530			215			38			16			218			^(f)	487
Taxes other than income	192		—		11		1				204			77			—			9			1				87
Net interest and other	—		—		—		125				125			—			—			—			171				171
Income tax provision (benefit)	328		139		40		(156		)		351
Segment income /Income from continuing operations	$	544	$	381	$	119	$	(286	)		$	758
Income tax benefit														(153		)	(14		)	(27		)	(150		)		(344		)
Segment income (loss) / Net income (loss)														$	(265	)	$	59		$	(86	)	$	(285	)		$	(577	)
Capital expenditures ^(b)	$	1,969	$	220	$	123	$	13			$	2,325		$	468		$	44		$	16		$	8			$	536


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

(b)Includes accruals.


^(c)	Unrealized loss on commodity derivative instruments.


^(d)	Related to net gain on disposal of assets (see Note 6).


^(e)	Impairments associated with decision to not drill remaining Gulf of Mexico undeveloped leases.


^(f)	Includes pension settlement loss of $79 million and severance related expenses associated with workforce reductions of $8 million (see Note 8).



	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) / Net income (loss)	$	(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)	~~Primarily related to the sale of non-core acreage (see Note 5).~~Unrealized loss on commodity derivative instruments.


^(d)	Proved property impairments (See Note 13).


^(e)	Includes pension settlement loss of ~~$71~~$81 million and severance related expenses associated with workforce reductions of $43 million (see Note 7)8).

~~7. Defined Benefit Postretirement Plans~~

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

Three Months Ended June 30,

Pension Benefits Other Benefits
(In millions) 2015 2014 2015 2014
Service cost $ 12
$ 11
$ 1
$ 1
Interest cost 13
15
2
3
Expected return on plan assets (17 ) (14 ) —
—
Amortization:

– prior service cost (credit) (2 ) 2
(1 ) (1 )
– actuarial loss 7
10
—
—
Net settlement loss ^(a)
64
8
—
—
Net curtailment loss^(b)
—
—
2
—
Net periodic benefit cost $ 77
$ 32
$ 4
$ 3


^(f)	Includes $135 million of deferred tax expense related to Alberta provincial corporate tax rate increase (see Note 9).

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

8. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:



	Three Months Ended June 30,
	Pension Benefits						Other Benefits
(In millions)	2016			2015			2016			2015
Service cost	$	6		$	12		$	1		$	1
Interest cost	10			13			2			2
Expected return on plan assets	(13		)	(17		)	—			—
Amortization:
– prior service cost (credit)	(3		)	(2		)	(1		)	(1		)
– actuarial loss	4			7			—			—
Net settlement loss ^(a)	31			64			—			—
Net curtailment loss ^(b)	—			—			—			2
Net periodic benefit cost	$	35		$	77		$	2		$	4



	Six Months Ended June 30,
	Pension Benefits						Other Benefits
(In millions)	2016			2015			2016			2015
Service cost	$	12		$	24		$	2		$	2
Interest cost	21			27			5			5
Expected return on plan assets	(28		)	(36		)	—			—
Amortization:
– prior service cost (credit)	(5		)	(1		)	(2		)	(2		)
– actuarial loss	7			14			—			—
Net settlement loss ^(a)	79			81			—			—
Net curtailment loss (gain) ^(b)	—			1			—			(4		)
Net periodic benefit cost	$	86		$	110		$	5		$	1


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


^(b)	Related to ~~the~~ workforce ~~reduction,~~reductions, which reduced the future expected years of service for employees participating in the plans.

During the first six months of ~~2015,~~2016, 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 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).~~cost.

During the first six months of ~~2015,~~2016, we made contributions of ~~$46~~$30 million to our funded pension plans. We expect to make additional contributions up to an estimated ~~$42~~$34 million to our funded pension plans over the remainder of ~~2015.~~2016. During the first six months of ~~2015,~~2016, we made payments of ~~$42~~$37 million and $8$10 million related to unfunded pension plans and other postretirement benefit plans, respectively.

8.9. Income Taxes

Effective Tax Rate

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

Our effective income tax rates ~~on continuing operations~~ for the first six months of 2016 and 2015 were 37% and ~~2014 were~~ 18% ~~and 32%~~. The tax provision (benefit) applicable to Libyan ordinary income (loss) was recorded as a discrete item in the first six months of 2015 and 2014. Excluding Libya, the effective tax rates on continuing operations, would be 15% and 34% for the first six months of 2015 and 2014. In Libya, considerable uncertainty remains around the timing of future production and sales levels. Reliable estimates of ~~2015~~2016 and ~~2014~~2015 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 tax benefit applicable to Libyan ordinary loss was

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

recorded as a discrete item in the first six months of ~~2015~~2016 and ~~2014,~~2015. For the first six months of 2016 and 2015, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss).

On Excluding Libya, the effective tax rates would be 36% and 15% for the first six months of 2016 and 2015. The change was driven by a shift in jurisdictional income and tax legislation enacted by the Alberta government 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.

Deferred Tax Assets

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 associatedconnection with our ~~Canadian operations to~~assessment of the realizability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of our deferred tax assets will not be ~~permanently reinvested outside~~realized. In the ~~U.S. As such, none~~event it is more likely than not that some portion or all 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 netour deferred taxes ~~have been recorded in~~will not be realized, such assets are reduced by a valuation allowance. Future increases to our valuation allowance are possible if our estimates and assumptions (particularly as they relate to our long-term commodity price forecast) are revised such that they reduce estimates of future taxable income during the ~~second quarter of 2015.~~carryforward period.

~~MARATHON OIL CORPORATION~~

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

9.10. Short-term Investments

As of June 30, 2015, ~~our~~we held 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~~which were classified as held-to-maturity investments ~~which are~~and recorded at amortized ~~cost. The carrying values~~cost, matured in the third quarter of ~~our short-term investments approximate fair value.~~2015.

~~10.~~11. Inventories

~~Inventories of liquid~~Liquid hydrocarbons, natural gas and bitumen are recorded at weighted average cost and carried at the lower of cost or market value. ~~Materials~~Supplies and ~~supplies~~other items consist principally of tubular goods and equipment which are valued at weighted average cost and reviewed periodically for obsolescence or impairment when market conditions indicate.


	June 30,		December 31,		June 30,		December 31,
(In millions)	2015		2014		2016		2015
Liquid hydrocarbons, natural gas and bitumen	$	50	$	58	$	31	$	35
Supplies and other items	286		299		241		278
Inventories, at cost	$	336	$	357	$	272	$	313

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


	June 30,		December 31,		June 30,		December 31,
(In millions)	2015		2014		2016		2015
North America E&P	$	16,757	$	16,717	$	13,965	$	15,226
International E&P	2,848		2,741		2,479		2,533
Oil Sands Mining	9,401		9,455		9,101		9,197
Corporate	115		127		112		105
Net property, plant and equipment	$	29,121	$	29,040	$	25,657	$	27,061

Our Libya operations continue to be impacted by civil ~~unrest~~unrest. Operations were interrupted in mid-2013 as a result of the shutdown of the Es-Sider crude oil terminal, and although temporarily re-opened during the second half of 2014, production remains shut-in. Earlier this year, an Internationally-backed Unity Government was established in ~~December 2014, Libya’s~~Tripoli. During the second quarter, the two National Oil ~~Corporation once again declared force majeure~~Companies agreed to unify and reportedly have begun preliminary discussions on re-opening the Es-Sider and other crude oil terminals which, if successful, will allow resumption of production operations at ~~the Es Sider oil terminal, as disruptions from civil unrest continue. Considerable~~our Waha concessions. However, considerable uncertainty remains around the timing of future production and sales levels.

As of June 30, ~~2015,~~2016, our net property, plant and equipment investment in Libya is $775 million, and total proved reserves (unaudited) in Libya as of December 31, ~~2014~~2015 are ~~243~~235 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~~continue to exceed the carrying value of $775 million by a material amount. However, changes in

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

management's forecast assumptions may cause us to reassess our assets in Libya for impairment, and could result in non-cash impairment charges in the future.

Exploratory well costs capitalized greater than one year after completion of drilling were ~~$88~~$118 million and ~~$126~~$85 million as of June 30, ~~2015~~2016 and December 31, ~~2014. This $38~~2015. The $33 million ~~net decrease was associated with our Canadian in-situ assets at Birchwood. After further evaluation~~increase primarily relates to the Alba Block Sub Area B offshore Equatorial Guinea where the Rodo well reached total depth in the first quarter of 2015. We have since completed a seismic feasibility study and continue to finalize next steps in the ~~estimated recoverable resources and our development plans, we withdrew our regulatory application for the proposed steam assisted gravity drainage ("SAGD") demonstration project.~~Alba Block Sub Area B exploration program.

~~MARATHON OIL CORPORATION~~

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

~~12.~~13. Fair Value Measurements

Fair Values - Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of June 30, ~~2015~~2016 and December 31, ~~2014~~2015 by fair value hierarchy level.


	June 30, 2015								June 30, 2016
(In millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity^(a)	$	—	$	5	$	—	$	5	$	—	$	6	$	—	$	6
Interest rate	—		11		—		11		—		12		—		12
Derivative instruments, assets	$	—	$	16	$	—	$	16	$	—	$	18	$	—	$	18
Derivative instruments, liabilities
Commodity^(a)	$	—	$	26	$	—	$	26	$	—	$	70	$	—	$	70
Derivative instruments, liabilities	$	—	$	26	$	—	$	26	$	—	$	70	$	—	$	70


^(a)	Derivative instruments are recorded on a net basis in the company's balance sheet (see Note ~~13)~~14).


	December 31, 2014								December 31, 2015
(In millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity^(a)									$	—	$	51	$	—	$	51
Interest rate	$	—	$	8	$	—	$	8	—		8		—		8
Derivative instruments, assets	$	—	$	8	$	—	$	8	$	—	$	59	$	—	$	59
Derivative instruments, liabilities
Commodity^(a)									$	—	$	1	$	—	$	1
Derivative instruments, liabilities									$	—	$	1	$	—	$	1


^(a)	Derivative instruments are recorded on a net basis in the company's balance sheet (see Note 14).

Commodity derivatives include three-way collars, ~~swaptions, extendable three-way~~two-way collars, call options and ~~call options.~~swaptions. These instruments are measured at fair value using either the Black-Scholes Model or the Black Model. Inputs to both models include commodity 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 1314 for additional discussion of the types of derivative instruments we use.

Fair Values -– Goodwill

Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. We estimate the fair value of our International E&P reporting unit using a combination of market and income approaches. The market approach referenced observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value, and valuation multiples of us and our peers from the investor analyst community. The income approach utilized discounted cash flows, which were based on forecasted assumptions. Key assumptions to the income approach include future liquid hydrocarbon and natural gas pricing, estimated quantities of liquid hydrocarbons and natural gas proved and probable reserves, estimated timing of production, discount rates, future capital requirements and operating expenses and tax rates. The assumptions used in the income approach

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

are consistent with those that management uses to make business decisions. These valuations methodologies represent Level 3 fair value measurements. We performed our annual impairment test in April 2016 and concluded no impairment was required. While the fair value of our International E&P reporting unit exceeded the book value, subsequent commodity price and/or common stock declines may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.

Fair Values- Nonrecurring

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


	Three Months Ended June 30,								Three Months Ended June 30,
	2015				2014				2016				2015
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	17	$	44	$	—	$	4	$	—	$	—	$	17	$	44


	Six Months Ended June 30,								Six Months Ended June 30,
	2015				2014				2016				2015
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	17	$	44	$	—	$	21	$	—	$	1	$	17	$	44

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

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

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

~~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~~East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets as a result of the anticipated ~~sale.~~sale (See Note 6). The fair values were measured using a probability weighted income approach based on both the anticipated sales price and a held-for-use model. ~~The held-for-use model contained internal estimates of future production levels, prices and discount rate. All such inputs were classified as Level 3.~~

The Ozona development in the Gulf of Mexico ceased producing in 2013, at which time those long-lived assets were fully impaired. In the first and second quarters of 2014, we recorded additional impairments of $17 million 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~~values by individual balance sheet line item at June 30, ~~2015~~2016 and December 31, ~~2014.~~2015.


	June 30, 2015				December 31, 2014				June 30, 2016				December 31, 2015
	Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount		Value		Amount		Value		Amount
Financial assets
Other noncurrent assets	$	134	$	133	$	132	$	129	$	198	$	206	$	104	$	118
Total financial assets	134		133		132		129		$	198	$	206	$	104	$	118
Financial liabilities
Other current liabilities	13		13		13		13		$	25	$	24	$	34	$	33
Long-term debt, including current portion^(a)	8,720		8,324		6,887		6,360		7,186		7,291		6,723		7,291
Deferred credits and other liabilities	73		67		69		68		121		117		97		95
Total financial liabilities	$	8,806	$	8,404	$	6,969	$	6,441	$	7,332	$	7,432	$	6,854	$	7,419

^(a) Excludes capital ~~leases.~~leases, debt issuance costs and interest rate swap adjustments.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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

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

~~13.~~14. Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note ~~12.~~13. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts where they appear on the consolidated balance ~~sheets as of June 30, 2015 and December 31, 2014.~~

~~MARATHON OIL CORPORATION~~

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

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

$ —

$ 11

sheets.


								June 30, 2016
(In millions)								Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate								$	12	$	—	$	12	Other noncurrent assets
Total Designated Hedges								$	12	$	—	$	12

	June 30, 2015							June 30, 2016
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location	Asset		Liability		Net Liability		Balance Sheet Location
Not Designated as Hedges
Commodity	$	5	$	17	$	12	Other current liabilities	$	6	$	39	$	33	Other current liabilities
Commodity	—		9		9		Other noncurrent liabilities	—		31		31		Deferred credits and other liabilities
Total	$	5	$	26	$	21
Total Not Designated as Hedges								$	6	$	70	$	64

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



	December 31, 2015
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	8	$	—	$	8	Other noncurrent assets

Not Designated as Hedges
Commodity	$	51	$	1	$	50	Other current assets

Derivatives Designated as Fair Value Hedges

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


	June 30, 2015				December 31, 2014				June 30, 2016				December 31, 2015
	Aggregate Notional Amount		Weighted Average, LIBOR-Based,		Aggregate Notional Amount		Weighted Average, LIBOR-Based,		Aggregate Notional Amount		Weighted Average, LIBOR-Based,		Aggregate Notional Amount		Weighted Average, LIBOR-Based,
Maturity Dates	(in millions)		Floating Rate		(in millions)		Floating Rate		(in millions)		Floating Rate		(in millions)		Floating Rate
October 1, 2017	$	600	4.67	%	$	600	4.64	%	$	600	4.94	%	$	600	4.73	%
March 15, 2018	$	300	4.52	%	$	300	4.49	%	$	300	4.77	%	$	300	4.66	%

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 June 30,						Six Months Ended June 30,							Three Months Ended June 30,					Six Months Ended June 30,
(In millions)	Income Statement Location	2015			2014			2015			2014			Income Statement Location	2016		2015			2016			2015
Derivative
Interest rate	Net interest and other	$	(2	)	$	4		$	3		$	3		Net interest and other	$	—	$	(2	)	$	4		$	3
Foreign currency	Discontinued operations	$	—		$	(14	)	$	—		$	(11	)
Hedged Item
Long-term debt	Net interest and other	$	2		$	(4	)	$	(3	)	$	(3	)	Net interest and other	$	—	$	2		$	(4	)	$	(3	)
Accrued taxes	Discontinued operations	$	—		$	14		$	—		$	11

Derivatives not Designated as Hedges

~~During the first six months of 2015, we~~We have entered into multiple crude oil and natural gas derivatives indexed to ~~New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI"),~~NYMEX WTI and Henry Hub related to a portion of our forecasted North America E&P sales through December ~~2016.~~2017. These commodity derivatives ~~primarily~~ consist of three-way collars, two-way collars, call options and ~~three way-collars which~~swaptions. Three-way collars consist of a sold call (ceiling), a purchased put (floor) and a sold put. The ceiling price is the maximum we will receive for the contract ~~crude oil~~ volumes, the floor is the minimum price we will receive, unless the market price falls below the sold put strike price.

~~MARATHON OIL CORPORATION~~

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

In this case, we receive the NYMEX ~~WTI~~WTI/Henry Hub price plus the difference between the floor and the sold put price. These commodity derivatives were not designated as ~~hedges~~hedges. The following table sets forth outstanding derivative contracts as of June 30, 2016 and ~~are shown in~~ the ~~table below:~~weighted average prices for those contracts:


Financial Instrument	Weighted Average Price	Barrels per day	Remaining Term
Crude Oil				Crude Oil
						Year Ending December 31,
				Third Quarter	Fourth Quarter	2017
Three-Way Collars				Three-Way Collars
Volume (Bbls/day)				47,000		—
Price per Bbl:
Ceiling	$70.34	35,000	July- December 2015 ^(a)	$55.37		—
Floor	$55.57			$50.23		—
Sold put	$41.29			$40.96		—

Sold call options ^(a)
Volume (Bbls/day)				10,000		35,000
Price per Bbl				$72.39		$61.91
Two-way Collars
Volume (Bbls/day)				10,000		—
Price per Bbl:						—
Ceiling	$71.84	12,000	January- December 2016	$50.00
Floor	$60.48			$41.55
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~~Call options settle monthly.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



Natural Gas
			Year Ending December 31,
	Third Quarter	Fourth Quarter	2017
Three-Way Collars ^(a)
Volume (MMBtu/day)	20,000	20,000	40,000
Price per MMBtu
Ceiling	$2.93	$2.93	$3.28
Floor	$2.50	$2.50	$2.75
Sold put	$2.00	$2.00	$2.25

^(a)

On our 2016 collars, the counterparty has the option to execute fixed-price swaps (swaptions) at a weighted average price of ~~$71.67~~$2.93 per ~~barrel~~MMBtu indexed to NYMEX ~~WTI,~~Henry Hub, which is exercisable on ~~October 30, 2015.~~December 22, 2016. If ~~counterparties exercise,~~counterparty exercises, the term of the ~~fixed price~~fixed-price swaps would be for the calendar year ~~2016~~2017 and, if all such options are exercised, ~~25,000 barrels~~20,000 MMBtu 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 mark-to-market impact of these ~~crude oil~~commodity derivative instruments appears in sales and other operating revenues in our consolidated statements of income for the three and six month periods ended June 30, 2016 was a net loss of $88 million and $90 million compared to a net loss of $43 million and $17 million for the same respective periods in ~~the second quarter and first six months~~2015. Net cash received from settlements of ~~2015. There were no crude oil~~commodity derivative instruments infor the ~~first~~three and six ~~months of 2014.~~

Onmonth periods ended June ~~1, 2015, we entered into Treasury rate locks, which expired on the same day,~~30, 2016 was $14 million and $46 million compared to ~~hedge against timing differences as it related to our Notes offering (see Note 15). Following the execution~~$4 million for both 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~~respective periods in ~~a gain of $6 million, which was recognized in net interest and other in our consolidated statements of income.~~2015.

~~14.~~15. Incentive Based Compensation

Stock ~~option~~options, restricted stock awards and restricted stock ~~awards~~units

The following table presents a summary of ~~stock option and restricted stock award~~ activity for the first six months of ~~2015:~~2016:


	Stock Options					Restricted Stock				Stock Options					Restricted Stock Awards & Units
	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
Outstanding at December 31, 2015										12,665,419				$29.97	4,017,344			$30.76
Granted	724,082		^(a)		$29.06	2,668,357			$30.53	1,680,000		^(a)		$7.22	5,233,984			$7.91
Options Exercised/Stock Vested	(480,458	)			$16.47	(921,404	)		$34.29	—			—		(1,148,953	)		$32.29
Canceled	(455,855	)			$34.48	(491,739	)		$33.70	(973,295	)			$25.76	(557,051	)		$23.20
Outstanding at June 30, 2015	13,215,605				$29.97	4,703,567			$32.04
Outstanding at June 30, 2016										13,372,124				$27.42	7,545,324			$15.23

^(a) The weighted average grant date fair value of stock option awards granted was ~~$6.84~~$1.97 per share.

Stock-based performance unit awards

During the first six months of ~~2015,~~2016, we granted ~~382,335~~1,205,517 stock-based performance units to certain officers. The grant date fair value per unit was ~~$31.77.~~$3.72.

~~MARATHON OIL CORPORATION~~

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

~~15.~~16. Debt

Revolving Credit Facility

As of June 30, ~~2015,~~2016, we had no borrowings against our revolving credit facility ~~(as amended, the~~(the "Credit Facility"), as described below.

In ~~May 2015,~~March 2016, we ~~amended~~increased our ~~$2.5~~$3.0 billion unsecured Credit Facility ~~to increase the facility size~~ by ~~$500~~$300 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.$3.3 billion.

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,~~2016, we were in compliance with this covenant with a debt-to-capitalization ratio of ~~29%~~28%.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Debt Issuance ~~On June 10,~~

In the second quarter of 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~~and used 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.~~17. Reclassifications Out of Accumulated Other Comprehensive ~~Income (Loss)~~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:~~loss:


	Three Months Ended June 30,						Six Months Ended June 30,							Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2015			2014			2015			2014			Income Statement Line	2016			2015			2016			2015			Income Statement Line

Postretirement and postemployment plans	Postretirement and postemployment plans													Postretirement and postemployment plans
Amortization of actuarial loss	$	(7	)	$	(10	)	$	(14	)	$	(16	)	General and administrative	$	(4	)	$	(7	)	$	(7	)	$	(14	)	General and administrative
Net settlement loss	(64		)	(8		)	(81		)	(71		)	General and administrative	(31		)	(64		)	(79		)	(81		)	General and administrative
Net curtailment gain (loss)	(2		)	—			3			—			General and administrative	—			(2		)	—			3			General and administrative
	(73		)	(18		)	(92		)	(87		)	Income (loss) from operations	(35		)	(73		)	(86		)	(92		)	Income (loss) from operations
	25			7			32			30			Benefit for income taxes	13			25			29			32			Provision (benefit) for income taxes
Other insignificant, net of tax	—			—			—			(1		)
Total reclassifications	$	(48	)	$	(11	)	$	(60	)	$	(58	)	Income (loss) from continuing operations
Total reclassifications to expense														$	(22	)	$	(48	)	$	(57	)	$	(60	)	Net income (loss)

~~MARATHON OIL CORPORATION~~18. Stockholder's Equity

~~Notes~~In March 2016, we issued 166,750,000 shares of our common stock, par value $1 per share, at a price of $7.65 per share, excluding underwriting discounts and commissions, for net proceeds of $1,236 million. The proceeds were used to ~~Consolidated Financial Statements (Unaudited)~~strengthen our balance sheet and for general corporate purposes, including funding a portion of our Capital Program.

~~17.~~19. 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



	Six Months Ended June 30,
(In millions)	2016			2015
Net cash (used in) operating activities:
Interest paid (net of amounts capitalized)	$	(177	)	$	(143	)
Income taxes paid to taxing authorities	(61		)	(165		)
Noncash investing activities:
Asset retirement cost increase	$	2		$	6
Asset retirement obligations assumed by buyer	83			—


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

~~18.~~20. Commitments and Contingencies

We are a defendant in a number of ~~lawsuits~~legal and administrative proceedings arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims, tax disputes 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.

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.

21. Subsequent Event

During the third quarter 2016, we executed an agreement to terminate our Gulf of Mexico deepwater drilling rig contract. As a result, we expect to recognize a termination payment of $113 million in other operating expense in that quarter.

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

Results of Operations

Critical Accounting Estimates

Cash Flows and Liquidity

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the preceding consolidated financial statements and notes in Item 1.

Executive Overview

We are aan independent global ~~energy~~exploration and production company based in Houston, Texas with operations in North America, Europe and ~~Africa. Each of our three reportable operating segments is organized~~Africa and ~~managed based upon both geographic location~~a focus on U.S. unconventional resource plays. Total proved reserves were 2.2 billion boe at December 31, 2015 and total assets were $33 billion at June 30, 2016.

Our significant strategic actions and financial results include the ~~nature of the products~~following:

Strengthened balance sheet


◦	At the end of the second quarter of 2016, we had $5.9 billion of liquidity, comprised of $2.6 billion in cash and an undrawn $3.3 billion revolving credit facility


◦	Cash-adjusted debt-to-capital ratio of 20% at June 30, 2016, as compared with 25% at December 31, 2015

Focused on cost reductions


◦	Production expenses per boe in the second quarter of 2016, as compared to the same period last year improved in the North America E&P segment by 13% to $6.28 per boe and in the International E&P segment by 22% to $5.09 per boe


◦	2016 Capital Program reduced by $100 million to $1.3 billion


◦	Eagle Ford completed well costs down 30% to $4.2 million versus the same quarter last year

Simplifying and ~~services it offers.~~concentrating portfolio


◦	Closed on the PayRock acquisition of STACK assets in Oklahoma for $888 million, funded with cash on hand


◦	Entered into agreements for over $1 billion of transaction value related to non-core asset sales; already received over $800 million in proceeds through August 1, 2016

Major Project updates


◦	Alba B3 compression project in E.G., designed to maintain the production plateau two additional years and extend field life up to eight years, was completed within budget and on schedule with first gas in July


◦	Outside-operated Gunflint development project in the Gulf of Mexico achieved first oil in July

Financial results


◦	Cash provided by operating activities of $252 million for the first six months of 2016, despite average crude oil and condensate price realizations of $35.27 per bbl.


◦	Net loss per share of $0.20 in the second quarter of 2016 as compared to net loss per share of $0.57 in the same period last year. Included in the second quarter 2016 net loss are:


▪	Unrealized losses from our commodity derivative instruments totaling $91 million, pre-tax


▪	Net gains on disposal of non-core assets totaling $294 million, pre-tax


▪	Non-cash impairments totaling $141 million, pre-tax, as a result of our decision not to drill any of our remaining Gulf of Mexico leases

~~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.~~

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.

~~Executive Overview~~Outlook

Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows and ~~their subsequent reinvestment~~the amount of capital available to reinvest into our business. ~~Commodity prices began declining~~Our focus continues on the strengthening of the balance sheet, the simplification and concentration of our portfolio and cost reductions which during the second quarter of 2016 included a reduction to our Capital Program of $100 million to $1.3 billion for the year.

Exploration Update

In September 2015, we announced our intention to scale back our conventional exploration program, with future exploration investment focused on fulfilling our existing commitments in the Gulf of Mexico and Gabon. In second ~~half~~quarter of ~~2014 and remain substantially lower through 2015 as compared~~2016, we made the decision to ~~the first six months~~not drill our remaining Gulf of ~~2014. We believe~~Mexico undeveloped leases. As a result, we ~~can manage in this lower commodity price cycle through~~recorded a continued focus on development in our three U.S. resource plays, operational execution, efficiency improvements, cost reductions, capital discipline and portfolio optimization, all while maintaining financial flexibility.

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

~~Increased company-wide net sales volumes from continuing operations by 4% to 411 thousand barrels~~non-cash impairment of ~~oil equivalent per day ("mboed")~~$141 million in the second quarter of ~~2015 from 394 mboed~~2016. Additionally, during the third quarter 2016, we executed an agreement to terminate our Gulf of Mexico deepwater drilling rig contract. As a result, we expect to recognize a termination payment of $113 million in ~~the second quarter of 2014~~


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

~~Maintained focus on cost discipline and efficiencies~~


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


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


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

~~Active management of liquidity and capital structure~~


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


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


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


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


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


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

~~Portfolio management activities~~


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


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

~~Financial results~~


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


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


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

other operating expense in that quarter.

We continue to optimize our resource allocation given the current price environment. We expect our full-year 2015 capital, investment and exploration budget to be at or below $3.3 billion. We estimate our full-year North America E&P and International E&P production volumes (excluding Libya) to be 375 - 390 net mboed.

Operations

~~North America E&P--Production~~The following table presents a summary of our sales volumes for each of our segments. Refer to the Results of Operations for a price-volume analysis for each of the segments.



	Three Months Ended June 30,			Six Months Ended June 30,
Net Sales Volumes	2016	2015	Increase (Decrease)	2016	2015	Increase (Decrease)
North America E&P (mboed)	224	274	(18)%	232	278	(17)%
International E&P (mboed)	120	108	11%	108	112	(4)%
Oil Sands Mining (mbbld) ^(a)	49	29	69%	54	44	23%
Total (mboed)	393	411	(4)%	394	434	(9)%

^(a)Includes blendstocks

North America E&P

Net sales volumes in the segment ~~average net sales volumes~~were lower in the second quarter and first six months of ~~2015 increased 21%~~2016 primarily as a result of decreased drilling and ~~26% compared~~completion activity resulting in fewer wells brought to sales as well as 17 mboed relating to dispositions of certain non-core assets (Gulf of Mexico and East Texas, North Louisiana and Wilburton, Oklahoma) during the second ~~quarter and first six months~~half of ~~2014. Net liquid hydrocarbon~~2015. The following tables provide details regarding net sales volumes, ~~increased 35 thousand barrels per day ("mbbld")~~sales mix and 47 mbbld, and net natural gas sales volumes increased 67 million cubic feet per day ("mmcfd") and 63 mmcfd in the second quarter and first six months of 2015 compared to the second quarter and first six months of 2014, reflecting continued growth from the combined U.S. resource plays.operational drilling activity for our significant operations within this segment:



	Three Months Ended June 30,			Six Months Ended June 30,
Net Sales Volumes	2016	2015	Increase (Decrease)	2016	2015	Increase (Decrease)
Equivalent Barrels (mboed)
Eagle Ford	109	135	(19)%	114	141	(19)%
Oklahoma Resource Basins	27	24	13%	27	24	13%
Bakken	53	61	(13)%	55	59	(7)%
Other North America ^(a)	35	54	(35)%	36	54	(33)%
Total North America E&P	224	274	(18)%	232	278	(17)%

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

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

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

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

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

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

^(a)Includes 17 mboed of Gulf of Mexico and other conventional onshore U.S. ~~production.~~

~~The following table presents a summary~~production, which was disposed of ~~our operated drilling activity in~~during the ~~U.S. resource plays:~~

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

~~Eagle Ford – Average net sales volumes from Eagle Ford were 135 mboed and 141 mboed~~sale of non-core assets in the second ~~quarter and first six months~~half of ~~2015 compared~~2015.



	Three Months Ended June 30, 2016
Sales Mix - U.S. Resource Plays	Crude oil and condensate	Natural gas liquids	Natural gas

Eagle Ford	56%	21%	23%
Oklahoma Resource Basins	21%	29%	50%
Bakken	83%	9%	8%



	Three Months Ended June 30,		Six Months Ended June 30,
	2016	2015	2016	2015
Gross Operated
Eagle Ford:
Wells drilled to total depth	40	59	98	147
Wells brought to sales	30	52	80	143
Oklahoma Resource Basins:
Wells drilled to total depth	6	5	11	13
Wells brought to sales	5	3	8	8
Bakken:
Wells drilled to total depth	—	5	3	25
Wells brought to sales	4	22	10	46

Eagle Ford – Of the 30 gross operated wells brought to ~~102 mboed and 99 mboed in~~sales during the ~~same periods of 2014, for increases of 32% and 42%. Approximately 61% of~~ second quarter of 2016, 19 were Lower Eagle Ford, 3 were Upper Eagle Ford and 8 were Austin Chalk. Production decreases were due to lower completion activity with fewer gross operated wells brought to sales ~~was crude oil~~ and ~~condensate, 19% was NGLs and 20% was natural gas.~~reduced contribution from 2015 high-density pads drilled at tighter well spacing. Our average time to drill an Eagle Ford well in the second quarter ~~2015,~~2016, spud-to-total depth, was 8 days, a decrease from 11 days. Also, during the second quarter of 2015, we brought online 8 Upper Eagle Ford, 33 Lower Eagle Ford 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 61 mboed and 59 mboed in the second quarter and first six months of 2015 compared to 50 mboed and 46 mboed~~days in the same ~~period for 2014, for increases~~quarter last year as efficiency gains in drilling continued. Wells were drilled at an average rate of 22% and 28%. Our Bakken production averaged approximately 89% crude oil, 5% NGLs and 6% natural gas. Our time to drill a Bakken well, spud-to-total depth, averaged 13 days in the second quarter of 2015.2,400 feet per day.

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

Oklahoma Resource Basins – Net sales volumes from the Oklahoma Resource Basins averaged 24 mboed in both the second quarter and first six months of 2015 compared to 18 mboed and 17 mboed in the comparable 2014 periods, for increases of 33% and 41%. Our second quarter 2015 production was approximately 20% crude, 25% NGLs and 55% natural gas. Of the ~~three~~5 gross operated wells brought to sales ~~this~~in the second quarter ~~two~~of 2016, 3 were ~~SCOOP wells and one was a STACK Osage well. We also finished drilling five operated Smith infill pilot wells this quarter.~~

~~Additionally, we continue to leverage the benefit of participation in outside-operated wells and plan to participate in approximately 85 outside-operated wells in 2015~~ in the SCOOP ~~Woodford, SCOOP Springer~~Woodford; 2 were in the STACK Meramec and ~~STACK areas. In the first six months of 2015, we~~all were extended laterals. We also participated in ~~four~~16 outside-operated ~~high-density spacing pilots~~wells during the second quarter of 2016, 10 of which were in the SCOOP ~~area; three~~and 6 were in the ~~Woodford (80-128 acre spacing) and one~~STACK.

We closed on the Payrock acquisition in the ~~emerging Springer shale (105-128 acre spacing) overlaying~~STACK play in Oklahoma on August 1, 2016 and continue to operate one drilling rig on the ~~Woodford. Two outside-operated STACK Meramec XL~~acreage with plans to add another rig late in the third quarter. This will bring the total rig count in Oklahoma to 4.

Bakken – Of the 4 gross operated wells ~~were~~ brought to sales ~~during~~in the ~~quarter.~~second quarter of 2016, 2 were in the Middle Bakken formation and 2 in the Three Forks formation, all with higher intensity completions. We do not currently have an active drilling rig in the Bakken.

Other North America – Net sales volumes declined in the second quarter of 2016 primarily due to the 2015 sales of the non-core assets in the Gulf of Mexico, ~~– Development work continues in~~East Texas, North Louisiana and Wilburton, Oklahoma. On June 30, we closed the sale of certain of our Wyoming upstream and midstream assets. Net sales volumes for all of our Wyoming assets were approximately 16 mboed for the second quarter and first half of 2016.

The Gunflint field, located onin Mississippi Canyon ~~Blocks~~block 948 ~~949, 992 (N/2) and 993 (N/2). We expect the two-well subsea tieback to be complete~~ in the ~~second half~~Gulf of ~~2015.~~Mexico, achieved first production in July 2016. Full production is expected to reach at least 20 mboed gross with oil representing approximately 75% of the volumes produced. We hold an 18% non-operated working interest in the Gunflint field.

~~North America E&P--Exploration~~

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

~~The third appraisal well on the Shenandoah prospect was spud in May 2015 and is still drilling. The well is located in Walker Ridge Block 52, in which we hold a 10% non-operated working interest.~~

~~International E&P--Production~~

International E&P ~~segment average net~~

Net sales volumes in the ~~second quarter and first six months of 2015 decreased 12% and 10% compared to the second quarter and first six months of 2014, reflecting field decline and a planned turnaround in Equatorial Guinea~~segment were higher in the second quarter of ~~2015, which also reduced sales to the AMPCO and LNG facilities. In addition, the AMPCO methanol facility completed~~2016 primarily as a result of planned turnaround and maintenance activities at the Alba field and E.G. LNG facilities in ~~first~~the second quarter of 2015. The following table provides details regarding net sales volumes for our significant operations within this segment.

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

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

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

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

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

Equatorial Guinea 89
105
93
107
United Kingdom^(a)
19
18
19
18
Total International E&P (mboed)
108
123
112
125
Net Sales Volumes of Equity Method Investees
LNG (mtd)
4,991
6,624
5,629
6,601
Methanol (mtd)
673
980
778
1,066



	Three Months Ended June 30,			Six Months Ended June 30,
Net Sales Volumes	2016	2015	Increase (Decrease)	2016	2015	Increase (Decrease)
Equivalent Barrels (mboed)
Equatorial Guinea	101	89	13%	93	93	—%
United Kingdom^(a)	19	19	—%	15	19	(21)%
Total International E&P	120	108	11%	108	112	(4)%
Equity Method Investees
LNG (mtd)	5,797	4,991	16%	5,060	5,629	(10)%
Methanol (mtd)	1,303	673	94%	1,292	778	66%
Condensate & LPG (boed)	11,306	8,586	32%	10,757	10,892	(1)%


^(a)	Includes natural gas acquired for injection and subsequent resale of 75 mmcfd and 57 mmcfd for the second quarters of 2016 and 2015, and ~~2014,~~5 mmcfd and 9 ~~mmcfd and 6~~ mmcfd for the first six months of ~~2015~~2016 and ~~2014.~~2015.

Equatorial Guinea – ~~Average~~Second quarter 2016 net sales ~~volumes~~ were ~~89 mboed and 93 mboed in~~higher compared to the ~~second~~same quarter ~~and first six months~~ of 2015 ~~compared~~due to ~~105 mboed and 107 mboed in the same periods of 2014. Planned~~lower planned turnaround and maintenance activities at the Alba field and EGE.G. LNG ~~facilities reduced production rates during the second quarter of 2015.~~facilities. The Alba ~~turnaround subsequently reduced sales~~field compression project achieved first gas in July, which is expected to ~~our equity method investees, Alba Plant LLC, EGHoldings~~maintain the production plateau for an additional two years and ~~AMPCO. Additionally, there was a planned turnaround at AMPCO in the first quarter of 2015.~~extend field life up to eight years.

~~During the second quarter of 2015, the Alba C21 development 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 for each of the second quarter and first six months of 2015, relatively flat as compared to 18 mboed in the same periods of 2014.~~ Net sales volumes benefited from improved production as two subsea development wells at West Brae began producing during the first and second quarters of 2015. This completed the last of the planned five-well Brae infill drilling program begun in ~~2014. In addition, as fullcompression was reinstated during the second quarter of 2015 at the non-operated Foinaven field, this contributed to improved reliability.~~

~~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 during~~ the first six months of ~~2015 as~~2016 were lower due to repair activities at the Brae Alpha facility following a ~~result of~~process pipe failure in late 2015. Production was restored at the facility in late April. Higher overall production efficiency at the remaining Brae facilities and improved reliability from the outside-operated Foinaven field partially offset the Brae Alpha shut-in.

Libya – Due to continued civil ~~unrest. In December 2014, Libya’s~~unrest, there were no liftings during the quarter, or any period presented. Earlier this year, an Internationally-backed Unity Government was established in Tripoli. During the second quarter, the two National Oil ~~Corporation reinstated force majeure~~Companies agreed to unify and reportedly have begun preliminary discussions on re-opening the Es-Sider and other crude oil terminals which, if successful, will allow resumption of production operations at ~~the Es Sider oil terminal, as disruptions from civil unrest continue. Considerable~~our Waha concessions. However, considerable uncertainty remains around the timing of future production and sales levels.

~~International E&P--Exploration~~

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

Oil Sands Mining

Our net synthetic crude oil sales volumes were 2949 mbbld and 4454 mbbld in the second quarter and first six months of ~~2015~~2016 compared to 4429 mbbld and 4544 mbbld in the same periods of ~~2014. Production declined~~2015. Sales volumes increased in ~~the~~comparison to second quarter and first six months of 2015 ~~primarily~~which were adversely affected due to ~~the~~ planned turnarounds at the base upgrader and Muskeg River Mine and unplanned downtime at the expansion upgrader. ~~Production was relatively flat~~These sales volume increases were partially offset by a brief suspension of operations at both the Muskeg River and Jackpine mines in May 2016 in order to support emergency response efforts related to the Fort McMurray area wildfires in addition to the completion of planned maintenance activities at the Jackpine Mine and expansion upgrader that began in the first ~~six months~~quarter 2016. Neither of ~~2015 compared to~~ the ~~same period in 2014~~mines sustained any damage as a result of the ~~planned turnarounds and unplanned downtime during the second quarter of 2015 were mostly offset by higher production driven by improved mine reliability during the first quarter of 2015.~~wildfires. We hold a 20% non-operated working interest in the ~~AOSP.~~Athabasca Oil Sands Project.

Market Conditions

Prevailing prices for the crude oil, NGLs and natural gas that we produce significantly impact our revenues and cash flows. The benchmark prices for crude oil, NGLs and natural gas were ~~significantly~~ lower in the second quarter and first six months of ~~2015~~2016 as compared to the same ~~periods~~period in ~~2014;~~2015; 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 six months of ~~2015~~2016 and ~~2014.~~2015.

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

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

Bakken
$51.36

$93.08

$45.84

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

Bakken
$11.63

$45.13

$7.19

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

Bakken
$49.29

$90.47

$43.72

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

Bakken
$2.62

$4.12

$2.76

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

$57.95

$102.99

$53.34

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



	Three Months Ended June 30,			Six Months Ended June 30,
	2016	2015	Decrease	2016		2015		Increase (Decrease)
Average Price Realizations ^(a)
Crude Oil and Condensate (per bbl) ^(b)	$40.77	$52.63	(23)%	$34.21		$47.11		(27	)%
Natural Gas Liquids (per bbl)	14.84	14.77	—%	11.43		14.60		(22	)%
Total Liquid Hydrocarbons (per bbl)	35.07	45.96	(24)%	29.32		41.37		(29	)%
Natural Gas (per mcf)	1.96	2.76	(29)%	1.99		2.88		(31	)%
Benchmarks
WTI crude oil (per bbl)	$45.64	$57.95	(21)%		$39.78		$53.34	(25	)%
LLS crude oil (per bbl)	47.35	62.94	(25)%	41.49		57.97		(28	)%
Mont Belvieu NGLs (per bbl)^(c)	17.52	17.65	(1)%	15.78		18.02		(12	)%
Henry Hub natural gas (per mmbtu)	1.95	2.64	(26)%	2.02		2.81		(28	)%


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

^(b)

Inclusion of realized gains on crude oil derivative instruments would have increased average ~~crude oil price realization~~realizations by $0.12 per bbl and $0.06 per bbl for the second quarter 2016 and 2015, and $0.91 per bbl and $0.14 per bbl for the first six months of 2016 and 2015. Inclusion of realized gains on natural gas derivative instruments would have increased average realizations by $0.02 per mcf and $0.01 per mcf for the second quarter and first six months of ~~2015. There were no crude oil derivative instruments in 2014.~~2016.


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


^(d)	~~NYMEX.~~


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


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


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


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

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

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

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

International E&P

The following table presents our average price realizations and the related benchmark for crude oil, NGLs, and natural gas for the second quarter and first six months of ~~2015~~2016 and ~~2014~~2015.

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

Equatorial Guinea
$52.27

$90.91

$47.55

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

Equatorial Guinea ^(a)

$1.00

$1.00

$1.00

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

Equatorial Guinea
$35.74

$59.72

$31.81

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

Equatorial Guinea ^(a)

$0.24

$0.24

$0.24

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

$61.69

$109.70

$57.81

$108.93



	Three Months Ended June 30,			Six Months Ended June 30,
	2016	2015	Increase (Decrease)	2016		2015		Increase (Decrease)
Average Price Realizations
Crude Oil and Condensate (per bbl)	$42.21	$56.70	(26)%	$37.56		$52.92		(29	)%
Natural Gas Liquids (per bbl)	2.65	3.10	(15)%	2.45		3.29		(26	)%
Liquid Hydrocarbons (per bbl)	32.11	44.70	(28)%	28.11		41.06		(32	)%
Natural Gas (per mcf)	0.53	0.78	(32)%	0.56		0.78		(28	)%
Benchmark
Brent (Europe) crude oil (per bbl) ^(a)	$45.52	$61.69	(26%)		$39.61		$57.81	(31	)%


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


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

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

~~NGLs~~

Our NGL and natural gas sales in the International E&P segment originate primarily from our E.G. operations and are ~~subject~~sold to our equity method investees under fixed-price, term contracts; therefore, our reported average ~~NGL~~ realized prices ~~within the International E&P segment~~for NGLs and natural gas will not fully track market price movements.

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

Oil Sands Mining

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

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

The following table presents our average price realizations and the related benchmarks ~~that impacted both our revenues and variable costs~~ for the second quarter and first six months of ~~2015~~2016 and ~~2014~~2015.


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,			Six Months Ended June 30,
	2015		2014		2015		2014		2016	2015	Decrease	2016		2015		Increase (Decrease)
Average Price Realizations
Synthetic Crude Oil (per bbl)		$52.46		$94.17		$44.33		$91.27	$40.88	$52.46	(22%)		$32.94		$44.33	(26	%)
Benchmark
Benchmarks
WTI crude oil (per bbl)^(a)		$57.95		$102.99		$53.34		$100.84	$45.64	$57.95	(21%)		$39.78		$53.34	(25	%)
WCS crude oil (per bbl)^(b)		$46.35		$82.95		$40.13		$79.25
AECO natural gas sales index (per mmbtu)^(c)		$2.05		$4.46		$2.07		$4.72
WCS crude oil (per bbl)^(a)									32.29	46.35	(30%)	25.75		40.13		(36	%)


^(a)	~~NYMEX.~~


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

Results of Operations

Three Months Ended June 30, 2016 vs. Three Months Ended June 30, 2015

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



	Three Months Ended June 30,
(In millions)	2016			2015
Sales and other operating revenues, including related party
North America E&P	$	617		$	993
International E&P	159			211
Oil Sands Mining	185			147
Segment sales and other operating revenues, including related party	$	961		$	1,351
Unrealized (loss) gain on commodity derivative instruments	(91		)	(44		)
Sales and other operating revenues, including related party	$	870		$	1,307

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



	Three Months Ended		Increase (Decrease) Related to						Three Months Ended
(In millions)	June 30, 2015		Price Realizations			Net Sales Volumes			June 30, 2016
North America E&P Price-Volume Analysis ^(a)
Liquid hydrocarbons	$	893	$	(172	)	$	(170	)	$	551
Natural gas	90		(22		)	(13		)	55
Realized gain on commodity
derivative instruments	1		2						3
Other sales	9								8
Total	$	993							$	617
International E&P Price-Volume Analysis
Liquid hydrocarbons	$	172	$	(50	)	$	7		$	129
Natural gas	28		(10		)	4			22
Other sales	11								8
Total	$	211							$	159
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil	$	137	$	(51	)	$	95		$	181
Other sales	10								4
Total	$	147							$	185


^(c)(a)	~~Monthly average AECO day ahead index.~~Three months ended June 30, 2016 includes a net sales volume reduction of 17 mboed related to dispositions in the Gulf of Mexico and other conventional onshore U.S. production.

Marketing revenues decreased $94 million in the second quarter of 2016 from the comparable prior-year period. Marketing activities include the purchase of commodities from third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points. Since the volume of marketing activity is based on market dynamics, it can fluctuate from period to period. The decreases are related primarily to lower marketed volumes in North America E&P and OSM, which were further compounded by a lower commodity price environment.

Income from equity method investmentsincreased $11 million in the second quarter of 2016 from the comparable 2015 period. The increase is primarily due to an increase in net sales volumes as 2015 volumes were lower because of planned turnaround and maintenance activities at the Alba field and E.G. LNG facilities.

Net gain on disposal of assets in the second quarter of 2016 was primarily related to the sale of our Wyoming upstream and midstream assets and West Texas acreage. See Note 6 to the consolidated financial statements for information about dispositions.

Production expenses decreased $100 million. North America E&P declined $50 million primarily due to lower operational, maintenance and labor costs, coupled with the disposition of our producing assets in the Gulf of Mexico and East Texas, North Louisiana and Wilburton, Oklahoma gas assets. International E&P declined $8 million primarily as a result of lower project and labor costs in the U.K. and 2015 also includes costs arising from planned flowline maintenance at the outside operated Foinaven field; these declines were partially offset by increased costs resulting from higher net sales volumes. OSM

decreased $42 million primarily due to lower turnaround costs andcontinued cost management, specifically staffing and contract labor.

The second quarter of 2016 production expense rate (expense per boe) for North America E&P declined as cost reductions occurred at a rate faster than our production decline. The expense rate for International E&P declined due to an increase in volumes, combined with reduced maintenance and project costs in the U.K. The OSM expense rate decreased as a result of higher sales volumes and lower production expenses, as discussed above.

The following table provides production expense rates for each segment:



	Three Months Ended June 30,
($ per boe)	2016		2015
Production Expense Rate
North America E&P		$6.28		$7.19
International E&P		$5.09		$6.51
Oil Sands Mining ^(a)		$39.02		$78.24


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

Marketing costs decreased $94 million in the second quarter of 2016 from the comparable 2015 period, consistent with the marketing revenues changes discussed above.

Exploration expensesincreased $78 million primarily as a result of our decision to not drill any of our remaining Gulf of Mexico undeveloped leases. The following table summarizes the components of exploration expenses:



	Three Months Ended June 30,
(In millions)	2016		2015
Exploration Expenses
Unproved property impairments	$	133	$	40
Dry well costs	22		41
Geological and geophysical	—		12
Other	34		18
Total exploration expenses	$	189	$	111

Depreciation, depletion and amortizationdecreased $190 million primarily as a result of production volume decreases, a higher proved reserve base in Eagle Ford in the second half of 2015 and as a result of the non-core asset dispositions in 2015. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, proved reserve and production volumes have an impact on DD&A expense.

The DD&A rate (expense per boe), which is impacted by changes in reserves, capitalized costs, and sales volume mix by field, can also cause changes to our DD&A. The following table provides DD&A rates for each segment. The DD&A rate for North America E&P decreased primarily as a result of a higher proved reserve base in Eagle Ford in the second half of 2015. The DD&A rate for International E&P declined due to lower asset retirement costs, with cost estimates refined in the fourth quarter of 2015. The DD&A rate for OSM declined as a result of a higher proved reserve base in the fourth quarter of 2015.



	Three Months Ended June 30,
($ per boe)	2016		2015
DD&A Rate
North America E&P		$21.16		$25.45
International E&P		$6.22		$7.17
Oil Sands Mining		$11.39		$12.87

Impairments decreased $44 million in the second quarter of 2016 as a result of the second quarter of 2015 non-cash impairment charge related to East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets in anticipation of the sale in 2015. See Note 13 to the consolidated financial statements for discussion of the impairment.

Taxes other than incomeinclude production, severance, and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes, decreased $39 million in the second quarter of 2016. The following table summarizes the components of taxes other than income:



	Three Months Ended June 30,
(In millions)	2016		2015
Production and severance	$	25	$	40
Ad valorem	5		15
Other	9		23
Total	$	39	$	78

General and administrative expensesdecreased $36 million primarily due to lower pension settlement charges in the second quarter of 2016, which totaled $31 million, compared to $64 million in the prior year.

Net interest and other increased $28 million primarily due to increased interest expense associated with our June 2015 debt issuance. See Note 16 to the consolidated financial statements for discussion of the June 2015 debt issuance.

Provision (benefit) for income taxes reflects an effective tax rate of 29% in the second quarter of 2016, as compared to 2% in the second quarter of 2015.

Segment Income(Loss)

Segment income (loss) represents income (loss) from operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments, unrealized gains or losses on commodity 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 June 30,
(In millions)	2016			2015
North America E&P	$	(70	)	$	(45	)
International E&P	55			41
Oil Sands Mining	(38		)	(77		)
Segment income (loss)	(53		)	(81		)
Items not allocated to segments, net of income taxes	(117		)	(305		)
Net income (loss)	$	(170	)	$	(386	)

North America E&P segment loss increased $25 million after-tax primarily due to lower price realizations and sales volumes, which was partially offset by the impact of lower net sales volumes to DD&A, production costs and taxes other than income; and lower exploration expenses.

International E&P segment incomeincreased $14 million after-tax primarily due to decreased exploration expenses and an increase in income from equity investments, which were partially offset by lower price realizations.

Oil Sands Mining segment loss decreased $39 million after-tax primarily due to higher sales volumes and lower production expenses, partially offset by lower price realizations and higher DD&A expense.

Results of Operations

Six Months Ended June 30, 2016 vs. Six Months Ended June 30, 2015

Consolidated Results of Operation

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


	Three Months Ended June 30,					Six Months Ended June 30,					Six Months Ended June 30,
(In millions)	2015			2014		2015			2014		2016			2015
Sales and other operating revenues, including related party
North America E&P	$	993		$	1,540	$	1,843		$	2,932	$	1,110		$	1,843
International E&P	211			347		393			727		255			393
Oil Sands Mining	147			383		372			760		333			372
Segment sales and other operating revenues, including related party	$	1,351		$	2,270	$	2,608		$	4,419	$	1,698		$	2,608
Unrealized loss on crude oil derivative instruments	(44		)	—		(21		)	—
Unrealized loss on commodity derivative instruments											(114		)	(21		)
Sales and other operating revenues, including related party	$	1,307		$	2,270	$	2,587		$	4,419	$	1,584		$	2,587

~~North America E&P~~


	Three Months Ended		Increase (Decrease) Related to					Three Months Ended			Six Months Ended		Increase (Decrease) Related to						Six Months Ended
(In millions)	June 30, 2014		Price Realizations			Net Sales Volumes		June 30, 2015			June 30, 2015		Price Realizations			Net Sales Volumes			June 30, 2016
North America E&P Price-Volume Analysis(a)
Liquid hydrocarbons	$	1,403	$	(786	)	$	276	$	893		$	1,633	$	(394	)	$	(279	)	$	960
Natural gas	133		(73		)	30		90			188		(51		)	(24		)	113
Realized gain on crude oil
Realized gain on commodity
derivative instruments	—		1					1			5		19						24
Other sales	4							9			17								13
Total	$	1,540						$	993		$	1,843							$	1,110
International E&P Price-Volume Analysis										International E&P Price-Volume Analysis
Crude oil and condensate
Natural gas liquids
Liquid hydrocarbons											$	310	$	(90	)	$	(26	)	$	194
Natural gas											60		(17		)	—			43
Other sales											23								18
Total											$	393							$	255
Oil Sands Mining Price-Volume Analysis										Oil Sands Mining Price-Volume Analysis
Synthetic crude oil											$	355	$	(112	)	$	81		$	324
Other sales											17								9
Total											$	372							$	333

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

~~International E&P~~

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

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

~~Oil Sands Mining~~

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

10
Total $ 383
$ 147

Six Months Ended Increase (Decrease) Related to Six Months Ended
(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
^(a)Six months ended June 30, 2016 includes a net sales volume reduction of 17 mboed related to dispositions in the Gulf of Mexico and other conventional onshore U.S. production.

Marketing revenues ~~decreased $435 million and $772 million in~~for the ~~second quarter and~~ first six months of ~~2015 from the comparable prior-year periods.~~2016 decreased by $240 million. Marketing activities include the purchase of commodities from third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points. Because the volume of marketing activity is based on market dynamics, it can fluctuate from period to period. The ~~decreases are~~decrease is related primarily to lower marketed volumes in North America, which were further compounded by a lower commodity price environment.

Income from equity method investments decreased ~~$94 million and $195 million in the second quarter and first six months of 2015 from the comparable 2014 period.~~$11 million. The decrease ~~in the 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 the decrease in 2015 were lowernet sales volumes ~~due to~~as a result of planned downtime at E.G. as a result of the ~~previously mentioned~~Alba field compression project which impacted our equity method plants, which was partially offset by planned turnaround and maintenance activities at the ~~AMPCO methanol plant, the~~ Alba field and E.G. LNG facilities in 2015. Also impacting the ~~LNG facility.~~first six months of 2016 were lower price realizations for LPG at our Alba plant.

Net gain on disposal of assets for the first six months of 2016 was primarily related to the sale of our Wyoming upstream and midstream assets and West Texas acreage. See Note 6 to the consolidated financial statements for information about dispositions.

Production expenses for the first six months of 2016 decreased ~~$112~~by $216 million ~~in the second quarter of 2015~~ compared to the ~~second quarter~~same period of ~~2014.~~2015. North America E&P declined ~~$38~~$118 million due to lower operational, maintenance and labor ~~costs.~~costs, coupled with the disposition of our producing assets in the Gulf of Mexico and East Texas, North Louisiana and Wilburton, Oklahoma gas assets. International E&P declined ~~$35~~$22 million ~~primarily because of lower costs related~~largely due to lower ~~sales volumes, while the second quarter of 2014 included $5 million of turnaround~~operational costs ~~at Brae and subsea maintenance costs at the non-operated Foinaven field~~ in the U.K. OSM decreased ~~$39~~$76 million primarily due to ~~lower feedstock purchases (due to planned turnarounds and unplanned downtime as previously discussed) and~~ continued cost management, ~~especially~~specifically staffing and contract ~~labor. Also contributing to the OSM decrease was~~labor, lower turnaround costs, and a ~~more~~ favorable exchange rate on expenses denominated in the Canadian Dollar. ~~These declines were partially offset by costs incurred from the turnaround.~~

~~Production expenses for the~~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~~

$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~~2016 production expense rate (expense per boe) for North America E&P declined ~~relative to the same quarter in 2014~~primarily due to ~~overall~~ cost reductions ~~as previously discussed, and leveraging efficiencies as~~that occurred at a rate faster than our 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.~~decline. The International E&P expense rate decreased in the first six months of ~~2015~~2016 primarily due to ~~lower~~reduced maintenance and project costs ~~as discussed~~ in the ~~preceding paragraphs.~~U.K. The OSM expense rate ~~remained relatively flat~~decreased in the first six months of ~~2015 as the~~2016 primarily due to higher production coupled with lower ~~feedstock purchases, cost management and a favorable exchange rate were offset by the aforementioned higher turnaround~~operational costs. ~~The following table provides production expense rates for each segment:~~


	Three Months Ended June 30,				Six Months Ended June 30,				Six Months Ended June 30,
($ per boe)	2015		2014		2015		2014		2016		2015
Production Expense Rate
North America E&P		$7.19		$10.47		$7.57		$10.74		$6.22		$7.57
International E&P		$6.51		$8.87		$6.45		$8.82		$5.53		$6.45
Oil Sands Mining ^(a)		$78.24		$51.53		$50.06		$49.54		$33.42		$50.06


^(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 ~~$432 million and $769~~$241 million in the ~~second quarter and~~ first six months of ~~2015~~2016 from the comparable ~~2014 periods,~~2015 period, consistent with the marketing revenues changes discussed above.

Exploration expenses ~~declined $34~~were $12 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 lower~~higher in the first six months of ~~2015~~2016 than in the comparable ~~2014~~2015 period primarily due to ~~lower~~higher unproved property impairments, which were partially offset by ~~higher~~lower dry well costs. Unproved property impairments were higher in ~~2014~~2016 primarily as a result of ~~Eagle Ford and Bakken~~Gulf of Mexico leases ~~that either expired or~~ that we decided not to ~~drill or extend.~~drill. Dry well costs ~~increased~~ for the first six months of 2015 ~~due to~~primarily consist of costs associated with the Sodalita West #1 well in E.G., the Key Largo well in the Gulf of Mexico, and ~~the aforementioned~~ suspended well costs related to Birchwood in-situ. ~~Dry well costs for the first six months of 2014 primarily consist of our exploration programs in Kurdistan, Ethiopia and Kenya.~~ The following table summarizes the components of exploration expenses:


	Three Months Ended				Six Months Ended June 30,				Six Months Ended June 30,
(In millions)	2015		2014		2015		2014		2016		2015
Exploration Expenses
Unproved property impairments	$	40	$	60	$	49	$	101	$	144	$	49
Dry well costs	41		53		99		55		22		99
Geological and geophysical	12		6		15		17		—		15
Other	18		26		38		45		47		38
Total exploration expenses	$	111	$	145	$	201	$	218	$	213	$	201

Depreciation, depletion and amortization (“DD&A”) ~~increased $71 million and $249~~decreased $402 million in the ~~second quarter and~~ first six months of ~~2015~~2016 from the comparable ~~2014 periods~~2015 period primarily as a result of production volume decreases and a 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~~proved reserve base in Eagle Ford in the second ~~quarter~~half of ~~2015, as previously discussed, also contributing to that quarter's decrease.~~2015. 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. The DD&A rate for North America E&P decreased primarily as a result of a higher proved reserve base in Eagle Ford in the second half of 2015.


	Three Months Ended				Six Months Ended June 30,				Six Months Ended June 30,
($ per boe)	2015		2014		2015		2014		2016		2015
DD&A Rate
North America E&P		$25.45		$26.58		$26.16		$26.72		$21.79		$26.16
International E&P		$7.17		$6.64		$6.62		$6.45		$5.98		$6.62
Oil Sands Mining		$12.87		$11.78		$12.58		$11.74		$11.34		$12.58

Impairments ~~are discussed~~decreased $43 million in the first six months of 2016 as a result of the second quarter of 2015 non-cash impairment charge related to East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets in anticipation of the sale in 2015. See Note 1213 to the consolidated financial ~~statements.~~statements for discussion of the impairment.

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~~volumes, decreased ~~$31 million and $59~~$58 million in the ~~second quarter and~~ first six months of ~~2015~~2016 from the comparable ~~2014 periods. This decrease was partially offset by an increase in sales volumes in North America E&P.~~2015 period. The following table summarizes the components of taxes other than income:


	Three Months Ended				Six Months Ended June 30,				Six Months Ended June 30,
(In millions)	2015		2014		2015		2014		2016		2015
Production and severance	$	40	$	68	$	74	$	122	$	44	$	74
Ad valorem	15		19		31		38		19		31
Other	23		22		40		44		24		40
Total	$	78	$	109	$	145	$	204	$	87	$	145

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

~~General and administrative expenses increased $13~~decreased $56 million in the first six months of ~~2015~~2016 compared to the same period in ~~2014.~~2015. This ~~increase~~decrease 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 costscost savings realized ~~in the second quarter of 2015 resulting~~ from the 2015 workforce ~~reductions.~~reductions and corresponding severance expenses.

Provision (benefit) for income taxes reflect effective tax rates of ~~2% and 18%~~37% in the ~~second quarter and~~ first six months of ~~2015,~~2016, as compared to ~~30% and 32%~~18% from the comparable ~~2014 periods. The effective rates for~~ 2015 ~~reflect $135 million of non-cash additional deferred tax expense recorded in the second quarter of 2015 as a result of enacted corporate tax changes in Alberta, Canada.~~period. See Note 89 to the consolidated financial statements for discussion of the effective tax rate.

~~Discontinued operations~~ ~~presented in 2014 are net of tax. See Note 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						Six Months Ended June 30,						Six Months Ended June 30,
(In millions)	2015			2014			2015			2014			2016			2015
North America E&P	$	(45	)	$	302		$	(206	)	$	544		$	(265	)	$	(206	)
International E&P	41			160			64			381			59			64
Oil Sands Mining	(77		)	55			(96		)	119			(86		)	(96		)
Segment income (loss)	(81		)	517			(238		)	1,044			(292		)	(238		)
Items not allocated to segments, net of income taxes	(305		)	(157		)	(424		)	(286		)	(285		)	(424		)
Income (loss) from continuing operations	(386		)	360			(662		)	758
Discontinued operations ^(a)	—			180			—			931
Net income (loss)	$	(386	)	$	540		$	(662	)	$	1,689		$	(577	)	$	(662	)


^(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)~~loss ~~decreased $347 million and $750~~increased $59 million after-tax in the ~~second quarter and~~ first six months of ~~2015~~2016 from the comparable ~~2014 periods. The decrease is~~2015 period primarily due to lower price realizations and sales volumes, which was partially offset by the ~~impacts from the increased~~impact of lower net sales volumes ~~from the U.S. resource plays.~~to DD&A, production costs and taxes other than income; and lower exploration expenses.

International E&P segment income decreased ~~$119 million and $317~~$5 million after-tax in the ~~second quarter and~~ first six months of ~~2015~~2016 from the comparable ~~2014 periods. The decreases are~~2015 period primarily due to lower liquid hydrocarbon price ~~realizations and net sales volumes, as well as reduced income from equity investments.~~realizations. These declines were partially offset by lower exploration, production and ~~exploration~~DD&A expenses.

Oil Sands Mining segment ~~income (loss)~~loss decreased ~~$132 million and $215~~$10 million after-tax in the ~~second quarter and~~ first six months of ~~2015~~2016 from the comparable ~~2014 periods~~2015 period primarily due to higher sales volumes and lower production expenses, partially offset by lower price realizations ~~partially offset by reduced production expenses.~~and higher DD&A expense.

Critical Accounting Estimates

There have been no material changes or developments in the evaluation of the accounting estimates and the underlying assumptions or methodologies pertaining to our ~~critical accounting estimates subsequent to~~ Critical Accounting Estimates disclosed in our Form 10-K for the year ended December 31, ~~2014~~2015, except as discussed below.

Fair Value Estimates - Goodwill

Goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. We performed our annual impairment test in April 2016 and concluded no impairment was required. While the fair value of our International E&P reporting unit exceeded book value, subsequent commodity price and/or common stock declines may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.

Estimated Quantities of Net Reserves

Our December 31, 2015 proved reserves were calculated using the unweighted average of closing benchmark prices nearest to the first day of each month within the 12-month period ("SEC pricing"). The table below provides the 2015 SEC pricing for certain benchmark prices as well as the unweighted average for the first eight months of 2016:



	Unweighted 8-month 2016 Average	Unweighted 12-month 2015 Average
WTI Crude oil	$40.48	$50.28
Henry Hub natural gas	2.24	2.59
Brent crude oil	41.08	54.25
Natural gas liquids	14.92	17.32

Any significant future price change could have a material effect on the quantity and present value of our proved reserves. To the extent that commodity prices decrease during the remainder of 2016, a portion of our proved reserves could be deemed uneconomic and no longer classified as proved. This could impact both proved developed producing reserves as well as proved undeveloped reserves. Assuming lower commodity pricing in the remaining 4-months of 2016, a material volume of our proved reserves could become uneconomic and would have to be reclassified to non-proved reserve or resource category. In this scenario, our OSM proved reserves represent the largest risk to be reclassified to non-proved reserve or resource category. However, any impact of lower SEC pricing will likely be partially offset by continued cost reduction efforts. Also, any volumes reclassified to non-proved reserves could return to proved reserves as commodity prices improve. In the event the OSM proved reserves are reclassified to non-proved reserves or resource, their classification will have no impact on future plans for production.

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:


	Six Months Ended June 30,						Six Months Ended June 30,
(In millions)	2015			2014			2016			2015
Sources of cash and cash equivalents
Continuing operations	$	717		$	2,118
Discontinued operations	—			440
Operating activities							$	252		$	717
Disposals of assets							758			2
Borrowings	1,996			—			—			1,996
Disposals of assets	2			2,232
Common stock issuance							1,236			—
Other	43			113			39			43
Total sources of cash and cash equivalents	$	2,758		$	4,903		$	2,285		$	2,758
Uses of cash and cash equivalents
Cash additions to property, plant and equipment	$	(2,320	)	$	(2,230	)	$	(753	)	$	(2,320	)
Investing activities of discontinued operations	—			(233		)
Deposit for acquisition							(89		)	—
Purchases of short-term investments	(925		)	—			—			(925		)
Debt issuance costs	(19		)	—			—			(19		)
Debt repayments	(34		)	(34		)	—			(34		)
Dividends paid	(285		)	(260		)	(77		)	(285		)
Purchases of common stock	—			(1,000		)
Commercial paper, net	—			(135		)
Other	(1		)	(10		)	(3		)	(1		)
Cash held for sale	—			(96		)
Total uses of cash and cash equivalents	$	(3,584	)	$	(3,998	)	$	(922	)	$	(3,584	)

~~Commodity prices began declining~~Cash flows generated from operating activities in ~~the second half of 2014 and remain substantially lower through 2015 as compared to~~ the first six months of ~~2014.~~2016 were lower as the downturn in the commodity cycle continued. This ~~lower~~continued downward pressure on price ~~trend adversely impacted our cash flows in 2015. Partially offsetting~~realizations, coupled with the ~~decline in prices were increased~~lower net sales volumes, ~~in the North America E&P 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~~activities. In the first six months of 2016, consolidated average oil and NGL price realizations were down by approximately 27% and consolidated net sales volumes declined by 9% as compared to the ~~previous~~prior year.

~~Borrowings reflect~~Proceeds from disposals of assets are primarily from the sale of our Wyoming upstream and midstream assets; see Note 6 to the consolidated financial statements for further information concerning dispositions. Common stock issuance reflects net proceeds received in March 2016 from ~~the issuance~~our public sale of ~~senior notes in June 2015.~~common stock. 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 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.

Additions to property, plant and equipment are our most significant use of cash and cash ~~equivalents.~~equivalents and were lower in the first half of 2016 consistent with a reduced Capital Program as compared to the prior year. 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:~~flows (the table excludes an $89 million deposit paid into escrow related to the acquisition of PayRock assets - see Note 5 to the consolidated financial statements for further information related to this acquisition):


	Six Months Ended June 30,					Six Months Ended June 30,
(In millions)	2015		2014			2016		2015
North America E&P	$	1,484	$	1,969		$	468	$	1,484
International E&P	245		220			44		245
Oil Sands Mining	37		123			16		37
Corporate	14		13			8		14
Total capital expenditures	1,780		2,325			536		1,780
(Increase) decrease in capital expenditure accrual	540		(95		)
Decrease in capital expenditure accrual						217		540
Total use of cash and cash equivalents for property, plant and equipment	$	2,320	$	2,230		$	753	$	2,320

~~During~~The Board of Directors approved a $0.05 per share dividend for the first ~~six months~~quarter of ~~2014, we acquired 29 million common shares at a cost of $1 billion under our share repurchase program, 13 million of~~2016, which ~~were acquired~~was paid in the second quarter of ~~2014 at a cost of $449 million.~~2016. See Capital Requirements below for additional information about the second quarter dividend.

Liquidity and Capital Resources

~~On June 10, 2015,~~In March 2016, we issued ~~$2 billion aggregate principal amount~~166,750,000 shares of ~~unsecured senior notes which consist~~our common stock, par value $1 per share, at a price 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~~$7.65 per share, excluding underwriting discounts and commissions, for net proceeds of $1,236 million. The proceeds were used to ~~repay~~strengthen our ~~$1 billion 0.90% senior notes due 2015, which mature on November 1, 2015,~~balance sheet and for general corporate ~~purposes.~~purposes, including funding a portion of our Capital Program.

~~In May 2015,~~Also in March 2016, we ~~amended~~increased our ~~$2.5~~$3 billion unsecured ~~revolving credit facility (as so amended, the "Credit Facility") to increase the facility size~~Credit Facility by ~~$500~~$300 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.$3.3 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain ~~unchanged.~~unaffected by the increase.

Our main sources of liquidity are cash and cash equivalents, ~~short-term investments,~~sales of non-core assets, internally generated cash flow from operations, ~~the issuance of notes,~~capital market transactions, and our $3$3.3 billion Credit ~~Facility and sales of non-core assets.~~Facility. Our working capital requirements are supported by these sources and we may ~~also~~draw on our $3.3 billion Credit Facility to meet short-term cash requirements, or issue ~~commercial paper, which is backed by~~debt or equity securities through the shelf registration statement discussed below as part of our ~~revolving credit facility. Furthermore, we actively manage our~~longer-term liquidity and capital ~~spending program, including the level and timing of activities associated with our drilling programs.~~management. Because of the alternatives available to us as discussed above, ~~and access to capital markets through the shelf registration discussed below,~~ we believe that our short-term and long-term liquidity is adequate to fund not only our current operations, but also our near-term and long-term funding requirements ~~for the foreseeable future,~~ including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, and other amounts that may ultimately be paid in connection with contingencies.

~~Outlook~~Due to decreases in crude oil and U.S. natural gas prices, credit rating agencies reviewed companies in the industry earlier this year, including us. During the first quarter of 2016, our corporate credit rating was downgraded by: Standard & Poor's Ratings Services to BBB- (stable) from BBB (stable); by Fitch Ratings to BBB (negative) from BBB+ (stable); and by Moody's Investor Services, Inc. to Ba1 (negative) from Baa1 (stable). Any further rating downgrades could increase our future cost of financing or limit our ability to access capital, and result in additional collateral requirements. See Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2015 for a discussion of how a further downgrade in our credit ratings could affect us.

~~We expect~~The June 23, 2016 referendum by British voters to exit the European Union (“Brexit”) provided uncertainty and potential volatility around European currencies, and resulted in a decline in the value of the British pound, as compared to the U.S. dollar and other currencies. Volatility in exchange rates may continue in the short term as the U.K. negotiates its exit from the European Union. A weaker British pound compared to the U.S. dollar during a reporting period causes local currency results of our ~~capital, investment and exploration spending budget for full-year 2015~~U.K. operations to be ~~at or below $3.3 billion~~translated into fewer U.S. dollars. For our U.K. operations a majority of our revenues are tied to global crude oil prices which are denominated in U.S. dollars while a significant portion of our operating and ~~estimate full-year North America E&P~~capital costs are denominated in British pounds. In addition, our U.K. operations have an asset retirement obligation, which represents a future cash commitment. In the longer term, any impact from Brexit on our U.K. operations will depend, in part, on the outcome of tariff, trade, regulatory, and ~~International E&P production volumes (excluding Libya) to be 375-390 net mboed.~~other negotiations.

Capital Resources

Credit Arrangements and Borrowings

At June 30, ~~2015,~~2016, we had no borrowings against our revolving credit ~~facility and no amounts outstanding under our U.S. commercial paper program that is backed by the revolving credit~~ facility.

At June 30, ~~2015,~~2016, we had ~~$8.4~~$7.3 billion in long-term debt outstanding, with our next debt maturity in the amount of ~~which approximately $1.0 billion matures~~$682 million due in the fourth quarter of ~~2015.~~ 2017.

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~~Asset Disposals

During the quarter, we announced the sale of our Wyoming upstream and ~~Short-Term Investments-Adjusted~~midstream assets for proceeds of $870 million, before closing adjustments, of which approximately $690 million was received in the second quarter. The remaining asset sales are subject to the receipt of certain tribal consents and are expected to close before year end. The proceeds for the remaining asset sales were deposited into an escrow account by the buyer.

In March and April 2016, we entered into separate agreements to sell our 10% working interest in the outside-operated Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Colorado and certain undeveloped acreage in West Texas for a combined total of approximately $80 million in proceeds, before closing adjustments. We closed on certain of the asset sales during the six months ended June 30, 2016. The remaining asset sales are expected to close by year-end.

Cash-Adjusted Debt-To-Capital Ratio

Our ~~cash and short-term investments-adjusted~~cash-adjusted debt-to-capital ratio (total debt-minus-cash and cash equivalents ~~and short-term investments~~ to total debt-plus-equity-minus-cash and cash ~~equivalents and short-term investments)~~equivalents) was ~~22%~~20% at June 30, ~~2015,~~2016, compared to ~~16%~~25% at December 31, ~~2014.~~2015.


	June 30,			December 31,			June 30,			December 31,
(In millions)	2015			2014			2016			2015
Long-term debt due within one year	$	1,035		$	1,068		$	1		$	1
Long-term debt	7,321			5,323			7,280			7,276
Total debt	$	8,356		$	6,391		$	7,281		$	7,277
Cash and cash equivalents	$	1,572		$	2,398		$	2,584		$	1,221
Short-term investments	$	925		$	—
Equity	$	20,218		$	21,020		$	19,153		$	18,553
Calculation:
Total debt	$	8,356		$	6,391		$	7,281		$	7,277
Minus cash and cash equivalents	1,572			2,398			2,584			1,221
Minus short-term investments	925			—
Total debt minus cash, cash equivalents and short-term investments	$	5,859		$	3,993
Total debt minus cash, cash equivalents							$	4,697		$	6,056
Total debt	$	8,356		$	6,391		$	7,281		$	7,277
Plus equity	20,218			21,020			19,153			18,553
Minus cash and cash equivalents	1,572			2,398			2,584			1,221
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		%
Total debt plus equity minus cash, cash equivalents							$	23,850		$	24,609
Cash-adjusted debt-to-capital ratio							20		%	25		%

Capital Requirements

~~As noted above~~We closed on our purchase agreement of PayRock for $888 million, as discussed in ~~"Outlook," we~~Note 5 to the consolidated financial statements. We expect our ~~total capital, investment and exploration spending budget~~Capital Program for full-year ~~2015~~2016 to be at$1.3 billion, or ~~below $3.3 billion.~~$100 million lower than the original budget, which includes the increased activity from the PayRock acquisition.

On July ~~29, 2015,~~27, 2016, our Board of Directors approved a dividend of ~~$0.21~~$0.05 per share for the second quarter of ~~2015~~2016 payable September ~~10, 2015~~12, 2016 to stockholders of record at the close of business on August ~~19, 2015.~~17, 2016.

As of June 30, ~~2015,~~2016, we plan to make contributions of up to ~~$42~~$34 million to our funded pension plans during the remainder of ~~2015.~~2016.

Contractual Cash Obligations

As of June 30, ~~2105,~~2016, there are no material changes to our consolidated cash obligations to make future payments under existing contracts, as disclosed in our ~~2014~~2015 Annual Report on Form 10-K, except for the agreement we entered into to acquire PayRock as described above, which was paid with cash on hand.

During the third quarter we executed an agreement to terminate our ~~issuance~~Gulf of ~~$2 billion aggregate principal amount~~Mexico deepwater drilling rig contract, as a result we expect to make a termination payment of ~~unsecured senior notes, as more fully described in Note~~ 15.$113 million during the third quarter of 2016.

Environmental Matters and Other Contingencies

~~We have incurred and will continue to incur capital, operating and maintenance, and remediation expenditures as~~In July 2015, we received a ~~result~~request for information from the EPA under Section 114 of ~~environmental laws and regulations. If these expenditures, as with all costs, are not ultimately reflected~~the Clean Air Act regarding several tank batteries used in our Bakken operations. Beginning in the ~~prices~~second quarter of 2016, we have been in settlement discussions with the State of North Dakota’s Department of Health regarding potential noncompliance with the Clean Air Act, North Dakota Century Code Air Pollution Control provisions, and implementing regulations. To date, no federal or state enforcement action has been commenced in connection with this matter. We anticipate that resolution of this matter will result in civil or administrative penalties of an undetermined amount and require us to undertake corrective actions which may increase our ~~products and services, our~~development and/or operating ~~results will be adversely affected.~~costs. We do not believe that ~~substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor~~any penalties or corrective action expenditures that may ~~vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes.~~

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

~~Other Contingencies~~

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

Forward-Looking Statements

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the "Exchange Act"). All statements other than statements of historical fact, ~~included or incorporated by reference in this report are forward-looking statements,~~ including without limitation statements 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,~~ future performance, business strategy, reserve estimates, asset quality, production guidance, drilling plans, ~~timing~~capital plans, cost and ~~expectations, maintenance activities~~expense estimates, assets acquisitions and ~~the timing and impact thereof, well spud timing and expectations, our financial and operational outlook and ability to fulfill that outlook, our~~sales, future financial position, ~~liquidity~~ and ~~capital resources, our 2015 budget and planned allocation, and the~~other plans and objectives ~~of our management~~ for ~~our~~ future ~~operations. In addition, many~~operations, are forward-looking ~~statements may be identified by the use of forward-looking terminology~~statements. Words such as “anticipate,” “believe,” "could," “estimate,” “expect,” ~~“target,~~“forecast,” "guidance," "intend," "may," “plan,” “project,” ~~“could,” “may,~~“seek,” “should,” "target," "will," “would” or similar words ~~indicating~~may be used to identify forward-looking statements; however, the absence of these words does not mean that ~~future outcomes~~the statements are ~~uncertain.~~not forward-looking. While we believe ~~that~~ our assumptions concerning future events are reasonable, a number of factors could cause results to differ materially from those ~~indicated by such forward-looking statements~~projected, including, but not limited to:

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

changes in expected reserve or production levels;

changes in ~~political or~~ economic conditions in ~~key operating markets,~~the jurisdictions in which we operate, including ~~international markets;~~changes in foreign currency exchange rates, interest rates, inflation rates, and global and domestic market conditions;

capital available for exploration and development;

risks related to our hedging activities;

our level of success in integrating acquisitions;

well production timing;

drilling and operating risks;

availability of ~~drilling rigs,~~ materials and labor;

difficulty in obtaining necessary approvals and permits;

non-performance by third parties of contractual obligations;

unforeseen hazards such as weather conditions;

political conditions and developments, including political instability, acts of war or terrorist acts, and the governmental or military response thereto;

cyber-attacks;

changes in safety, health, environmental, tax and other regulations;

other geological, operating and economic considerations; and

the risk factors, forward-looking statements and challenges and uncertainties described in our ~~2014~~2015 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and ~~those set forth from time to time in our~~other filings with the SEC.

All forward-looking statements included in this report are based on information available to us on the date of this report. ~~Except as required by law, we assume~~We undertake no ~~duty~~obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.

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~~2015 Annual Report on Form 10-K. ~~Additional~~Notes 13 and 14 to the consolidated financial statements include 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 12 and 13 to the consolidated financial statements.~~measured.

Commodity Price Risk During the first six months of ~~2015,~~2016, we entered into crude oil and natural gas derivatives, indexed to NYMEX WTI and Henry Hub, related to a portion of our forecasted North America E&P sales. The ~~table below provides~~following tables provide a summary of open positions as of June 30, ~~2015:~~2016 and the weighted average price for those contracts:


Financial Instrument	Weighted Average Price	Barrels per day	Remaining Term
Crude Oil				Crude Oil
						Year Ending December 31,
				Third Quarter	Fourth Quarter	2017
Three-Way Collars				Three-Way Collars
Volume (Bbls/day)				47,000		—
Price per Bbl:
Ceiling	$70.34	35,000	July- December 2015 ^(a)	$55.37		—
Floor	$55.57			$50.23		—
Sold put	$41.29			$40.96		—

Sold call options ^(a)
Volume (Bbls/day)				10,000		35,000
Price per Bbl				$72.39		$61.91
Two-way Collars
Volume (Bbls/day)				10,000		—
Price per Bbl:						—
Ceiling	$71.84	12,000	January- December 2016	$50.00
Floor	$60.48			$41.55
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~~Call options settle monthly.



Natural Gas
			Year Ending December 31,
	Third Quarter	Fourth Quarter	2017
Three-Way Collars ^(a)
Volume (MMBtu/day)	20,000	20,000	40,000
Price per MMBtu
Ceiling	$2.93	$2.93	$3.28
Floor	$2.50	$2.50	$2.75
Sold put	$2.00	$2.00	$2.25

^(a)


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


^(c)	~~Call options settle monthly.~~

The following table provides a sensitivity analysis of the projected incremental effect on income (loss) from operations of a hypothetical 10% change in NYMEX WTI and Henry Hub prices on our open commodity derivative instruments as of June 30, ~~2015.~~2016.


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

Crude oil derivatives						$	(32	)	$	73
Natural gas derivatives						(5		)	5
Total						$	(37	)	$	78

Interest Rate Risk Sensitivity analysis of the incremental effect of a hypothetical ~~10 percent~~10% change in interest rates on financial assets and liabilities as of June 30, ~~2015,~~2016, is provided in the following table.


(In millions)	Fair Value				Incremental Change in Fair Value			Fair Value				Incremental Change in Fair Value
Financial assets (liabilities):(a)
Interest rate swap agreements								$	12		^(b)	$	1
Long term debt, including amounts due within one year	$	(8,720	)	^(a)(b)	$	(288	)	$	(7,186	)	^(b)(c)	$	(287	)


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


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


^(b)(c)	Excludes capital leases.

Item 4. Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this Report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as of June 30, ~~2015.~~2016.

During the second quarter of ~~2015,~~2016, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

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

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

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


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


^(b)	~~Includes accruals.~~

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

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

Crude Oil and Condensate (mbbld)

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

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

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

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

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


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

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

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

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

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

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

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

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


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


^(e)	~~Includes blendstocks.~~

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

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

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

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

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

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


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


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

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

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

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

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

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

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


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

Part II – OTHER INFORMATION

Item 1. Legal and Administrative Proceedings

In July 2015, we received a request for information from the EPA under Section 114 of the Clean Air Act regarding several tank batteries used in our Bakken operations. Beginning in the second quarter of 2016, we have been in settlement discussions with the State of North Dakota’s Department of Health regarding potential noncompliance with the Clean Air Act, North Dakota Century Code Air Pollution Control provisions, and implementing regulations. To date, no federal or state enforcement action has been commenced in connection with this matter. We anticipate that resolution of this matter will result in civil or administrative penalties of an undetermined amount and require us to undertake corrective actions which may increase our development and/or operating costs. We do not believe that any penalties or corrective action expenditures that may result from this matter will have a material adverse effect on our financial position, results of operation or cash flows.

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. There have been no material changes to the risk factors under Item 1A. Risk Factors in our ~~2014~~2015 Annual Report on Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table provides information about ~~purchases~~repurchases by Marathon Oil of its common stock during the quarter ended June 30, ~~2015, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Exchange Act of 1934.~~2016.

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

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



	Total Number of	Average Price	Total Number of Shares Purchased as Part of Publicly Announced	Approximate Dollar Value of Shares that May Yet Be Purchased Under the
Period	Shares Purchased ^(a)	Paid per Share	Plans or Programs	Plans or Programs
04/01/16 - 04/30/16	103,922	$10.97	—	n/a
05/01/16 - 05/31/16	141,243	13.56	—	n/a
06/01/16 - 06/30/16	486	13.00	—	n/a
Total	245,651	$12.46	—


^(a)	~~161,719~~245,651 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

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.

SIGNATURES

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



August ~~6, 2015~~4, 2016		MARATHON OIL CORPORATION

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

Exhibit Index

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



		Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
Exhibit Number	Exhibit Description	Form	Exhibit	Filing Date
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 February 24, 2016)*
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	Marathon Oil Corporation 2016 Incentive Compensation Plan	14A	App. A	4/07/2016
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.



	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	2019
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	37
Item 4.	Controls and Procedures	38
		~~Supplemental Statistics (Unaudited)~~	39
Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	4439
Item 1A.	Risk Factors	4439
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4439
Item 6.	Exhibits	4439
	Signatures	4540



	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