UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended ~~September~~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 ~~677,260,116~~847,258,512 shares of Marathon Oil Corporation common stock outstanding as of ~~October~~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 ~~2014~~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						Nine Months Ended						Three Months Ended						Six Months Ended
	September 30,						September 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	$	1,300		$	2,316		$	3,887		$	6,735		$	870		$	1,307		$	1,584		$	2,587
Marketing revenues	84			554			471			1,713			89			183			147			387
Income from equity method investments	36			89			98			346			37			26			51			62
Net loss on disposal of assets	(109		)	(3		)	(108		)	(88		)
Net gain (loss) on disposal of assets													294			—			234			1
Other income	12			15			38			55			12			15			16			26
Total revenues and other income	1,323			2,971			4,386			8,761			1,302			1,531			2,032			3,063
Costs and expenses:
Production	406			593			1,300			1,697			350			450			678			894
Marketing, including purchases from related parties	84			554			471			1,710			88			182			146			387
Other operating	93			99			281			303			95			81			204			188
Exploration	585			96			786			314			189			111			213			201
Depreciation, depletion and amortization	717			737			2,289			2,060			561			751			1,170			1,572
Impairments	337			109			381			130			—			44			1			44
Taxes other than income	46			115			191			319			39			78			87			145
General and administrative	125			160			464			486			132			168			283			339
Total costs and expenses	2,393			2,463			6,163			7,019			1,454			1,865			2,782			3,770
Income (loss) from operations	(1,070		)	508			(1,777		)	1,742			(152		)	(334		)	(750		)	(707		)
Net interest and other	(75		)	(55		)	(180		)	(180		)	(86		)	(58		)	(171		)	(105		)
Income (loss) from continuing operations before income taxes	(1,145		)	453			(1,957		)	1,562
Income (loss) before income taxes													(238		)	(392		)	(921		)	(812		)
Provision (benefit) for income taxes	(396		)	149			(546		)	500			(68		)	(6		)	(344		)	(150		)
Income (loss) from continuing operations	(749		)	304			(1,411		)	1,062
Discontinued operations	—			127			—			1,058
Net income (loss)	$	(749	)	$	431		$	(1,411	)	$	2,120		$	(170	)	$	(386	)	$	(577	)	$	(662	)
Per basic share:
Income (loss) from continuing operations	$	(1.11	)	$	0.45		$	(2.09	)	$	1.56
Discontinued operations	$	—		$	0.19		$	—		$	1.55
Net income (loss)	$	(1.11	)	$	0.64		$	(2.09	)	$	3.11
Per diluted share:
Income (loss) from continuing operations	$	(1.11	)	$	0.45		$	(2.09	)	$	1.55
Discontinued operations	$	—		$	0.19		$	—		$	1.55
Net income (loss)	$	(1.11	)	$	0.64		$	(2.09	)	$	3.10
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		$	0.21		$	0.63		$	0.59		$	0.05		$	0.21		$	0.10		$	0.42
Weighted average common shares outstanding:
Basic	677			675			677			681			848			677			790			676
Diluted	677			678			677			684			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						Nine Months Ended						Three Months Ended						Six Months Ended
	September 30,						September 30,						June 30,						June 30,
(In millions)	2015			2014			2015			2014			2016			2015			2016			2015
Net income (loss)	$	(749	)	$	431		$	(1,411	)	$	2,120		$	(170	)	$	(386	)	$	(577	)	$	(662	)
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	(2		)	3			160			(40		)	19			86			(5		)	162
Income tax benefit (provision)	(1		)	(2		)	(58		)	13
Income tax provision (benefit)													(7		)	(30		)	2			(57		)
Postretirement and postemployment plans, net of tax	(3		)	1			102			(27		)	12			56			(3		)	105
Other, net of tax													(2		)	—			(2		)	—
Other comprehensive income (loss)													10			56			(5		)	105
Comprehensive income (loss)	$	(752	)	$	432		$	(1,309	)	$	2,093		$	(160	)	$	(330	)	$	(582	)	$	(557	)

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)


	September 30,			December 31,			June 30,			December 31,
(In millions, except per share data)	2015			2014			2016			2015
Assets
Current assets:
Cash and cash equivalents	$	1,680		$	2,398		$	2,584		$	1,221
Short-term investments	700			—
Receivables, less reserve of $4 and $3	991			1,729
Receivables, less reserve of $4 and $4							822			912
Inventories	324			357			272			313
Other current assets	163			109			76			144
Total current assets	3,858			4,593			3,754			2,590
Equity method investments	1,012			1,113			944			1,003
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $23,713 and $21,884	27,920			29,040
depletion and amortization of $21,659 and $23,260							25,657			27,061
Goodwill	457			459			115			115
Other noncurrent assets	1,427			806			2,057			1,542
Total assets	$	34,674		$	36,011		$	32,527		$	32,311
Liabilities
Current liabilities:
Accounts payable	$	1,246		$	2,545		$	953		$	1,313
Payroll and benefits payable	138			191			114			133
Accrued taxes	143			285			85			132
Other current liabilities	286			290			229			150
Long-term debt due within one year	1,035			1,068			1			1
Total current liabilities	2,848			4,379			1,382			1,729
Long-term debt	7,323			5,323			7,280			7,276
Deferred tax liabilities	2,542			2,486			2,392			2,441
Defined benefit postretirement plan obligations	436			598			409			403
Asset retirement obligations	1,965			1,917			1,597			1,601
Deferred credits and other liabilities	225			288			314			308
Total liabilities	15,339			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	(3,553		)	(3,642		)
Held in treasury, at cost – 89 million and 93 million shares							(3,397		)	(3,554		)
Additional paid-in capital	6,493			6,531			7,433			6,498
Retained earnings	15,800			17,638			14,320			14,974
Accumulated other comprehensive loss	(175		)	(277		)	(140		)	(135		)
Total stockholders' equity	19,335			21,020			19,153			18,553
Total liabilities and stockholders' equity	$	34,674		$	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)


	Nine Months Ended						Six Months Ended
	September 30,						June 30,
(In millions)	2015			2014			2016			2015
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income (loss)	$	(1,411	)	$	2,120		$	(577	)	$	(662	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations	—			(1,058		)
Deferred income taxes	(590		)	337			(392		)	(185		)
Depreciation, depletion and amortization	2,289			2,060			1,170			1,572
Impairments	381			130			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	9			(27		)	14			14
Exploratory dry well costs and unproved property impairments	708			220			166			148
Net loss on disposal of assets	108			88
Net (gain) loss on disposal of assets							(234		)	(1		)
Equity method investments, net	41			51			22			37
Changes in:
Current receivables	738			(270		)	88			534
Inventories	30			(32		)	30			21
Current accounts payable and accrued liabilities	(954		)	(115		)	(211		)	(770		)
All other operating, net	(136		)	(28		)	41			(56		)
Net cash provided by continuing operations	1,213			3,476
Net cash provided by discontinued operations	—			856
Net cash provided by operating activities	1,213			4,332			252			717
Investing activities:
Acquisitions, net of cash acquired	—			(12		)
Additions to property, plant and equipment	(2,948		)	(3,639		)	(753		)	(2,320		)
Disposal of assets	105			2,237			758			2
Investments - return of capital	61			46			37			31
Purchases of short-term investments	(925		)	—			—			(925		)
Maturities of short-term investments	225			—
Investing activities of discontinued operations	—			(356		)
Deposit for acquisition							(89		)	—
All other investing, net	22			(24		)	2			(1		)
Net cash used in investing activities	(3,460		)	(1,748		)	(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	(427		)	(401		)	(77		)	(285		)
All other financing, net	14			150			—			11
Net cash provided by (used in) financing activities	1,530			(1,420		)	1,159			1,669
Effect of exchange rate on cash and cash equivalents:
Continuing operations	(1		)	(1		)
Discontinued operations	—			(11		)
Cash held for sale	—			(655		)
Effect of exchange rate on cash and cash equivalents							(3		)	1
Net increase (decrease) in cash and cash equivalents	(718		)	497			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	$	1,680		$	761		$	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 SEC and do not include all of the information and disclosures required by U.S. 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 our ~~2014~~2015 Annual Report on Form 10-K. The results of operations for the ~~third~~second quarter and first ~~nine~~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. 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 byin which a reporting entity assesses ~~whether~~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 if the decision-making over the subject entity’s most significant activities was outsourced.~~rights. This standard is effective for us in the first quarter of ~~2016 and early adoption is permitted. 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 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, 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 ~~September~~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 ~~$471~~$468 million as of ~~September~~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 per share assumes exercise of stock options, provided the effect is not antidilutive. The per share calculations below exclude ~~13 million and 2~~14 million stock options for the ~~third quarters of 2015~~three and ~~2014~~six month periods ended June 30, 2016 and 13 ~~million and 4~~ million stock options for the ~~first nine months of~~three and six month periods ended June 30, 2015 ~~and 2014~~ that were antidilutive.

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

Weighted average common shares outstanding 677
675
677
681
Effect of dilutive securities —
3
—
3
Weighted average common shares, diluted 677
678
677
684
Per basic share:
Income (loss) from continuing operations $ (1.11 ) $ 0.45
$ (2.09 ) $ 1.56
Discontinued operations $ —
$ 0.19
$ —
$ 1.55
Net income (loss) $ (1.11 ) $ 0.64
$ (2.09 ) $ 3.11
Per diluted share:
Income (loss) from continuing operations $ (1.11 ) $ 0.45
$ (2.09 ) $ 1.55
Discontinued operations $ —
$ 0.19
$ —
$ 1.55
Net income (loss) $ (1.11 ) $ 0.64
$ (2.09 ) $ 3.10



	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	)

~~MARATHON OIL CORPORATION~~

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


5.	5. Acquisitions

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

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 ~~third~~oil window of the Anadarko Basin STACK play in Oklahoma. In the second quarter of ~~2014, we acquired acreage in~~2016 an $89 million deposit was paid into escrow related to the ~~Oklahoma Resource Basins at a cost~~acquisition. The purchase price was paid with cash on hand. We accounted for this transaction as an asset acquisition, with the majority of ~~$68 million after final settlement adjustments.~~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 ~~August~~the third quarter of 2015, we closed on the sale of our East ~~Texas,~~ Texas/North Louisiana and Wilburton, Oklahoma natural gas assets for proceeds of approximately $100 million and recorded a pretax loss of $1 million. During the second quarter of 2015, we recorded a non-cash impairment charge of $44 million related to these assets ~~(See~~as a result of the anticipated sale (see Note ~~15)~~13).

~~2015 - International E&P Segment~~

In September 2015, we entered into an agreement to sell our East Africa exploration acreage in Ethiopia and Kenya. A pretax loss of $109 million was recorded in the third quarter of 2015. This transaction is expected to close during the fourth quarter of 2015.

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

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

~~2014 - International E&P Segment~~

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

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

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2014 2014
Revenues applicable to discontinued operations $ 528
$ 1,901

Pretax income from discontinued operations $ 487
$ 1,617

After-tax income from discontinued operations $ 127
$ 449
^(a)

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

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

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

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

7. Segment Information

We ~~are a global energy company with operations in North America, Europe and Africa.~~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.

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

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

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

Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”). Segment income represents income ~~from continuing operations excluding~~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 6, as a result of the sale of our Angola assets and our Norway business in 2014, both are reflected as discontinued operations and excluded from the Int'l E&P segment for 2014.~~


	Three Months Ended September 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	$	796		$	182	$	242		$	80		^(c)	$	1,300		$	617		$	159		$	185		$	(91	)	^(c)	$	870
Marketing revenues	57			25		2			—				84			53			23			13			—				89
Total revenues	853			207		244			80				1,384			670			182			198			(91		)		959
Income (loss) from equity method investments	—			48		—			(12		)	^(d)	36
Net gain (loss) on disposal of assets and other income	6			6		—			(109		)	^(e)	(97		)
Income from equity method investments																—			37			—			—				37
Net gain on disposal of assets and other income																2			7			1			296			^(d)	306
Less:
Production expenses	179			61		166			—				406			129			56			165			—				350
Marketing costs	56			25		3			—				84			52			23			13			—				88
Exploration expenses	22			10		—			553			^(f)	585			37			4			7			141			^(e)	189
Depreciation, depletion and amortization	549			79		76			13				717			433			68			49			11				561
Impairments	—			—		4			333			^(g)	337
Other expenses ^(a)	106			25		8			79			^(h)	218			97			22			9			99			^(f)	227
Taxes other than income	42			—		5			(1		)		46			35			—			4			—				39
Net interest and other	—			—		—			75				75			—			—			—			86				86
Income tax provision (benefit)	(34		)	32		(7		)	(387		)		(396		)
Segment income (loss) /Loss from continuing operations	$	(61	)	$	29	$	(11	)	$	(706	)		$	(749	)
Income tax benefit																(41		)	(2		)	(10		)	(15		)		(68		)
Segment income (loss) / Net income (loss)																$	(70	)	$	55		$	(38	)	$	(117	)		$	(170	)
Capital expenditures ^(b)	$	564		$	30	$	(11	)	$	12			$	595		$	153		$	12		$	7		$	5			$	177


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


^(b)	Includes accruals.


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


^(d)	~~Partial impairment~~Primarily related to partial sale of ~~investment in equity method investee~~Wyoming upstream and midstream assets. (See ~~Note 15).~~note 6.)


^(e)	~~Includes loss on sale~~Impairments associated with decision to not drill remaining Gulf of ~~East Africa exploration acreage (See Note~~ 6). Mexico undeveloped leases.


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


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


^(h)	Includes pension settlement loss of ~~$18 million and severance related expenses associated with workforce reductions of $4~~$31 million (See ~~Note~~note 8).

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended September 30, 2014
Not Allocated
(In millions) N.A. E&P Int'l E&P OSM to Segments Total
Sales and other operating revenues $ 1,586
$ 273
$ 457
$ —
$ 2,316
Marketing revenues 506
46
2
—
554
Total revenues 2,092
319
459
—
2,870
Income from equity method investments —
89
—
—
89
Net gain (loss) on disposal of assets and other income (1 ) 12
—
1
12
Less:
Production expenses 233
108
252
—
593
Marketing costs 507
45
2
—
554
Exploration expenses 55
41
—
—
96
Depreciation, depletion and amortization 609
55
62
11
737
Impairments —
—
—
109
^(c)
109
Other expenses ^(a)
118
26
14
101
^(d)
259
Taxes other than income 109
—
5
1
115
Net interest and other —
—
—
55
55
Income tax provision (benefit) 168
39
31
(89 ) 149
Segment income/Income from continuing operations $ 292
$ 106
$ 93
$ (187 ) $ 304
Capital expenditures ^(b)
$ 1,277
$ 166
$ 49
$ 16
$ 1,508


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


^(b)	~~Includes accruals.~~


^(c)	~~Proved property impairment (See Note 14).~~


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


	Nine Months Ended September 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	$	2,639		$	575	$	614		$	59		^(c)	$	3,887		$	993		$	211	$	147		$	(44	)	^(c)	$	1,307
Marketing revenues	345			81		45			—				471			110			30		43			—				183
Total revenues	2,984			656		659			59				4,358			1,103			241		190			(44		)		1,490
Income (loss) from equity method investments	—			110		—			(12		)	^(d)	98
Net gain (loss) on disposal of assets and other income	17			20		1			(108		)	^(e)	(70		)
Income from equity method investments																—			26		—			—				26
Net gain on disposal of assets and other income																11			4		—			—				15
Less:
Production expenses	560			192		548			—				1,300			179			64		207			—				450
Marketing costs	348			79		44			—				471			112			29		41			—				182
Exploration expenses	148			85		—			553			^(f)	786			91			20		—			—				111
Depreciation, depletion and amortization	1,866			214		173			36				2,289			634			71		35			11				751
Impairments	—			—		4			377			^(g)	381			—			—		—			44			^(d)	44
Other expenses ^(a)	322			67		26			330			^(h)	745			99			19		9			122			^(e)	249
Taxes other than income	170			—		15			6				191			67			—		5			6				78
Net interest and other	—			—		—			180				180			—			—		—			58				58
Income tax provision (benefit)	(146		)	56		(43		)	(413		)	⁽ⁱ⁾	(546		)	(23		)	27		(30		)	20			^(f)	(6		)
Segment income (loss) /Loss from continuing operations	$	(267	)	$	93	$	(107	)	$	(1,130	)		$	(1,411	)
Segment income (loss) / Net income (loss)																$	(45	)	$	41	$	(77	)	$	(305	)		$	(386	)
Capital expenditures ^(b)	$	2,048		$	275	$	26		$	26			$	2,375		$	551		$	99	$	16		$	12			$	678


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


^(b)	Includes accruals.


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


^(d)	~~Partial~~Proved property impairment ~~of investment in equity-method investee~~ (See Note ~~15)~~13).


^(e)	Includes ~~loss on sale of East Africa exploration acreage (See Note 6).~~


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


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


^(h)	~~Includes~~ pension settlement loss of ~~$99~~$64 million ~~and severance related expenses associated with workforce reductions of $47 million (See~~(see Note 8).


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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


	Nine Months Ended September 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	$	4,518	$	1,000	$	1,217	$	—			$	6,735		$	1,110		$	255		$	333		$	(114	)	^(c)	$	1,584
Marketing revenues	1,486		177		50		—				1,713			84			38			25			—				147
Total revenues	6,004		1,177		1,267		—				8,448			1,194			293			358			(114		)		1,731
Income from equity method investments	—		346		—		—				346			—			51			—			—				51
Net gain (loss) on disposal of assets and other income	17		44		3		(97		)	^(c)	(33		)
Net gain on disposal of assets and other income														3			13			1			233			^(d)	250
Less:
Production expenses	661		307		729		—				1,697			263			109			306			—				678
Marketing costs	1,484		176		50		—				1,710			84			37			25			—				146
Exploration expenses	194		120		—		—				314			55			10			7			141			^(e)	213
Depreciation, depletion and amortization	1,674		201		152		33				2,060			920			118			109			23				1,170
Impairments	21		—		—		109			^(d)	130			1			—			—			—				1
Other expenses ^(a)	354		98		40		297			^(e)	789			215			38			16			218			^(f)	487
Taxes other than income	301		—		16		2				319			77			—			9			1				87
Net interest and other	—		—		—		180				180			—			—			—			171				171
Income tax provision (benefit)	496		178		71		(245		)		500
Segment income /Income from continuing operations	$	836	$	487	$	212	$	(473	)		$	1,062
Income tax benefit														(153		)	(14		)	(27		)	(150		)		(344		)
Segment income (loss) / Net income (loss)														$	(265	)	$	59		$	(86	)	$	(285	)		$	(577	)
Capital expenditures ^(b)	$	3,246	$	386	$	172	$	29			$	3,833		$	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 6).~~Unrealized loss on commodity derivative instruments.


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


^(e)	Includes pension settlement loss of ~~$93~~$81 million ~~(See~~and severance related expenses associated with workforce reductions of $43 million (see Note 8).

~~8. Defined Benefit Postretirement Plans~~

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

Three Months Ended September 30,

Pension Benefits Other Benefits
(In millions) 2015 2014 2015 2014
Service cost $ 11
$ 12
$ —
$ —
Interest cost 12
15
3
4
Expected return on plan assets (17 ) (16 ) —
—
Amortization:

– prior service cost (credit) (3 ) 1
(1 ) (1 )
– actuarial loss 5
7
1
—
Net settlement loss ^(a)
18
22
—
—
Net curtailment loss^(b)
4
—
—
—
Net periodic benefit cost $ 30
$ 41
$ 3
$ 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)

Nine Months Ended September 30,
Pension Benefits Other Benefits
(In millions) 2015 2014 2015 2014
Service cost $ 35
$ 35
$ 2
$ 2
Interest cost 39
46
8
10
Expected return on plan assets (53 ) (48 ) —
—
Amortization:

– prior service cost (credit) (4 ) 4
(3 ) (3 )
– actuarial loss 19
23
1
—
Net settlement loss^(a)
99
93
—
—
Net curtailment loss (gain)^(b)
5
—
(4 ) —
Net periodic benefit cost $ 140

$ 153

$ 4

$ 9

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

During the first ~~nine~~six months of 2015, we recorded the effects of a workforce reduction, a U.S. pension plan amendment and the discontinuation of accruals for future benefits under the U.K. pension plan. The U.S. pension plan amendment freezes the final average pay used to calculate the benefit under the legacy final average pay formula and was effective July 6, 2015. For the U.K. pension plan, a final decision was reached with the plan trustees to close the plan to future benefit accruals effective December 31, 2015. Additionally, during the first nine months of 2015 and 2014,2016, we recorded the effects of 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.

During the first ~~nine~~six months of ~~2015,~~2016, we made contributions of ~~$65~~$30 million to our funded pension plans. We expect to make additional contributions up to an estimated ~~$18~~$34 million to our funded pension plans over the remainder of ~~2015.~~2016. During the first ~~nine~~six months of ~~2015,~~2016, we made payments of ~~$57~~$37 million and ~~$13~~$10 million related to unfunded pension plans and other postretirement benefit plans, respectively.

9. Income Taxes

Effective Tax Rate

The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The difference between the total provision ~~(benefit)~~ and the sum of the amounts allocated to segments is reported in the “Not Allocated to Segments” column of the tables in Note 7.

Our effective income tax rates ~~on continuing operations~~ for the first ~~nine~~six months of 2016 and 2015 were 37% and ~~2014 were 28% and 32%~~18%. The tax provision (benefit) applicable to Libyan ordinary income (loss) was recorded as a discrete item in the first nine months of 2015 and 2014. Excluding Libya, the effective tax rates on continuing operations, would be 27% and 32% for the first nine 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 ~~nine~~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).

~~Change~~ 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 ~~Tax Law~~

Onjurisdictional 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.

~~Indefinite Reinvestment Assertion~~

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

~~MARATHON OIL CORPORATION~~

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

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

Deferred Tax Assets

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

10. Short-term Investments

As of ~~September~~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. ~~They are~~These short-term investments, 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. These short-term investments matured during October~~ 2015.

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.


	September 30,		December 31,		June 30,		December 31,
(In millions)	2015		2014		2016		2015
Liquid hydrocarbons, natural gas and bitumen	$	39	$	58	$	31	$	35
Supplies and other items	285		299		241		278
Inventories, at cost	$	324	$	357	$	272	$	313

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


	September 30,		December 31,		June 30,		December 31,
(In millions)	2015		2014		2016		2015
North America E&P	$	15,875	$	16,717	$	13,965	$	15,226
International E&P	2,604		2,741		2,479		2,533
Oil Sands Mining	9,334		9,455		9,101		9,197
Corporate	107		127		112		105
Net property, plant and equipment	$	27,920	$	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 ~~September~~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 ~~boe.~~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 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 ~~September~~June 30, ~~2015~~2016 and December 31, ~~2014. This $38~~2015. The $33 million ~~net decrease was associated with a write-down of our Canadian in-situ assets at Birchwood~~increase primarily relates to the Alba Block Sub Area B offshore Equatorial Guinea where the Rodo well reached total depth in the ~~second~~first quarter of 2015. ~~After further evaluation of the estimated recoverable~~

~~MARATHON OIL CORPORATION~~

~~Notes~~We have since completed a seismic feasibility study and continue to ~~Consolidated Financial Statements (Unaudited)~~

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

~~13. Other Noncurrent Assets~~

September 30, December 31,
(in millions) 2015 2014
Deferred tax assets $ 1,115
$ 525
Intangible assets 95
96
Other 217
185
Other noncurrent assets $ 1,427
$ 806

~~14. Impairments and Exploration Expenses~~

The continued decline of commodity prices resulted in a downward revision of our long-term commodity price assumptions and was a triggering event which required us to reassess long-lived assets related to oil and gas producing properties for impairment as of September 30, 2015. Further changes in management's forecast assumptions may cause us to reassess our long-lived assets for impairment, and could result in non-cash impairment chargesfinalize next steps in the ~~future.~~Alba Block Sub Area B exploration program.

~~The following table summarizes impairment charges of proved properties:~~

Three Months Ended September 30, Nine Months Ended September 30,
(in millions) 2015 2014 2015 2014
Total impairments $ 337
$ 109
$ 381
$ 130

~~Impairments for the three and nine months ended September 30, 2015 consisted primarily of proved properties in Colorado and the Gulf of Mexico as a result of lower forecasted commodity prices.~~

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

~~The following table summarizes the components of exploration expenses:~~

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2015 2014 2015 2014
Exploration Expenses
Unproved property impairments $ 563
$ 39
$ 612
$ 140
Dry well costs (3 ) 25
96
80
Geological and geophysical 8
10
23
27
Other 17
22
55
67
Total exploration expenses $ 585
$ 96
$ 786
$ 314

Included in the unproved property impairments for the three and nine months ended September 30, 2015 are non-cash charges of $553 million as a result of changes in our conventional exploration strategy (Gulf of Mexico and Harir block in the Kurdistan Region of Iraq) and lower forecasted commodity prices (Colorado).

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

~~MARATHON OIL CORPORATION~~

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

~~15.~~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 ~~September~~June 30, ~~2015~~2016 and December 31, ~~2014~~2015 by fair value hierarchy level.


	September 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)	$	—	$	61	$	—	$	61	$	—	$	6	$	—	$	6
Interest rate	—		15		—		15		—		12		—		12
Derivative instruments, assets	$	—	$	76	$	—	$	76	$	—	$	18	$	—	$	18
Derivative instruments, liabilities
Commodity^(a)	$	—	$	3	$	—	$	3	$	—	$	70	$	—	$	70
Derivative instruments, liabilities	$	—	$	3	$	—	$	3	$	—	$	70	$	—	$	70


^(a)	Derivative instruments are recorded on a net basis in the company's balance sheet (see Note ~~16)~~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 1614 for additional discussion of the types of derivative instruments we use.

~~Fair Values - Nonrecurring~~

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

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

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

Commodity prices began declining in the second half of 2014 and remain substantially lower through 2015. The prolonged decline in commodity prices, and the resulting change in management's future commodity price assumptions, was a triggering event which required us to reassess long-lived assets related to oil and gas producing properties for impairment as of September 30, 2015. Further changes in management's forecast assumptions may cause us to reassess our long-lived assets for impairment, and could result in non-cash impairment charges in the future. Long-lived assets held for use that were impaired are discussed below. The fair values of each were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs, unless otherwise noted. Inputs to the fair value measurement include reserve and production estimates made by our reservoir engineers, estimated future commodity prices

~~MARATHON OIL CORPORATION~~

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

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

~~2015 - North America E&P~~

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

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

~~2015 - International E&P~~

~~In the third quarter of 2015, a partial impairment of~~ ~~$12 million~~ ~~was recorded to an investment in an equity method investee as a result of lower forecasted commodity prices, to a fair value of~~ ~~$604 million. This impairment was reflected in income from equity method investments in our consolidated statements of income.~~

~~2014 - North America E&P~~

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

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

Fair Values – Goodwill

Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. ~~After we~~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 ~~goodwill~~ impairment test in April 2015, a triggering event (downward revision of forecasted commodity price assumptions) required us to reassess our goodwill for impairment as of September 30, 2015. Based on the results of this assessment, we2016 and concluded no impairment was required. ~~The~~While the fair value of ~~the North America E&P and~~our International E&P reporting ~~units~~unit exceeded ~~their respective~~the book ~~values by a significant margin. Changes in management's forecast~~value, subsequent commodity price ~~assumptions~~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,
	2016				2015
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	—	$	—	$	17	$	44



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

Long-lived assets held for use that were impaired are discussed below. The fair values of each were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs. Inputs to the fair value measurement include reserve and production estimates made by our reservoir engineers, estimated future commodity prices adjusted for quality and location differentials and forecasted operating expenses for the remaining estimated life of the reservoir.

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

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, payables and derivative financial instruments, and their reported fair values by individual balance sheet line item at June 30, 2016 and December 31, 2015.



	June 30, 2016				December 31, 2015
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Other noncurrent assets	$	198	$	206	$	104	$	118
Total financial assets	$	198	$	206	$	104	$	118
Financial liabilities
Other current liabilities	$	25	$	24	$	34	$	33
Long-term debt, including current portion^(a)	7,186		7,291		6,723		7,291
Deferred credits and other liabilities	121		117		97		95
Total financial liabilities	$	7,332	$	7,432	$	6,854	$	7,419

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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

September 30, 2015 December 31, 2014
Fair Carrying Fair Carrying
(In millions) Value Amount Value Amount
Financial assets
Other noncurrent assets $ 109
$ 116
$ 132
$ 129
Total financial assets   109
116
132
129
Financial liabilities

     Other current liabilities 15
14
13
13
     Long-term debt, including current portion^(a)
8,302
8,324
6,887
6,360
Deferred credits and other liabilities 69
64
69
68
Total financial liabilities   $ 8,386
$ 8,402
$ 6,969
$ 6,441

^(a) ~~Excludes capital leases.~~

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

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

~~16.~~14. Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note ~~15.~~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 September 30, 2015 and December 31, 2014.~~sheets.


	September 30, 2015							June 30, 2016
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	15	$	—	$	15	Other noncurrent assets	$	12	$	—	$	12	Other noncurrent assets
Total Designated Hedges	15		—		15			$	12	$	—	$	12

								June 30, 2016
(In millions)								Asset		Liability		Net Liability		Balance Sheet Location
Not Designated as Hedges
Commodity	55		2		53		Other current assets	$	6	$	39	$	33	Other current liabilities
Commodity	6		1		5		Other noncurrent assets	—		31		31		Deferred credits and other liabilities
Total Not Designated as Hedges	61		3		58			$	6	$	70	$	64
Total	$	76	$	3	$	73


	December 31, 2014							December 31, 2015
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	8	$	—	$	8	Other noncurrent assets	$	8	$	—	$	8	Other noncurrent assets
Total	$	8	$	—	$	8

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

~~MARATHON OIL CORPORATION~~

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

Derivatives Designated as Fair Value Hedges

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


	September 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	4.68	%	$	600	4.64	%	$	600	4.94	%	$	600	4.73	%
March 15, 2018	$	300	4.54	%	$	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 September 30,						Nine Months Ended September 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	$	4		$	(6	)	$	7		$	(3	)	Net interest and other	$	—	$	(2	)	$	4		$	3
Foreign currency	Discontinued operations	$	—		$	(18	)	$	—		$	(29	)
Hedged Item
Long-term debt	Net interest and other	$	(4	)	$	6		$	(7	)	$	3		Net interest and other	$	—	$	2		$	(4	)	$	(3	)
Accrued taxes	Discontinued operations	$	—		$	18		$	—		$	29

Derivatives not Designated as Hedges

~~During the first nine months of 2015, we~~We have entered into multiple crude oil and natural gas derivatives indexed to ~~New York Mercantile Exchange ("NYMEX")~~NYMEX WTI and Henry Hub related to a portion of our forecasted North America E&P sales through December ~~2016.~~2017. These commodity derivatives consist of three-way collars, ~~extendable three-way~~two-way collars, call options and ~~call options. Three way-collars~~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. 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:



Crude Oil
			Year Ending December 31,
	Third Quarter	Fourth Quarter	2017
Three-Way Collars
Volume (Bbls/day)	47,000	47,000	—
Price per Bbl:
Ceiling	$55.37	$55.37	—
Floor	$50.23	$50.23	—
Sold put	$40.96	$40.96	—
Sold call options ^(a)
Volume (Bbls/day)	10,000	10,000	35,000
Price per Bbl	$72.39	$72.39	$61.91
Two-way Collars
Volume (Bbls/day)	10,000	10,000	—
Price per Bbl:			—
Ceiling	$50.00	$50.00
Floor	$41.55	$41.55


^(a)	Call options settle monthly.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


Financial Instrument	Weighted Average Price	Barrels per day	Remaining Term
Three-Way Collars
Natural Gas				Natural Gas
						Year Ending December 31,
				Third Quarter	Fourth Quarter	2017
Three-Way Collars ^(a)
Volume (MMBtu/day)				20,000		40,000
Price per MMBtu
Ceiling	$70.34	35,000	October- December 2015	$2.93		$3.28
Floor	$55.57			$2.50		$2.75
Sold put	$41.29			$2.00		$2.25

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

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

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


^(a)	~~Counterparties have~~On our 2016 collars, the counterparty has the option ~~exercisable on March 31, 2016,~~ to ~~extend these collars through September of 2016~~execute fixed-price swaps (swaptions) at ~~the same volume and~~a weighted average price ~~as the underlying three-way collars.~~


^(b)	~~Counterparty has the option,~~of $2.93 per MMBtu indexed to NYMEX Henry Hub, which is exercisable on ~~June 30, 2016, to extend these collars through~~December 22, 2016. If counterparty exercises, the ~~remainder~~term of ~~2016 at~~ the ~~same volume~~fixed-price swaps would be for the calendar year 2017 and, ~~weighted average price as the underlying three-way collars.~~


^(c)	~~Call~~if all such options ~~settle monthly.~~are exercised, 20,000 MMBtu per day.

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 ~~gain~~loss of ~~$108~~$88 million and ~~$91~~$90 million compared to a net loss of $43 million and $17 million for the same respective periods in ~~the third quarter and first nine months~~ 2015. ~~There were no crude oil~~Net cash received from settlements of commodity derivative instruments infor the ~~first nine months of 2014.~~

Onthree and six month 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 18). 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.

~~17.~~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 ~~nine~~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	2,674,987			$30.52	1,680,000		^(a)		$7.22	5,233,984			$7.91
Options Exercised/Stock Vested	(549,926	)			$16.84	(1,135,635	)		$33.25	—			—		(1,148,953	)		$32.29
Canceled	(605,760	)			$34.11	(708,380	)		$33.20	(973,295	)			$25.76	(557,051	)		$23.20
Outstanding at September 30, 2015	12,996,232				$29.99	4,279,325			$32.17
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 ~~nine~~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)~~

~~18.~~16. Debt

Revolving Credit Facility

As of ~~September~~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 extended the maturity date by an additional year such that the Credit Facility now matures in May 2020. The amendment additionally provides us the ability to request two one-year extensions to the maturity date and an option to increase the commitment amount by up to an additional $500 million, subject to the consent of any increasing lenders. The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unchanged.$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 ~~September~~June 30, ~~2015,~~2016, we were in compliance with this covenant with a debt-to-capitalization ratio of ~~30%~~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~~and used the ~~following series:~~

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

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

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

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

~~19.~~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 September 30,						Nine Months Ended September 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	$	(6	)	$	(7	)	$	(20	)	$	(23	)	General and administrative	$	(4	)	$	(7	)	$	(7	)	$	(14	)	General and administrative
Net settlement loss	(18		)	(22		)	(99		)	(93		)	General and administrative	(31		)	(64		)	(79		)	(81		)	General and administrative
Net curtailment gain (loss)	(4		)	—			(1		)	—			General and administrative	—			(2		)	—			3			General and administrative
	(28		)	(29		)	(120		)	(116		)	Income (loss) from operations	(35		)	(73		)	(86		)	(92		)	Income (loss) from operations
	10			10			44			38			Benefit for income taxes	13			25			29			32			Provision (benefit) for income taxes
Other insignificant, net of tax	—			—			—			(1		)
Total reclassifications	$	(18	)	$	(19	)	$	(76	)	$	(79	)	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.

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

Nine Months Ended September 30,
(In millions) 2015 2014
Net cash used in operating activities:
Interest paid (net of amounts capitalized) $ (200 ) $ (201 )
Income taxes paid to taxing authorities ^(a)
(174 ) (1,514 )
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 $ 12
$ 240
Asset retirement obligations assumed by buyer 23
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 nine months of 2014 included $1,195 million related to discontinued operations.~~

~~21.~~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 an independent global exploration and production company based in Houston, ~~Texas. Our~~Texas with operations ~~are primarily located~~ in North America, Europe and Africa ~~with~~and a focus on ~~our North American~~U.S. unconventional ~~shale~~resource plays. Total proved reserves were 2.2 billion boe at December 31, ~~2014~~2015 and total assets were ~~$35~~$33 billion at ~~September~~June 30, ~~2015.~~2016.

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

~~Increased company-wide net sales volumes from continuing operations by 7% to 445 mboed in the third quarter of 2015 from 417 mboed in the third quarter of 2014~~


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

~~Maintained focus on cost discipline and efficiencies~~


◦	~~Reduced third quarter cash capital expenditures to $628 million, a 28% decrease compared to the previous quarter, reflecting continued capital discipline and benefits from operating efficiencies~~


◦	~~Reduced company-wide production expenses per boe in the third quarter of 2015 compared to the same period last year~~


▪	~~North America E&P - 27% reduction to $7.43 per boe~~


▪	~~International E&P - 47% reduction to $5.53 per boe~~


▪	~~Oil Sands Mining - 30% reduction to $26.01 per boe~~


◦	~~Achieved 97% average operational availability for our operated assets in the third quarter of 2015~~

~~Active management of liquidity and capital structure~~Strengthened balance sheet


◦	At the end of the ~~third~~second quarter of 2016, we had ~~$5.4~~$5.9 billion of liquidity, ~~including $2.4~~comprised of $2.6 billion in cash and ~~short-term investments, $1~~an undrawn $3.3 billion ~~of which was used to repay our senior notes that matured in November~~revolving credit facility


◦	~~Cash and short-term investments-adjusted~~Cash-adjusted debt-to-capital ratio of ~~24%~~20% at ~~September~~June 30, ~~2015,~~2016, as compared with ~~16%~~25% at December 31, ~~2014~~2015

~~Portfolio management activities~~Focused on cost reductions


◦	~~We continue~~Production expenses per boe in the second quarter of 2016, as compared to ~~make progress advancing our goal~~the same period last year improved in the North America E&P segment by 13% to ~~divest at least $500~~$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 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~~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:


▪	~~Closed on the sale of~~Unrealized losses from our ~~East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets in August 2015 for proceeds of approximately $100~~commodity derivative instruments totaling $91 million, pre-tax


▪	~~Signed agreement for sale~~Net gains on disposal of ~~our East Africa exploration acreage~~

•~~Financial results~~


◦	~~Loss from continuing operations per diluted share of $1.11 in the third quarter of 2015 as compared to income from continuing operations of $0.45 per diluted share in the same period last year~~non-core assets totaling $294 million, pre-tax


◦▪	~~Included in the loss for the third quarter are $611~~Non-cash impairments totaling $141 million, ~~($949 million pre-tax)~~pre-tax, as a result of ~~non-cash charges comprised largely~~our decision not to drill any of ~~losses and asset impairments resulting from lower forecasted commodity prices and changes in~~ our ~~conventional exploration strategy (refer to Exploration Update below)~~


◦	~~Operating cash flow provided by continuing operations for the first nine months~~remaining Gulf of ~~2015 was $1.2 billion, compared to $3.5 billion in the same period last year, reflecting the lower commodity price environment~~Mexico leases

Subsequent to the end of the third quarter, we reduced our quarterly dividend from $0.21 to $0.05 per share to address the uncertainty of a lower for longer commodity price environment, to align with our priority of maintaining a strong balance sheet through the cycle and to provide us with additional capital flexibility to support growth from the U.S. resource plays when commodity prices improve.

Outlook

Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows and the amount of capital available to reinvest into our business. ~~Commodity prices began declining in~~Our focus continues on the strengthening of the balance sheet, the simplification and concentration of our portfolio and cost reductions which during the second ~~half~~quarter of ~~2014 and remain substantially lower through 2015. We believe we can manage in this lower commodity price cycle through~~2016 included a ~~continued focus on development in~~reduction to our ~~three U.S. resource plays, operational execution, efficiency improvements, cost reductions, capital discipline and portfolio optimization, all while maintaining financial flexibility.~~Capital Program of $100 million to $1.3 billion for the year.

We expect our full-year 2015 capital, investment and exploration budget to be $3.1 billion. We estimate our full-year North America E&P and International E&P production volumes (excluding Libya) to be 380 - 390 net mboed and OSM's synthetic crude oil production to be 40 - 45 net mboed. In addition, based on our current outlook and preliminary plan discussions, we would anticipate a 2016 capital, investment and exploration program of up to $2.2 billion which would give us the flexibility to deliver 2016 annual average production in the U.S. resource plays flat to the 2015 exit rate.

Exploration Update

In September 2015, we announced our intention to scale back our conventional exploration program, with ~~an anticipated 2016 program of approximately $100 million, a reduction of 60% as compared to the 2015 budget, subject to approval by~~future exploration investment focused on fulfilling our ~~Board of Directors. Our conventional exploration focus will be redirected to~~ existing commitments in the Gulf of Mexico and Gabon. In second quarter of 2016, we made the decision to not drill our remaining Gulf of Mexico undeveloped leases. As a result, we recorded a non-cash ~~impairments related to unproved properties~~impairment of $141 million in the second quarter of 2016. Additionally, during the third quarter 2016, we executed an agreement to terminate our Gulf of Mexico ~~and the Harir block~~deepwater drilling rig contract. As a result, we expect to recognize a termination payment of $113 million in ~~the Kurdistan Region of Iraq~~other operating expense in ~~the third~~that quarter.

Operations

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



	Three Months Ended 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)%

Three Months Ended September 30, Nine Months Ended September 30,
Net Sales Volumes 2015 2014 Increase
(Decrease) 2015 2014 Increase
(Decrease)
North America E&P (mboed)
261 250 4% 273 230 19%
International E&P (mboed)
119 112 6% 115 121 (5)%
Oil Sands Mining (mbbld) ^(a)
65 55 18% 51 49 4%
Total Continuing Operations (mboed)
445 417 7% 439 400 10%

^(a)Includes blendstocks

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

Net sales volumes in the ~~North America E&P~~ segment ~~increased~~were lower in the second quarter and first six months of 2016 primarily as a result of ~~continued growth from~~decreased drilling and 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 ~~combined U.S. resource plays.~~second half of 2015. The following ~~table provides~~tables provide details regarding net sales volumes, sales mix and operational drilling activity for our significant ~~operational areas~~operations within this ~~segment.~~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)%

^(a)Includes 17 mboed of Gulf of Mexico and other conventional onshore U.S. production, which was disposed of during the sale of non-core assets in the second half of 2015.

Three Months Ended September 30, Nine Months Ended September 30,
Net Sales Volumes 2015 2014 Increase
(Decrease) 2015 2014 Increase
(Decrease)
Equivalent Barrels (mboed)

Eagle Ford 126 117 8% 137 105 30%
Oklahoma Resource Basins 23 19 21% 24 17 41%
Bakken 61 56 9% 59 50 18%
Other North America ^(a)
51 58 (12)% 53 58 (9)%
Total North America E&P 261 250 4% 273 230 19%


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

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

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



	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%

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



	Three Months Ended June 30,		Six Months Ended June 30,
	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

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

Eagle Ford – Of the 5730 gross operated wells brought to sales during ~~this~~the second quarter 11of 2016, 19 were ~~in the Austin Chalk, 6~~Lower Eagle Ford, 3 were ~~in the~~ Upper Eagle Ford and ~~40 in the Lower Eagle Ford.~~8 were Austin Chalk. Production decreases were due to lower completion activity with fewer gross operated wells brought to sales and reduced contribution from 2015 high-density pads drilled at tighter well spacing. Our average time to drill an Eagle Ford well in the ~~third~~second quarter ~~2015,~~2016, spud-to-total depth, ~~decreased to 10 days.~~was 8 days, a decrease from 11 days in the same quarter last year as efficiency gains in drilling continued. Wells were drilled at an average rate of 2,400 feet per day.

Oklahoma Resource Basins – ~~During~~Of the ~~third quarter, we spud our first Springer well and brought online 8~~5 gross operated wells (6 in SCOOP and 2 in STACK), with one of the SCOOP wells being an extended-reach lateral. In addition to the 8 wells mentioned above, we completed an additional Smith infill pilot well in the SCOOP which was brought to sales on October 1. These wells are all in the very early stages of production. We continue to leverage the benefit of participation in outside-operated wells and plan to participate in approximately 55-70 gross outside-operated wells in 2015 in the SCOOP Woodford, SCOOP Springer and STACK areas, with 17 outside-operated wells brought to sales in the second quarter of 2016, 3 were in the SCOOP Woodford; 2 were in the STACK Meramec and all were extended laterals. We also participated in 16 outside-operated wells during the ~~quarter.~~second quarter of 2016, 10 of which were in the SCOOP and 6 were in the STACK.

We closed on the Payrock acquisition in the STACK play in Oklahoma on August 1, 2016 and continue to operate one drilling rig on the acreage with plans to add another rig late in the third quarter. This will bring the total rig count in Oklahoma to 4.

Bakken – ~~The 5~~Of the 4 gross operated wells brought to sales ~~this~~in the second quarter of 2016, 2 were in the ~~East Myrmidon area. Despite~~Middle Bakken formation and 2 in the ~~lower number of wells to sales this quarter, sales volumes were driven by continued strong performance from~~Three Forks formation, all with higher intensity completions. We do not currently have an active drilling rig in the ~~Doll pad wells (West Myrmidon) which came online in late June as well as sustained improvement in production uptime. We expect reduced completions activity during the fourth quarter.~~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, 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. ~~– Development work continues in the~~

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

~~North America~~

International E~~&P--Exploration~~&P

~~Gulf of Mexico~~ ~~– The third appraisal well on~~Net sales volumes in the ~~Shenandoah prospect was spud~~segment were higher in May 2015 and reached total depth in October, finding more than 620 feet of net oil pay. The operator completed logging operations and will obtain a whole core across the reservoir interval. The well is located in Walker Ridge Block 51, in which we hold a 10% non-operated working interest. The Solomon exploration prospect located on Walker Ridge Block 225 was spud during the second quarter of ~~2015~~2016 primarily as a result of planned turnaround and ~~is expected to reach total depth~~maintenance activities at the Alba field and E.G. LNG facilities in the ~~fourth quarter. We hold a 58% operated working interest in this prospect.~~

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

second quarter of 2015. The following table provides details regarding net sales volumes for our significant ~~operational areas~~operations within this segment.


	Three Months Ended September 30,			Nine Months Ended September 30,
	2015	2014	Increase (Decrease)	2015	2014	Increase (Decrease)	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	97	4%	96	104	(8)%	101	89	13%	93	93	—%
United Kingdom^(a)	18	9	100%	19	15	27%	19	19	—%	15	19	(21)%
Libya	—	6	(100)%	—	2	(100)%
Total International E&P (mboed)	119	112	6%	115	121	(5)%
Net Sales Volumes of Equity Method Investees
Total International E&P							120	108	11%	108	112	(4)%
Equity Method Investees
LNG (mtd)	5,700	6,265	(9)%	5,653	6,488	(13)%	5,797	4,991	16%	5,060	5,629	(10)%
Methanol (mtd)	1,125	1,103	2%	895	1,078	(17)%	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 85 mmcfd and 37 mmcfd for the ~~third~~second quarters of 2016 and 2015, and ~~2014, and 8~~5 mmcfd and 59 mmcfd for the first ~~nine~~six months of ~~2015~~2016 and ~~2014.~~2015.

Equatorial Guinea – ~~Third~~Second quarter 2016 net sales ~~volumes increased as production from~~were higher compared to the same quarter of 2015 due to lower planned turnaround and maintenance activities at the Alba ~~C21 development well came online with higher than expected yields, combined with a successful wire-line intervention program on five existing Alba wells.~~field and E.G. LNG facilities. The ~~ongoing~~ Alba field compression project ~~designed~~achieved first gas in July, which is expected to maintain the production plateau for an additional two ~~additional~~ years and extend field life up to eight ~~years, achieved mechanical completion at the fabrication yard in the Netherlands during the third quarter and is on schedule to be operational in mid-2016.~~years.

United Kingdom – Net sales volumes ~~benefited from improved production as two subsea development wells at West Brae began producing during 2015. Overall, operating availability was higher for all U.K. assets~~ in ~~2015 as compared~~the first six months of 2016 were lower due to ~~comparative 2014 periods which included planned and unplanned maintenance activities. During the third quarter of 2015, planned maintenance~~repair activities ~~were completed~~ at the ~~East~~ Brae ~~field and continue~~Alpha facility following a process pipe failure in late 2015. Production was restored at the ~~non-operated~~facility in late April. Higher overall production efficiency at the remaining Brae facilities and improved reliability from the outside-operated Foinaven ~~field. The activity at Foinaven will impact production volumes during~~field partially offset the ~~fourth quarter of 2015.~~Brae Alpha shut-in.

Libya – ~~We had no sales during the first nine months of 2015 as a result of~~Due to continued civil unrest, ~~as compared to one lifting~~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 ~~third~~second quarter, ~~of 2014. In December 2014, Libya’s~~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. Considerable~~our Waha concessions. However, considerable uncertainty remains around the timing of future production and sales levels.

Oil Sands Mining

Our net synthetic crude oil sales volumes were 6549 mbbld and 5154 mbbld in the ~~third~~second quarter and first ~~nine~~six months of ~~2015~~2016 compared to 5529 mbbld and 4944 mbbld in the same periods of ~~2014. Net sales~~2015. Sales volumes increased in ~~the third~~comparison to second quarter and first six months of 2015 ~~primarily~~which were adversely affected due to ~~improved mine reliability~~planned turnarounds at the base upgrader and ~~no major maintenance activities. Planned maintenance~~Muskeg River Mine and unplanned downtime at the expansion upgrader. 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 ~~fourth~~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 quarter 2016. Neither of ~~2015 is expected to impact production.~~the mines sustained any damage as a result of the wildfires. We hold a 20% non-operated working interest in the 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 ~~third~~second quarter and first ~~nine~~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 ~~third~~second quarter and first ~~nine~~six months of ~~2015~~2016 and ~~2014.~~2015.


	Three Months Ended September 30,			Nine Months Ended September 30,			Three Months Ended June 30,			Six Months Ended June 30,
	2015	2014	Decrease	2015	2014	Decrease	2016	2015	Decrease	2016		2015		Increase (Decrease)
Average Price Realizations ^(a)
Crude Oil and Condensate (per bbl) ^(b)	$41.37	$89.65	(54)%	$45.27	$92.59	(51)%	$40.77	$52.63	(23)%	$34.21		$47.11		(27	)%
Natural Gas Liquids (per bbl)	11.88	33.93	(65)%	13.67	36.96	(63)%	14.84	14.77	—%	11.43		14.60		(22	)%
Total Liquid Hydrocarbons (per bbl)	35.75	80.89	(56)%	39.55	83.89	(53)%	35.07	45.96	(24)%	29.32		41.37		(29	)%
Natural Gas (per mcf)	2.75	4.21	(35)%	2.84	4.81	(41)%	1.96	2.76	(29)%	1.99		2.88		(31	)%
Benchmarks
WTI crude oil (per bbl)	$46.50	$97.25	(52)%	$51.01	$99.62	(49)%	$45.64	$57.95	(21)%		$39.78		$53.34	(25	)%
LLS crude oil (per bbl)	50.22	101.03	(50)%	55.33	103.63	(47)%	47.35	62.94	(25)%	41.49		57.97		(28	)%
Mont Belvieu NGLs (per bbl)^(c)	15.86	32.69	(51)%	17.28	35.15	(51)%	17.52	17.65	(1)%	15.78		18.02		(12	)%
Henry Hub natural gas (per mmbtu)	2.77	4.06	(32)%	2.80	4.55	(38)%	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 ~~$1.87~~$0.12 per bbl and ~~$0.69~~$0.06 per bbl for the ~~third~~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 ~~nine~~six months of ~~2015. There were no crude oil derivative instruments in 2014.~~2016.


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

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 ~~third~~second quarter and first ~~nine~~six months of ~~2015~~2016 and ~~2014~~2015.


	Three Months Ended September 30,			Nine Months Ended September 30,			Three Months Ended June 30,			Six Months Ended June 30,
	2015	2014	Increase (Decrease)	2015	2014	Increase (Decrease)	2016	2015	Increase (Decrease)	2016		2015		Increase (Decrease)
Average Price Realizations
Crude Oil and Condensate (per bbl)	$46.18	$89.07	(48)%	$50.51	$95.71	(47)%	$42.21	$56.70	(26)%	$37.56		$52.92		(29	)%
Natural Gas Liquids (per bbl)	2.69	1.00	169%	3.08	2.83	9%	2.65	3.10	(15)%	2.45		3.29		(26	)%
Liquid Hydrocarbons (per bbl)	35.88	66.80	(46)%	39.21	72.88	(46)%	32.11	44.70	(28)%	28.11		41.06		(32	)%
Natural Gas (per mcf)	0.59	0.56	5%	0.71	0.73	(3)%	0.53	0.78	(32)%	0.56		0.78		(28	)%
Benchmark
Brent (Europe) crude oil (per bbl) ^(a)	$50.23	$101.82	(51%)	$55.28	$106.56	(48%)	$45.52	$61.69	(26%)		$39.61		$57.81	(31	)%


^(a)	Average of monthly prices obtained from EIA website.

Liquid hydrocarbons – Our 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.

Our NGL and natural gas sales in the International E&P segment originate primarily from our E.G. operations and are sold to our equity method investees under fixed-price, term contracts; therefore, our reported average realized prices for NGLs and natural gas will not fully track market price movements. The equity affiliates then utilize, process and sell the NGLs at market prices and natural gas at ~~market~~fixed prices under long-term contracts, with our share of their income/loss reflected in the ~~Income~~income from equity method investments line ~~item~~ on the ~~Consolidated Statements~~consolidated statements of ~~Income.~~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 WCS.

The following table presents our average price realizations and the related benchmarks for the ~~third~~second quarter and first ~~nine~~six months of ~~2015~~2016 and ~~2014~~2015.


	Three Months Ended September 30,			Nine Months Ended September 30,			Three Months Ended June 30,			Six Months Ended June 30,
	2015	2014	Decrease	2015	2014	Decrease	2016	2015	Decrease	2016		2015		Increase (Decrease)
Average Price Realizations
Synthetic Crude Oil (per bbl)	$39.49	$88.22	(55%)	$42.26	$90.11	(53%)	$40.88	$52.46	(22%)		$32.94		$44.33	(26	%)
Benchmarks
WTI crude oil (per bbl)	$46.50	$97.25	(52%)	$51.01	$99.62	(49%)	$45.64	$57.95	(21%)		$39.78		$53.34	(25	%)
WCS crude oil (per bbl)^(a)	33.16	76.99	(57%)	37.80	78.50	(52%)	32.29	46.35	(30%)	25.75		40.13		(36	%)


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

Results of Operations

Three Months Ended ~~September~~June 30, ~~2015~~2016 vs. Three Months Ended ~~September~~June 30, ~~2014~~2015

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


	Three Months Ended September 30,				Three Months Ended June 30,
(In millions)	2015		2014		2016			2015
Sales and other operating revenues, including related party
North America E&P	$	796	$	1,586	$	617		$	993
International E&P	182		273		159			211
Oil Sands Mining	242		457		185			147
Segment sales and other operating revenues, including related party	$	1,220	$	2,316	$	961		$	1,351
Unrealized gain on crude oil derivative instruments	80		—
Unrealized (loss) gain on commodity derivative instruments					(91		)	(44		)
Sales and other operating revenues, including related party	$	1,300	$	2,316	$	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		Three Months Ended		Increase (Decrease) Related to						Three Months Ended
(In millions)	September 30, 2014			Price Realizations			Net Sales Volumes		September 30, 2015		June 30, 2015		Price Realizations			Net Sales Volumes			June 30, 2016
North America E&P Price-Volume Analysis(a)
Liquid hydrocarbons	$	1,464		$	(850	)	$	60	$	674	$	893	$	(172	)	$	(170	)	$	551
Natural gas	123			(45		)	7		85		90		(22		)	(13		)	55
Realized gain on crude oil
Realized gain on commodity
derivative instruments	—			28					28		1		2						3
Other sales	(1		)						9		9								8
Total	$	1,586							$	796	$	993							$	617
International E&P Price-Volume Analysis
Liquid hydrocarbons	$	240		$	(130	)	$	42	$	152	$	172	$	(50	)	$	7		$	129
Natural gas	22			2			—		24		28		(10		)	4			22
Other sales	11								6		11								8
Total	$	273							$	182	$	211							$	159
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil	$	445		$	(294	)	$	85	$	236	$	137	$	(51	)	$	95		$	181
Other sales	12								6		10								4
Total	$	457							$	242	$	147							$	185


^(a)	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 ~~$470~~$94 million in the ~~third~~second quarter of ~~2015~~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 investments ~~decreased $53~~increased $11 million in the ~~third~~second quarter of ~~2015~~2016 from the comparable ~~2014~~2015 period. The ~~decrease~~increase is primarily due to an increase in net sales volumes as 2015 volumes were lower ~~price realizations for LPG~~because of planned turnaround and maintenance activities at ~~our~~the Alba ~~plant,~~field and E.G. LNG ~~at our LNG facility, and lower methanol prices at our AMPCO methanol facility, all~~facilities.

Net gain on disposal of ~~which are located~~ assets in ~~E.G. Also impacting~~ the second quarter of 2016 was ~~a partial impairment~~primarily related to the sale of our ~~investment in an equity method investee.~~Wyoming upstream and midstream assets and West Texas acreage. See Note 6 to the consolidated financial statements for information about dispositions.

Production expenses decreased ~~$187~~$100 million. North America E&P declined ~~$54~~$50 million primarily 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 ~~$47~~$8 million primarily ~~the~~as a result of ~~higher~~lower project and labor costs in ~~2014, such as~~ the ~~non-operated~~U.K. and 2015 also includes costs arising from planned flowline maintenance at the outside operated Foinaven ~~subsea power project. Also contributing~~field; these declines were ~~lower production~~partially offset by increased costs ~~in Libya during 2015 as the third quarter of 2014 had one lifting.~~resulting from higher net sales volumes. OSM

decreased ~~$86~~$42 million primarily due to lower turnaround costs andcontinued cost management, ~~especially~~specifically staffing and contract labor. ~~Also contributing to the OSM decrease was a more favorable exchange rate on expenses denominated in the Canadian Dollar and lower feedstock purchases given increased reliability.~~

The ~~third~~second quarter of ~~2015~~2016 production expense rate (expense per boe) for North America E&P declined ~~due to overall~~as cost reductions ~~as previously discussed, and leveraging efficiencies as~~occurred at a rate faster than our production ~~volumes increased.~~decline. The expense rate for International E&P declined due to an increase in volumes, combined with reduced maintenance and project costs ~~and lower operational costs~~ in ~~Libya.~~the U.K. The OSM expense rate decreased as a result of higher sales volumes and lower production ~~volume increased, coupled with the increased cost focus~~expenses, as discussed above.

The following table provides production expense rates for each segment:


	Three Months Ended September 30,		Three Months Ended June 30,
($ per boe)	2015	2014	2016		2015
Production Expense Rate
North America E&P	$7.43	$10.16		$6.28		$7.19
International E&P	$5.53	$10.48		$5.09		$6.51
Oil Sands Mining ^(a)	$26.01	$37.38		$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 ~~$470~~$94 million in the ~~third~~second quarter of ~~2015~~2016 from the comparable ~~2014~~2015 period, consistent with the marketing revenues changes discussed above.

Exploration expenses increased ~~$489 million. We made a strategic decision to reduce the overall level of our conventional exploration program;~~$78 million primarily as a result ~~we impaired certain~~ of our ~~leases in the~~decision to not drill any of our remaining Gulf of Mexico and the Harir block in the Kurdistan Region of Iraq. Further contributing to the increase was an impairment of unproved property in Colorado, which we deemed uneconomic given our forecasted natural gas prices.undeveloped leases. The following table summarizes the components of exploration expenses:


	Three Months Ended September 30,					Three Months Ended June 30,
(In millions)	2015			2014		2016		2015
Exploration Expenses
Unproved property impairments	$	563		$	39	$	133	$	40
Dry well costs	(3		)	25		22		41
Geological and geophysical	8			10		—		12
Other	17			22		34		18
Total exploration expenses	$	585		$	96	$	189	$	111

Depreciation, depletion and amortization ~~(“DD&A”)~~ decreased ~~$20~~$190 million primarily as a result of production volume decreases, a higher proved reserve base in Eagle Ford ~~the effects of which more than offset additional DD&A resulting from production volume increases~~ in the ~~International E&P~~second half of 2015 and ~~OSM segments.~~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 ~~field-level~~ changes in ~~sales volumes, proved~~ reserves, ~~and~~ 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.~~Ford in the second half of 2015. The DD&A rate for International E&P ~~rate increased primarily~~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 ~~sales volumes from~~proved reserve base in the ~~Brae infill drilling program.~~fourth quarter of 2015.


	Three Months Ended September 30,				Three Months Ended June 30,
($ per boe)	2015		2014		2016		2015
DD&A Rate
North America E&P		$22.84		$26.54		$21.16		$25.45
International E&P		$7.32		$5.30		$6.22		$7.17
Oil Sands Mining		$12.62		$12.75		$11.39		$12.87

Impairments ~~are discussed~~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 1413 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 ~~$69~~$39 million in the ~~third~~second quarter of ~~2015. This decrease was partially offset by an increase in sales volumes in North America E&P.~~2016. The following table summarizes the components of taxes other than income:


	Three Months Ended September 30,				Three Months Ended June 30,
(In millions)	2015		2014		2016		2015
Production and severance	$	28	$	69	$	25	$	40
Ad valorem	2		20		5		15
Other	16		26		9		23
Total	$	46	$	115	$	39	$	78

General and administrative expenses decreased ~~$35~~$36 million primarily due to ~~cost savings realized from the workforce reductions that occurred in the first quarter of 2015. Pension~~lower pension settlement charges in the ~~three months~~second quarter of ~~2015~~2016, which totaled ~~$18~~$31 million, compared to ~~$22~~$64 million in the prior year. ~~In addition, we incurred severance related expenses in the first three months of 2015~~

Net interest and other increased $28 million primarily due to increased interest expense associated with ~~workforce reductions~~our June 2015 debt issuance. See Note 16 to the consolidated financial statements for discussion of ~~$4 million.~~the June 2015 debt issuance.

Provision (benefit) for income taxes reflects an effective tax rate of ~~35%~~29% in the ~~third~~second quarter of ~~2015,~~2016, as compared to ~~33%~~2% in the ~~third~~second quarter of ~~2014. See Note 9 to the consolidated financial statements for discussion of the effective tax rate.~~

~~Discontinued operations~~ ~~presented in 2014 are net of tax. See Note 6 to the consolidated financial statements for financial information about discontinued operations.~~2015.

Segment Income (Loss)

Segment income (loss) represents income (loss) from ~~continuing~~ operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments, unrealized gains or losses on ~~crude oil~~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 September 30,						Three Months Ended June 30,
(In millions)	2015			2014			2016			2015
North America E&P	$	(61	)	$	292		$	(70	)	$	(45	)
International E&P	29			106			55			41
Oil Sands Mining	(11		)	93			(38		)	(77		)
Segment income (loss)	(43		)	491			(53		)	(81		)
Items not allocated to segments, net of income taxes	(706		)	(187		)	(117		)	(305		)
Income (loss) from continuing operations	(749		)	304
Discontinued operations ^(a)	—			127
Net income (loss)	$	(749	)	$	431		$	(170	)	$	(386	)


^(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 $353~~increased $25 million after-tax 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 ~~production and operating costs.~~exploration expenses.

International E&P segment income ~~decreased $77~~increased $14 million after-tax primarily due to ~~lower liquid hydrocarbon price realizations as well as reduced~~decreased exploration expenses and an increase in income from equity ~~investments. These declines~~investments, which were partially offset by ~~increased sales volumes and~~ lower ~~production and exploration expenses.~~price realizations.

Oil Sands Mining segment ~~income (loss)~~lossdecreased ~~$104~~$39 million after-tax primarily due to higher sales volumes and lower production expenses, partially offset by lower price realizations ~~partially offset by~~and higher ~~volumes and reduced production expenses.~~DD&A expense.

Results of Operations

~~Nine~~Six Months Ended ~~September~~June 30, ~~2015~~2016 vs. ~~Nine~~Six Months Ended ~~September~~June 30, ~~2014~~2015

Consolidated Results of Operation

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


	Nine Months Ended September 30,				Six Months Ended June 30,
(In millions)	2015		2014		2016			2015
Sales and other operating revenues, including related party
North America E&P	$	2,639	$	4,518	$	1,110		$	1,843
International E&P	575		1,000		255			393
Oil Sands Mining	614		1,217		333			372
Segment sales and other operating revenues, including related party	$	3,828	$	6,735	$	1,698		$	2,608
Unrealized gain on crude oil derivative instruments	59		—
Unrealized loss on commodity derivative instruments					(114		)	(21		)
Sales and other operating revenues, including related party	$	3,887	$	6,735	$	1,584		$	2,587

Nine Months Ended Increase (Decrease) Related to Nine Months Ended
(In millions) September 30, 2014 Price Realizations Net Sales Volumes September 30, 2015
North America E&P Price-Volume Analysis
Liquid hydrocarbons $ 4,112
$ (2,586 ) $ 781
$ 2,307
Natural gas 398
(190 ) 65
273
Realized gain on crude oil
derivative instruments —
33
33
Other sales 8
26
Total $ 4,518
$ 2,639
International E&P Price-Volume Analysis
Liquid hydrocarbons $ 873
$ (396 ) $ (15 ) $ 462
Natural gas 92
(2 ) (7 ) 83
Other sales 35
30
Total $ 1,000
$ 575
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil $ 1,195
$ (672 ) $ 69
$ 592
Other sales 22
22
Total $ 1,217
$ 614



	Six Months Ended		Increase (Decrease) Related to						Six 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	$	1,633	$	(394	)	$	(279	)	$	960
Natural gas	188		(51		)	(24		)	113
Realized gain on commodity
derivative instruments	5		19						24
Other sales	17								13
Total	$	1,843							$	1,110
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
Synthetic crude oil	$	355	$	(112	)	$	81		$	324
Other sales	17								9
Total	$	372							$	333

^(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 for the first six months of 2016 decreased ~~$1,242~~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. ~~Since~~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 ~~$248 million~~$11 million. The decrease is primarily due to lower net sales volumes as a result of planned downtime at E.G. as a result of the Alba field compression project which impacted our equity method plants, which was partially offset by planned turnaround and maintenance activities at the Alba field and E.G. LNG facilities in 2015. Also impacting the first six months of 2016 were lower price realizations for LPG at our Alba ~~Plant, LNG at our LNG facility and lower methanol prices at our AMPCO methanol facility, all~~plant.

Net gain on disposal of ~~which are located in E.G. Also contributing~~assets for the first six months of 2016 was primarily related to the ~~decrease in 2015 were lower sales volumes due~~sale of our Wyoming upstream and midstream assets and West Texas acreage. See Note 6 to the ~~planned turnaround and maintenance activities at the AMPCO methanol plant, the Alba field and the LNG facility.~~consolidated financial statements for information about dispositions.

Production expenses for the first ~~nine~~six months of ~~2015~~2016 decreased by ~~$397 million.~~$216 million compared to the same period of 2015. North America E&P declined ~~$101~~$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 ~~$115~~$22 million largely due to lower ~~project work, repair, maintenance and turnaround~~operational costs ~~as well as slightly lower production volumes.~~in the U.K. OSM ~~declined $181~~decreased $76 million primarily due to continued cost management, ~~especially~~specifically staffing and contract ~~labor. Also contributing to the OSM decrease are~~labor, lower ~~feedstock purchases given increased reliability~~turnaround costs, and a ~~more~~ favorable exchange rate on expenses denominated in the Canadian Dollar.

The ~~expense rates during the~~ first ~~nine~~six months of ~~2015 decreased~~2016 production expense rate (expense per boe) for ~~each of our segments as total production costs declined due to the reasons described in the preceding paragraph. The~~ North America E&P ~~and OSM segments also experienced volume increases, which further contributed~~declined primarily due to ~~the~~cost reductions that occurred at a rate faster than our production decline. The International E&P expense rate ~~decline.~~decreased in the first six months of 2016 primarily due to reduced maintenance and project costs in the U.K. The ~~following table provides~~OSM expense rate decreased in the first six months of 2016 primarily due to higher production ~~expense rates for each segment:~~coupled with lower operational costs.


	Nine Months Ended September 30,				Six Months Ended June 30,
($ per boe)	2015		2014		2016		2015
Production Expense Rate
North America E&P		$7.52		$10.52		$6.22		$7.57
International E&P		$6.13		$9.34		$5.53		$6.45
Oil Sands Mining ^(a)		$39.58		$44.73		$33.42		$50.06


^(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.~~income and insurance costs and excludes pre-development costs.

Marketing costs decreased ~~$1,239~~$241 million in the first ~~nine~~six months of ~~2015~~2016 from the comparable ~~2014~~2015 period, consistent with the marketing revenues changes discussed above.

Exploration expenses ~~increased~~were $12 million higher in the first six months of 2016 than in the comparable 2015 period primarily due to higher unproved property impairments, which were partially offset by~~$472 million~~ lower dry well costs. Unproved property impairments were higher in 2016 primarily as a result of ~~unproved property impairments recognized during the third quarter~~Gulf of 2015. See the preceding three month period discussion for further information on our unproved property impairments. Unproved property impairments in 2014 primarily were a result of Eagle Ford and BakkenMexico leases ~~that either expired or~~ that we decided not to ~~drill or extend.~~drill. Dry well costs for the first ~~nine~~six months of 2015 ~~include~~primarily consist of costs associated with the Sodalita West #1 well in E.G., the Key Largo well in the Gulf of Mexico, and suspended well costs related to Birchwood ~~in-situ that were expensed during the second quarter of 2015. Dry well costs for the first nine months of 2014 primarily consist of our exploration programs in Kurdistan, Ethiopia and Kenya.~~in-situ. The following table summarizes the components of exploration expenses:


	Nine Months Ended September 30,				Six Months Ended June 30,
(In millions)	2015		2014		2016		2015
Exploration Expenses
Unproved property impairments	$	612	$	140	$	144	$	49
Dry well costs	96		80		22		99
Geological and geophysical	23		27		—		15
Other	55		67		47		38
Total exploration expenses	$	786	$	314	$	213	$	201

Depreciation, depletion and amortization (“DD&A”) ~~increased $229~~decreased $402 million in the first six months of 2016 from the comparable 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.~~proved reserve base in Eagle Ford in the second half of 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 field-level changes in sales volumes, ~~proved~~ reserves and capitalized costs, can also cause changes to our DD&A. The following table provides DD&A rates for each segment. The DD&A rate for North America E&P decreased primarily as a result of a higher proved reserve base in Eagle Ford in the second half of 2015.


	Nine Months Ended September 30,				Six Months Ended June 30,
($ per boe)	2015		2014		2016		2015
DD&A Rate
North America E&P		$25.09		$26.65		$21.79		$26.16
International E&P		$6.87		$6.09		$5.98		$6.62
Oil Sands Mining		$12.60		$12.14		$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 1413 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 ~~$128~~$58 million in the first ~~nine~~six months of ~~2015. This decrease was partially offset by an increase in sales volumes in North America E&P.~~2016 from the comparable 2015 period. The following table summarizes the components of taxes other than income:


	Nine Months Ended September 30,				Six Months Ended June 30,
(In millions)	2015		2014		2016		2015
Production and severance	$	102	$	191	$	44	$	74
Ad valorem	33		58		19		31
Other	56		70		24		40
Total	$	191	$	319	$	87	$	145

General and administrative expensesdecreased ~~$22~~$56 million in the first six months of 2016 compared to the same period in 2015. This decrease was primarily due to cost savings realized from the 2015 workforce reductions ~~that occurred in the first quarter of 2015. This decrease was partially offset by $47 million of~~and corresponding severance ~~related~~ expenses. ~~The first nine months of 2015 include $99 million of pension settlement expense as compared to $93 million for the previous year.~~

Provision (benefit) for income taxes ~~reflects an~~reflect effective tax ~~rate~~rates of ~~28%~~37% in the first ~~nine~~six months of ~~2015,~~2016, as compared to ~~32% in~~18% from the comparable ~~2014~~2015 period. ~~The effective rate for 2015 reflects a $135 million non-cash deferred tax expense recorded in the second quarter of 2015 as a result of enacted corporate tax changes in Alberta, Canada.~~ See Note 9 to the consolidated financial statements for discussion of the effective tax rate.

~~Discontinued operations~~ ~~presented in 2014 are net of tax. See Note 6 to the consolidated financial statements for financial information about discontinued operations.~~

Segment Income (Loss)

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

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


	Nine Months Ended September 30,						Six Months Ended June 30,
(In millions)	2015			2014			2016			2015
North America E&P	$	(267	)	$	836		$	(265	)	$	(206	)
International E&P	93			487			59			64
Oil Sands Mining	(107		)	212			(86		)	(96		)
Segment income (loss)	(281		)	1,535			(292		)	(238		)
Items not allocated to segments, net of income taxes	(1,130		)	(473		)	(285		)	(424		)
Income (loss) from continuing operations	(1,411		)	1,062
Discontinued operations ^(a)	—			1,058
Net income (loss)	$	(1,411	)	$	2,120		$	(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 $1,103~~increased $59 million after-tax in the first ~~nine~~six months of 2016 from the comparable 2015 period primarily due to lower price ~~realizations; these were~~realizations and sales volumes, which was partially offset by ~~increased~~the impact of lower net sales volumes ~~from the U.S. resource plays~~to DD&A, production costs and taxes other than income; and lower ~~production costs.~~exploration expenses.

International E&P segment income decreased ~~$394~~$5 million after-tax in the first six months of 2016 from the comparable 2015 period primarily due to lower liquid hydrocarbon price ~~realizations and 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 ~~$319~~$10 million after-tax in the first six months of 2016 from the comparable 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 disclosed in our Form 10-K for the year ended December 31, ~~2014,~~2015, except as discussed below.

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

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

~~Unlike long-lived assets, goodwill~~Goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. ~~After we~~We performed our annual ~~goodwill~~ impairment test in April 2015, a triggering event (downward revision to forecasted commodity price assumptions) required us to reassess our goodwill for impairment as of September 30, 2015. Based on the results of this assessment, we2016 and concluded no impairment was required. ~~The~~While the fair value of ~~the North America E&P and~~our International E&P reporting ~~units~~unit exceeded ~~their respective~~ book ~~values by a significant margin. Changes in management's forecast~~value, subsequent commodity price ~~assumptions~~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.

~~Income Tax Estimates - Deferred Tax Assets~~Estimated Quantities of Net Reserves

~~In connection with our assessment~~Our December 31, 2015 proved reserves were calculated using the unweighted average of closing benchmark prices nearest to the ~~realizability~~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 ~~deferred tax assets, we consider whether it is more likely than not~~proved reserves. To the extent that ~~some~~commodity prices decrease during the remainder of 2016, a portion ~~or all~~ of our ~~deferred tax assets~~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 ~~not~~likely be ~~realized.~~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 ~~it is more likely than not that some portion~~the OSM proved reserves are reclassified to non-proved reserves or ~~all of our deferred taxes~~resource, their classification will not be realized, such assets are reduced by a valuation allowance. Future increases to our valuation allowance are possible if our estimates and assumptions (particularly as they relate to downward revisions of our long-term commodity price forecast) are revised such that they reduce estimates ofhave no impact on future ~~taxable income during the carryforward period.~~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~~equivalents:


	Nine Months Ended September 30,						Six Months Ended June 30,
(In millions)	2015			2014			2016			2015
Sources of cash and cash equivalents
Operating activities of continued operations	$	1,213		$	3,476
Operating activities of discontinued operations	—			856
Operating activities							$	252		$	717
Disposals of assets							758			2
Borrowings	1,996			—			—			1,996
Disposals of assets	105			2,237
Maturities of short-term investments	225			—
Common stock issuance							1,236			—
Other	97			196			39			43
Total sources of cash and cash equivalents	$	3,636		$	6,765		$	2,285		$	2,758
Uses of cash and cash equivalents
Cash additions to property, plant and equipment	$	(2,948	)	$	(3,639	)	$	(753	)	$	(2,320	)
Investing activities of discontinued operations	—			(356		)
Deposit for acquisition							(89		)	—
Purchases of short-term investments	(925		)	—			—			(925		)
Debt issuance costs	(19		)	—			—			(19		)
Debt repayments	(34		)	(34		)	—			(34		)
Dividends paid	(427		)	(401		)	(77		)	(285		)
Purchases of common stock	—			(1,000		)
Commercial paper, net	—			(135		)
Other	(1		)	(48		)	(3		)	(1		)
Cash held for sale	—			(655		)
Total uses of cash and cash equivalents	$	(4,354	)	$	(6,268	)	$	(922	)	$	(3,584	)

~~Commodity prices began declining~~Cash flows generated from operating activities in the ~~second half~~first six months of ~~2014 and remain substantially~~2016 were lower ~~through 2015.~~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 and OSM segments. While we are unable to predict future commodity price movements, if this lower price environment~~ continues ~~it would continue~~ to negatively impact our cash flows from operating ~~activities~~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. Disposal of assets in 2015 pertain to the August 2015 sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets. Disposals of assets in 2014 primarily reflect the net proceeds from the sales of our Angola assets. Disposition transactions are discussed in further detail in Note 6 to the consolidated financial statements.

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

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

Additions to property, plant and equipment are our most significant use of cash and cash ~~equivalents.~~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):


	Nine Months Ended September 30,					Six Months Ended June 30,
(In millions)	2015		2014			2016		2015
North America E&P	$	2,048	$	3,246		$	468	$	1,484
International E&P	275		386			44		245
Oil Sands Mining	26		172			16		37
Corporate	26		29			8		14
Total capital expenditures	2,375		3,833			536		1,780
(Increase) decrease in capital expenditure accrual	573		(194		)
Decrease in capital expenditure accrual						217		540
Total use of cash and cash equivalents for property, plant and equipment	$	2,948	$	3,639		$	753	$	2,320

~~During~~The Board of Directors approved a $0.05 per share dividend for the first ~~nine months~~quarter of ~~2014, we acquired 29 million common shares at a cost~~2016, which was paid in the second quarter of ~~$1 billion under our share repurchase program. There were no stock repurchases during 2015.~~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 used 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 on November 2, 2015,~~balance sheet and ~~the remainder~~ 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 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.$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.

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.

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 U.K. operations to be 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 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 other negotiations.

Capital Resources

Credit Arrangements and Borrowings

At ~~September~~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 ~~September~~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 matured and was repaid~~$682 million due in ~~November 2015. We utilized cash on hand and proceeds from~~ the ~~maturities~~fourth quarter of ~~our short-term investments to fund the debt payment.~~ 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.

Asset Disposals

~~We are targeting to generate at least $500 million from select non-core asset sales.~~ During the ~~third~~ quarter, ~~of 2015,~~ we ~~closed the sale of our East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets for proceeds of approximately $100 million and~~ announced the sale of our ~~Kenya~~Wyoming upstream and ~~Ethiopia exploration acreage. See Note 6~~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 ~~consolidated financial statements~~receipt of certain tribal consents and are expected to close before year end. The proceeds for ~~additional discussion~~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 ~~these dispositions.~~ 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 and Short-Term Investments-Adjusted~~

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 ~~24%~~20% at ~~September~~June 30, ~~2015,~~2016, compared to ~~16%~~25% at December 31, ~~2014.~~2015.


	September 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	7,323			5,323			7,280			7,276
Total debt	$	8,358		$	6,391		$	7,281		$	7,277
Cash and cash equivalents	$	1,680		$	2,398		$	2,584		$	1,221
Short-term investments	$	700		$	—
Equity	$	19,335		$	21,020		$	19,153		$	18,553
Calculation:
Total debt	$	8,358		$	6,391		$	7,281		$	7,277
Minus cash and cash equivalents	1,680			2,398			2,584			1,221
Minus short-term investments	700			—
Total debt minus cash, cash equivalents and short-term investments	$	5,978		$	3,993
Total debt minus cash, cash equivalents							$	4,697		$	6,056
Total debt	$	8,358		$	6,391		$	7,281		$	7,277
Plus equity	19,335			21,020			19,153			18,553
Minus cash and cash equivalents	1,680			2,398			2,584			1,221
Minus short-term investments	700			—
Total debt plus equity minus cash, cash equivalents and short-term investments	$	25,313		$	25,013
Cash and short-term investments-adjusted debt-to-capital ratio	24		%	16		%
Total debt plus equity minus cash, cash equivalents							$	23,850		$	24,609
Cash-adjusted debt-to-capital ratio							20		%	25		%

Capital Requirements

We closed on our purchase agreement of PayRock for $888 million, as discussed in Note 5 to the consolidated financial statements. We expect our ~~revised total capital, investment and exploration spending budget~~Capital Program for full-year ~~2015~~2016 to be ~~$3.1~~$1.3 billion, or $100 million lower than the original budget, which ~~is $200 million less than our previous budget.~~includes the increased activity from the PayRock acquisition.

On ~~October 28, 2015,~~July 27, 2016, our Board of Directors approved a dividend of $0.05 per share for the ~~third~~second quarter of ~~2015~~2016 payable ~~December 10, 2015~~September 12, 2016 to stockholders of record at the close of business on November 18, 2015. This dividend represents a reduction from the previous quarterly dividend of $0.21 per share as we continue to address the uncertainty of a lower for longer commodity price environment, align with our priority of maintaining a strong balance sheet through the cycle, and provide additional capital flexibility to support growth from the U.S. resource plays when commodity prices improve.August 17, 2016.

As of ~~September~~June 30, ~~2015,~~2016, we plan to make contributions of up to ~~$18~~$34 million to our funded pension plans during the remainder of ~~2015.~~2016.

Contractual Cash Obligations

As of ~~September~~June 30, ~~2015,~~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~~ 18.$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:~~regarding our ~~operational, financial and growth strategies, including planned projects,~~future performance, business strategy, reserve estimates, asset quality, production guidance, drilling plans, ~~maintenance activities, asset~~capital plans, cost and expense estimates, assets acquisitions and sales, productivity improvements, and drilling and completion efficiencies; our ability to effect those strategies and the expected timing and results thereof; our financial and operational outlook and ability to fulfill that outlook; expectations regarding future economic and market conditions and their effects on our business; our 2015 and 2016 capital, investment and exploration programs, including planned allocation and reductions, and the expected benefits thereof; our declared dividend and the expected benefits thereof; our financial position, ~~liquidity~~ and ~~capital resources; production guidance; 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 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 or~~ 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 15 and 16 to the consolidated financial statements.~~measured.

Commodity Price Risk During the first ~~nine~~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 ~~September~~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	October- December 2015	$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	$60.00	2,000	October 2015- March 2016 ^(a)	$50.00
Floor	$50.00			$41.55
Sold put	$40.00

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

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


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

^(b)(a)

~~Counterparty~~On our 2016 collars, the counterparty has the option ~~exercisable on June 30, 2016,~~ to ~~extend these collars through the remainder of 2016~~execute fixed-price swaps (swaptions) at ~~the same volume and~~a weighted average price asof $2.93 per MMBtu indexed to NYMEX Henry Hub, which is exercisable on December 22, 2016. If counterparty exercises, the ~~underlying three-way collars.~~term of the fixed-price swaps would be for the calendar year 2017 and, if all such options are exercised, 20,000 MMBtu per day.


^(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 ~~September~~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	$	(46	)	$	6

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 ~~September~~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	$	(8,302	)	^(a)(b)	$	(295	)	$	(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 ~~September~~June 30, ~~2015.~~2016.

During the ~~third~~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.

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



	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)	~~55,320~~245,651 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

~~Item 5. Other Information~~

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

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

Item 6. Exhibits

The information required by this Item 6 is set forth in the Exhibit Index accompanying this 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.



~~November 5, 2015~~August 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 September 1, 2015) 8-K 3.1 8/28/2015
3.3 Specimen of Common Stock Certificate 10-K 3.3 2/28/2014
4.1 Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the SEC upon its request 10-K 4.1 2/28/2014
12.1 Computation of Ratio of Earnings to Fixed Charges*
31.1 Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934*
31.2 Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934*
32.1 Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350*
32.2 Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350*
101.INS XBRL Instance Document*
101.SCH XBRL Taxonomy Extension Schema*
101.CAL XBRL Taxonomy Extension Calculation Linkbase*
101.DEF XBRL Taxonomy Extension Definition Linkbase*
101.LAB XBRL Taxonomy Extension Label Linkbase*
101.PRE XBRL Taxonomy Extension Presentation Linkbase*
* Filed herewith.
++ Marathon Oil agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request.



		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	2219
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3937
Item 4.	Controls and Procedures	4038
Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	4139
Item 1A.	Risk Factors	4139
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
~~Item 5.~~	~~Other Information~~	4139
Item 6.	Exhibits	4139
	Signatures	4240



	Three Months Ended September 30, 2014
								Not Allocated
(In millions)	N.A. E&P			Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	1,586		$	273	$	457	$	—			$	2,316
Marketing revenues	506			46		2		—				554
Total revenues	2,092			319		459		—				2,870
Income from equity method investments	—			89		—		—				89
Net gain (loss) on disposal of assets and other income	(1		)	12		—		1				12
Less:
Production expenses	233			108		252		—				593
Marketing costs	507			45		2		—				554
Exploration expenses	55			41		—		—				96
Depreciation, depletion and amortization	609			55		62		11				737
Impairments	—			—		—		109			^(c)	109
Other expenses ^(a)	118			26		14		101			^(d)	259
Taxes other than income	109			—		5		1				115
Net interest and other	—			—		—		55				55
Income tax provision (benefit)	168			39		31		(89		)		149
Segment income/Income from continuing operations	$	292		$	106	$	93	$	(187	)		$	304
Capital expenditures ^(b)	$	1,277		$	166	$	49	$	16			$	1,508