UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended ~~June 30, 2015~~March 31, 2016



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

Commission file number 1-5153

Marathon Oil Corporation

(Exact name of registrant as specified in its charter)



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

5555 San Felipe Street, Houston, TX 77056-2723

(Address of principal executive offices)

(713) 629-6600

(Registrant’s telephone number, including area code)

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

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

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



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

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

Yes o No þ

There were ~~677,184,913~~847,648,273 shares of Marathon Oil Corporation common stock outstanding as of ~~July 31, 2015.~~April 29, 2016.

MARATHON OIL CORPORATION

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

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

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)


	Three Months Ended						Six Months Ended						Three Months Ended
	June 30,						June 30,						March 31,
(In millions, except per share data)	2015			2014			2015			2014			2016			2015
Revenues and other income:
Sales and other operating revenues, including related party	$	1,307		$	2,270		$	2,587		$	4,419		$	714		$	1,280
Marketing revenues	183			618			387			1,159			58			204
Income from equity method investments	26			120			62			257			14			36
Net gain (loss) on disposal of assets	—			(87		)	1			(85		)	(60		)	1
Other income	15			20			26			40			4			11
Total revenues and other income	1,531			2,941			3,063			5,790			730			1,532
Costs and expenses:
Production	450			562			894			1,104			328			444
Marketing, including purchases from related parties	182			614			387			1,156			58			205
Other operating	81			101			188			204			109			107
Exploration	111			145			201			218			24			90
Depreciation, depletion and amortization	751			680			1,572			1,323			609			821
Impairments	44			4			44			21			1			—
Taxes other than income	78			109			145			204			48			67
General and administrative	168			139			339			326			151			171
Total costs and expenses	1,865			2,354			3,770			4,556			1,328			1,905
Income (loss) from operations	(334		)	587			(707		)	1,234			(598		)	(373		)
Net interest and other	(58		)	(76		)	(105		)	(125		)	(85		)	(47		)
Income (loss) from continuing operations before income taxes	(392		)	511			(812		)	1,109
Income (loss) before income taxes													(683		)	(420		)
Provision (benefit) for income taxes	(6		)	151			(150		)	351			(276		)	(144		)
Income (loss) from continuing operations	(386		)	360			(662		)	758
Discontinued operations	—			180			—			931
Net income (loss)	$	(386	)	$	540		$	(662	)	$	1,689		$	(407	)	$	(276	)
Per basic share:
Income (loss) from continuing operations	$	(0.57	)	$	0.53		$	(0.98	)	$	1.11
Discontinued operations	$	—		$	0.27		$	—		$	1.36
Net income (loss)	$	(0.57	)	$	0.80		$	(0.98	)	$	2.47
Per diluted share:
Income (loss) from continuing operations	$	(0.57	)	$	0.53		$	(0.98	)	$	1.10
Discontinued operations	$	—		$	0.27		$	—		$	1.36
Net income (loss)	$	(0.57	)	$	0.80		$	(0.98	)	$	2.46
Net income (loss) per share:
Basic													$	(0.56	)	$	(0.41	)
Diluted													$	(0.56	)	$	(0.41	)
Dividends per share	$	0.21		$	0.19		$	0.42		$	0.38		$	0.05		$	0.21
Weighted average common shares outstanding:
Basic	677			676			676			684			730			675
Diluted	677			679			676			688			730			675

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

MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income (Unaudited)


	Three Months Ended						Six Months Ended						Three Months Ended
	June 30,						June 30,						March 31,
(In millions)	2015			2014			2015			2014			2016			2015
Net income (loss)	$	(386	)	$	540		$	(662	)	$	1,689		$	(407	)	$	(276	)
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	86			(13		)	162			(43		)	(24		)	76
Income tax benefit (provision)	(30		)	5			(57		)	15
Income tax provision (benefit)													9			(27		)
Postretirement and postemployment plans, net of tax	56			(8		)	105			(28		)	(15		)	49
Comprehensive income (loss)	$	(330	)	$	532		$	(557	)	$	1,661		$	(422	)	$	(227	)

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)


	June 30,			December 31,			March 31,			December 31,
(In millions, except per share data)	2015			2014			2016			2015
Assets
Current assets:
Cash and cash equivalents	$	1,572		$	2,398		$	2,072		$	1,221
Short-term investments	925			—
Receivables, less reserve of $4 and $3	1,195			1,729
Receivables, less reserve of $4 and $4							779			912
Inventories	336			357			306			313
Other current assets	102			109			111			144
Total current assets	4,130			4,593			3,268			2,590
Equity method investments	1,045			1,113			959			1,003
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $23,395 and $21,884	29,121			29,040
depletion and amortization of $22,763 and $23,260							26,737			27,061
Goodwill	459			459			115			115
Other noncurrent assets	1,015			806			1,789			1,542
Total assets	$	35,770		$	36,011		$	32,868		$	32,311
Liabilities
Current liabilities:
Accounts payable	$	1,507		$	2,545		$	1,084		$	1,313
Payroll and benefits payable	119			191			79			133
Accrued taxes	156			285			151			132
Other current liabilities	235			290			211			150
Long-term debt due within one year	1,035			1,068			1			1
Total current liabilities	3,052			4,379			1,526			1,729
Long-term debt	7,321			5,323			7,280			7,276
Deferred tax liabilities	2,531			2,486			2,368			2,441
Defined benefit postretirement plan obligations	438			598			446			403
Asset retirement obligations	1,963			1,917			1,614			1,601
Deferred credits and other liabilities	247			288			283			308
Total liabilities	15,552			14,991			13,517			13,758
Commitments and contingencies
Stockholders’ Equity
Preferred stock – no shares issued or outstanding (no par value,
26 million shares authorized)	—			—			—			—
Common stock:
Issued – 770 million shares (par value $1 per share,
Issued – 937 million shares and 770 million shares (par value $1 per share,
1.1 billion shares authorized)	770			770			937			770
Securities exchangeable into common stock – no shares issued or
outstanding (no par value, 29 million shares authorized)	—			—			—			—
Held in treasury, at cost – 93 million and 95 million shares	(3,555		)	(3,642		)
Held in treasury, at cost – 89 million and 93 million shares							(3,397		)	(3,554		)
Additional paid-in capital	6,484			6,531			7,428			6,498
Retained earnings	16,691			17,638			14,533			14,974
Accumulated other comprehensive loss	(172		)	(277		)	(150		)	(135		)
Total stockholders' equity	20,218			21,020			19,351			18,553
Total liabilities and stockholders' equity	$	35,770		$	36,011		$	32,868		$	32,311

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)


	Six Months Ended						Three Months Ended
	June 30,						March 31,
(In millions)	2015			2014			2016			2015
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income (loss)	$	(662	)	$	1,689		$	(407	)	$	(276	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations	—			(931		)
Deferred income taxes	(185		)	173			(320		)	(179		)
Depreciation, depletion and amortization	1,572			1,323			609			821
Impairments	44			21			1			—
Pension and other postretirement benefits, net	14			26			14			(7		)
Exploratory dry well costs and unproved property impairments	148			156			11			67
Net (gain) loss on disposal of assets	(1		)	85			60			(1		)
Equity method investments, net	37			(10		)	30			3
Changes in:
Current receivables	534			(266		)	133			388
Inventories	21			(58		)	7			(22		)
Current accounts payable and accrued liabilities	(770		)	(31		)	(121		)	(469		)
All other operating, net	(35		)	(59		)	57			(16		)
Net cash provided by continuing operations	717			2,118
Net cash provided by discontinued operations	—			440
Net cash provided by operating activities	717			2,558			74			309
Investing activities:
Additions to property, plant and equipment	(2,320		)	(2,230		)	(454		)	(1,452		)
Disposal of assets	2			2,232			17			2
Investments - return of capital	31			27			14			10
Purchases of short-term investments	(925		)	—
Investing activities of discontinued operations	—			(233		)
All other investing, net	(1		)	—			2			(2		)
Net cash used in investing activities	(3,213		)	(204		)	(421		)	(1,442		)
Financing activities:
Commercial paper, net	—			(135		)
Borrowings	1,996			—
Debt issuance costs	(19		)	—
Debt repayments	(34		)	(34		)
Purchases of common stock	—			(1,000		)
Common stock issuance							1,232			—
Dividends paid	(285		)	(260		)	(34		)	(142		)
All other financing, net	11			86			—			4
Net cash provided by (used in) financing activities	1,669			(1,343		)	1,198			(138		)
Effect of exchange rate on cash and cash equivalents:
Continuing operations	1			—
Discontinued operations	—			(10		)
Cash held for sale	—			(96		)
Effect of exchange rate on cash and cash equivalents							—			(1		)
Net increase (decrease) in cash and cash equivalents	(826		)	905			851			(1,272		)
Cash and cash equivalents at beginning of period	2,398			264			1,221			2,398
Cash and cash equivalents at end of period	$	1,572		$	1,169		$	2,072		$	1,126

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

1. Basis of Presentation

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

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

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

2. Accounting Standards

Not Yet Adopted

In ~~May 2015,~~March 2016, the FASB issued ana new accounting standards update that ~~removes the~~changes several aspects of accounting for share-based payment transactions, including a requirement to ~~categorize within~~recognize all excess tax benefits and tax deficiencies as income tax expense or benefit in the ~~fair value hierarchy all investments for which fair value is measured using~~income statement, classification of awards as either equity or liabilities, and classification on 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.statement of cash flows. This standard is effective for us in the first quarter of ~~2016~~2017 and ~~will~~varying transition methods (modified retrospective, retrospective or prospective) should be applied ~~on a retrospective basis.~~to different provisions of the standard. Early adoption is permitted. ~~This standard only modifies disclosure requirements; as such, there will be no~~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 ~~April 2015,~~February 2016, the FASB issued ~~an update that~~a new lease accounting standard, which requires ~~debt issuance costs~~lessees to ~~be presented in~~recognize most leases, including operating leases, on the balance sheet as a ~~direct reduction from the associated debt~~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 ~~2016~~2019 and ~~will~~should be applied onusing a modified retrospective ~~basis.~~approach at the beginning of the earliest period presented in the financial statements. Early adoption is ~~permitted, including~~permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it may 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 ~~interim periods.~~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 ~~February~~July 2015, the FASB issued an ~~amendment to the guidance for determining whether~~update that requires an entity ~~is a variable interest entity ("VIE"). The standard does not add~~to measure inventory at the lower of cost and net realizable value. This excludes inventory measured using LIFO or ~~remove any of~~ the five characteristics that determine if an entity is a VIE. However, it does change the manner in which a reporting entity assesses one of the characteristics. In particular, when decision-making over the entity’s most significant activities has been outsourced, the standard changes how a reporting entity assesses if the equity holders at risk lack decision making rights.retail inventory method. This standard is effective for us in the first quarter of ~~2016~~2017 and ~~early~~will be applied prospectively. Early adoption is ~~permitted, including in interim periods.~~permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

In August 2014, the FASB issued an update that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in ~~United States ("~~U.S.") auditing standards. This standard is effective for us infor the ~~first quarter of 2017~~annual period ending after December 15, 2016 and ~~early~~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.

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.~~permitted. 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.

Recently Adopted

6In 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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~Recently Adopted~~

~~In April 2014,~~removes certain disclosure requirements regarding all investments that are eligible to be measured using the ~~FASB issued~~net asset value per share practical expedient and only requires certain disclosures on those investments for which an ~~amendment~~entity elects to ~~accounting standards that changes~~use 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 werenet asset value per share expedient. This standard is effective for us in the first quarter of ~~2015~~2016 and ~~apply to dispositions or classifications~~was applied on a retrospective basis. This standard only modifies disclosure requirements; as ~~held for sale thereafter. Adoption of this standard did not~~such, there was no 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 whether an entity is a VIE. However, it does change the manner in which a reporting entity assesses one of the characteristics. In particular, when decision-making over the entity’s most significant activities has been outsourced, the standard changes how a reporting entity assesses if the equity holders at risk lack decision making rights. This standard is effective for us in the first quarter of 2016. The adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

3. Variable Interest Entity

The owners of the Athabasca Oil Sands Project, ~~("AOSP"),~~ in which we hold a 20% undivided interest, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton, Alberta, Canada. Costs under this contract are accrued and recorded on a monthly basis, with current liabilities of $2 million recorded at ~~June 30, 2015~~March 31, 2016 and ~~$3 million at~~ December 31, ~~2014.~~2015. This contract qualifies as a variable interest contractual arrangement, and the Corridor Pipeline qualifies as a VIE. We hold a variable interest but are not the primary beneficiary because our shipments are only 20% of the total; therefore, the Corridor Pipeline is not consolidated by us. Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was ~~$508~~$472 million as of ~~June 30, 2015.~~March 31, 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.


4.	Income (Loss) per Common Share

Basic income (loss) per share is based on the weighted average number of common shares outstanding. Diluted income ~~(loss)~~ per share assumes exercise of stock options, provided the effect is not antidilutive. The per share calculations below exclude 13 million ~~and 5 million stock options for the second quarters of 2015 and 2014 and 13 million and 4 million~~ stock options for the first ~~six~~three months of ~~2015~~2016 and ~~2014~~2015 that were antidilutive.



	Three Months Ended March 31,
(In millions, except per share data)	2016			2015
Net income (loss)	$	(407	)	$	(276	)

Weighted average common shares outstanding	730			675
Weighted average common shares, diluted	730			675
Net income (loss) per share:
Basic	$	(0.56	)	$	(0.41	)
Diluted	$	(0.56	)	$	(0.41	)


5.	Dispositions

North America E&P Segment

In April 2016, we entered into agreements to sell our Wyoming upstream and midstream assets for proceeds of $870 million, before closing adjustments. The upstream properties are comprised mainly of waterflood developments in the Big Horn and Wind River basins. The midstream assets include the 570-mile Red Butte pipeline. We expect the transaction to close mid-year 2016.

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, before closing adjustments. The transactions are expected to close mid-year 2016.

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

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


5.	~~Dispositions~~

~~2015 - North America E&P Segment~~

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

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

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

~~2014 - International E&P Segment~~

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

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

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

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

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

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

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

6. Segment Information

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

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

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

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

~~MARATHON OIL CORPORATION~~

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

Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”). Segment income represents income ~~from continuing operations excluding~~which excludes certain items not allocated to segments, net of income taxes, attributable to the operating segments. ~~Our~~A portion of our corporate and operations support general and administrative costs are not allocated to the operating segments. These unallocated costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Gains 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, or other items that affect comparability (as determined by the CODM) also are not allocated to operating segments.

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



	Three Months Ended March 31, 2016
										Not Allocated
(In millions)	N.A. E&P			Int'l E&P			OSM			to Segments				Total
Sales and other operating revenues	$	493		$	96		$	148		$	(23	)	^(c)	$	714
Marketing revenues	31			15			12			—				58
Total revenues	524			111			160			(23		)		772
Income from equity method investments	—			14			—			—				14
Net gain (loss) on disposal of assets and other income	1			6			—			(63		)	^(d)	(56		)
Less:
Production expenses	134			53			141			—				328
Marketing costs	32			14			12			—				58
Exploration expenses	18			6			—			—				24
Depreciation, depletion and amortization	487			50			60			12				609
Impairments	1			—			—			—				1
Other expenses ^(a)	118			16			7			119			^(e)	260
Taxes other than income	42			—			5			1				48
Net interest and other	—			—			—			85				85
Income tax benefit	(112		)	(12		)	(17		)	(135		)		(276		)
Segment income (loss) / Net income (loss)	$	(195	)	$	4		$	(48	)	$	(168	)		$	(407	)
Capital expenditures ^(b)	$	315		$	32		$	9		$	3			$	359


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

(b)Includes accruals.


^(c)	Unrealized loss on commodity derivative instruments.


^(d)	Related to the net loss on disposal of assets (see Note 5).


^(e)	Includes pension settlement loss of $48 million and severance related expenses associated with workforce reductions of $7 million (see Note 7).

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


	Three Months Ended June 30, 2015															Three Months Ended March 31, 2015
									Not Allocated																Not Allocated
(In millions)	N.A. E&P			Int'l E&P		OSM			to Segments				Total			N.A. E&P			Int'l E&P			OSM			to Segments				Total
Sales and other operating revenues	$	993		$	211	$	147		$	(44	)	^(c)	$	1,307		$	850		$	182		$	225		$	23		^(c)	$	1,280
Marketing revenues	110			30		43			—				183			178			26			—			—				204
Total revenues	1,103			241		190			(44		)		1,490			1,028			208			225			23				1,484
Income from equity method investments	—			26		—			—				26			—			36			—			—				36
Net gain on disposal of assets and other income	11			4		—			—				15			—			10			1			1				12
Less:
Production expenses	179			64		207			—				450			202			67			175			—				444
Marketing costs	112			29		41			—				182			180			25			—			—				205
Exploration expenses	91			20		—			—				111			35			55			—			—				90
Depreciation, depletion and amortization	634			71		35			11				751			683			64			62			12				821
Impairments	—			—		—			44			^(d)	44
Other expenses ^(a)	99			19		9			122			^(e)	249			117			23			9			129			^(d)	278
Taxes other than income	67			—		5			6				78			61			—			5			1				67
Net interest and other	—			—		—			58				58			—			—			—			47				47
Income tax provision (benefit)	(23		)	27		(30		)	20			^(f)	(6		)
Segment income (loss) /Loss from continuing operations	$	(45	)	$	41	$	(77	)	$	(305	)		$	(386	)
Income tax benefit																(89		)	(3		)	(6		)	(46		)		(144		)
Segment income (loss) / Net income (loss)																$	(161	)	$	23		$	(19	)	$	(119	)		$	(276	)
Capital expenditures ^(b)	$	551		$	99	$	16		$	12			$	678		$	933		$	146		$	21		$	2			$	1,102


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


^(b)	Includes accruals.


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


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


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


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

~~MARATHON OIL CORPORATION~~

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

Three Months Ended June 30, 2014
Not Allocated
(In millions) N.A. E&P Int'l E&P OSM to Segments Total
Sales and other operating revenues $ 1,540
$ 347
$ 383
$ —
$ 2,270
Marketing revenues 540
61
17
—
618
Total revenues 2,080
408
400
—
2,888
Income from equity method investments —
120
—
—
120
Net gain (loss) on disposal of assets and other income 15
15
1
(98 )
^(c)
(67 )
Less:
Production expenses 217
99
246
—
562
Marketing costs 537
60
17
—
614
Exploration expenses 82
63
—
—
145
Depreciation, depletion and amortization 550
75
45
10
680
Impairments 4
—
—
—
4
Other expenses ^(a)
126
34
13
67
^(d)
240
Taxes other than income 102
—
6
1
109
Net interest and other —
—
—
76
76
Income tax provision (benefit) 175
52
19
(95 ) 151
Segment income/Income from continuing operations $ 302
$ 160
$ 55
$ (157 ) $ 360
Capital expenditures ^(b)
$ 1,102
$ 115
$ 55
$ 10
$ 1,282


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


^(b)	~~Includes accruals.~~


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


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

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


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


^(b)	~~Includes accruals.~~


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


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


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


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

~~MARATHON OIL CORPORATION~~

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

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


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


^(b)	~~Includes accruals.~~


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


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

7. Defined Benefit Postretirement Plans

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



	Three Months Ended March 31,
	Pension Benefits						Other Benefits
(In millions)	2016			2015			2016			2015
Service cost	$	6		$	12		$	1		$	1
Interest cost	11			14			3			3
Expected return on plan assets	(15		)	(19		)	—			—
Amortization:
– prior service cost (credit)	(2		)	1			(1		)	(1		)
– actuarial loss	3			7			—			—
Net settlement loss^(a)	48			17			—			—
Net curtailment loss (gain)^(b)	—			1			—			(6		)
Net periodic benefit cost	$	51		$	33		$	3		$	(3	)

Three Months Ended June 30,

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

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

~~MARATHON OIL CORPORATION~~

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

Six Months Ended June 30,
Pension Benefits Other Benefits
(In millions) 2015 2014 2015 2014
Service cost 24
23
2
2
Interest cost 27
31
5
6
Expected return on plan assets (36 ) (32 ) —
—
Amortization:

– prior service cost (credit) (1 ) 3
(2 ) (2 )
– actuarial loss 14
16
—
—
Net settlement loss^(a)
81
71
—
—
Net curtailment loss (gain)^(b)
1
—
(4 ) —
Net periodic benefit cost $ 110

$ 112

$ 1

$ 6


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


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

During the first ~~six~~three months of ~~2015,~~2016, we recorded the effects of a workforce reduction and a pension plan amendment. The pension plan amendment freezes the final average pay used to calculate the formula benefit and is effective July 6, 2015. Additionally, during the first six months of 2015 and 2014, we recorded the effects of partial settlements of our U.S. pension plans. As required, we remeasured the plans' assets and liabilities as of the applicable balance sheet dates. The cumulative effects of these events are included in the remeasurement and reflected in both the pension liability and net periodic benefit ~~cost (credit).~~cost.

During the first ~~six~~three months of ~~2015,~~2016, we made contributions of ~~$46~~$14 million to our funded pension plans. We expect to make additional contributions up to an estimated ~~$42~~$48 million to our funded pension plans over the remainder of ~~2015.~~2016. During the first ~~six~~three months of ~~2015,~~2016, we made payments of ~~$42~~$19 million and $8$5 million related to unfunded pension plans and other postretirement benefit plans, respectively.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

8. Income Taxes

Effective Tax Rate

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

Our effective income tax rates ~~on continuing operations~~ for the first ~~six~~three months of 2016 and 2015 ~~and 2014~~ were 18% and 32%. The tax provision (benefit) applicable to Libyan ordinary income (loss) was recorded as a discrete item in the first six months of 2015 and 2014. Excluding Libya, the effective tax rates on continuing operations, would be 15%40% and 34% ~~for the first six months of 2015 and 2014.~~. In Libya, 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 recorded as a discrete item in the first ~~six~~three months of ~~2015~~2016 and ~~2014,~~2015. For the first three months of 2016 and 2015, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss). Excluding Libya, the effective tax rates, would be 39% and 31% for the first three months of 2016 and 2015. The change was driven by a shift in jurisdictional income.

~~On June 29, 2015,~~Deferred Tax Assets

In connection with our assessment of the ~~Alberta government enacted legislation to increase the provincial corporate tax rate from 10% to 12%. As a result~~realizability of ~~this legislation, we recorded additional non-cash~~our deferred tax ~~expense~~assets, we consider whether it is more likely than not that some portion or all of ~~$135 million in the second quarter of 2015.~~

our deferred tax assets will not be realized. In the ~~second quarter~~event it is more likely than not that some portion or all of ~~2015, we reviewed~~ our operations and concluded that we do not have the same level of capital needs outside the U.S. as previously expected. Therefore, we no longer intend for previously unremitted foreign earnings of approximately $1 billion associated with our Canadian operations to be permanently reinvested outside the U.S. As such, none of Marathon Oil’s foreign earnings remain permanently reinvested abroad. We anticipate foreign tax credits associated with these Canadian earnings would be sufficient to offset any incremental U.S. tax liabilities, and therefore, no additional net deferred taxes ~~have been recorded in the second quarter of 2015.~~

~~MARATHON OIL CORPORATION~~

~~Notes~~will not be realized, such assets are reduced by a valuation allowance. Future increases to ~~Consolidated Financial Statements (Unaudited)~~

~~9. Short-term Investments~~

~~As of June 30, 2015,~~ our ~~short-term investments~~valuation allowance are ~~comprised of bank time deposits with original maturities of greater than three months~~possible if our estimates and ~~remaining maturities of less than twelve months. The maturity dates range from September 2015~~assumptions (particularly as they relate to ~~October 2015. These short-term investments are classified as held-to-maturity investments, which are recorded at amortized cost. The carrying values~~downward revisions of our ~~short-term investments approximate fair value.~~long-term commodity price forecast) are revised such that they reduce estimates of future taxable income during the carryforward period.

~~10.~~9. Inventories

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


	June 30,		December 31,		March 31,		December 31,
(In millions)	2015		2014		2016		2015
Liquid hydrocarbons, natural gas and bitumen	$	50	$	58	$	33	$	35
Supplies and other items	286		299		273		278
Inventories, at cost	$	336	$	357	$	306	$	313

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


	June 30,		December 31,		March 31,		December 31,
(In millions)	2015		2014		2016		2015
North America E&P	$	16,757	$	16,717	$	14,953	$	15,226
International E&P	2,848		2,741		2,521		2,533
Oil Sands Mining	9,401		9,455		9,148		9,197
Corporate	115		127		115		105
Net property, plant and equipment	$	29,121	$	29,040	$	26,737	$	27,061

Our Libya operations continue to be impacted by civil ~~unrest and,~~unrest. Operations were interrupted in ~~December 2014, Libya’s National Oil Corporation once again declared force majeure at~~mid-2013 as a result of the shutdown of the Es Sider crude oil terminal, ~~as disruptions from civil unrest continue.~~and although temporarily re-opened during the second half of 2014, production remains shut-in. Considerable uncertainty remains around the timing of future production and sales levels.

As of ~~June 30, 2015,~~March 31, 2016, our net property, plant and equipment investment in Libya is ~~$775~~$776 million, and total proved reserves (unaudited) in Libya as of December 31, ~~2014~~2015 are ~~243~~235 million barrels of oil equivalent ("mmboe"). We and our partners in the Waha concessions continue to assess the situation and the condition of our assets in Libya. Our periodic assessment of the carrying value of our net property, plant and equipment in Libya specifically considers the net investment in the assets, the duration of our concessions and the reserves anticipated to be recoverable in future periods. The undiscounted cash flows related to our Libya assets ~~continues~~continue to exceed the carrying value of ~~$775~~$776 million by a material amount.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Exploratory well costs capitalized greater than one year after completion of drilling were ~~$88~~$120 million and ~~$126~~$85 million as of ~~June 30, 2015~~March 31, 2016 and December 31, ~~2014. This $38~~2015. The $35 million ~~net decrease was associated with our Canadian in-situ assets at Birchwood. After further evaluation~~increase primarily relates to the Alba Block Sub Area B offshore Equatorial Guinea where the Rodo well reached total depth in the first quarter of 2015. We have since completed a seismic feasibility study and continue to finalize next steps in the ~~estimated recoverable resources and our development plans, we withdrew our regulatory application for the proposed steam assisted gravity drainage ("SAGD") demonstration project.~~Alba Block Sub Area B exploration program.

~~MARATHON OIL CORPORATION~~

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

~~12.~~11. Fair Value Measurements

Fair Values - Recurring

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


	June 30, 2015								March 31, 2016
(In millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity^(a)	$	—	$	5	$	—	$	5	$	—	$	51	$	—	$	51
Interest rate	—		11		—		11		—		12		—		12
Derivative instruments, assets	$	—	$	16	$	—	$	16	$	—	$	63	$	—	$	63
Derivative instruments, liabilities
Commodity^(a)	$	—	$	26	$	—	$	26	$	—	$	24	$	—	$	24
Derivative instruments, liabilities	$	—	$	26	$	—	$	26	$	—	$	24	$	—	$	24


^(a)	Derivative instruments are recorded on a net basis in the company's balance sheet (see Note ~~13)~~12).


	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 12).

Commodity derivatives include three-way collars, ~~swaptions,~~ extendable three-way collars, call options, swaps 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 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 1312 for additional discussion of the types of derivative instruments we use.

Fair Values ~~- Nonrecurring~~– Goodwill

~~The following table shows~~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 ~~values of assets, by major category, measured at~~ fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. We estimate the fair value of our International E&P reporting unit using a combination of market and income approaches. The market approach referenced observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value, and valuation multiples of us and our peers for the investor analyst community. The income approach utilized discounted cash flows, which were based on ~~a nonrecurring basis in periods subsequent~~forecasted assumptions. Key assumptions to ~~their initial recognition.~~

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

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

~~Commodity prices began declining~~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 ~~second half of 2014 and remain substantially lower through 2015 as compared~~income approach are consistent with those that management uses to ~~the first six months of 2014. As this period of sustained reduced commodity prices continues, it could result in non-cash impairment charges~~make business decisions. These valuations methodologies represent Level 3 fair value measurements. A triggering event related to ~~long-lived assets~~price declines in ~~future periods.~~

~~All long-lived assets held for use that were impaired in the first six months of 2015 and 2014 were held by~~ our ~~North America E&P segment.~~common stock required us to reassess our goodwill

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~In July 2015,~~for impairment as of March 31, 2016. Based on the results of this assessment, we ~~entered into an agreement~~concluded no impairment was required. While the fair value of our International E&P reporting unit exceeded book value, subsequent commodity price and/or common stock declines may cause us to ~~sell~~reassess our ~~East Texas/North Louisiana~~goodwill for impairment, and ~~Wilburton, Oklahoma natural gas assets. We expect the transaction to close during the third quarter of 2015. During the second quarter of 2015, we recorded a~~could result in non-cash impairment charge of $44 million related to these assets as a result of the anticipated sale. The fair values were measured using a probability weighted income approach based on both the anticipated sales price and a held-for-use model. The held-for-use model contained internal estimates of future production levels, prices and discount rate. All such inputs were classified as Level 3.

~~The Ozona development~~charges in the Gulf of Mexico ceased producing in 2013, at which time those long-lived assets were fully impaired. In the first and second quarters of 2014, we recorded additional impairments of $17 million and $4 million as a result of estimated abandonment cost revisions. The fair value was measured using an income approach based upon forecasted future abandonment costs, which are Level 3 inputs. future.

Fair Values – Financial Instruments

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

The following table summarizes financial instruments, excluding receivables, ~~short-term investments,~~ payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at ~~June 30, 2015~~March 31, 2016 and December 31, ~~2014.~~2015.


	June 30, 2015				December 31, 2014				March 31, 2016				December 31, 2015
	Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount		Value		Amount		Value		Amount
Financial assets
Other noncurrent assets	$	134	$	133	$	132	$	129	$	115	$	120	$	104	$	118
Total financial assets	134		133		132		129		$	115	$	120	$	104	$	118
Financial liabilities
Other current liabilities	13		13		13		13		$	34	$	33	$	34	$	33
Long-term debt, including current portion^(a)	8,720		8,324		6,887		6,360		6,575		7,291		6,723		7,291
Deferred credits and other liabilities	73		67		69		68		104		105		97		95
Total financial liabilities	$	8,806	$	8,404	$	6,969	$	6,441	$	6,713	$	7,429	$	6,854	$	7,419

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

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

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

~~13.~~12. Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note ~~12.~~11. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts where they appear on the consolidated balance ~~sheets as of June 30, 2015 and December 31, 2014.~~sheets.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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

$ —

$ 11


								March 31, 2016
(In millions)								Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate								$	12	$	—	$	12	Other noncurrent assets
Total Designated Hedges								$	12	$	—	$	12

Not Designated as Hedges
Commodity								$	51	$	7	$	44	Other current assets
Total Not Designated as Hedges								$	51	$	7	$	44
Total								$	63	$	7	$	56

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

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



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

Not Designated as Hedges
Commodity	$	51	$	1	$	50	Other current assets
Total Not Designated as Hedges	$	51	$	1	$	50
Total	$	59	$	1	$	58

Derivatives Designated as Fair Value Hedges

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


	June 30, 2015				December 31, 2014				March 31, 2016				December 31, 2015
	Aggregate Notional Amount		Weighted Average, LIBOR-Based,		Aggregate Notional Amount		Weighted Average, LIBOR-Based,		Aggregate Notional Amount		Weighted Average, LIBOR-Based,		Aggregate Notional Amount		Weighted Average, LIBOR-Based,
Maturity Dates	(in millions)		Floating Rate		(in millions)		Floating Rate		(in millions)		Floating Rate		(in millions)		Floating Rate
October 1, 2017	$	600	4.67	%	$	600	4.64	%	$	600	4.92	%	$	600	4.73	%
March 15, 2018	$	300	4.52	%	$	300	4.49	%	$	300	4.77	%	$	300	4.66	%

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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


		Gain (Loss)													Gain (Loss)
		Three Months Ended June 30,						Six Months Ended June 30,								Three Months Ended March 31,
(In millions)	Income Statement Location	2015			2014			2015			2014			Income Statement Location		2016			2015
Derivative
Interest rate	Net interest and other	$	(2	)	$	4		$	3		$	3		Net interest and other		$	4		$	5
Foreign currency	Discontinued operations	$	—		$	(14	)	$	—		$	(11	)
Hedged Item
Long-term debt	Net interest and other	$	2		$	(4	)	$	(3	)	$	(3	)	Net interest and other		$	(4	)	$	(5	)
Accrued taxes	Discontinued operations	$	—		$	14		$	—		$	11

Derivatives not Designated as Hedges

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

~~MARATHON OIL CORPORATION~~

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

In this case, we receive the NYMEX ~~WTI~~WTI/Henry Hub price plus the difference between the floor and the sold put price. These commodity derivatives were not designated as ~~hedges~~hedges. The following table sets forth outstanding derivative contracts as of March 31, 2016 and ~~are shown in~~ the ~~table below:~~weighted average prices for those contracts:


Financial Instrument	Weighted Average Price	Barrels per day	Remaining Term
Three-Way Collars
Crude Oil ^(a)				Crude Oil ^(a)
				2016			Year Ending December 31,
				Second Quarter	Third Quarter	Fourth Quarter	2017
Three-Way Collars ^(b)				Three-Way Collars ^(b)
Volume (Bbls/day)				39,000	37,000		—
Price per Bbl:
Ceiling	$70.34	35,000	July- December 2015 ^(a)	$55.47	$54.52		—
Floor	$55.57			$51.56	$50.83		—
Sold put	$41.29			$41.67	$41.22		—

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)
Options ^(c)
Volume (Bbls/day)				10,000			25,000
Price per Bbl				$72.39			$60.67
Swaps
Volume (Bbls/day)				25,000	—
Price per Bbl				$39.25	—

^(a)

^(a)Subsequent to March 31, 2016, we entered into 10,000 Bbls/day of two-way collars for July - December 2016 with a ceiling price of $50.00 and a floor price of $41.55. We also entered into 10,000 Bbls/day of 2016 three-way collars for May - December 2016 with a ceiling price of $58.51, a floor price of $48.00, and a sold put price of $40.00, traded in conjunction with sold call options of 10,000 Bbls/day for 2017 at $65.00.

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


^(b)	~~Counterparty~~A counterparty has the option, exercisable on June 30, 2016, to extend ~~these~~three-way collars for 2,000 Bbls/day through the remainder of 2016 at ~~the same volume~~a ceiling of $73.13, floor of $65.00 and ~~weighted average price as the underlying three-way collars.~~sold put of $50.00.


^(c)	Call options settle monthly.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



Natural Gas ^(a)
	2016			Year Ending December 31,
	Second Quarter	Third Quarter	Fourth Quarter	2017
Three-Way Collars ^(b)
Volume (MMBtu/day)	20,000	20,000	20,000	20,000
Price per MMBtu
Ceiling	$2.93	$2.93	$2.93	$3.07
Floor	$2.50	$2.50	$2.50	$2.75
Sold put	$2.00	$2.00	$2.00	$2.25


^(a)	Subsequent to March 31, 2016, we entered into 20,000 MMBtu/day of 2017 three-way collars with a ceiling price of $3.50, a floor price of $2.75, and a sold put price of $2.25.


^(b)	Counterparty has the option to execute fixed-price swaps (swaptions) at a weighted average price of $2.93 per MMBtu indexed to NYMEX Henry Hub, which is exercisable on December 22, 2016. If counterparty exercises, the 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.

The impact of these ~~crude oil~~commodity derivative instruments appears in sales and other operating revenues in our consolidated statements of income and was a net loss of ~~$43~~$2 million and ~~$17~~net gain of $26 million in the ~~second quarter~~first quarters of 2016 and ~~first six months of 2015. There were no crude oil derivative instruments in the first six months of 2014.~~2015, respectively.

On June 1, 2015, we entered into Treasury rate locks, which expired on the same day, to hedge against timing differences as it related to our Notes offering (see Note 15). Following the execution of the Treasury locks, corresponding interest rates increased during the day of June 1. As a result, the settlement of the Treasury rate locks resulted in a gain of $6 million, which was recognized in net interest and other in our consolidated statements of income.

~~14.~~13. Incentive Based Compensation

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

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


	Stock Options					Restricted Stock				Stock Options					Restricted Stock Awards & Units
	Number of Shares			Weighted Average Exercise Price		Awards		Weighted Average Grant Date Fair Value		Number of Shares			Weighted Average Exercise Price		Awards		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2014	13,427,836				$29.68	3,448,353			$34.04
Outstanding at December 31, 2015										12,665,419				$29.97	4,017,344			$30.76
Granted	724,082		^(a)		$29.06	2,668,357			$30.53	1,680,000		^(a)		$7.22	5,230,708			$7.91
Options Exercised/Stock Vested	(480,458	)			$16.47	(921,404	)		$34.29	—			—		(44,096	)		$32.01
Canceled	(455,855	)			$34.48	(491,739	)		$33.70	(181,681	)			$29.69	(220,614	)		$30.00
Outstanding at June 30, 2015	13,215,605				$29.97	4,703,567			$32.04
Outstanding at March 31, 2016										14,163,738				$27.27	8,983,342			$17.47

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

Stock-based performance unit awards

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

~~MARATHON OIL CORPORATION~~

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

~~15.~~14. Debt

Revolving Credit Facility

As of ~~June 30, 2015,~~March 31, 2016, we had no borrowings against our revolving credit facility ~~(as amended, the~~(the "Credit Facility"), as described below.

In ~~May 2015,~~March 2016, we ~~amended~~increased our ~~$2.5~~$3.0 billion unsecured Credit Facility ~~to increase the facility size~~ by ~~$500~~$300 million to a total of $3 billion and extend the maturity date by an additional year such that the Credit Facility now matures in May 2020. The amendment additionally provides us the ability to request two one-year extensions to the maturity date and an option to increase the commitment amount by up to an additional $500 million, subject to the consent of any increasing lenders. The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively.$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.

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

the cash collateralization of all outstanding letters of credit under the Credit Facility. As of ~~June 30, 2015,~~March 31, 2016, we were in compliance with this covenant with a debt-to-capitalization ratio of ~~29%~~27%.

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

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

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

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

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

~~16.~~15. Reclassifications Out of Accumulated Other Comprehensive ~~Income (Loss)~~Loss

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


	Three Months Ended June 30,						Six Months Ended June 30,							Three Months Ended March 31,
(In millions)	2015			2014			2015			2014			Income Statement Line	2016			2015			Income Statement Line

Postretirement and postemployment plans	Postretirement and postemployment plans
Amortization of actuarial loss	$	(7	)	$	(10	)	$	(14	)	$	(16	)	General and administrative	$	(3	)	$	(7	)	General and administrative
Net settlement loss	(64		)	(8		)	(81		)	(71		)	General and administrative	(48		)	(17		)	General and administrative
Net curtailment gain (loss)	(2		)	—			3			—			General and administrative	—			5			General and administrative
	(73		)	(18		)	(92		)	(87		)	Income (loss) from operations	(51		)	(19		)	Income (loss) from operations
	25			7			32			30			Benefit for income taxes	19			7			Provision (benefit) for income taxes
Other insignificant, net of tax	—			—			—			(1		)
Total reclassifications	$	(48	)	$	(11	)	$	(60	)	$	(58	)	Income (loss) from continuing operations
Total reclassifications to expense														$	(32	)	$	(12	)	Net income (loss)

~~MARATHON OIL CORPORATION~~

~~Notes~~16. Stockholder's Equity

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 $1,232 million. The proceeds will be used to ~~Consolidated Financial Statements (Unaudited)~~strengthen our balance sheet and for general corporate purposes, including funding a portion of our Capital Program.

17. Supplemental Cash Flow Information

Six Months Ended June 30,
(In millions) 2015 2014
Net cash used in operating activities:
Interest paid (net of amounts capitalized) $ (143 ) $ (149 )
Income taxes paid to taxing authorities ^(a)
(165 ) (1,336 )
Net cash provided by (used in) financing activities:
Commercial paper, net:

Issuances $ —
$ 2,285
Repayments —
(2,420 )
Commercial paper, net $ —
$ (135 )
Noncash investing activities, related to continuing operations:

Asset retirement costs capitalized, net of revisions $ 6
$ 42
Asset retirement obligations assumed by buyer —
52
Receivable for disposal of assets —
44



	Three Months Ended March 31,
(In millions)	2016			2015
Net cash (used in) operating activities:
Interest paid (net of amounts capitalized)	$	(87	)	$	(55	)
Income taxes paid to taxing authorities	(15		)	(47		)
Noncash investing activities:
Asset retirement cost increase	$	2		$	21
Asset retirement obligations assumed by buyer	54			—


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

18. Commitments and Contingencies

We are a defendant in a number of ~~lawsuits~~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.

19. Subsequent Event

In September 2015, we announced our intention to scale back our conventional exploration program, with future exploration investment focused on fulfilling our existing commitments in the Gulf of Mexico and Gabon. In April 2016, we made the decision not to drill any of our remaining Gulf of Mexico undeveloped leases. As a result, we expect to record a non-cash impairment between $140 million and $150 million in the second quarter of 2016. We retain our existing deepwater drilling rig commitment, in which we have approximately 200 days of contract term remaining.

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

Results of Operations

Critical Accounting Estimates

Cash Flows and Liquidity

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

Executive Overview

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

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

Continued to strengthen the ~~products and services it offers.~~balance sheet


◦	Raised net $1.2 billion from equity offering in the first quarter of 2016


◦	At the end of the first quarter of 2016, we had $5.4 billion of liquidity, comprised of $2.1 billion in cash and an undrawn $3.3 billion revolving credit facility


◦	Announced or closed $1.3 billion of non-core asset sales since August 2015, surpassing our target of $750 million to $1 billion. The largest component of this total was the $950 million non-core asset sales announced in April 2016 which consisted of:


▪	Wyoming upstream and midstream assets of $870 million, before closing adjustments


▪	Shenandoah discovery in the Gulf of Mexico (10% outside operated working interest); Piceance operated natural gas assets in Colorado; certain undeveloped acreage in West Texas for a combined total of approximately $80 million, before closing adjustments


◦	Additions to property, plant and equipment, including accruals, of $359 million for the first quarter of 2016, down 67% compared to the year-ago quarter, reflecting continued capital discipline


◦	Executed additional commodity derivative instruments during the first quarter to reduce commodity price uncertainty for North America E&P crude oil and natural gas


◦	Reduced production expenses per boe in the first quarter of 2016 compared to the same period last year


▪	North America E&P - 22% reduction to $6.17 per boe


▪	Oil Sands Mining - 17% reduction to $28.80 per boe


◦	Cash-adjusted debt-to-capital ratio of 21% at March 31, 2016, as compared with 25% at December 31, 2015

Financial results


◦	Net loss per share of $0.56 in the first quarter of 2016 as compared to net loss per share of $0.41 in the same period last year

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

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

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

~~Executive Overview~~Outlook

Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows and ~~their subsequent reinvestment~~the amount of capital available to reinvest into our business. ~~Commodity prices began declining~~We remain on track to achieve our objective of spending within our cash flows in 2016, inclusive of the non-core asset sales recently announced. We will continue to strengthen the balance sheet, evaluate our portfolio for strategic opportunities, adjust our Capital Program as necessary, and drive the fundamentals of expense management.

Exploration Update

In September 2015, we announced our intention to scale back our conventional exploration program, with future exploration investment focused on fulfilling our existing commitments in the ~~second half~~Gulf of ~~2014~~Mexico and ~~remain substantially lower through 2015 as compared~~Gabon. In April 2016, we made the decision not to ~~the first six months~~drill any of ~~2014. We believe~~our remaining Gulf of Mexico undeveloped leases. As a result, we ~~can manage in this lower commodity price cycle through~~expect to record a ~~continued focus on development in our three U.S. resource plays, operational execution, efficiency improvements, cost reductions, capital discipline~~non-cash impairment between $140 million and ~~portfolio optimization, all while maintaining financial flexibility.~~

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

~~Increased company-wide net sales volumes from continuing operations by 4% to 411 thousand barrels of oil equivalent per day ("mboed")~~$150 million in the second quarter of ~~2015 from 394 mboed~~2016. We retain our existing deepwater drilling rig commitment, in which we have approximately 200 days of contract term remaining. We are currently evaluating our options related to this commitment. We expect this rig to return to us late in the ~~second~~third quarter or early fourth quarter of ~~2014~~


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

~~Maintained focus on cost discipline and efficiencies~~


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


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


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

~~Active management of liquidity and capital structure~~


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


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


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


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


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


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

~~Portfolio management activities~~


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


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

~~Financial results~~


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


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


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

2016.

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

Operations

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



	Three Months Ended March 31,
Net Sales Volumes	2016	2015	Increase (Decrease)
North America E&P (mboed)	239	283	(16)%
International E&P (mboed)	96	116	(17)%
Oil Sands Mining (mbbld) ^(a)	59	60	(2)%
Total (mboed)	394	459	(14)%

^(a)Includes blendstocks

North America E&P ~~segment average net~~

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



	Three Months Ended March 31,
Net Sales Volumes	2016	2015	Increase (Decrease)
Equivalent Barrels (mboed)
Eagle Ford	121	147	(18)%
Oklahoma Resource Basins	27	25	8%
Bakken	57	57	—
Other North America ^(a)	34	54	(37)%
Total North America E&P	239	283	(16)%

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

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

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

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

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

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

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

~~The following table presents a summary~~production, which was impacted by the sale of ~~our operated drilling activity~~certain Gulf of Mexico assets in the ~~U.S. resource plays:~~fourth quarter of 2015.



	Three Months Ended March 31, 2016
Sales Mix - U.S. Resource Plays	Crude oil and condensate	Natural gas liquids	Natural gas

Eagle Ford	58%	21%	21%
Oklahoma Resource Basins	19%	26%	55%
Bakken	82%	11%	7%


	Three Months Ended June 30,		Six Months Ended June 30,		Three Months Ended March 31,
	2015	2014	2015	2014	2016	2015
Gross Operated
Eagle Ford:
Wells drilled to total depth	59	88	147	171	58	88
Wells brought to sales	52	76	143	125	50	91
Oklahoma Resource Basins:
Wells drilled to total depth					5	8
Wells brought to sales					3	5
Bakken:
Wells drilled to total depth	5	19	25	22	3	20
Wells brought to sales	22	19	46	16	6	24
Oklahoma Resource Basins:
Wells drilled to total depth	5	6	13	11
Wells brought to sales	3	4	8	8

Eagle Ford – Of the 50 gross operated wells brought to sales during the first quarter of 2016, 23 were Lower Eagle Ford, ~~– Average net sales volumes from~~19 were Upper Eagle Ford and 8 were 135 mboed and 141 mboed in the second quarter and first six months of 2015 compared to 102 mboed and 99 mboed in the same periods of 2014, for increases of 32% and 42%. Approximately 61% of second quarter sales was crude oil and condensate, 19% was NGLs and 20% was natural gas.Austin Chalk. Our average time to drill an Eagle Ford well in ~~second~~the first quarter ~~2015,~~2016, spud-to-total depth, ~~was 11 days. Also, during~~decreased to 8 days from 12 days in the ~~second~~same quarter last year as efficiency gains in drilling continued. Wells were drilled at an average rate of 2,300 feet per day and the top-performing Eagle Ford rigs drilled four wells in excess of 3,300 feet per day.

Oklahoma Resource Basins – In the first quarter of ~~2015,~~2016, we continued our focus on leasehold protection and delineation and brought ~~online 8 Upper Eagle Ford, 33 Lower Eagle Ford and 11 Austin Chalk~~3 gross operated wells ~~and we completed and brought online three "stack-and-frac" pilots with wells in three horizons.~~

~~Bakken – Average net~~to sales, ~~volumes from the Bakken shale were 61 mboed and 59 mboed~~of which one was in the ~~second quarter and first six months of 2015 compared to 50 mboed and 46 mboed~~SCOOP Woodford, one in the ~~same period for 2014, for increases~~SCOOP Springer and one in the STACK Meramec. We also participated in 7 outside-operated wells during the first quarter of ~~22%~~2016 that were focused in SCOOP and ~~28%.~~STACK.

Bakken – The 6 gross operated wells brought to sales in the first quarter of 2016 were in the greater Hector area, of which 4 were in Middle Bakken and 2 in Three Forks. Our ~~Bakken production averaged approximately 89% crude oil, 5% NGLs and 6% natural gas. Our~~average time to drill a Bakken well in the first quarter of 2016, spud-to-total depth, ~~averaged 13~~decreased to 12 days from 17 days in the ~~second~~first quarter of 2015.

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

~~Oklahoma Resource Basins~~

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

~~Additionally, we continue to leverage the benefit of participation in outside-operated wells and plan to participate in approximately 85 outside-operated wells in 2015~~non-core assets in the SCOOP Woodford, SCOOP Springer and STACK areas. In the first six months of 2015, we participated in four outside-operated high-density spacing pilots in the SCOOP area; three in the Woodford (80-128 acre spacing) and one in the emerging Springer shale (105-128 acre spacing) overlaying the Woodford. Two outside-operated STACK Meramec XL wells were brought to sales during the quarter.

Gulf of Mexico ~~– Development~~and East Texas, North Louisiana and Wilburton, Oklahoma. Additionally, development work continues in the Gunflint field located onin Mississippi ~~Canyon Blocks 948, 949, 992 (N/2) and 993 (N/2). We expect the two-well subsea tieback to be complete~~Canyon. First oil is expected in the second half of ~~2015.~~2016 after the completion of work at a third party facility. We hold an 18% non-operated working interest in the Gunflint field.

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

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

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

~~International E&P--Production~~

International E&P ~~segment average net~~

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

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

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

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

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

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

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



	Three Months Ended March 31,
Net Sales Volumes	2016	2015	Increase (Decrease)
Equivalent Barrels (mboed)
Equatorial Guinea	84	97	(13)%
United Kingdom^(a)	12	19	(37)%
Total International E&P	96	116	(17)%
Equity Method Investees
LNG (mtd)	4,322	6,275	(31)%
Methanol (mtd)	1,280	884	45%
Condensate & LPG (boed)	10,208	13,223	(23)%


^(a)	Includes natural gas acquired for injection and subsequent resale of 75 mmcfd and ~~5 mmcfd for the second quarters of 2015 and 2014, and 9 mmcfd and 6~~10 mmcfd for the first ~~six months~~quarters of ~~2015~~2016 and ~~2014.~~2015.

Equatorial Guinea – ~~Average~~First quarter 2016 net sales ~~volumes~~ were ~~89 mboed~~reduced compared to prior year quarter due to planned downtime associated with the installation of the Alba compression jacket and ~~93 mboed~~topsides, and planned maintenance activities in the ~~second quarter~~onshore plants. This planned maintenance was successfully completed under budget and ~~first six months~~ahead of ~~2015 compared to 105 mboed and 107 mboed in the same periods of 2014. Planned turnaround and maintenance activities at the~~schedule. The ongoing Alba field compression project, designed to maintain the production plateau for an additional two years and ~~EG LNG facilities reduced~~extend field life up to eight years, remains on schedule with first production rates during the second quarter of 2015. The Alba turnaround subsequently reduced sales to our equity method investees, Alba Plant LLC, EGHoldings and AMPCO. Additionally, there was a planned turnaround at AMPCO in the first quarter of 2015.mid-year.

~~During the second quarter of 2015, the Alba C21 development well reached total depth and completion activities are underway. To date, well performance results are consistent with pre-drill estimates.~~

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

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

~~Libya – We had no sales during the first six months of 2015~~2016 were lower as a result of repairs at Brae Alpha which was shut-in throughout the quarter following a process pipe failure in late 2015, partially offset by improved reliability from the outside-operated Foinaven field. Full production from Brae Alpha resumed in late April.

Libya – Due to continued civil ~~unrest. In December 2014, Libya’s National Oil Corporation reinstated force majeure at~~unrest, there were no liftings during the ~~Es Sider oil terminal, as disruptions from civil unrest continue.~~quarter. Considerable uncertainty remains around the timing of future production and sales levels.

~~International E&P--Exploration~~

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

Oil Sands Mining

Our net synthetic crude oil sales volumes were 2959 mbbld ~~and 44 mbbld in the second~~first quarter ~~and first six months~~ of ~~2015~~2016 compared to ~~44 mbbld and 45~~60 mbbld in the same ~~periods~~period of ~~2014. Production declined~~2015. Planned maintenance activities began ahead of schedule in ~~the second quarter of 2015 primarily due to the planned turnarounds~~mid-March at the base upgrader and the Jackpine mine which will impact production in the second quarter. In addition, in early May our operations at the Muskeg River ~~Mine~~ and ~~unplanned downtime at the expansion upgrader. Production was relatively flat in the first six months of 2015 compared~~Jackpine mines have been suspended to support emergency response efforts related to the ~~same period in 2014 as~~Fort McMurray area wildfires. The mines are approximately 60 miles north of the ~~planned turnarounds~~wildfires and ~~unplanned downtime during the second quarter of 2015 were mostly offset~~not currently threatened by ~~higher production driven by improved mine reliability during the first quarter of 2015.~~fire. We hold a 20% non-operated working interest in the ~~AOSP.~~Athabasca Oil Sands Project.

Market Conditions

Prevailing prices for the crude oil, NGLs and natural gas that we produce significantly impact our revenues and cash flows. The benchmark prices for crude oil, NGLs and natural gas were ~~significantly~~ lower in the ~~second~~first quarter ~~and first six months~~ of ~~2015~~2016 as compared to the same ~~periods~~period in ~~2014;~~2015; as a result, we experienced ~~significant~~ declines in our price realizations associated with those benchmarks. Additional detail on market conditions, including our average price realizations and benchmarks for crude oil, NGLs and natural gas relative to our operating segments, follows.

North America E&P

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

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

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

Bakken
$51.36

$93.08

$45.84

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

Bakken
$11.63

$45.13

$7.19

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

Bakken
$49.29

$90.47

$43.72

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

Bakken
$2.62

$4.12

$2.76

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

$57.95

$102.99

$53.34

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



	Three Months Ended March 31,
	2016		2015		Increase (Decrease)
Average Price Realizations ^(a)
Crude Oil and Condensate (per bbl) ^(b)	$28.21		$41.75		(32	)%
Natural Gas Liquids (per bbl)	8.12		14.43		(44	)%
Total Liquid Hydrocarbons (per bbl)	24.00		36.92		(35	)%
Natural Gas (per mcf)	2.02		3.01		(33	)%
Benchmarks
WTI crude oil (per bbl)		$33.63		$48.58	(31	)%
LLS crude oil (per bbl)	35.33		52.84		(33	)%
Mont Belvieu NGLs (per bbl)^(c)	13.95		18.39		(24	)%
Henry Hub natural gas (per mmbtu)	2.09		2.98		(30	)%


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


^(b)	Inclusion of realized gains on crude oil derivative instruments would have increased average ~~crude oil price realization~~realizations by ~~$0.06~~$1.64 per bbl and ~~$0.14~~$0.21 per bbl for the ~~second~~first quarter 2016 and ~~first six months of~~ 2015. ~~There were no crude oil derivative instruments in 2014.~~


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


^(d)	~~NYMEX.~~


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


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


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


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

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

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

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

International E&P

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

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

Equatorial Guinea
$52.27

$90.91

$47.55

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

Equatorial Guinea ^(a)

$1.00

$1.00

$1.00

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

Equatorial Guinea
$35.74

$59.72

$31.81

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

Equatorial Guinea ^(a)

$0.24

$0.24

$0.24

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

$61.69

$109.70

$57.81

$108.93



	Three Months Ended March 31,
	2016		2015		Increase (Decrease)
Average Price Realizations
Crude Oil and Condensate (per bbl)	$30.95		$48.87		(37	)%
Natural Gas Liquids (per bbl)	2.20		3.46		(36	)%
Liquid Hydrocarbons (per bbl)	22.66		37.31		(39	)%
Natural Gas (per mcf)	0.60		0.78		(23	)%
Benchmark
Brent (Europe) crude oil (per bbl) ^(a)		$33.70		$53.92	(38	)%


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


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

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

~~NGLs~~

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

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

Oil Sands Mining

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

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

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


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended March 31,
	2015		2014		2015		2014		2016		2015		Increase (Decrease)
Average Price Realizations
Synthetic Crude Oil (per bbl)		$52.46		$94.17		$44.33		$91.27		$26.41		$40.37	(35	%)
Benchmark
Benchmarks
WTI crude oil (per bbl)^(a)		$57.95		$102.99		$53.34		$100.84		$33.63		$48.58	(31	%)
WCS crude oil (per bbl)^(b)		$46.35		$82.95		$40.13		$79.25
AECO natural gas sales index (per mmbtu)^(c)		$2.05		$4.46		$2.07		$4.72
WCS crude oil (per bbl)^(a)									19.21		33.90		(43	%)


^(a)	~~NYMEX.~~


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


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

Results of Operations

~~Consolidated Results of Operation~~Three Months Ended March 31, 2016 vs. Three Months Ended March 31, 2015

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

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



	Three Months Ended March 31,
(In millions)	2016			2015
Sales and other operating revenues, including related party
North America E&P	$	493		$	850
International E&P	96			182
Oil Sands Mining	148			225
Segment sales and other operating revenues, including related party	$	737		$	1,257
Unrealized (loss) gain on crude oil derivative instruments	(23		)	23
Sales and other operating revenues, including related party	$	714		$	1,280

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

~~North America E&P~~

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

1
Other sales 4

9
Total $ 1,540
$ 993

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

~~International E&P~~

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

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

~~Oil Sands Mining~~

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

10
Total $ 383
$ 147


	Six Months Ended		Increase (Decrease) Related to						Six Months Ended			Three Months Ended		Increase (Decrease) Related to						Three Months Ended
(In millions)	June 30, 2014		Price Realizations			Net Sales Volumes			June 30, 2015			March 31, 2015		Price Realizations			Net Sales Volumes			March 31, 2016
North America E&P Price-Volume Analysis											North America E&P Price-Volume Analysis
Liquid hydrocarbons												$	741	$	(220	)	$	(113	)	$	408
Natural gas												97		(29		)	(11		)	57
Realized gain on crude oil
derivative instruments												3		19						22
Other sales												9								6
Total												$	850							$	493
International E&P Price-Volume Analysis											International E&P Price-Volume Analysis
Liquid hydrocarbons												$	139	$	(43	)	$	(30	)	$	66
Natural gas												32		(6		)	(5		)	21
Other sales												11								9
Total												$	182							$	96
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil	$	750	$	(376	)	$	(19	)	$	355		$	217	$	(74	)	$	—		$	143
Other sales	10								17			8								5
Total	$	760							$	372		$	225							$	148

Marketing revenues decreased ~~$435 million and $772~~$146 million in the ~~second~~first quarter ~~and first six months~~ of ~~2015~~2016 from the comparable prior-year ~~periods.~~period. Marketing activities include the purchase of commodities from third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points. ~~Because~~Since the volume of marketing activity is based on market dynamics, it can fluctuate from period to period. The decreases are related primarily to lower marketed volumes in North America, which were further compounded by a lower commodity price environment.

Income from equity method investments decreased ~~$94 million and $195~~$22 million in the ~~second~~first quarter ~~and first six months~~ of ~~2015~~2016 from the comparable ~~2014~~2015 period. The decrease ~~in the second quarter of 2015~~ 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. Also impacting the quarter were lower price realizations for ~~Liquified Natural Gas ("LNG") at our LNG facility, Liquified Petroleum Gas ("LPG")~~LPG at our Alba plant and lower methanol prices at our AMPCO methanol ~~facility, all~~facility.

Net loss on disposal of ~~which are located~~ assets in ~~E.G. Also contributing~~the first quarter of 2016 was related to the ~~decrease in 2015 were lower sales volumes due~~sale of non-core assets. See Note 5 to the ~~previously mentioned 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 decreased ~~$112 million in the second quarter of 2015 compared to the second quarter of 2014.~~$116 million. North America E&P declined ~~$38~~$68 million primarily due to lower operational, maintenance and labor ~~costs.~~costs, coupled with the 2015 disposition of certain producing Gulf of Mexico assets. International E&P declined ~~$35~~$14 million primarily ~~because~~as a result of lower operational costs ~~related to~~in Libya and lower ~~sales volumes, while the second quarter of 2014 included $5 million of turnaround~~ costs ~~at Brae and subsea maintenance costs at the non-operated Foinaven field~~ in the U.K. associated with lower net sales volumes, which was offset by higher planned maintenance costs in E.G. during the first quarter of 2016. OSM decreased ~~$39~~$34 million primarily due to lower feedstock purchases (due to planned turnarounds and unplanned downtime as previously discussed) and continued cost management, especially staffing and contract labor. Also contributing to the OSM decrease was a more favorable exchange rate on expenses denominated in the Canadian ~~Dollar. These declines were partially offset by costs incurred from the turnaround.~~Dollar and continued cost management, especially staffing and contract labor.

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

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

The ~~second~~first quarter of ~~2015~~2016 production expense rate (expense per boe) for North America E&P declined ~~relative to the same quarter in 2014 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 reduced maintenance and project costs and lower operational costs in ~~second quarter of 2015 as compared to 2014.~~Libya. The OSM expense rate ~~increased~~decreased due to the ~~turnarounds~~positive currency effects and ~~unplanned downtime in~~ the ~~second quarter of 2015, which resulted in lower sales volumes and higher costs.~~

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

The following table provides production expense rates for each segment:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended March 31,
($ per boe)	2015		2014		2015		2014		2016		2015
Production Expense Rate
North America E&P		$7.19		$10.47		$7.57		$10.74		$6.17		$7.94
International E&P		$6.51		$8.87		$6.45		$8.82		$6.08		$6.40
Oil Sands Mining ^(a)		$78.24		$51.53		$50.06		$49.54		$28.80		$34.78


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

Marketing costs decreased ~~$432 million and $769~~$147 million in the ~~second~~first quarter ~~and first six months~~ of ~~2015~~2016 from the comparable ~~2014 periods,~~2015 period, consistent with the marketing revenues changes discussed above.

Exploration expenses ~~declined $34~~decreased $66 million primarily due to higher dry well costs in the ~~second~~first quarter of 2015 compared to the second quarter of 2014 due to lower unproved property impairments and dry well costs. Unproved property impairments declined primarily as a result of fewer Eagle Ford and Bakken leases that either expired or that we decided not to drill or extend. The second quarter of 2014which included dry well costs associated with our exploration programs in Kurdistan, Ethiopia and Kenya. Included in the dry well costs for the second quarter of 2015 is $38 million of previously suspended well costs that were written off. The well costs are associated with our Canadian in-situ assets at Birchwood. See Note 11 to the consolidated financial statements for further discussion.

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


	Three Months Ended				Six Months Ended June 30,				Three Months Ended March 31,
(In millions)	2015		2014		2015		2014		2016		2015
Exploration Expenses
Unproved property impairments	$	40	$	60	$	49	$	101	$	11	$	9
Dry well costs	41		53		99		55		—		58
Geological and geophysical	12		6		15		17		—		3
Other	18		26		38		45		13		20
Total exploration expenses	$	111	$	145	$	201	$	218	$	24	$	90

Depreciation, depletion and amortization ~~(“DD&A”) increased $71~~decreased $212 million ~~and $249 million in the second quarter and first six months of 2015 from the comparable 2014 periods~~ primarily as a result of production volume decreases, a higher ~~North America E&P net sales volumes from our three U.S. resource plays, partially offset by lower International E&P sales volumes. OSM net sales volumes also declined~~proved reserve base in Eagle Ford and as a result of the ~~second quarter~~Gulf of Mexico disposition in 2015 ~~as previously~~ discussed ~~also contributing to that quarter's decrease.~~above. 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,~~ 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.


	Three Months Ended				Six Months Ended June 30,				Three Months Ended March 31,
($ per boe)	2015		2014		2015		2014		2016		2015
DD&A Rate
North America E&P		$25.45		$26.58		$26.16		$26.72		$22.39		$26.85
International E&P		$7.17		$6.64		$6.62		$6.45		$5.68		$6.10
Oil Sands Mining		$12.87		$11.78		$12.58		$11.74		$11.30		$12.44

~~Impairments~~ ~~are discussed in Note 12 to the consolidated financial statements.~~

Taxes other than income include production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. With the decrease in North America E&P revenues due to lower price realizations, taxes other than income decreased ~~$31 million and $59~~$19 million in the ~~second~~first quarter ~~and first six months~~ of ~~2015 from the comparable 2014 periods. 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				Six Months Ended June 30,				Three Months Ended March 31,
(In millions)	2015		2014		2015		2014		2016		2015
Production and severance	$	40	$	68	$	74	$	122	$	19	$	34
Ad valorem	15		19		31		38		13		16
Other	23		22		40		44		16		17
Total	$	78	$	109	$	145	$	204	$	48	$	67

General and administrative expenses ~~increased $29~~decreased $20 million ~~in the second quarter of 2015 compared to the same period in 2014~~ primarily due to higher pension settlement charges. Settlement charges in the second quarter of 2015 totaled $64 million, compared to settlement charges of $8 million in the prior year quarter. This increase in pension settlement costs was partially offset by costscost savings realized from the workforce reductions ~~that occurred~~ in ~~the first quarter of 2015.~~

~~General and administrative expenses increased $13 million in the first six months of~~ 2015, ~~compared to the same period in 2014. This increase was primarily due to $43 million of~~as well as lower severance related expenses in the first quarter of 2015 and $10 million of increased pension settlement expense (first six months of 2015 totaled $81 million as compared to $71 million for the previous year). These increased costs werecurrent year. This was partially offset by ~~costs savings realized~~pension settlement charges in the ~~second quarter~~first three months of 2016 which totaled $48 million compared to $17 million in the prior year.

Net interest and other increased $38 million primarily due to higher net foreign currency loss and increased interest expense associated with our June 2015 ~~resulting from the workforce reductions.~~debt issuance.

Provision (benefit) for income taxes ~~reflect~~reflects an effective tax ~~rates~~rate of ~~2% and 18%~~40% in the ~~second~~first quarter ~~and first six months~~ of ~~2015,~~2016, as compared to ~~30% and 32% from the comparable 2014 periods. The effective rates for 2015 reflect $135 million of non-cash additional deferred tax expense recorded~~34% in the ~~second~~first quarter of ~~2015 as a result of enacted corporate tax changes in Alberta, Canada.~~2015. See Note 8 to the consolidated financial statements for discussion of the effective tax rate.

~~Discontinued operations~~ ~~presented in 2014 are net of tax. See Note 5 to the consolidated financial statements for financial information about discontinued operations.~~

Segment Income (Loss)

Segment income (loss) represents income (loss) from ~~continuing~~ operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. Gains or losses on dispositions, certain impairments, ~~change in tax expense associated with a tax rate change,~~ unrealized gains or losses on ~~crude oil~~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						Six Months Ended June 30,						Three Months Ended March 31,
(In millions)	2015			2014			2015			2014			2016			2015
North America E&P	$	(45	)	$	302		$	(206	)	$	544		$	(195	)	$	(161	)
International E&P	41			160			64			381			4			23
Oil Sands Mining	(77		)	55			(96		)	119			(48		)	(19		)
Segment income (loss)	(81		)	517			(238		)	1,044			(239		)	(157		)
Items not allocated to segments, net of income taxes	(305		)	(157		)	(424		)	(286		)	(168		)	(119		)
Income (loss) from continuing operations	(386		)	360			(662		)	758
Discontinued operations ^(a)	—			180			—			931
Net income (loss)	$	(386	)	$	540		$	(662	)	$	1,689		$	(407	)	$	(276	)


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

North America E&P segment ~~income (loss)~~loss ~~decreased $347~~increased $34 million ~~and $750 million~~ after-tax ~~in the second quarter and first six months of 2015 from the comparable 2014 periods. The decrease is~~ primarily due to lower price realizations and sales volumes, which was partially offset by ~~the impacts from the increased net sales volumes from the U.S. resource plays.~~lower DD&A and production expenses.

International E&P segment income decreased ~~$119~~$19 million ~~and $317 million~~ after-tax ~~in the second quarter and first six months of 2015 from the comparable 2014 periods. The decreases are~~ primarily due to lower ~~liquid hydrocarbon~~ price realizations and ~~net~~ sales volumes as well as reduced income from equity investments. These declines were partially offset by lower exploration, production and ~~exploration~~DD&A expenses.

Oil Sands Mining segment ~~income (loss)~~loss ~~decreased $132~~increased $29 million ~~and $215 million~~ after-tax ~~in the second quarter and first six months of 2015 from the comparable 2014 periods~~ primarily due to lower price realizations, partially offset by ~~reduced~~lower production expenses.

Critical Accounting Estimates

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

Fair Value Estimates - Goodwill

Goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. A triggering event related to price declines in our common stock required us to reassess our goodwill for impairment as of March 31, 2016. Based on the results of this assessment, we concluded no impairment was required. While the fair value of our International E&P reporting unit exceeded book value, subsequent commodity price and/or common stock declines may cause us to reassess our goodwill for impairment, and could result in non-cash impairment charges in the future.

Estimated Quantities of Net Reserves

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



	Unweighted 12-month 2015 Average	Unweighted 4-month 2016 Average
WTI Crude oil	$50.28	$35.67
Henry Hub natural gas	2.59	2.00
Brent crude oil	54.25	35.95
Natural gas liquids	17.32	13.16

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

Accounting Standards Not Yet Adopted

See Note 2 to the consolidated financial statements.

~~Cash Flows and Liquidity~~

Cash Flows

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


	Six Months Ended June 30,						Three Months Ended March 31,
(In millions)	2015			2014			2016			2015
Sources of cash and cash equivalents
Continuing operations	$	717		$	2,118
Discontinued operations	—			440
Borrowings	1,996			—
Operating activities							$	74		$	309
Common stock issuance							1,232			—
Disposals of assets	2			2,232			17			2
Other	43			113			16			14
Total sources of cash and cash equivalents	$	2,758		$	4,903		$	1,339		$	325
Uses of cash and cash equivalents
Cash additions to property, plant and equipment	$	(2,320	)	$	(2,230	)	$	(454	)	$	(1,452	)
Investing activities of discontinued operations	—			(233		)
Purchases of short-term investments	(925		)	—
Debt issuance costs	(19		)	—
Debt repayments	(34		)	(34		)
Dividends paid	(285		)	(260		)	(34		)	(142		)
Purchases of common stock	—			(1,000		)
Commercial paper, net	—			(135		)
Other	(1		)	(10		)	—			(3		)
Cash held for sale	—			(96		)
Total uses of cash and cash equivalents	$	(3,584	)	$	(3,998	)	$	(488	)	$	(1,597	)

~~Commodity prices began declining~~Cash flows generated from operating activities in the ~~second half~~first quarter of ~~2014 and remain substantially~~2016 were lower ~~through 2015~~ as ~~compared to~~ the ~~first six months of 2014.~~downturn in the commodity cycle continued. This ~~lower~~continued downward pressure on price ~~trend adversely impacted our cash flows in 2015. Partially offsetting~~realizations, coupled with the ~~decline in prices were increased~~lower net sales volumes, ~~in the North America E&P segment. While we are unable to predict future commodity price movements, if this lower price environment~~ continues ~~it would continue~~ to negatively impact our cash flows from operating ~~activities~~activities. In the first quarter of 2016, consolidated average liquids price realizations were down by approximately 35% and consolidated net sales volumes declined by 14% as compared to the ~~previous year.~~prior year quarter.

~~Borrowings reflect~~Common stock issuance reflects net proceeds received in March 2016 from ~~the issuance~~our public sale of ~~senior notes in June 2015.~~common stock. See Liquidity and Capital Resources below for additional information.

Cash flows from discontinued operations are primarily related to our Norway business, which we disposed of in the fourth quarter of 2014. Disposals of assets in the first six months of 2014 primarily reflect the net proceeds from the sales of our Angola assets. Disposition transactions are discussed in further detail in Note 5 to the consolidated financial statements.

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

Additions to property, plant and equipment are our most significant use of cash and cash equivalents. Total capital expenditures, including accruals, were 67% lower in the first quarter 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:


	Six Months Ended June 30,					Three Months Ended March 31,
(In millions)	2015		2014			2016		2015
North America E&P	$	1,484	$	1,969		$	315	$	933
International E&P	245		220			32		146
Oil Sands Mining	37		123			9		21
Corporate	14		13			3		2
Total capital expenditures	1,780		2,325			359		1,102
(Increase) decrease in capital expenditure accrual	540		(95		)
Decrease in capital expenditure accrual						95		350
Total use of cash and cash equivalents for property, plant and equipment	$	2,320	$	2,230		$	454	$	1,452

~~During the first six months of 2014,~~In October 2015, we ~~acquired 29 million common shares at a cost of $1 billion under~~announced an adjustment to our ~~share repurchase program, 13 million of which were acquired in the second quarter of 2014 at a cost of $449 million.~~quarterly dividend. See Capital Requirements below for additional information.

Liquidity and Capital Resources

~~On June 10, 2015,~~In March 2016, we issued ~~$2 billion aggregate principal amount~~166,750,000 shares of ~~unsecured senior notes which consist~~our common stock, par value $1 per share, at a price of ~~the following series:~~

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

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

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

~~Interest on each series of senior notes is payable semi-annually beginning December 1, 2015. We will use the aggregate~~$7.65 per share, excluding underwriting discounts and commissions, for net proceeds of $1,232 million. The proceeds will be used to ~~repay~~strengthen our ~~$1 billion 0.90% senior notes due 2015, which mature on November 1, 2015,~~balance sheet and for general corporate ~~purposes.~~purposes, including funding a portion of our Capital Program.

~~In May 2015,~~Also in March 2016, we ~~amended~~increased our ~~$2.5~~$3.0 billion unsecured ~~revolving credit facility (as so amended, the "Credit Facility") to increase the facility size~~Credit Facility by ~~$500~~$300 million to a total of $3 billion and extend the maturity date by an additional year such that the Credit Facility now matures in May 2020. The amendment additionally provides us the ability to request two one-year extensions to the maturity date and an option to increase the commitment amount by up to an additional $500 million, subject to the consent of any increasing lenders. The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively.$3.3 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain ~~unchanged.~~unaffected by the increase.

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

~~Outlook~~

~~We expect~~Due to decreases in crude oil and U.S. natural gas prices earlier this year, credit rating agencies recently reviewed many companies in the industry, including us. During the first quarter of 2016, our ~~capital, investment~~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 ~~exploration spending budget~~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. See Item 1A. Risk Factors in our Annual Report on Form 10-K for ~~full-year~~the year ended December 31, 2015 ~~to be at or below $3.3 billion and estimate full-year North America E&P and International E&P production volumes (excluding Libya) to be 375-390 net mboed.~~for a discussion of how a further downgrade in our credit ratings could affect us.

Capital Resources

Credit Arrangements and Borrowings

At ~~June 30, 2015,~~March 31, 2016, we had no borrowings against our revolving credit ~~facility and no amounts outstanding under our U.S. commercial paper program that is backed by the revolving credit~~ facility.

At ~~June 30, 2015,~~March 31, 2016, we had ~~$8.4~~$7.3 billion in long-term debt outstanding, with our next debt maturity in the amount of ~~which approximately $1.0 billion matures~~$680 million due in the fourth quarter of ~~2015.~~ 2017.

We do not have any triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit ratings.

Shelf Registration

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

~~Cash~~

Asset Disposals

Since August 2015, we have announced or closed non-core asset sales of approximately $1.3 billion, surpassing our targeted range of $750 million to $1 billion. In the largest transaction, we will divest all of our Wyoming upstream and ~~Short-Term Investments-Adjusted~~midstream assets for $870 million, before closing adjustments, with closing expected mid-year 2016. In separate transactions, we signed agreements for the sale of 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, before closing adjustments, with closing expected mid-year 2016.

Cash-Adjusted Debt-To-Capital Ratio

Our ~~cash and short-term investments-adjusted~~cash-adjusted debt-to-capital ratio (total debt-minus-cash and cash equivalents ~~and short-term investments~~ to total debt-plus-equity-minus-cash and cash ~~equivalents and short-term investments)~~equivalents) was ~~22%~~21% at ~~June 30, 2015,~~March 31, 2016, compared to ~~16%~~25% at December 31, ~~2014.~~2015.


	June 30,			December 31,			March 31,			December 31,
(In millions)	2015			2014			2016			2015
Long-term debt due within one year	$	1,035		$	1,068		$	1		$	1
Long-term debt	7,321			5,323			7,280			7,276
Total debt	$	8,356		$	6,391		$	7,281		$	7,277
Cash and cash equivalents	$	1,572		$	2,398		$	2,072		$	1,221
Short-term investments	$	925		$	—
Equity	$	20,218		$	21,020		$	19,351		$	18,553
Calculation:
Total debt	$	8,356		$	6,391		$	7,281		$	7,277
Minus cash and cash equivalents	1,572			2,398			2,072			1,221
Minus short-term investments	925			—
Total debt minus cash, cash equivalents and short-term investments	$	5,859		$	3,993
Total debt minus cash, cash equivalents							$	5,209		$	6,056
Total debt	$	8,356		$	6,391		$	7,281		$	7,277
Plus equity	20,218			21,020			19,351			18,553
Minus cash and cash equivalents	1,572			2,398			2,072			1,221
Minus short-term investments	925			—
Total debt plus equity minus cash, cash equivalents and short-term investments	$	26,077		$	25,013
Cash and short-term investments-adjusted debt-to-capital ratio	22		%	16		%
Total debt plus equity minus cash, cash equivalents							$	24,560		$	24,609
Cash-adjusted debt-to-capital ratio							21		%	25		%

Capital Requirements

~~As noted above in "Outlook," we expect our total capital, investment and exploration spending budget~~Our Board of Directors approved a Capital Program of $1.4 billion for ~~full-year 2015 to be at or below $3.3 billion.~~2016.

On ~~July 29, 2015,~~April 27, 2016, our Board of Directors approved a dividend of ~~$0.21~~$0.05 per share for the ~~second~~first quarter of ~~2015~~2016 payable ~~September~~June 10, ~~2015~~2016 to stockholders of record at the close of business on ~~August 19, 2015.~~May 18, 2016.

As of ~~June 30, 2015,~~March 31, 2016, we plan to make contributions of up to ~~$42~~$48 million to our funded pension plans during the remainder of ~~2015.~~2016.

Contractual Cash Obligations

As of ~~June 30, 2105,~~March 31, 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 our issuance of $2 billion aggregate principal amount of unsecured senior notes, as more fully described in Note~~ 15.10-K.

Environmental Matters

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

There have been no significant changes to our environmental matters subsequent to December 31, ~~2014.~~2015.

Other Contingencies

Forward-Looking Statements

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

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

changes in expected reserve or production levels;

changes in political or economic conditions in ~~key operating markets, including international markets;~~the jurisdictions in which we operate;

capital available for exploration and development;

well production timing;

availability of drilling rigs, materials and labor;

difficulty in obtaining necessary approvals and permits;

non-performance by third parties of contractual obligations;

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

cyber-attacks;

changes in safety, health, environmental and other regulations;

other geological, operating and economic considerations; and

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

All forward-looking statements included in this report are based on information available to us on the date of this report. Except as required by law, we assume 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 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 1211 and 1312 to the consolidated financial statements.

Commodity Price Risk During the first ~~six~~three months of ~~2015,~~2016, we entered into crude oil and natural gas derivatives, indexed to NYMEX WTI and Henry Hub, related to a portion of our forecasted North America E&P sales. The ~~table below provides~~following tables provide a summary of open positions as of ~~June 30, 2015:~~March 31, 2016 and the weighted average price for those contracts:


Financial Instrument	Weighted Average Price	Barrels per day	Remaining Term
Three-Way Collars
Crude Oil ^(a)				Crude Oil ^(a)
				2016			Year Ending December 31,
				Second Quarter	Third Quarter	Fourth Quarter	2017
Three-Way Collars ^(b)				Three-Way Collars ^(b)
Volume (Bbls/day)				39,000	37,000		—
Price per Bbl
Ceiling	$70.34	35,000	July- December 2015 ^(a)	$55.47	$54.52		—
Floor	$55.57			$51.56	$50.83		—
Sold put	$41.29			$41.67	$41.22		—

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)
Options ^(c)
Volume (Bbls/day)				10,000			25,000
Price per Bbl				$72.39			$60.67
Swaps
Volume (Bbls/day)				25,000	—
Price per Bbl				$39.25	—

^(a)


^(b)	~~Counterparty~~A counterparty has the option, exercisable on June 30, 2016, to extend ~~these~~three-way collars for 2,000 Bbls/day through the remainder of 2016 at ~~the same volume~~a ceiling of $73.13, floor of $65.00 and ~~weighted average price as the underlying three-way collars.~~sold put of $50.00.


^(c)	Call options settle monthly.



Natural Gas ^(a)
	2016			Year Ending December 31,
	Second Quarter	Third Quarter	Fourth Quarter	2017
Three-Way Collars ^(b)
Volume (MMBtu/day)	20,000	20,000	20,000	20,000
Price per MMBtu
Ceiling	$2.93	$2.93	$2.93	$3.07
Floor	$2.50	$2.50	$2.50	$2.75
Sold put	$2.00	$2.00	$2.00	$2.25


^(a)	Subsequent to March 31, 2016, we entered into 20,000 MMBtu/day of 2017 three-way collars with a ceiling price of $3.50, a floor price of $2.75, and a sold put price of $2.25.


^(b)	Counterparty has the option to execute fixed-price swaps (swaptions) at a weighted average price of $2.93 per MMBtu indexed to NYMEX Henry Hub, which is exercisable on December 22, 2016. If counterparty exercises, the 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.

The following table provides a sensitivity analysis of the projected incremental effect on income (loss) from operations of a hypothetical 10% change in NYMEX WTI and Henry Hub prices on our open commodity derivative instruments as of ~~June 30, 2015.~~March 31, 2016.


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

Crude oil derivatives						$	(46	)	$	38
Natural gas derivatives						(3		)	3
Total						$	(49	)	$	41

Interest Rate Risk Sensitivity analysis of the incremental effect of a hypothetical ~~10 percent~~10% change in interest rates on financial assets and liabilities as of ~~June 30, 2015,~~March 31, 2016, is provided in the following table.


(In millions)	Fair Value				Incremental Change in Fair Value			Fair Value				Incremental Change in Fair Value
Financial assets (liabilities):(a)
Interest rate swap agreements								$	12		^(b)	$	1
Long term debt, including amounts due within one year	$	(8,720	)	^(a)(b)	$	(288	)	$	(6,575	)	^(b)(c)	$	(310	)


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


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


^(b)(c)	Excludes capital leases.

Item 4. Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this Report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as of ~~June 30, 2015.~~March 31, 2016.

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

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

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

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

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


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


^(b)	~~Includes accruals.~~

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

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

Crude Oil and Condensate (mbbld)

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

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

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

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

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


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

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

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

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

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

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

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

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


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


^(e)	~~Includes blendstocks.~~

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

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

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

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

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

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


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


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

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

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

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

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

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

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


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

Part II – OTHER INFORMATION

Item 1. Legal and Administrative Proceedings

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 by Marathon Oil during the quarter ended ~~June 30, 2015,~~March 31, 2016, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Exchange Act of 1934.

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

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



	Total Number of	Average Price	Total Number of Shares Purchased as Part of Publicly Announced	Approximate Dollar Value of Shares that May Yet Be Purchased Under the
Period	Shares Purchased ^(a)	Paid per Share	Plans or Programs	Plans or Programs
01/01/16 - 01/31/16	4,032	$12.96	—	n/a
02/01/16 - 02/29/16	7,402	$8.01	—	n/a
03/01/16 - 03/31/16	290	$7.82	—	n/a
Total	11,724	$9.71	—


^(a)	~~161,719~~11,724 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

Item 6. Exhibits

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

SIGNATURES

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



~~August 6, 2015~~May 5, 2016		MARATHON OIL CORPORATION

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

Exhibit Index

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



		Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
Exhibit Number	Exhibit Description	Form	Exhibit	Filing Date
3.1	Restated Certificate of Incorporation of Marathon Oil Corporation	10-Q	3.1	8/8/2013
3.2	Marathon Oil Corporation By-laws (Amended and restated as of February 24, 2016)	8-K	3.1	3/1/2016
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
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	2017
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3730
Item 4.	Controls and Procedures	38
	~~Supplemental Statistics (Unaudited)~~	3931
Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	4432
Item 1A.	Risk Factors	4432
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4432
Item 6.	Exhibits	4432
	Signatures	4533



	Three Months Ended June 30, 2014
							Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	1,540	$	347	$	383	$	—			$	2,270
Marketing revenues	540		61		17		—				618
Total revenues	2,080		408		400		—				2,888
Income from equity method investments	—		120		—		—				120
Net gain (loss) on disposal of assets and other income	15		15		1		(98		)	^(c)	(67		)
Less:
Production expenses	217		99		246		—				562
Marketing costs	537		60		17		—				614
Exploration expenses	82		63		—		—				145
Depreciation, depletion and amortization	550		75		45		10				680
Impairments	4		—		—		—				4
Other expenses ^(a)	126		34		13		67			^(d)	240
Taxes other than income	102		—		6		1				109
Net interest and other	—		—		—		76				76
Income tax provision (benefit)	175		52		19		(95		)		151
Segment income/Income from continuing operations	$	302	$	160	$	55	$	(157	)		$	360
Capital expenditures ^(b)	$	1,102	$	115	$	55	$	10			$	1,282



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



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