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, ~~2016~~2017



[ ]	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 Rþ No £o

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 Rþ No £o

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



Large accelerated filer þ	Accelerated filero
Non-accelerated filer o ~~(Do~~	(Do not check if a smaller reporting company)
Smaller reporting companyo	Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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 ~~847,258,512~~849,834,915 shares of Marathon Oil Corporation common stock outstanding as of July 31, ~~2016.~~2017.

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~~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"~~“Definitions” in our ~~2015~~2016 Annual Report on Form 10-K.

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)


	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
(In millions, except per share data)	2016			2015			2016			2015			2017			2016			2017			2016
Revenues and other income:
Sales and other operating revenues, including related party	$	870		$	1,307		$	1,584		$	2,587		$	958		$	685		$	1,912		$	1,251
Marketing revenues	89			183			147			387			35			76			69			122
Income from equity method investments	37			26			51			62			51			37			120			51
Net gain (loss) on disposal of assets	294			—			234			1			6			294			7			234
Other income	12			15			16			26			9			11			23			15
Total revenues and other income	1,302			1,531			2,032			3,063			1,059			1,103			2,131			1,673
Costs and expenses:
Production	350			450			678			894			176			185			327			372
Marketing, including purchases from related parties	88			182			146			387			38			75			72			121
Other operating	95			81			204			188			111			87			200			190
Exploration	189			111			213			201			30			182			58			206
Depreciation, depletion and amortization	561			751			1,170			1,572			592			512			1,148			1,061
Impairments	—			44			1			44			—			—			4			1
Taxes other than income	39			78			87			145			45			35			84			78
General and administrative	132			168			283			339			93			131			202			282
Total costs and expenses	1,454			1,865			2,782			3,770			1,085			1,207			2,095			2,311
Income (loss) from operations	(152		)	(334		)	(750		)	(707		)	(26		)	(104		)	36			(638		)
Net interest and other	(86		)	(58		)	(171		)	(105		)	(86		)	(88		)	(164		)	(167		)
Income (loss) before income taxes	(238		)	(392		)	(921		)	(812		)
Income (loss) from continuing operations before income taxes													(112		)	(192		)	(128		)	(805		)
Provision (benefit) for income taxes	(68		)	(6		)	(344		)	(150		)	41			(54		)	75			(307		)
Income (loss) from continuing operations													(153		)	(138		)	(203		)	(498		)
Income (loss) from discontinued operations													14			(32		)	(4,893		)	(79		)
Net income (loss)	$	(170	)	$	(386	)	$	(577	)	$	(662	)	$	(139	)	$	(170	)	$	(5,096	)	$	(577	)
Net income (loss) per share:
Basic	$	(0.20	)	$	(0.57	)	$	(0.73	)	$	(0.98	)
Diluted	$	(0.20	)	$	(0.57	)	$	(0.73	)	$	(0.98	)
Per basic share:
Income (loss) from continuing operations													$	(0.18	)	$	(0.16	)	$	(0.24	)	$	(0.63	)
Income (loss) from discontinued operations													$	0.02		$	(0.04	)	$	(5.76	)	$	(0.10	)
Net income (loss)													$	(0.16	)	$	(0.20	)	$	(6.00	)	$	(0.73	)
Per diluted share:
Income (loss) from continuing operations													$	(0.18	)	$	(0.16	)	$	(0.24	)	$	(0.63	)
Income (loss) from discontinued operations													$	0.02		$	(0.04	)	$	(5.76	)	$	(0.10	)
Net income (loss)													$	(0.16	)	$	(0.20	)	$	(6.00	)	$	(0.73	)
Dividends per share	$	0.05		$	0.21		$	0.10		$	0.42		$	0.05		$	0.05		$	0.10		$	0.10
Weighted average common shares outstanding:
Basic	848			677			790			676			850			848			850			790
Diluted	848			677			790			676			850			848			850			790

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

MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income (Unaudited)


	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
(In millions)	2016			2015			2016			2015			2017			2016			2017			2016
Net income (loss)	$	(170	)	$	(386	)	$	(577	)	$	(662	)	$	(139	)	$	(170	)	$	(5,096	)	$	(577	)
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	19			86			(5		)	162			8			19			12			(5		)
Income tax provision (benefit)	(7		)	(30		)	2			(57		)	—			(7		)	—			2
Postretirement and postemployment plans, net of tax	12			56			(3		)	105			8			12			12			(3		)
Other, net of tax	(2		)	—			(2		)	—
Derivative hedges
Net unrecognized gain (loss)													(14		)	—			(13		)	—
Income tax provision													—			—			—			—
Derivative hedges, net of tax													(14		)	—			(13		)	—
Foreign currency hedges
Net recognized gain reclassified to discontinued operations													—			—			34			—
Income tax benefit (provision)													—			—			(4		)	—
Foreign currency hedges, net of tax													—			—			30			—
Other, Net of Tax													—			(2		)	—			(2		)

Other comprehensive income (loss)	10			56			(5		)	105			(6		)	10			29			(5		)
Comprehensive income (loss)	$	(160	)	$	(330	)	$	(582	)	$	(557	)	$	(145	)	$	(160	)	$	(5,067	)	$	(582	)

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)


	June 30,			December 31,			June 30,			December 31,
(In millions, except per share data)	2016			2015			2017			2016
Assets
Current assets:
Cash and cash equivalents	$	2,584		$	1,221		$	2,614		$	2,488
Receivables, less reserve of $4 and $4	822			912
Receivables, less reserve of $5 and $6							767			748
Notes receivable							742			—
Inventories	272			313			140			136
Other current assets	76			144			160			66
Current assets held for sale							1			227
Total current assets	3,754			2,590			4,424			3,665
Equity method investments	944			1,003			821			931
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $21,659 and $23,260	25,657			27,061
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $21,238 and $20,255							18,337			16,727
Goodwill	115			115			115			115
Other noncurrent assets	2,057			1,542			543			558
Noncurrent assets held for sale							1			9,098
Total assets	$	32,527		$	32,311		$	24,241		$	31,094
Liabilities
Current liabilities:
Accounts payable	$	953		$	1,313		$	1,158		$	967
Payroll and benefits payable	114			133			92			129
Accrued taxes	85			132			78			94
Other current liabilities	229			150			206			243
Long-term debt due within one year	1			1			548			686
Current liabilities held for sale							—			121
Total current liabilities	1,382			1,729			2,082			2,240
Long-term debt	7,280			7,276			6,715			6,581
Deferred tax liabilities	2,392			2,441			839			769
Defined benefit postretirement plan obligations	409			403			340			345
Asset retirement obligations	1,597			1,601			1,642			1,602
Deferred credits and other liabilities	314			308			211			225
Noncurrent liabilities held for sale							7			1,791
Total liabilities	13,374			13,758			11,836			13,553
Commitments and contingencies
Stockholders’ Equity
Preferred stock – no shares issued or outstanding (no par value,
26 million shares authorized)	—			—
Preferred stock – no shares issued or outstanding (no par value, 26 million shares authorized)							—			—
Common stock:
Issued – 937 million shares and 770 million shares (par value $1 per share,
1.1 billion shares authorized)	937			770
Securities exchangeable into common stock – no shares issued or
outstanding (no par value, 29 million shares authorized)	—			—
Held in treasury, at cost – 89 million and 93 million shares	(3,397		)	(3,554		)
Issued – 937 million shares and 937 million shares (par value $1 per share, 1.1 billion shares authorized)							937			937
Securities exchangeable into common stock – no shares issued or outstanding (no par value, 29 million shares authorized)							—			—
Held in treasury, at cost – 87 million and 90 million shares							(3,318		)	(3,431		)
Additional paid-in capital	7,433			6,498			7,349			7,446
Retained earnings	14,320			14,974			7,491			12,672
Accumulated other comprehensive loss	(140		)	(135		)	(54		)	(83		)
Total stockholders' equity	19,153			18,553			12,405			17,541
Total liabilities and stockholders' equity	$	32,527		$	32,311		$	24,241		$	31,094

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)


	Six Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2016			2015			2017			2016
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income (loss)	$	(577	)	$	(662	)	$	(5,096	)	$	(577	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations							4,893			79
Depreciation, depletion and amortization							1,148			1,061
Exploratory dry well costs and unproved property impairments							45			159
Net (gain) loss on disposal of assets							(7		)	(234		)
Deferred income taxes	(392		)	(185		)	38			(352		)
Depreciation, depletion and amortization	1,170			1,572
Impairments	1			44
Net (gain) loss on derivative instruments	88			17			(140		)	90
Net cash received (paid) in settlement of derivative instruments	46			4			3			44
Pension and other postretirement benefits, net	14			14
Exploratory dry well costs and unproved property impairments	166			148
Net (gain) loss on disposal of assets	(234		)	(1		)
Stock based compensation							26			26
Equity method investments, net	22			37			61			22
Changes in:
Current receivables	88			534			(15		)	92
Inventories	30			21			(5		)	25
Current accounts payable and accrued liabilities	(211		)	(770		)	(41		)	(207		)
All other operating, net	41			(56		)	13			39
Net cash provided by operating activities	252			717
Net cash provided by operating activities from continuing operations							923			267
Investing activities:
Additions to property, plant and equipment	(753		)	(2,320		)	(775		)	(728		)
Disposal of assets	758			2
Investments - return of capital	37			31
Purchases of short-term investments	—			(925		)
Deposit for acquisition	(89		)	—
Acquisitions, net of cash acquired							(1,828		)	—
Deposits for acquisitions							—			(89		)
Disposal of assets, net of cash transferred to buyer							1,726			758
Equity method investments - return of capital							49			37
All other investing, net	2			(1		)	(5		)	2
Net cash used in investing activities	(45		)	(3,213		)
Net cash used in investing activities from continuing operations							(833		)	(20		)
Financing activities:
Borrowings	—			1,996
Debt issuance costs	—			(19		)
Debt repayments	—			(34		)	(1		)	—
Common stock issuance	1,236			—			—			1,236
Purchases of common stock							(10		)	(4		)
Dividends paid	(77		)	(285		)	(85		)	(77		)
All other financing, net	—			11
Net cash provided by (used in) financing activities	1,159			1,669			(96		)	1,155
Cash Flow from Discontinued Operations:
Operating activities							141			(11		)
Investing activities							(13		)	(25		)
Changes in cash included in current assets held for sale							2			36
Net increase in cash and cash equivalents of discontinued operations							130			—
Effect of exchange rate on cash and cash equivalents	(3		)	1			2			(3		)
Net increase (decrease) in cash and cash equivalents	1,363			(826		)	126			1,399
Cash and cash equivalents at beginning of period	1,221			2,398			2,488			1,119
Cash and cash equivalents at end of period	$	2,584		$	1,572		$	2,614		$	2,518

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

1. Basis of Presentation

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

A reclassification between operating cash flow categories was made to the prior year's financial information to present it on a basis comparable with the current year's presentation with no impact on net cash provided by operating activities.

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our ~~2015~~2016 Annual Report on Form 10-K. The results of operations for the second quarter and first six months of ~~2016~~2017 are not necessarily indicative of the results to be expected for the full year.

As a result of the announcement to divest our Canadian business in the first quarter of 2017, we have reflected this business as discontinued operations in all periods presented. Assets and liabilities are presented as held for sale in the historical periods presented in the consolidated balance sheets. The disclosures in this report related to the results of operations and cash flows are presented on the basis of continuing operations, unless otherwise noted. This transaction closed in the second quarter of 2017. The characteristics and composition of our North America E&P reporting segment remained unchanged and there was no effect on previously reported segment information. As all our remaining properties within the segment are located within the United States, we concluded that our North America E&P segment would be renamed United States E&P segment, effective June 30, 2017. During the quarter no changes occurred to our International E&P segment. See Note 6 for discussion of the divestiture in further detail and Note 7 for further information on our reportable segments.

During the first quarter of 2017, we adopted the accounting standards update issued by the FASB in March 2016 pertaining to share-based payment transactions. See Note 2 for additional discussion. As a result of this adoption, all cash payments for withheld shares made to taxing authorities on the employees' behalf will be presented within the financing activities section instead of the operating activities section of the statement of cash flows. We have elected the retrospective method for adoption of this update and the change in the statement of cash flows is not material for six months ended June 30, 2016. Excess tax benefits will be classified as an operating activity within the statement of cash flows on a prospective basis; as such, prior periods were not adjusted. See Note 2 for additional discussion.

2. Accounting Standards

Not Yet Adopted

In March 2017, the FASB issued a new accounting standards update that will change how employers that sponsor defined pension and/or other postretirement benefit plans present the net periodic benefit cost in the income statement. Employers will present the service cost component of net periodic benefit cost in the same income statement line item(s) as other employee compensation costs arising from services rendered during the period. Only the service cost component will be eligible for capitalization in assets. This standard is effective for us in the first quarter of 2018 and shall be applied on a retrospective basis. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it may have on our results of operations, financial position, or cash flows.

In February 2017, the FASB issued a new accounting standards update that clarifies the accounting for the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. The standard also clarifies that the derecognition of all businesses (except those related to conveyances of oil and gas mineral rights or contracts with customers) should be accounted for in accordance with the derecognition and deconsolidation guidance in Subtopic 810-10. This standard is effective for us in the first quarter of 2018 and will be applied using the modified retrospective approach. Early adoption is permitted. We plan to adopt this new standard in the first quarter of 2018 concurrently with the new revenue recognition standard. 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 2017, the FASB issued a new accounting standards update that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities would not represent a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue guidance. This standard is effective for us in the first quarter of 2018 and shall be applied on a prospective basis. Early adoption is permitted for certain transactions as described in the guidance. Since we will adopt the standard on a prospective basis, we do not expect an impact on our consolidated results of operations, financial position or cash flows for prior periods.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

In January 2017, the FASB issued a new accounting standards update that eliminates the requirement to calculate the implied fair value of the goodwill (i.e., Step 2 of goodwill impairment test under the current guidance) to measure a goodwill impairment charge. The standard will require entities to record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value (i.e., measure the charge based on Step 1 under the current guidance). This standard is effective for us in the first quarter of 2020 and shall be applied on a prospective basis. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. Since we will adopt the standard on a prospective basis, we do not expect an impact on our consolidated results of operations, financial position or cash flows for prior periods.

In November 2016, the FASB issued a new accounting standards update that requires entities to show the changes in the total of cash, cash equivalents and restricted cash in the statement of cash flows. As a result, entities will no longer present transfers between cash and cash equivalents and restricted cash in the statement of cash flows. When cash, cash equivalents, and restricted cash are presented in more than one line item on the balance sheet, the standard requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. This reconciliation can be presented either on the face of the statement of cash flows or in the notes to the financial statements. This standard is effective for us in the first quarter of 2018 and shall be applied on a retrospective basis. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it may have on our consolidated statements of cash flows and related disclosures.

In August 2016, the FASB issued a new accounting standards update which seeks to reduce the existing diversity in practice in how certain transactions are classified in the statement of cash flows. This standard is effective for us in the first quarter of 2018 and shall be applied on a retrospective basis. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated statements of cash flows and related disclosures.

In June 2016, the FASB issued a new accounting standards update that changes the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. The standard requires the use of a forward-looking ~~"expected loss"~~“expected loss” model as opposed to the current ~~"incurred loss"~~“incurred loss” model. This standard is effective for us in the first quarter of 2020 and will be adopted on a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period. Early adoption is permitted starting January 2019. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.

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

In February 2016, the FASB issued a new lease accounting standard, which requires lessees to recognize most leases, including operating leases, on the balance sheet as a right of use asset and lease liability. Short-term leases can continue being accounted for off balance sheet based on a policy election. This standard does not apply to leases to explore for or use minerals, oil, natural gas and similar non-regenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained. This standard is effective for us in the first quarter of 2019 and should be applied using a modified retrospective approach at the beginning of the earliest period presented in the financial statements. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it ~~will~~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 the first quarter of 2018. Early adoption is allowed for certain provisions. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

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

In August 2014, the FASB issued an update that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards. This standard is effective for us for the annual period ending after December 15, 2016 and for annual periods and interim periods thereafter. Early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

~~MARATHON OIL CORPORATION~~

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

In May 2014 and August 2015, the FASB issued an update that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. Among other things, the standard requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for us in the first quarter of 2018 and ~~should~~shall be applied retrospectively to each prior reporting period presented (“full retrospective method”) or with the cumulative effect of initially applying the update recognized at the date of initial ~~application.~~application (“modified retrospective method”). While early adoption is permitted, we plan to adopt this new standard in the first quarter of ~~2018. We continue~~2018 using the modified retrospective method. Based on our assessment to ~~evaluate certain provisions~~date, we do not expect the adoption of this ~~accounting standards update and are assessing the impact it will~~ASU to have ~~on our consolidated results of operations, financial position or cash flows.~~

~~Recently Adopted~~

In May 2015, the FASB issued an update that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The amendment also removes certain disclosure requirements regarding all investments that are eligible to be measured using the net asset value per share practical expedient and only requires certain disclosures on those investments for which an entity elects to use the net asset value per share expedient. This standard is effective for us in the first quarter of 2016 and was applied on a ~~retrospective basis. This standard only modifies disclosure requirements; as such, there was no~~material impact on our consolidated results of operations, financial position or cash flows. However, we do expect to change our presentation of future marketing revenues and marketing expenses from the current gross presentation to a net presentation for a portion of our international contracts. For the six months ended June 30, 2017, we estimate this impact to be

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

approximately $50 million in marketing revenue and expenses in our consolidated results of operations. We continue to evaluate the disclosure requirements, are developing accounting policies, and assessing changes to the relevant business processes and the control activities as a result of this standard.

Recently Adopted

In ~~February 2015,~~March 2016, the FASB issued ~~an amendment~~a new accounting standards update that changes several aspects of accounting for share-based payment transactions, including a requirement to recognize all excess tax benefits and tax deficiencies as income tax expense or benefit in the ~~guidance for determining whether an entity is a variable interest entity ("VIE"). The standard does not add~~income statement, classification of awards as either equity or ~~remove any~~liabilities, and classification on the statement 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.cash flows. This standard iswas effective for us in the first quarter of ~~2016.~~2017. The new standard requires a company to make a policy election on how it accounts for forfeitures; we elected to continue estimating forfeitures using the same methodology practiced prior to adoption of this standard. See Note 1 for the impact this standard has on the presentation of our financial statements.

In July 2015, the FASB issued an update that requires an entity to measure inventory at the lower of cost or net realizable value. This excludes inventory measured using LIFO or the retail inventory method. This standard was effective for us in the first quarter of 2017, and was applied prospectively. 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~~During the second quarter of 2017 we closed on the sale of our Canadian business, which included our 20% undivided interest in the Athabasca Oil Sands Project ~~in which we hold a 20% undivided interest,~~(AOSP). The owners of the AOSP 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 was transferred to the purchaser of our Canadian business upon closing of the sale in the second quarter of 2017. Historically, this contract ~~are accrued and recorded on a monthly basis, with current liabilities of $2 million recorded at June 30, 2016 and December 31, 2015. This contract qualifies~~qualified as a variable interest contractual arrangement, and the Corridor Pipeline ~~qualifies~~qualified as a VIE. ~~We hold a~~Prior to the closing of the sale of our Canadian business, we held this variable interest but ~~are~~were not the primary beneficiary because our shipments ~~are~~were only 20% of the total; therefore, the Corridor Pipeline iswas 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 $468 million as of June 30, 2016. The liability on our books related to this contract at any given time will reflect amounts dueSee Note 6 for ~~the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term.~~further discussion regarding dispositions.

~~MARATHON OIL CORPORATION~~

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


4.	Income (Loss) per Common Share

Basic income (loss) per share is based on the weighted average number of common shares outstanding. Diluted income per share assumes exercise of stock options in all years, provided the effect is not antidilutive. The per share calculations below exclude 12 million stock options for the three and six month periods ended June 30, 2017 and 14 million stock options for the three and six month periods ended June 30, 2016 ~~and 13 million stock options for the three and six month periods ended June 30, 2015~~ that were antidilutive.

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

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



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions, except per share data)	2017			2016			2017			2016
Income (loss) from operations	$	(153	)	$	(138	)	$	(203	)	$	(498	)
Income (loss) from discontinued operations	14			(32		)	(4,893		)	(79		)
Net income (loss)	$	(139	)	$	(170	)	$	(5,096	)	$	(577	)

Weighted average common shares outstanding	850			848			850			790
Per basic share:
Income (loss) from continuing operations	$	(0.18	)	$	(0.16	)	$	(0.24	)	$	(0.63	)
Income (loss) from discontinued operations	$	0.02		$	(0.04	)	$	(5.76	)	$	(0.10	)
Net income	$	(0.16	)	$	(0.20	)	$	(6.00	)	$	(0.73	)
Per diluted share:
Income (loss) from continuing operations	$	(0.18	)	$	(0.16	)	$	(0.24	)	$	(0.63	)
Income (loss) from discontinued operations	$	0.02		$	(0.04	)	$	(5.76	)	$	(0.10	)
Net income	$	(0.16	)	$	(0.20	)	$	(6.00	)	$	(0.73	)

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

5. Acquisitions

2017 - United States E&P

In ~~June 2016,~~the second quarter of 2017 we ~~executed a purchase agreement~~closed on our acquisitions to acquire ~~PayRock Energy Holdings, LLC ("PayRock"), a portfolio company~~approximately 91,000 net acres in the Permian basin, including over 70,000 net acres in the Northern Delaware basin of ~~EnCap Investments, which~~New Mexico. On May 1, 2017 we closed on ~~August 1, 2016~~our acquisition with BC Operating, Inc. and other entities for ~~$888 million,~~$1.1 billion in cash, subject to ~~closing adjustments. PayRock has~~post-closing adjustments, to acquire approximately ~~61,000~~70,000 net surface acres and current production of approximately ~~9,000~~5,000 net barrels of oil equivalent per day. On June 1, 2017 we closed on our acquisition with Black Mountain Oil & Gas and other private sellers for approximately $700 million in cash, subject to post-closing adjustments, to acquire approximately 21,000 net surface acres. The purchase price for these acquisitions was paid with cash on hand. We accounted for these transactions as asset acquisitions, with substantially all of the purchase price allocated to unproved property within property, plant and equipment. Although the purchase price allocation has not been finalized, we do not expect to record any material adjustments to the preliminary purchase price allocation.

2016 - United States E&P

On August 1, 2016, we closed on our acquisition of PayRock Energy Holdings, LLC (“PayRock”), a portfolio company of EnCap Investments, including approximately 61,000 net surface acres in the oil window of the Anadarko Basin STACK play in Oklahoma. ~~In the second quarter of 2016 an $89 million deposit was paid into escrow related to the acquisition.~~ The purchase price of $904 million, subject to closing adjustments, was paid with cash on hand. We accounted for this transaction as an asset acquisition, with ~~the~~a majority of the purchase price allocated to unproved property within property, plant and equipment.


6.	Dispositions

~~2016 -~~Oil Sands Mining Segment

On May 31, 2017 we closed on the sale of our Canadian business, which includes our 20% non-operated interest in the AOSP to Shell and Canadian Natural Resources Limited (“CNRL”) for $2.5 billion, excluding closing adjustments. Under the terms of the agreement, $1.8 billion was paid to us upon closing and the remaining proceeds will be paid in the first quarter of 2018. At closing we received two notes receivable for the remaining proceeds, each with a face value of $375 million. We initially recorded these notes receivable at fair value and, in subsequent periods, will report them at amortized cost. See Note 13 for fair value measurements. Our notes receivable are with 10084751 Canada Limited (“Canada Limited”), an affiliate of Shell Canada Limited, and CNRL. The Canada Limited note receivable is guaranteed by Shell Canada Limited and the CNRL note receivable is guaranteed by Toronto Dominion Bank. In the first quarter of 2017, we recorded an after-tax non-cash impairment charge of $4.96 billion primarily related to the property, plant and equipment of our Canadian business. As the effective date of the transaction is January 1, 2017, we recorded a loss on sale of $43 million due to second quarter results of operations from our Canadian business that were recorded in our financial statements but transferred to the buyer upon closing.

Our Canadian business is reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for all periods presented. The following table contains select amounts reported in our consolidated statements of income as discontinued operations:



	Three Months Ended June 30,							Six Months Ended June 30,
(In millions)		2017			2016			2017			2016
Total sales and other revenues and other income		$	173		$	199		$	431		$	359
Net gain (loss) on disposal of assets		(43		)	—			(43		)	—
Total revenues and other income		130			199			388			359
Costs and expenses:
Production expenses		103			165			254			306
Depreciation, depletion and amortization		1			49			40			109
Impairments		—			—			6,636			—
Other		12			31			25			60
Total costs and expenses		116			245			6,955			475
Pretax income (loss) from discontinued operations		14			(46		)	(6,567		)	(116		)
Provision (benefit) for income taxes		—			(14		)	(1,674		)	(37		)
Income (loss) from discontinued operations		$	14		$	(32	)	$	(4,893	)	$	(79	)

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The following table presents the carrying value of the major categories of assets and liabilities of our Canadian business reported as discontinued operations and assets and liabilities from continuing operations, that are reflected as held for sale on our consolidated balance sheets at June 30, 2017 and December 31, 2016:



	June 30,		December 31,
(In millions)	2017		2016
Assets held for sale
Current assets:
Cash and cash equivalents	$	—	$	2
Accounts receivables	—		129
Inventories	—		91
Other	—		4
Total current assets held for sale—discontinued operations	—		226
Total current assets held for sale—continuing operations	1		1
Total current assets held for sale	$	1	$	227

Noncurrent assets:
Property, plant and equipment, net	$	—	$	8,991
Other	—		106
Total noncurrent assets held for sale—discontinued operations	—		9,097
Total noncurrent assets held for sale—continuing operations	1		1
Total noncurrent assets held for sale	$	1	$	9,098

Liabilities associated with assets held for sale
Current liabilities:
Accounts payable	$	—	$	111
Other	—		10
Total current liabilities held for sale—discontinued operations	—		121
Total current liabilities held for sale—continuing operations	—		—
Total current liabilities held for sale	$	—	$	121

Noncurrent liabilities:
Asset retirement obligations	$	—	$	95
Deferred tax liabilities	—		1,669
Other	—		20
Total noncurrent liabilities held for sale—discontinued operations	—		1,784
Total noncurrent liabilities held for sale—continuing operations	7		7
Total noncurrent liabilities held for sale	$	7	$	1,791

United States E&P Segment

As disclosed above, we closed on the sale of our Canadian business in May of 2017. This sale included interests in our exploration stage in-situ leases which were included within our historically named North America E&P ~~Segment~~Segment. See Note 1 for further detail. These interests have been reflected as discontinued operations and are included within the disclosure above.

~~During the quarter,~~In April 2016, we announced the sale of our Wyoming upstream and midstream ~~assets for~~assets. During the second quarter 2016, we received proceeds of ~~$870 million, before closing adjustments, of which~~ approximately $690 million ~~was received in the second quarter. A~~and recorded a pre-tax gain of $266 million with the remaining asset sales closing in November 2016 for proceeds of $155 million, excluding closing adjustments. A pre-tax gain of $38 million was recognized in the ~~second~~fourth quarter 2016. ~~The remaining asset sales are subject~~

MARATHON OIL CORPORATION

Notes to the receipt of certain tribal consents and are expected to close before year end. These assets are classified as held for sale in the consolidated balance sheet as of June 30, 2016 with total assets of $104 million and total liabilities of $4 million. The proceeds for the remaining asset sales were deposited into an escrow account by the buyer.Consolidated Financial Statements (Unaudited)

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 and New Mexico, for a combined total of approximately $80 million in ~~proceeds, before closing adjustments.~~proceeds. We closed on certain of the asset sales and recognized a net pre-tax ~~net~~ loss on sale of $48 million ~~for the six months ended June 30, 2016. The remaining asset sales are expected to close by year-end.~~

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

In the third quarter of 2015, we closed on the sale of our East Texas/North Louisiana and Wilburton, Oklahoma natural gas assets for proceeds of approximately $100 million and recorded a pretax loss of $1 million. Duringin the second quarter of ~~2015, we recorded a non-cash impairment charge~~2016, with the remaining Piceance basin asset sale expected to close in the second half of ~~$44 million related to these assets as a result of the anticipated sale (see Note 13).~~

2017.

~~MARATHON OIL CORPORATION~~

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

7. Segment Information

We have ~~three~~two reportable operating segments. ~~Each~~Both of these segments isare organized and managed based upon ~~both~~ geographic location and the nature of the products and services ~~it offers.~~offered.

~~N.A.~~U.S. E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in ~~North America;~~the United States

~~Int'l~~Int’l E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of ~~North America~~the United States and produces and markets products manufactured from natural gas, such as 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.~~

Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”). Segment income (loss) represents income (loss) which excludes certain items not allocated to segments, net of income taxes, attributable to the operating segments. 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. Additionally, items which affect comparability such as: gains or losses on dispositions, certain impairments, ~~change in tax expense associated with a tax rate change,~~ unrealized gains or losses on commodity derivative instruments, pension settlement losses or other items (as determined by the CODM) are not allocated to operating segments.

As discussed in Note 6, we closed on the sale of our Canadian business, which includes our Oil Sands Mining segment and exploration stage in-situ leases, in the second quarter of 2017. The Canadian business is reflected as discontinued operations and is excluded from segment information in all periods presented. Additionally, we have renamed our North America E&P segment to United States E&P segment effective June 30, 2017 in all periods presented. See Note 1 for further information.


	Three Months Ended June 30, 2016																Three Months Ended June 30, 2017
										Not Allocated												Not Allocated
(In millions)	N.A. E&P			Int'l E&P			OSM			to Segments				Total			U.S. E&P			Int'l E&P		to Segments				Total
Sales and other operating revenues	$	617		$	159		$	185		$	(91	)	^(c)	$	870		$	695		$	220	$	43		^(c)	$	958
Marketing revenues	53			23			13			—				89			7			28		—				35
Total revenues	670			182			198			(91		)		959			702			248		43				993
Income from equity method investments	—			37			—			—				37			—			51		—				51
Net gain on disposal of assets and other income	2			7			1			296			^(d)	306			2			4		9				15
Less:
Production expenses	129			56			165			—				350			118			58		—				176
Marketing costs	52			23			13			—				88			9			29		—				38
Exploration expenses	37			4			7			141			^(e)	189			30			—		—				30
Depreciation, depletion and amortization	433			68			49			11				561			495			89		8				592
Other expenses ^(a)	97			22			9			99			^(f)	227			126			22		56			^(d)	204
Taxes other than income	35			—			4			—				39			33			—		12				45
Net interest and other	—			—			—			86				86			—			—		86				86
Income tax benefit	(41		)	(2		)	(10		)	(15		)		(68		)
Segment income (loss) / Net income (loss)	$	(70	)	$	55		$	(38	)	$	(117	)		$	(170	)
Income tax provision (benefit)																	—			46		(5		)		41
Segment income (loss) / Income (loss) from continuing operations																	$	(107	)	$	59	$	(105	)		$	(153	)
Capital expenditures ^(b)	$	153		$	12		$	7		$	5			$	177		$	575		$	14	$	10			$	599


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


^(b)	Includes accruals.


^(c)	Unrealized gain on commodity derivative instruments.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


^(d)	Includes pension settlement loss of $3 million. (See Note 8.)



	Three Months Ended June 30, 2016
							Not Allocated
(In millions)	U.S. E&P			Int'l E&P			to Segments				Total
Sales and other operating revenues	$	617		$	159		$	(91	)	^(c)	$	685
Marketing revenues	53			23			—				76
Total revenues	670			182			(91		)		761
Income from equity method investments	—			37			—				37
Net gain on disposal of assets and other income	2			7			296			^(d)	305
Less:
Production expenses	129			56			—				185
Marketing costs	52			23			—				75
Exploration expenses	37			4			141			^(e)	182
Depreciation, depletion and amortization	433			68			11				512
Other expenses ^(a)	97			22			99			^(f)	218
Taxes other than income	35			—			—				35
Net interest and other	—			—			88				88
Income tax provision (benefit)	(41		)	(2		)	(11		)		(54		)
Segment income (loss) / Income (loss) from continuing operations	$	(70	)	$	55		$	(123	)		$	(138	)
Capital expenditures ^(b)	$	153		$	12		$	5			$	170


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


^(b)	Includes accruals.


^(c)	Unrealized loss on commodity derivative instruments.


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


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


^(f)	Includes pension settlement loss of $31 million (See ~~note~~Note 8).

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


	Three Months Ended June 30, 2015															Six Months Ended June 30, 2017
									Not Allocated												Not Allocated
(In millions)	N.A. E&P			Int'l E&P		OSM			to Segments				Total			U.S. E&P			Int'l E&P		to Segments				Total
Sales and other operating revenues	$	993		$	211	$	147		$	(44	)	^(c)	$	1,307		$	1,369		$	423	$	120		^(c)	$	1,912
Marketing revenues	110			30		43			—				183			13			56		—				69
Total revenues	1,103			241		190			(44		)		1,490			1,382			479		120				1,981
Income from equity method investments	—			26		—			—				26			—			120		—				120
Net gain on disposal of assets and other income	11			4		—			—				15			7			14		9				30
Less:
Production expenses	179			64		207			—				450			227			100		—				327
Marketing costs	112			29		41			—				182			16			56		—				72
Exploration expenses	91			20		—			—				111			56			2		—				58
Depreciation, depletion and amortization	634			71		35			11				751			967			164		17				1,148
Impairments	—			—		—			44			^(d)	44			4			—		—				4
Other expenses ^(a)	99			19		9			122			^(e)	249			233			43		126			^(d)	402
Taxes other than income	67			—		5			6				78			72			—		12				84
Net interest and other	—			—		—			58				58			—			—		164				164
Income tax provision (benefit)	(23		)	27		(30		)	20			^(f)	(6		)	—			96		(21		)		75
Segment income (loss) / Net income (loss)	$	(45	)	$	41	$	(77	)	$	(305	)		$	(386	)
Segment income (loss) / Income (loss) from continuing operations																$	(186	)	$	152	$	(169	)		$	(203	)
Capital expenditures ^(b)	$	551		$	99	$	16		$	12			$	678		$	924		$	23	$	11			$	958


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


^(b)	Includes accruals.


^(c)	Unrealized gain on commodity derivative instruments.


^(d)	Includes pension settlement loss of $17 million. (See Note 8.)



	Six Months Ended June 30, 2016
							Not Allocated
(In millions)	U.S. E&P			Int'l E&P			to Segments				Total
Sales and other operating revenues	$	1,110		$	255		$	(114	)	^(c)	$	1,251
Marketing revenues	84			38			—				122
Total revenues	1,194			293			(114		)		1,373
Income from equity method investments	—			51			—				51
Net gain on disposal of assets and other income	3			13			233			^(d)	249
Less:
Production expenses	263			109			—				372
Marketing costs	84			37			—				121
Exploration expenses	55			10			141			^(e)	206
Depreciation, depletion and amortization	920			118			23				1,061
Impairments	1			—			—				1
Other expenses ^(a)	215			38			219			^(f)	472
Taxes other than income	77			—			1				78
Net interest and other	—			—			167				167
Income tax provision (benefit)	(153		)	(14		)	(140		)		(307		)
Segment income (loss) / Income (loss) from continuing operations	$	(265	)	$	59		$	(292	)		$	(498	)
Capital expenditures ^(b)	$	468		$	44		$	8			$	520


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


^(b)	Includes accruals.


^(c)	Unrealized loss on commodity derivative instruments.


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


^(e)	~~Includes pension settlement loss of $64 million (see Note 8).~~


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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Six Months Ended June 30, 2016
Not Allocated
(In millions) N.A. E&P Int'l E&P OSM to Segments Total
Sales and other operating revenues $ 1,110
$ 255
$ 333
$ (114 )
^(c)
$ 1,584
Marketing revenues 84
38
25
—
147
Total revenues 1,194
293
358
(114 ) 1,731
Income from equity method investments —
51
—
—
51
Net gain on disposal of assets and other income 3
13
1
233
^(d)
250
Less:
Production expenses 263
109
306
—
678
Marketing costs 84
37
25
—
146
Exploration expenses 55
10
7
141
^(e)
213
Depreciation, depletion and amortization 920
118
109
23
1,170
Impairments 1
—
—
—
1
Other expenses ^(a)
215
38
16
218
^(f)
487
Taxes other than income 77
—
9
1
87
Net interest and other —
—
—
171
171
Income tax benefit (153 ) (14 ) (27 ) (150 ) (344 )
Segment income (loss) / Net income (loss) $ (265 ) $ 59
$ (86 ) $ (285 ) $ (577 )
Capital expenditures ^(b)
$ 468
$ 44
$ 16
$ 8
$ 536


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

~~(b)Includes accruals.~~


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


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


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


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

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


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


^(b)	~~Includes accruals.~~


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


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


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


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

~~MARATHON OIL CORPORATION~~

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

8. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:


	Three Months Ended June 30,												Three Months Ended June 30,
	Pension Benefits						Other Benefits						Pension Benefits						Other Benefits
(In millions)	2016			2015			2016			2015			2017			2016			2017			2016
Service cost	$	6		$	12		$	1		$	1		$	5		$	6		$	—		$	1
Interest cost	10			13			2			2			7			10			2			2
Expected return on plan assets	(13		)	(17		)	—			—			(10		)	(13		)	—			—
Amortization:
– prior service cost (credit)	(3		)	(2		)	(1		)	(1		)	(2		)	(3		)	(1		)	(1		)
– actuarial loss	4			7			—			—			2			4			—			—
Net settlement loss ^(a)	31			64			—			—			3			31			—			—
Net curtailment loss ^(b)	—			—			—			2
Net periodic benefit cost	$	35		$	77		$	2		$	4		$	5		$	35		$	1		$	2


	Six Months Ended June 30,												Six Months Ended June 30,
	Pension Benefits						Other Benefits						Pension Benefits						Other Benefits
(In millions)	2016			2015			2016			2015			2017			2016			2017			2016
Service cost	$	12		$	24		$	2		$	2		$	11		$	12		$	1		$	2
Interest cost	21			27			5			5			15			21			4			5
Expected return on plan assets	(28		)	(36		)	—			—			(22		)	(28		)	—			—
Amortization:
– prior service cost (credit)	(5		)	(1		)	(2		)	(2		)	(4		)	(5		)	(3		)	(2		)
– actuarial loss	7			14			—			—			4			7			—			—
Net settlement loss ^(a)	79			81			—			—			17			79			—			—
Net curtailment loss (gain) ^(b)	—			1			—			(4		)
Net periodic benefit cost	$	86		$	110		$	5		$	1		$	21		$	86		$	2		$	5


^(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~~plan’s total service and interest cost for that year.


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

During the first six months of ~~2016,~~2017, we recorded the effects of settlements of our U.S. pension plans. As required, we remeasured the ~~plans'~~plans’ assets and liabilities as of the applicable balance sheet dates. The cumulative effects of these events are included in the remeasurement and reflected in both the pension liability and net periodic benefit cost.

During the first six months of ~~2016,~~2017, we made contributions of ~~$30~~$27 million to our funded pension ~~plans. We~~plans and we expect to make additional contributions up to an estimated ~~$34~~$33 million ~~to our funded pension plans~~ over the remainder of ~~2016.~~2017. During the first six months of ~~2016,~~2017, we made payments of ~~$37~~$8 million and ~~$10~~$12 million related to unfunded pension plans and other postretirement benefit plans, respectively.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

9. Income Taxes

Effective Tax Rate

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

~~Our~~ For the second quarter and first six months of 2017 and 2016, our effective income tax rates on continuing operations were as follows:



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2017			2016			2017			2016
Total pre-tax income (loss) from continuing operations	$	(112	)	$	(192	)	$	(128	)	$	(805	)
Total income tax expense (benefit)	$	41		$	(54	)	$	75		$	(307	)
Effective income tax expense (benefit) rate on continuing operations	37		%	(28		)%	59		%	(38		)%

Income taxes at the statutory tax rate of 35%	$	(39	)	$	(67	)	$	(45	)	$	(282	)
Effects of foreign operations	2			5			(2		)	(30		)
Adjustments to valuation allowances	76			5			133			5
State income taxes	—			3			(13		)	(3		)
Other federal tax effects	2			—			2			3
Income tax expense (benefit) on continuing operations	$	41		$	(54	)	$	75		$	(307	)

Income tax expense for the second quarter and first six months of 2017 was impacted by a full valuation allowance on our federal deferred tax assets generated in 2017 and increased sales volumes in our Libyan operations where the statutory income tax rate is in excess of 90%. Our Libya income tax expense was $32 million in the second quarter and $77 million in the first six months of 2017 compared to a benefit of $10 million and $21 million for the same periods last year.

In the first six months of 2017 we settled our 2011-2013 Alaska income tax audit, which resulted in the recognition of a tax benefit totaling $13 million. As of June 30, 2017 there are no uncertain tax positions for which it is reasonably possible that the amount would significantly increase or decrease in the next twelve months. However, as discussed in Note 20, we may be required to adjust the timing of our tax deduction for decommissioning costs and make a payment to the U.K. tax authorities of approximately $130 million in the next twelve months, which would be recovered as future decommissioning activities are performed and deductions claimed. We estimate that any revisions to current and deferred tax liabilities, if we do not prevail, would have no cumulative adverse earnings impact in our consolidated results of operations. While we believe that it is more likely than not that we will prevail in the Tribunal, if we do not, we have the option to seek appeal.

The effective tax rate change between years for the second quarter and first six months of 2017 and 2016, was driven by the full valuation allowance on our federal deferred tax assets generated in 2017, and the impacts of foreign operations which includes the tax effects associated with increased sales volumes in Libya.

The impact of foreign operations for the second quarter and first six months of 2017 totaled tax expense of $2 million for three months ended June 30, 2017 and a tax benefit of $2 million for the first six months of ~~2016~~2017 due to income tax rate differentials from the U.S. statutory rate of 35% associated with foreign operations in Libya, E.G. and ~~2015 were 37% and 18%.~~ the U.K. This was offset by deferred tax benefits being generated in the U.K. related to future tax refunds associated with abandonment costs.

In Libya, ~~considerable uncertainty remains around the timing of future production and sales levels. Reliable~~reliable estimates of ~~2016~~2017 and ~~2015 Libyan~~2016 annual ordinary income from our Libyan operations could not be made, and the range of possible scenarios in the worldwide annual effective tax rate calculation demonstrates significant variability. Thus, the tax ~~benefit~~impacts applicable to Libyan ordinary ~~loss was~~

~~MARATHON OIL CORPORATION~~

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

income (loss) were recorded as a discrete item in the ~~first six months of 2016~~second quarter and ~~2015. For~~ the first six months of ~~2016~~2017 and ~~2015,~~2016. For the second quarter and the first six months of 2017 and 2016, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss). Excluding Libya, the effective income tax expense and benefit rates would be ~~36%~~an expense of 7% and ~~15%~~a benefit of 25% for the second quarter of 2017 and 2016. Excluding Libya, the effective income tax expense and benefit rates would be a benefit of 1% and 36% for the first six months of ~~2016~~2017 and ~~2015. The change was driven by~~2016.

We expect to be in a ~~shift~~cumulative loss position in ~~jurisdictional income~~2017, and ~~tax legislation enacted by the Alberta government on June 29, 2015 to increase the provincial corporate tax rate from 10% to 12%. As~~as a result ~~of this legislation,~~ we ~~recorded additional non-cash~~have placed a full valuation allowance on our federal deferred tax ~~expense of $135 million in~~assets. In the second quarter and first six months of ~~2015.~~ 2017 this valuation allowance was $76 million and

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

$133 million. During 2017 we expect to realize no tax benefit on any federal deferred tax assets generated. See Deferred Tax Assets section below for further detail.

Deferred Tax Assets

In connection with our assessment of the realizability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of our deferred tax assets will not be realized. In the event it is more likely than not that some portion or all of our deferred taxes will not be realized, such assets are reduced by a valuation allowance. ~~Future increases to~~The estimated realizability of the benefit of our ~~valuation allowance are possible if our estimates~~deferred tax asset is assessed considering a preponderance of evidence. This assessment requires analysis of all available positive and ~~assumptions (particularly as they relate to our long-term commodity price forecast) are revised such that they reduce estimates~~negative evidence. Positive evidence includes reversals of temporary differences, forecasts of future taxable income, ~~during~~assessment of future business assumptions and applicable tax planning strategies. Negative evidence includes losses in recent years as well as the ~~carryforward~~forecasts of future income (loss) in the realizable period. As of the fourth quarter of 2016, we expected to be in a cumulative loss position in 2017, which constitutes significant objective negative evidence as to the future realizability of the value of our federal deferred tax assets. Due to this negative evidence, we placed a full valuation allowance on our federal deferred tax assets in the fourth quarter of 2016 and expect to realize no tax benefit on any federal deferred tax assets generated in 2017.

10. ~~Short-term Investments~~

As of June 30, 2015, we held short-term investments comprised of bank time deposits with original maturities of greater than three months and remaining maturities of less than twelve months. These short-term investments, which were classified as held-to-maturity investments and recorded at amortized cost, matured in the third quarter of 2015.

~~11.~~ Inventories

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


	June 30,		December 31,		June 30,		December 31,
(In millions)	2016		2015		2017		2016
Liquid hydrocarbons, natural gas and bitumen	$	31	$	35
Crude oil and natural gas					$	11	$	6
Supplies and other items	241		278		129		130
Inventories, at cost	$	272	$	313
Inventories					$	140	$	136

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


	June 30,		December 31,		June 30,		December 31,
(In millions)	2016		2015		2017		2016
North America E&P	$	13,965	$	15,226
United States E&P					$	15,888	$	14,158
International E&P	2,479		2,533		2,358		2,470
Oil Sands Mining	9,101		9,197
Corporate	112		105		91		99
Net property, plant and equipment	$	25,657	$	27,061	$	18,337	$	16,727

Our Libya operations ~~continue~~have been interrupted in recent years due to ~~be impacted by~~ civil unrest. ~~Operations were interrupted~~On September 14, 2016, Force Majeure was lifted and production resumed in mid-2013 as a result of the shutdown of the Es-Sider crude oil terminal, and although temporarily re-opened during the second half of 2014, production remains shut-in. Earlier this year, an Internationally-backed Unity Government was established in Tripoli. During the second quarter, the two National Oil Companies agreed to unify and reportedly have begun preliminary discussions on re-opening the Es-Sider and other crude oil terminals which, if successful, will allow resumption of production operationsOctober 2016 at our Waha ~~concessions. However, considerable uncertainty remains around~~concession. During December 2016, liftings resumed from the ~~timing~~Es Sider crude oil terminal. Sales volumes and production continued during the first six months of ~~future production and sales levels.~~2017, except for a brief interruption in March 2017 due to civil unrest.

As of June 30, ~~2016,~~2017, our net property, plant and equipment investment in Libya is ~~$775~~$767 million, and total proved reserves (unaudited) in Libya as of December 31, ~~2015~~2016 are ~~235~~206 million barrels of oil equivalent ~~("mmboe"~~(“mmboe”). We and our partners in the Waha concessions continue to assess the situation and the condition of our assets in Libya. Our periodic assessment of the carrying value of our net property, plant and equipment in Libya specifically considers the net investment in the assets, the duration of our concessions and the reserves anticipated to be recoverable in future periods. The undiscounted cash flows related to our Libya assets continue to exceed the carrying value of ~~$775~~$767 million by a ~~material~~significant amount. ~~However, changes in~~

~~MARATHON OIL CORPORATION~~

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

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

Exploratory well costs capitalized greater than one year after completion of drilling were ~~$118~~$96 million and ~~$85~~$118 million as of June 30, ~~2016~~2017 and December 31, ~~2015.~~2016. The ~~$33~~decrease in costs of $22 million ~~increase~~was primarily ~~relates~~due to an April 2017 approval by the host government in E.G. to develop Block D offshore E.G. through unitization with the Alba ~~Block Sub Area B offshore Equatorial Guinea where~~field. As such, the ~~Rodo~~$22 million exploratory well ~~reached total depth~~costs capitalized greater than one year after completion associated with the Corona well are no longer being deferred.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

12. Impairments and Exploration Expenses

As a result of our announced disposition of our Canadian business in the first quarter of ~~2015. We have since completed~~2017, we recorded a ~~seismic feasibility study~~pre-tax non-cash impairment charge of $6.6 billion primarily related to property, plant and ~~continue to finalize next steps~~equipment. This impairment in our Canadian business is reflected as discontinued operations in the ~~Alba Block Sub Area B~~consolidated statements of income and the consolidated statements of cash flows for all periods presented. See Note 6 for relevant detail regarding dispositions.

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



	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2017		2016		2017		2016
Exploration Expenses
Unproved property impairments	$	25	$	133	$	45	$	144
Dry well costs	—		15		—		15
Geological and geophysical	—		—		1		—
Other	5		34		12		47
Total exploration expenses	$	30	$	182	$	58	$	206

13. Fair Value Measurements

Fair Values - Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of June 30, ~~2016~~2017 and December 31, ~~2015~~2016 by fair value hierarchy level.


	June 30, 2016								June 30, 2017
(In millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity^(a)	$	—	$	6	$	—	$	6	$	—	$	60	$	—	$	60
Interest rate	—		12		—		12		—		54		—		54
Derivative instruments, assets	$	—	$	18	$	—	$	18	$	—	$	114	$	—	$	114
Derivative instruments, liabilities
Commodity^(a)	$	—	$	70	$	—	$	70	$	—	$	—	$	—	$	—
Derivative instruments, liabilities	$	—	$	70	$	—	$	70	$	—	$	—	$	—	$	—


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


	December 31, 2015								December 31, 2016
(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		—		68		—		68
Derivative instruments, assets	$	—	$	59	$	—	$	59	$	—	$	68	$	—	$	68
Derivative instruments, liabilities
Commodity^(a)	$	—	$	1	$	—	$	1	$	—	$	60	$	—	$	60
Derivative instruments, liabilities	$	—	$	1	$	—	$	1	$	—	$	60	$	—	$	60


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

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

~~Interest~~

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Both our interest rate swaps and forward starting interest rate swaps are measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs. See Note 14 for additional discussion of the types of derivative instruments we use.

Fair Values –- Goodwill

Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. As of June 30, 2017 we have $115 million of goodwill associated with our International E&P reporting unit. We estimate the fair value of our International E&P reporting unit using a combination of market and income approaches. The market approach referenced observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value, and valuation multiples of us and our peers from the investor analyst community. The income approach utilized discounted cash flows, which were based on forecasted assumptions. Key assumptions to the income approach include future liquid hydrocarbon and natural gas pricing, estimated quantities of liquid hydrocarbons and natural gas proved and probable reserves, estimated timing of production, discount rates, future capital requirements, ~~and~~ operating expenses and tax rates. The assumptions used in the income approach

~~MARATHON OIL CORPORATION~~

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

are consistent with those that management uses to make business decisions. These valuations methodologies represent Level 3 fair value measurements. We performed our annual impairment test in April ~~2016~~2017 and concluded no impairment was required. As of the date of our last impairment assessment, the fair value of our International E&P reporting unit exceeded its book value by over 40%. While the fair value of our International E&P reporting unit exceeded the book value, subsequent ~~commodity price and/or common stock declines may cause us to reassess our goodwill for impairment, and~~variations in the above assumptions could result in ~~non-cash~~materially different calculations of fair value and determinations of whether or not an impairment ~~charges in the future.~~is indicated.

Fair Values- Nonrecurring

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

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

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

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

~~During the second~~first quarter of ~~2015,~~2017, we recorded a non-cash impairment charge of ~~$44 million~~$6.6 billion primarily related to ~~East Texas, North Louisiana~~property, plant and ~~Wilburton, Oklahoma natural gas~~equipment. This impairment was recorded for excess net book value over anticipated sales proceeds less costs to sell. Fair values of assets ~~as a result of the anticipated~~held for sale ~~(See Note 6). The fair values~~ were ~~measured using a probability weighted income approach~~determined based ~~on both~~upon the anticipated sales ~~price and~~proceeds less costs to sell, which resulted in a ~~held-for-use model.~~Level 2 classification. See Note6 for relevant detail regarding dispositions.

Fair Values – Financial Instruments

Our current assets and liabilities include financial instruments, the most significant of which are receivables, long-term debt and payables. We believe the carrying values of our receivables 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 credit rating, and (3) our historical incurrence of and expected future insignificant bad debt expense, which includes an evaluation of counterparty credit risk.

The following table summarizes financial instruments, excluding receivables, payables and derivative financial instruments, and their reported fair values by individual balance sheet line item at June 30, ~~2016~~2017 and December 31, ~~2015.~~

2016.


	June 30, 2016				December 31, 2015				June 30, 2017				December 31, 2016
	Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount		Value		Amount		Value		Amount
Financial assets
Current assets (a)									$	753	$	753	$	7	$	7
Other noncurrent assets	$	198	$	206	$	104	$	118	104		107		105		108
Total financial assets	$	198	$	206	$	104	$	118	$	857	$	860	$	112	$	115
Financial liabilities
Other current liabilities	$	25	$	24	$	34	$	33	$	43	$	54	$	68	$	75
Long-term debt, including current portion^(a)	7,186		7,291		6,723		7,291
Long-term debt, including current portion (b)									7,451		7,293		7,449		7,292
Deferred credits and other liabilities	121		117		97		95		110		103		114		107
Total financial liabilities	$	7,332	$	7,432	$	6,854	$	7,419	$	7,604	$	7,450	$	7,631	$	7,474

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

^(a) Includes our two notes receivable relating to the sale of our Canadian business as of June 30, 2017, see note 6 for further information.

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

~~MARATHON OIL CORPORATION~~

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

Fair values of our notes receivable and 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.~~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~~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.

14. Derivatives

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


	June 30, 2016							June 30, 2017
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	12	$	—	$	12	Other noncurrent assets	$	1	$	—	$	1	Other current assets
Total Designated Hedges	$	12	$	—	$	12		$	1	$	—	$	1

	June 30, 2016
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location
Not Designated as Hedges
Interest rate								$	53	$	—	$	53	Other current assets
Commodity	$	6	$	39	$	33	Other current liabilities	57		—		57		Other current assets
Commodity	—		31		31		Deferred credits and other liabilities	3		—		3		Other noncurrent assets
Total Not Designated as Hedges	$	6	$	70	$	64		$	113	$	—	$	113
Total								$	114	$	—	$	114



	December 31, 2016
(In millions)	Asset		Liability		Net Asset			Balance Sheet Location
Fair Value Hedges
Interest rate	$	3	$	—	$	3		Other current assets
Interest rate	1		—		1			Other noncurrent assets
Cash Flow Hedges
Interest rate	$	64	$	—	$	64		Other noncurrent assets
Total Designated Hedges	$	68	$	—	$	68

Not Designated as Hedges
Commodity	$	—	$	60	$	(60	)	Other current liabilities
Total Not Designated as Hedges	$	—	$	60	$	(60	)
Total	$	68	$	60	$	8

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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

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

Derivatives Designated as Fair Value Hedges

The following table presents, by maturity date, information about our interest rate swap agreements, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.

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

~~MARATHON OIL CORPORATION~~

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



	June 30, 2017				December 31, 2016
	Aggregate Notional Amount		Weighted Average, LIBOR		Aggregate Notional Amount		Weighted Average, LIBOR
Maturity Dates	(in millions)		Floating Rate		(in millions)		Floating Rate
October 1, 2017	$	600	5.54	%	$	600	5.10	%
March 15, 2018	$	300	5.49	%	$	300	5.04	%

The pretax effects of derivative instruments designated as hedges of fair value in our consolidated statements of income ~~are summarized~~has a gross impact that is not material to net interest and other in ~~the table below. There~~all periods presented. Additionally, there is no ineffectiveness related to fair value ~~hedges.~~hedges in all periods presented.

Gain (Loss)
Three Months Ended June 30, Six Months Ended June 30,
(In millions) Income Statement Location 2016 2015 2016 2015
Derivative
Interest rate Net interest and other $ —
$ (2 ) $ 4
$ 3
Hedged Item

Long-term debt Net interest and other $ —
$ 2
$ (4 ) $ (3 )

Derivatives ~~not~~Not Designated as Hedges

Interest Rate Swaps

During the third quarter of 2016, we entered into forward starting interest rate swaps to hedge the variations in cash flows related to fluctuations in long term interest rates from debt that are probable to be refinanced by us in 2018, specifically interest rate risk associated with future changes in the benchmark treasury rate. We designated these derivative instruments as cash flow hedges. The occurrence of the forecasted transaction was probable at June 30, 2017 and each respective derivative contract can be tied to an anticipated underlying dollar notional amount. During the second quarter of 2017 we de-designated the forward starting interest rate swaps previously designated as cash flow hedges resulting in a mark-to-market gain of $3 million, in net interest and other, at June 30, 2017, of which $1 million was reclassified from other comprehensive income.

The following table presents, by maturity date, information about our forward starting interest rate swap agreements, including the rate.



	June 30, 2017		December 31, 2016
	Aggregate Notional Amount	Weighted Average, LIBOR	Aggregate Notional Amount	Weighted Average, LIBOR
Maturity Dates	(in millions)	Fixed Rate	(in millions)	Fixed Rate
March 15, 2018	$750	1.57%	$750	1.57%

The following table sets forth the net impact of the forward starting interest rates swap derivatives de-designated as cash flow hedges on other comprehensive income (loss).



	Three Months Ended June 30,					Six Months Ended June 30,
(In millions)	2017			2016		2017			2016
Interest Rate Swaps
Beginning balance	$	61		$	—	$	60		$	—
Change in fair value recognized in other comprehensive income	(14		)	—		(13		)	—
Reclassification from other comprehensive income	(1		)	—		(1		)	—
Ending balance	$	46		$	—	$	46		$	—

At June 30, 2017, accumulated other comprehensive income included deferred gains of $46 million related to the de-designated forward starting interest rate swaps previously designated as cash flow hedges. As of June 30, 2017, we expected to reclassify this amount into earnings as an adjustment to net interest and other upon the occurrence of the forecasted transaction.

In July of 2017, the forecasted transaction consummated and we issued $1 billion in senior unsecured notes, see Note 16 for further detail. This resulted in the termination of our forward starting interest rate swaps, previously designated as cash flow hedges, with proceeds of $54 million. In the third quarter of 2017, we will recognize into earnings a gain of

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

approximately $47 million, in net interest and other, as we have previously reclassified into earnings a gain of $7 million primarily from other comprehensive income due to ineffectiveness.

Commodity Derivatives

We have entered into multiple crude oil and natural gas derivatives indexed to NYMEX WTI and Henry Hub related to a portion of our forecasted ~~North America~~United States E&P sales through December ~~2017.~~2018. These commodity derivatives consist of three-way collars, ~~two-way collars,~~swaps, and call ~~options and swaptions.~~options. 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 volumes, the floor is the minimum price we will receive, unless the market price falls below the sold put strike price. In this case, we receive the NYMEX WTI/Henry Hub price plus the difference between the floor and the sold put price. These commodity derivatives were not designated as hedges. The following table sets forth outstanding derivative contracts as of June 30, ~~2016~~2017 and the weighted average prices for those contracts:

								Crude Oil
			Year Ending December 31,	2017		2018
	Third Quarter	Fourth Quarter	2017	Third Quarter	Fourth Quarter	First Quarter	Second Quarter
Three-Way Collars(a)	Three-Way Collars(a)			Three-Way Collars(a)
Volume (Bbls/day)	47,000		—	50,000	50,000	20,000	20,000
Price per Bbl:
Weighted average price per Bbl:
Ceiling	$55.37		—	$60.37	$60.37	$57.86	$57.86
Floor	$50.23		—	$54.80	$54.80	$53.00	$53.00
Sold put	$40.96		—	$47.80	$47.80	$47.00	$47.00
Sold call options ^(a)(b)
Volume (Bbls/day)	10,000		35,000	35,000	35,000	—	—
Price per Bbl	$72.39		$61.91
Two-way Collars
Volume (Bbls/day)	10,000		—
Price per Bbl:			—
Ceiling	$50.00
Floor	$41.55
Weighted average price per Bbl				$61.91	$61.91	—	—


^(a)	Subsequent to June 30, 2017, we entered into 20,000 Bbls/day of three-way collars for January - December 2018 with an average ceiling price of $55.09, a floor price of $50.00, and a sold put price of $43.00.


^(b)	Call options settle monthly.

~~MARATHON OIL CORPORATION~~

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



Natural Gas
	2017		2018
	Third Quarter	Fourth Quarter	First Quarter	Second Quarter	Third Quarter	Fourth Quarter
Three-Way Collars
Volume (MMBtu/day)	120,000	120,000	200,000	160,000	160,000	160,000
Weighted average price per MMBtu:
Ceiling	$3.58	$3.71	$3.79	$3.61	$3.61	$3.61
Floor	$3.09	$3.14	$3.08	$3.00	$3.00	$3.00
Sold put	$2.55	$2.60	$2.55	$2.50	$2.50	$2.50
Swaps
Volume (MMBtu/day)	20,000	20,000	—	—	—	—
Weighted average price per MMBtu	$2.93	$2.93	—	—	—	—

Natural Gas
Year Ending December 31,
Third Quarter Fourth Quarter 2017
Three-Way Collars ^(a)

Volume (MMBtu/day) 20,000 20,000 40,000
Price per MMBtu
Ceiling $2.93 $2.93 $3.28
Floor $2.50 $2.50 $2.75
Sold put $2.00 $2.00 $2.25


^(a)	On our 2016 collars, the counterparty has the option to execute fixed-price swaps (swaptions) at a weighted average price of $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 mark-to-market impact and settlement of these commodity derivative instruments appears in sales and other operating revenues in our consolidated statements of income for the three and six month periods ended June 30, 2017 and 2016, respectively. The three and six month periods ended June 30, 2017 impact was a net gain of $56 million and $137 million compared to a net loss of $88 million and $90 million ~~compared to a net loss of $43 million and $17 million~~ for the same respective ~~periods~~period in ~~2015.~~2016. Net ~~cash received from~~ settlements of commodity derivative instruments for the three and six month periods ended June 30, ~~2016~~2017 was ~~$14~~$13 million and ~~$46~~$17 million compared to $4$2 million and $24 million for ~~both of~~ the respective ~~periods~~period in ~~2015.~~2016.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

15. Incentive Based Compensation

Stock options, restricted stock awards and restricted stock units

The following table presents a summary of activity for the first six months of ~~2016:~~2017:


	Stock Options					Restricted Stock Awards & Units				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, 2015	12,665,419				$29.97	4,017,344			$30.76
Outstanding at December 31, 2016										11,915,533				$27.71	6,933,533			$14.44
Granted	1,680,000		^(a)		$7.22	5,233,984			$7.91	799,591		^(a)		$15.80	3,908,344			$16.37
Options Exercised/Stock Vested	—			—		(1,148,953	)		$32.29	(8,666	)			$7.22	(2,237,657	)		$17.61
Canceled	(973,295	)			$25.76	(557,051	)		$23.20	(2,009,085	)			$35.48	(529,721	)		$15.84
Outstanding at June 30, 2016	13,372,124				$27.42	7,545,324			$15.23
Outstanding at June 30, 2017										10,697,373				$25.37	8,074,499			$14.40

^(a) The weighted average grant date fair value of stock option awards granted was ~~$1.97~~$6.07 per share.

Stock-based performance unit awards

During the first six months of ~~2016,~~2017, we granted ~~1,205,517~~563,631 stock-based performance units to certain officers. The grant date fair value per unit was ~~$3.72.~~$17.75.

16. Debt

Revolving Credit Facility

As of June 30, ~~2016,~~2017, we had no borrowings against our $3.3 billion revolving credit facility (the ~~"Credit Facility"~~“Credit Facility”), as described below.

In ~~March 2016,~~June 2017, we extended the maturity date of our Credit Facility from May 28, 2020 to May 28, 2021, and maintained the Credit Facility at $3.3 billion. In July 2017, we increased our ~~$3.0~~$3.3 billion unsecured Credit Facility by ~~$300~~$93 million to a total of ~~$3.3~~$3.4 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the increase and term extension. We have the ability to request two additional one-year extensions and an option to increase the commitment amount by up to an additional $107 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.

The Credit Facility includes a covenant requiring that our ratio of total debt to total capitalization not exceed 65% as of the last day of each fiscal quarter. If an event of default occurs, the lenders holding more than half of the commitments may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility. As of June 30, ~~2016,~~2017, we were in compliance with this covenant with a debt-to-capitalization ratio of ~~28%~~37%.

Long-term debt

On July 24, 2017, we issued $1 billion of 4.4% senior unsecured notes that will mature on July 15, 2027. Interest on the senior notes is payable semi-annually beginning January 15, 2018. We may redeem some or all of the senior notes at any time at the applicable redemption price, plus accrued interest, if any. We will use the net proceeds of $990 million plus existing cash on hand to redeem the following senior notes:

$682 million 6.0% Notes Due in 2017

$854 million 5.9% Notes Due in 2018

$228 million 7.5% Notes Due in 2019

The new issuance together with the redemption will result in a reduction in total gross debt of approximately $750 million in the third quarter of 2017.

In July 2017, we gave notice that we will redeem during the third quarter of 2017, $1.76 billion of the senior unsecured notes discussed above in accordance with their make-whole call provisions. As a result of this notice we expect to recognize into earnings an estimated loss of approximately $40 to $50 million, in loss on extinguishment of debt, during the third quarter of 2017. See Note 14 for detail relating to the proceeds of $54 million, which will result in a gain of approximately $47 million

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~Debt Issuance~~

Ininto earnings in the ~~second~~third quarter of ~~2015,~~2017, on the termination of our forward starting interest rate swaps associated with this issuance.

As a result of the debt issuance discussed above, we ~~issued $2 billion aggregate principal amount~~reclassified $990 million of ~~unsecured senior~~the 6.0% notes due in 2017 and ~~used~~5.9% notes due in 2018 to long-term debt as we have the ~~aggregate~~intent and ability to redeem them with the net proceeds ~~to repay our $1 billion 0.90% senior notes November 1, 2015, and for general corporate purposes.~~received from the debt issuance. Therefore, as of June 30, 2017, we had long-term debt due within one year of $548 million.

17. Reclassifications Out of Accumulated Other Comprehensive Loss

The following table presents a summary of amounts reclassified from accumulated other comprehensive loss:


	Three Months Ended June 30,						Six Months Ended June 30,							Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015			Income Statement Line	2017			2016			2017			2016			Income Statement Line

Postretirement and postemployment plans	Postretirement and postemployment plans													Postretirement and postemployment plans
Amortization of actuarial loss	$	(4	)	$	(7	)	$	(7	)	$	(14	)	General and administrative	$	(2	)	$	(4	)	$	(4	)	$	(7	)	General and administrative
Net settlement loss	(31		)	(64		)	(79		)	(81		)	General and administrative	(3		)	(31		)	(17		)	(79		)	General and administrative
Net curtailment gain (loss)	—			(2		)	—			3			General and administrative
Derivative hedges
Ineffective portion of derivative hedge														(1		)	—			(1		)	—			Net interest and other
	(35		)	(73		)	(86		)	(92		)	Income (loss) from operations	(6		)	(35		)	(22		)	(86		)	Income (loss) from operations
	13			25			29			32			Provision (benefit) for income taxes	—			13			—			29			Benefit for income taxes
Total reclassifications to expense, net of tax														(6		)	(22		)	(22		)	(57		)	Income (loss) from continuing operations
Foreign currency hedges
Net recognized gain in discontinued operations, net of tax														—			—			(30		)	—			Income (loss) from discontinued operations
Total reclassifications to expense	$	(22	)	$	(48	)	$	(57	)	$	(60	)	Net income (loss)	$	(6	)	$	(22	)	$	(52	)	$	(57	)	Net income (loss)

18. 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 $1,236 million. The proceeds were used to strengthen our balance sheet and for general corporate purposes, including funding a portion of our Capital Program.

19. Supplemental Cash Flow Information


	Six Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015			2017			2016
Net cash (used in) operating activities:
Interest paid (net of amounts capitalized)	$	(177	)	$	(143	)	$	(193	)	$	(177	)
Income taxes paid to taxing authorities	(61		)	(165		)	(43		)	(61		)
Noncash investing activities:
Noncash investing activities, related to continuing operations:
Asset retirement cost increase	$	2		$	6		$	12		$	2
Asset retirement obligations assumed by buyer	83			—			2			83
Increase in capital expenditure accrual							183			—
Notes receivable for disposal of assets							742			—

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

20. Commitments and Contingencies

The U.K. tax authorities have challenged the timing of deductibility for certain Brae area decommissioning costs which we claimed for U.K. corporation tax purposes. The dispute relates to the timing of the deduction and does not dispute the general deductibility of decommissioning costs. In July 2017, a hearing took place at the U.K.’s First-tier Tribunal with respect to this tax deduction. If we do not prevail in the Tribunal, we may be required to adjust the timing of our tax deduction and make a payment to the U.K. tax authorities of approximately $130 million, which would be recovered as future decommissioning activities are performed and deductions claimed. We estimate that any revisions to current and deferred tax liabilities, if we do not prevail, would have no cumulative adverse earnings impact in our consolidated results of operations. While we believe that it is more likely than not that we will prevail in the Tribunal, if we do not, we have the option to seek appeal.

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

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

~~21. Subsequent Event~~

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

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

Executive Overview

~~Outlook~~

Operations

Market Conditions

Results of Operations

Critical Accounting Estimates

Accounting Standards Not Yet Adopted

Cash Flows

Liquidity and ~~Liquidity~~Capital Resources

Environmental Matters and Other Contingencies

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

Executive Overview

We are an independent ~~global~~ exploration and production company based in Houston, Texas ~~with operations in North America, Europe and Africa and a focus~~focused on U.S. unconventional resource ~~plays.~~plays with operations in the United States, Africa and Europe. Total proved reserves were ~~2.2~~1.4 billion boe at December 31, ~~2015~~2016, excluding our Canadian business, and total assets were ~~$33~~$24.2 billion at June 30, ~~2016.~~2017.

~~Our significant strategic actions~~As discussed in Note 6 to the consolidated financial statements, we closed on the sale of our Canadian business, which has been reflected as discontinued operations and ~~financial results~~is excluded from operations in all periods presented.

Key highlights include the following:

~~Strengthened balance sheet~~Liquidity and corporate financing

At the end of the second quarter 2017, we had $5.9 billion of liquidity, comprised of $2.6 billion in cash and an undrawn $3.3 billion revolving credit facility.

In July 2017 we expanded the capacity of the revolving credit facility from $3.3 billion to $3.4 billion, and in June 2017 we extended the maturity date one year to 2021.

In July 2017, we issued $1 billion of 4.4% senior notes due in 2027. Net proceeds plus existing cash on hand will be used in the third quarter to redeem approximately $1.8 billion of 6% senior notes due in 2017, 5.9% senior notes due in 2018 and 7.5% senior notes due in 2019. The offering and redemption will reduce total gross debt by approximately $750 million.

Simplifying our portfolio

Closed on the sale of our Canadian business for approximately $2.5 billion with over $1.8 billion in proceeds received to date and $750 million to be received in first quarter 2018.

Closed on the Permian basin acquisitions for approximately $1.8 billion with cash on hand.

Financial and Operational results

Net sales volumes from continuing operations are 357 mboed, which is 4% higher compared to the same quarter last year; this includes a 7% increase to 202 mboed sales volumes in the U.S. resource plays in our United States E&P segment.

Cash provided by operating activities from continuing operations of $923 million for the first six months of 2017, is primarily a result of our average crude oil and condensate price realizations of $47.46 per bbl in the first half of 2017.

Our net loss per share from continuing operations was $0.18 in the second quarter of 2017 as compared to a net loss per share of $0.16 in the same period last year. Included in the second quarter 2017 and comparable period net loss are:


◦	AtAn increase in sales and other operating revenues of approximately 40% to $958 million, including a commodity derivative net gain of $56 million compared to a net loss of $88 million in the ~~end of the second quarter of 2016, we had $5.9 billion of liquidity, comprised of $2.6 billion in cash and an undrawn $3.3 billion revolving credit facility~~comparable quarter.


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

~~Focused on cost reductions~~


◦	Production ~~expenses per boe~~expense decreased 5% while sales volumes increased in ~~the~~ second quarter ~~of 2016, as~~2017 compared to the same ~~period~~quarter last ~~year improved in the North America E&P segment by 13% to $6.28 per boe and in the International E&P segment by 22% to $5.09 per boe~~year.


◦	Our provision for income taxes was $41 million in the second quarter of 2017 compared to a benefit of $54 million

in the same quarter last year, resulting from Libya tax expense due to resumption of production and no tax benefit due to the full valuation allowance on our federal deferred tax assets in the current quarter.


◦	Exploration expenses decreased primarily as a result of our decision in 2016 ~~Capital Program reduced by $100 million~~not to ~~$1.3 billion~~drill any of our remaining undeveloped Gulf of Mexico leases.


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

~~Simplifying and concentrating portfolio~~


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


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

~~Major Project updates~~


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


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

~~Financial results~~


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


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


▪	~~Unrealized losses from our commodity derivative instruments totaling $91~~gain on sale of $294 million ~~pre-tax~~


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


▪	~~Non-cash impairments totaling $141 million, pre-tax, as a result~~ primarily relating to the sale of our ~~decision not to drill any of our remaining Gulf of Mexico leases~~Wyoming upstream and midstream non-core assets.

~~Outlook~~

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

~~Exploration Update~~

In September 2015, we announced our intention to scale back our conventional exploration program, with future exploration investment focused on fulfilling our existing commitments in the Gulf of Mexico and Gabon. In second quarter of 2016, we made the decision to not drill our remaining Gulf of Mexico undeveloped leases. As a result, we recorded a non-cash impairment of $141 million in the second quarter of 2016. Additionally, during the third quarter 2016, we executed an agreement to terminate our Gulf of Mexico deepwater drilling rig contract. As a result, we expect to recognize a termination payment of $113 million in other operating expense in that quarter.

Operations

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

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

^(a)~~Includes blendstocks~~

~~North America~~



	Three Months Ended June 30,			Six Months Ended June 30,
Net Sales Volumes	2017	2016	Increase (Decrease)	2017	2016	Increase (Decrease)
United States E&P (mboed)	222	224	(1)%	215	232	(7)%
International E&P (mboed)	135	120	13%	131	108	21%
Total Continuing Operations (mboed)	357	344	4%	346	340	2%

United States E&P

Net sales volumes in the segment were marginally lower in ~~the~~ second quarter ~~and first six months of 2016~~2017 primarily as a result of ~~decreased drilling~~the disposition of Wyoming and ~~completion activity resulting~~certain other non-operated assets in ~~fewer wells brought to sales as well as 17 mboed relating to dispositions of certain non-core assets (Gulf of~~West Texas and New Mexico in 2016, which was partially offset by the acquisitions and ~~East Texas, North Louisiana~~development in the Oklahoma STACK and ~~Wilburton, Oklahoma) during the second half of 2015.~~Northern Delaware. The following tables provide details regarding net sales volumes, sales mix and operational drilling activity for our significant operations within this segment:

Three Months Ended June 30, Six Months Ended June 30,
Net Sales Volumes 2016 2015 Increase
(Decrease) 2016 2015 Increase
(Decrease)
Equivalent Barrels (mboed)

Eagle Ford 109 135 (19)% 114 141 (19)%
Oklahoma Resource Basins 27 24 13% 27 24 13%
Bakken 53 61 (13)% 55 59 (7)%
Other North America ^(a)
35 54 (35)% 36 54 (33)%
Total North America E&P 224 274 (18)% 232 278 (17)%

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



	Three Months Ended June 30,			Six Months Ended June 30,
Net Sales Volumes (a)	2017	2016	Increase (Decrease)	2017	2016	Increase (Decrease)
Equivalent Barrels (mboed)
Oklahoma Resource Basins	49	27	81%	46	27	70%
Eagle Ford	100	109	(8)%	100	114	(12)%
Bakken	49	53	(8)%	48	55	(13)%
Northern Delaware	4	—	100%	2	—	100%
Other United States ^(b)	20	35	(43)%	19	36	(47)%
Total United States E&P	222	224	(1)%	215	232	(7)%

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

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



^(a)											Our U.S. Resource plays consists of the Oklahoma Resource Basins, Eagle Ford, Bakken and Northern Delaware.

^(b) Three and six months ended June 30, 2017 includes a net sales volume reduction from June 30, 2016 of 21 mboed primarily consisting of the disposition of Wyoming and certain non-operated assets in West Texas and New Mexico in 2016. See Note 6 to the consolidated financial statements for further disposition information.

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



	Three Months Ended June 30, 2017
Sales Mix - U.S. Resource Plays	Oklahoma Resource Basins	Eagle Ford	Bakken	Northern Delaware	Total
Crude oil and condensate	29%	59%	80%	56%	56%
Natural gas liquids	24%	20%	12%	16%	19%
Natural gas	47%	21%	8%	28%	25%



	Three Months Ended June 30,		Six Months Ended June 30,
	2017	2016	2017	2016
Gross Operated - U.S. Resource Plays

Oklahoma Resource Basins:
Wells drilled to total depth	23	6	38	11
Wells brought to sales	20	5	32	8
Eagle Ford:
Wells drilled to total depth	53	40	98	98
Wells brought to sales	41	30	88	80
Bakken:
Wells drilled to total depth	33	—	45	3
Wells brought to sales	2	4	6	10
Northern Delaware
Wells drilled to total depth	2	—	2	—
Wells brought to sales ^(a)	2	—	2	—

~~Eagle Ford~~^(a) ~~– Of the 30 gross operated wells~~Includes one well brought to sales during the second quarter of 2016, 19 were Lower Eagle Ford, 3 were Upper Eagle Ford and 8 were Austin Chalk. Production decreases were due to lower completion activity with fewer gross operated wells brought to sales and reduced contribution from 2015 high-density pads drilled at tighter well spacing. Our average time to drill an Eagle Ford wellearly in the second quarter ~~2016, spud-to-total depth, was 8 days, a decrease from 11 days in~~prior to the ~~same quarter last year as efficiency gains in drilling continued. Wells were drilled at an average rate~~closing of ~~2,400 feet per day.~~the acquisition.

Oklahoma Resource Basins – OfOur net sales volumes in the 5second quarter increased by more than 80% from the year ago quarter, with net sales volumes of 49 mboed in second quarter 2017. Our second STACK infill spacing pilot, the Hansens pad located in the normally pressured Meramec black oil window east of the Yost pad, tested a tighter well spacing design. Additionally, we also continued delineation and leasehold activity with strong results.

Eagle Ford – Our net sales volumes were 100 mboed in the second quarter 2017 which was 8% lower compared to the prior year quarter. We brought 41 gross operated wells ~~brought~~ to sales in the second quarter ~~of 2016, 3 were~~compared to 30 in ~~the SCOOP Woodford; 2 were in the STACK Meramec and all were extended laterals. We also participated in 16 outside-operated wells during~~ the second quarter ~~of 2016, 10 of which were~~2016. A new Company record was set again for the fastest operated well drilled in the ~~SCOOP and 6 were in the STACK.~~Eagle Ford at a rate of more than 4,200 feet per day.

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

Bakken – OfOur net sales volumes were 49 mboed compared to 53 mboed in the 4prior year quarter. In second quarter 2017 we brought two gross operated wells ~~brought~~ to sales in the Hector with enhanced completion designs.

Northern Delaware – Our net sales volumes were 4 net mboed in second quarter 2017, reflecting the May 1 closing of ~~2016, 2 were~~BC Operating assets and June 1 closing of Black Mountain assets. During second quarter 2017 we brought online our first well with a company designed completion in ~~the Middle Bakken formation and 2~~Northern Delaware with successful results, pushing delineation west in ~~the Three Forks formation, all with higher intensity completions. We do not currently have an active drilling rig in the Bakken.~~Eddy County.

Other ~~North America~~United States – Net sales volumes declined in ~~the~~ second quarter ~~of 2016~~2017 primarily due to the ~~2015 sales~~disposition of ~~the non-core~~Wyoming and certain non-operated assets in West Texas and New Mexico in 2016. See Note 6 to the ~~Gulf of Mexico, East Texas, North Louisiana and Wilburton, Oklahoma. On June 30, we closed~~consolidated financial statements for information about dispositions. This decrease was partially offset by the ~~sale of certain of our Wyoming upstream and midstream assets. Net sales volumes for all of our Wyoming assets were approximately 16 mboed for the second quarter and first half of 2016.~~

~~The~~ Gunflint field located in Mississippi Canyon block 948 in the Gulf of Mexico ~~achieved first~~which began production in ~~July~~the second half of 2016. ~~Full production is expected to reach at least 20 mboed gross with oil representing approximately 75% of the volumes produced. We hold an 18% non-operated working interest in the Gunflint field.~~

International E&P

Net sales volumes ~~in the segment~~ were higher in ~~the~~ second quarter of2017 compared to second quarter 2016 primarily ~~as a result~~due to the resumption of ~~planned turnaround~~sales volumes and ~~maintenance activities at~~production in Libya and increased sales volumes in E.G. resulting from the completion and start-up of the E.G. Alba field ~~and E.G. LNG facilities~~compression project in ~~the second quarter of 2015.~~mid-2016. The following table provides details regarding net sales volumes for our significant operations within this segment.


	Three Months Ended June 30,			Six Months Ended June 30,			Three Months Ended June 30,			Six Months Ended June 30,
Net Sales Volumes	2016	2015	Increase (Decrease)	2016	2015	Increase (Decrease)	2017	2016	Increase (Decrease)	2017	2016	Increase (Decrease)
Equivalent Barrels (mboed)
Equatorial Guinea	101	89	13%	93	93	—%	105	101	4%	104	93	12%
United Kingdom^(a)	19	19	—%	15	19	(21)%	18	19	(5)%	14	15	(7)%
Libya							11	—	100%	12	—	100%
Other International							1	—	100%	1	—	100%
Total International E&P	120	108	11%	108	112	(4)%	135	120	13%	131	108	21%
Equity Method Investees
LNG (mtd)	5,797	4,991	16%	5,060	5,629	(10)%	6,243	5,797	8%	6,195	5,060	22%
Methanol (mtd)	1,303	673	94%	1,292	778	66%	1,182	1,303	(9)%	1,244	1,292	(4)%
Condensate & LPG (boed)	11,306	8,586	32%	10,757	10,892	(1)%	11,608	11,306	3%	13,069	10,757	21%


^(a)	Includes natural gas acquired for injection and subsequent ~~resale of 5 mmcfd and 7 mmcfd for the second quarters of 2016 and 2015, and 5 mmcfd and 9 mmcfd for the first six months of 2016 and 2015.~~resale.

Equatorial Guinea – Second quarter ~~2016~~2017 net sales were higher compared to the same quarter in 2016 as a result of ~~2015 due to lower planned turnaround~~the completion and ~~maintenance activities at the Alba field and E.G. LNG facilities. The~~start-up of our Alba field compression project ~~achieved first gas~~ in ~~July, which is expected to maintain the production plateau for an additional two years and extend field life up to eight years.~~mid-2016.

United Kingdom – Net sales volumes in the first six months of 2017 were marginally lower compared to the first six months of 2016 ~~were lower due to repair activities~~as a result of reliability issues at the Brae Alpha facility following a process pipe failure in late 2015. Production was restored at the facility in late April. Higher overall production efficiency at the remaining Brae facilities and improved reliability from the outside-operated Foinaven ~~field partially offset the Brae Alpha shut-in.~~Field.

Libya – ~~Due~~Our Libya operations have been interrupted in recent years due to civil unrest. In late 2016, liftings resumed from the Es Sider crude oil terminal. Sales volumes and production continued ~~civil unrest, there were no liftings~~without interruption during ~~the quarter, or any period presented. Earlier this year, an Internationally-backed Unity Government was established in Tripoli. During the~~ second quarter the two National Oil Companies agreed to unify and reportedly have begun preliminary discussions on re-opening the Es-Sider and other crude oil terminals which, if successful, will allow resumption of production operations at our Waha concessions. However, considerable uncertainty remains around the timing of future production and sales levels.2017.

~~Oil Sands Mining~~

~~Our net synthetic crude~~

Market Conditions

Crude oil, ~~sales volumes were 49 mbbld~~natural gas and ~~54 mbbld~~NGL benchmarks increased in the second quarter and first six months of 2016 compared to 29 mbbld and 44 mbbld in the same periods of 2015. Sales volumes increased in comparison to second quarter and first six months of 2015 which were adversely affected due to planned turnarounds at the base upgrader and Muskeg River Mine and unplanned downtime at the expansion upgrader. These sales volume increases were partially offset by a brief suspension of operations at both the Muskeg River and Jackpine mines in May 2016 in order to support emergency response efforts related to the Fort McMurray area wildfires in addition to the completion of planned maintenance activities at the Jackpine Mine and expansion upgrader that began in the first quarter 2016. Neither of the mines sustained any damage as a result of the wildfires. We hold a 20% non-operated working interest in the Athabasca Oil Sands Project.

~~Market Conditions~~

Prevailing prices for the crude oil, NGLs and natural gas that we produce significantly impact our revenues and cash flows. The benchmark prices for crude oil, NGLs and natural gas were lower in the second quarter and first six months of 20162017 as compared to the same period in ~~2015;~~2016; as a result, we experienced ~~declines in our~~increased 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~~United States E&P

The following table presents our average price realizations and the related benchmarks for crude oil, NGLs and natural gas for the second quarter and first six months of ~~2016~~2017 and ~~2015.~~2016.


	Three Months Ended June 30,			Six Months Ended June 30,						Three Months Ended June 30,			Six Months Ended June 30,
	2016	2015	Decrease	2016		2015		Increase (Decrease)		2017	2016	Increase (Decrease)	2017	2016	Increase (Decrease)
Average Price Realizations ^(a)
Crude Oil and Condensate (per bbl) ^(b)	$40.77	$52.63	(23)%	$34.21		$47.11		(27	)%	$45.81	$40.77	12%	$47.09	$34.21	38%
Natural Gas Liquids (per bbl)	14.84	14.77	—%	11.43		14.60		(22	)%	17.61	14.84	19%	18.46	11.43	62%
Total Liquid Hydrocarbons (per bbl)	35.07	45.96	(24)%	29.32		41.37		(29	)%	39.00	35.07	11%	40.04	29.32	37%
Natural Gas (per mcf)(c)	1.96	2.76	(29)%	1.99		2.88		(31	)%	3.05	1.96	56%	3.03	1.99	52%
Benchmarks
WTI crude oil (per bbl)	$45.64	$57.95	(21)%		$39.78		$53.34	(25	)%	$48.15	$45.64	5%	$49.95	$39.78	26%
LLS crude oil (per bbl)	47.35	62.94	(25)%	41.49		57.97		(28	)%	50.18	47.35	6%	51.77	41.49	25%
Mont Belvieu NGLs (per bbl)^(c)(d)	17.52	17.65	(1)%	15.78		18.02		(12	)%	20.99	17.52	20%	21.95	15.78	39%
Henry Hub natural gas (per mmbtu)	1.95	2.64	(26)%	2.02		2.81		(28	)%	3.18	1.95	63%	3.25	2.02	61%


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

^(b)

Inclusion of realized gains on crude oil derivative instruments would have increased liquid hydrocarbons average price realizations by ~~$0.12~~$1.07 per bbl and ~~$0.06~~$0.12 per bbl for the second quarter 2017 and 2016, and ~~2015, and $0.91~~$0.72 per bbl and ~~$0.14~~$0.91 per bbl for the first six months of ~~2016~~2017 and ~~2015. Inclusion of realized gains on natural gas derivative instruments would have increased average realizations by $0.02 per mcf and $0.01 per mcf for the second quarter and first six months of~~ 2016.


^(c)	Inclusion of realized gains (losses) on natural gas derivative instruments would have a minimal impact on average price realizations for the periods presented.


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

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

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

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

International E&P

The following table presents our average price realizations and the related benchmark for crude oil ~~NGLs, and natural gas~~ for the second quarter and first six months of ~~2016~~2017 and ~~2015~~2016.


	Three Months Ended June 30,			Six Months Ended June 30,						Three Months Ended June 30,			Six Months Ended June 30,
	2016	2015	Increase (Decrease)	2016		2015		Increase (Decrease)		2017	2016	Increase (Decrease)	2017	2016	Increase (Decrease)
Average Price Realizations
Crude Oil and Condensate (per bbl)	$42.21	$56.70	(26)%	$37.56		$52.92		(29	)%	$47.04	$42.21	11%	$48.58	$37.56	29%
Natural Gas Liquids (per bbl)	2.65	3.10	(15)%	2.45		3.29		(26	)%	1.77	2.65	(33)%	2.83	2.45	16%
Liquid Hydrocarbons (per bbl)	32.11	44.70	(28)%	28.11		41.06		(32	)%	37.11	32.11	16%	37.83	28.11	35%
Natural Gas (per mcf)	0.53	0.78	(32)%	0.56		0.78		(28	)%	0.57	0.53	8%	0.56	0.56	—%
Benchmark
Brent (Europe) crude oil (per bbl) ^(a)	$45.52	$61.69	(26%)		$39.61		$57.81	(31	)%	$49.67	$45.52	9%	$51.68	$39.61	30%


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

~~Liquid hydrocarbons~~ –

Our U.K. liquid hydrocarbon production is generally sold in relation to the Brent crude benchmark. Our production from the Alba field in E.G. is condensate and gas. Condensate is sold at market prices and the gas is shipped to the onshore Alba Plant. The Alba Plant extracts NGLs and secondary condensate, which ~~receives lower~~have been supplied under a long-term contract at a fixed price, leaving dry natural gas. The extracted NGLs and secondary condensate are sold by Alba Plant at market prices, ~~than crude oil.~~

~~Our NGL~~with our share of its income/loss reflected in Income from equity method investments, and the dry natural gas ~~sales in the International E&P segment originate primarily~~ from ~~our E.G. operations~~Alba Plant is supplied to AMPCO and ~~are sold to our equity method investees~~EGHoldings under ~~fixed-price, term contracts; therefore,~~long-term contracts at fixed prices. Therefore, our reported average realized prices for condensate, NGLs and natural gas will not fully track market price movements. ~~The equity affiliates then utilize,~~Because of the location and limited local demand for natural gas in E.G., we consider the prices under the contracts with Alba Plant LLC, EGHoldings and AMPCO to be comparable to the price that could be realized from transactions with unrelated parties in this market under the same or similar circumstances. EGHoldings and AMPCO process the gas into LNG and ~~sell the NGLs~~methanol, which are sold at market prices, ~~and natural gas at fixed prices under long-term contracts,~~ with our share of their income/loss reflected in the ~~income~~Income from equity method investments line item on the ~~consolidated statements~~Consolidated Statements of ~~income.~~Income. Although uncommon, any dry gas not sold is returned offshore and re-injected into the Alba field for later production.

~~Oil Sands Mining~~

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

~~The following table presents our average price realizations and the related benchmarks for the~~ ~~second quarter and first six months of2016~~ ~~and~~ ~~2015~~.

Three Months Ended June 30, Six Months Ended June 30,
2016 2015 Decrease 2016 2015 Increase (Decrease)
Average Price Realizations
Synthetic Crude Oil (per bbl)
$40.88 $52.46 (22%)
$32.94

$44.33
(26 %)
Benchmarks
WTI crude oil (per bbl)
$45.64 $57.95 (21%)
$39.78

$53.34
(25 %)
WCS crude oil (per bbl)^(a)
32.29 46.35 (30%) 25.75
40.13
(36 %)


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

Results of Operations

Three Months Ended June 30, ~~2016~~2017 vs. Three Months Ended June 30, ~~2015~~2016

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


	Three Months Ended June 30,						Three Months Ended June 30,
(In millions)	2016			2015			2017		2016
Sales and other operating revenues, including related party
North America E&P	$	617		$	993
United States E&P							$	695	$	617
International E&P	159			211			220		159
Oil Sands Mining	185			147
Segment sales and other operating revenues, including related party	$	961		$	1,351		$	915	$	776
Unrealized (loss) gain on commodity derivative instruments	(91		)	(44		)
Unrealized gain (loss) on commodity derivative instruments							43		(91		)
Sales and other operating revenues, including related party	$	870		$	1,307		$	958	$	685

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


	Three Months Ended		Increase (Decrease) Related to						Three Months Ended			Three Months Ended		Increase (Decrease) Related to					Three Months Ended
(In millions)	June 30, 2015		Price Realizations			Net Sales Volumes			June 30, 2016			June 30, 2016		Price Realizations		Net Sales Volumes			June 30, 2017
North America E&P Price-Volume Analysis ^(a)
United States E&P Price-Volume Analysis ^(a)											United States E&P Price-Volume Analysis ^(a)
Liquid hydrocarbons	$	893	$	(172	)	$	(170	)	$	551		$	551	$	59	$	(22	)	$	588
Natural gas	90		(22		)	(13		)	55			55		34		5			94
Realized gain on commodity
derivative instruments	1		2						3			3							13
Other sales	9								8			8							—
Total	$	993							$	617		$	617						$	695
International E&P Price-Volume Analysis
Liquid hydrocarbons	$	172	$	(50	)	$	7		$	129		$	129	$	25	$	33		$	187
Natural gas	28		(10		)	4			22			22		2		1			25
Other sales	11								8			8							8
Total	$	211							$	159		$	159						$	220
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil	$	137	$	(51	)	$	95		$	181
Other sales	10								4
Total	$	147							$	185

^(a)

Three months ended June 30, ~~2016~~2017 includes a net sales volume reduction from June 30, 2016 of 1721 mboed ~~related~~primarily consisting of the disposition of Wyoming and certain non-operated assets in West Texas and New Mexico in 2016. See Note 6 to ~~dispositions in~~ the ~~Gulf of Mexico and other conventional onshore U.S. production.~~consolidated financial statements for further information.

Marketing revenuesdecreased ~~$94~~$41 million in the second quarter of ~~2016~~2017 from the comparable ~~prior-year~~2016 period. Marketing activities include the purchase of commodities from third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points. Since the volume of marketing activity is based on market dynamics, it can fluctuate from period to period. The ~~decreases are~~decrease is primarily related ~~primarily~~ to lower marketed volumes in ~~North America E&P and OSM, which were further compounded by a lower commodity price environment.~~the United States due to non-core asset dispositions.

Income from equity method investments increased ~~$11~~$14 million in the second quarter of ~~2016~~2017 from the comparable ~~2015~~2016 period. The ~~increase~~improvement is primarily due to ~~an increase in net sales volumes as 2015 volumes were lower because of planned turnaround and maintenance activities~~higher price realizations from methanol at ~~the Alba field and E.G. LNG facilities.~~our AMPCO methanol facility.

Net gain on disposal of assets decreased$288 million in the second quarter of ~~2016 was~~2017 primarily related to the gain on sale of our Wyoming upstream and midstream non-core assets ~~and West Texas acreage.~~in the second quarter of 2016. See Note 6 to the consolidated financial statements for ~~information about dispositions.~~further information.

Production expenses decreased ~~$100 million. North America~~$9 million in the second quarter of 2017 versus the same period in 2016. United States E&P declined ~~$50~~$11 million primarily due to ~~lower operational, maintenance and labor costs, coupled with~~ the disposition of our ~~producing~~non-core assets in Wyoming during the ~~Gulf~~second half of ~~Mexico~~2016 partially offset by our Gunflint field beginning production in the second half of 2016 and ~~East Texas, North Louisiana~~the acquisitions of our Oklahoma STACK and ~~Wilburton, Oklahoma gas~~Northern Delaware assets. International E&P ~~declined $8~~increased $2 million primarily ~~as a result~~in Libya during the second quarter of lower project and labor costs in the U.K. and 2015 also includes costs arising from planned flowline maintenance at the outside operated Foinaven field; these declines were partially offset by increased costs resulting from higher net sales volumes. OSM

~~decreased $42 million primarily due to lower turnaround costs andcontinued cost management, specifically staffing and contract labor.~~2017.

The second quarter of ~~2016~~2017 production expense rate (expense per boe) for ~~North America~~United States E&P was lower as costs declined, primarily due to dispositions, as ~~cost reductions occurred at a rate faster than our production decline.~~sales volumes were marginally lower. The expense rate for International E&P declined due to an increase in ~~volumes, combined with reduced maintenance and project costs in the U.K. The OSM expense rate decreased as a result of higher~~ sales volumes in E.G. and ~~lower production expenses, as discussed above.~~Libya.

The following table provides production expense rates for each segment:


	Three Months Ended June 30,				Three Months Ended June 30,
($ per boe)	2016		2015		2017		2016
Production Expense Rate
North America E&P		$6.28		$7.19
United States E&P						$5.86		$6.28
International E&P		$5.09		$6.51		$4.68		$5.09
Oil Sands Mining ^(a)		$39.02		$78.24


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

Marketing costs decreased ~~$94~~$37 million in the second quarter of ~~2016~~2017 from the comparable ~~2015~~2016 period, consistent with the marketing revenues changes discussed above.

Other operating expenses increased $24 million in the second quarter of 2017 primarily as a result of an increase in shipping and handling costs due to rate increases in Bakken and Oklahoma. Additionally, increased sales volumes in Oklahoma due to the Oklahoma STACK acquisition in the second half of 2016 attributed to the increase.

Exploration expensesinclude unproved property impairments, dry well costs, geological and geophysical, and other, which ~~increased $78~~decreased $152 million in the second quarter of 2017primarily as a result of our decision in 2016 not to ~~not~~ drill any of our remaining Gulf of Mexico undeveloped leases. The following table summarizes the components of exploration expenses:


	Three Months Ended June 30,				Three Months Ended June 30,
(In millions)	2016		2015		2017		2016
Exploration Expenses
Unproved property impairments	$	133	$	40	$	25	$	133
Dry well costs	22		41		—		15
Geological and geophysical	—		12		—		—
Other	34		18		5		34
Total exploration expenses	$	189	$	111	$	30	$	182

Depreciation, depletion and amortization ~~decreased $190~~increased $80 million in the second quarter of 2017 primarily as a result of ~~production volume decreases, a higher proved reserve base~~an increase of $62 million in ~~Eagle Ford~~the United States E&P due to our Gunflint field beginning production in the second half of ~~2015~~2016 and ~~as a result~~sales volumes from the acquisitions and development in the Oklahoma STACK and Northern Delaware.Also contributing to this higher expense was an increase of $21 million in our International E&P segment resulting from higher sales volumes in E.G. due to the ~~non-core~~completion and start-up of our Alba field compression project in mid-2016, and increased U.K. asset ~~dispositions~~retirement expenses due to changes in ~~2015.~~timing and cost estimates for abandonment that occurred at year-end 2016. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, ~~proved reserve and production~~ volumes have an impact on DD&A expense.

The DD&A rate (expense per boe), which is impacted by changes in reserves, capitalized costs, and sales volume mix by field, can also cause changes to our DD&A. Our United States E&P DD&A rate increased in the second quarter of 2017 primarily due to the increased rate in the Gulf of Mexico as a result of the Gunflint field achieving first production in mid-2016 and our Oklahoma STACK acquisition. The DD&A rate for International E&P increased primarily due to sales volume mix changes between countries in the current quarter, and increased U.K. asset retirement expenses due to changes in timing and cost estimates for abandonment that occurred at year-end 2016. The following table provides DD&A rates for each segment. The DD&A rate for North America E&P decreased primarily as a result of a higher proved reserve base in Eagle Ford in the second half of 2015. The DD&A rate for International E&P declined due to lower asset retirement costs, with cost estimates refined in the fourth quarter of 2015. The DD&A rate for OSM declined as a result of a higher proved reserve base in the fourth quarter of 2015.

Three Months Ended June 30,
($ per boe) 2016 2015
DD&A Rate
North America E&P
$21.16

$25.45
International E&P
$6.22

$7.17
Oil Sands Mining
$11.39

$12.87

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



	Three Months Ended June 30,
($ per boe)	2017		2016
DD&A Rate
United States E&P		$24.49		$21.16
International E&P		$7.23		$6.22

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, decreased $39~~volumes. Taxes other than income increased $10 million in the second quarter of 2017 versus the same period in 2016. The increase in the second quarter of 2017 is primarily due to a reserve for non-income tax examinations relating to open tax years. The following table summarizes the components of taxes other than income:


	Three Months Ended June 30,				Three Months Ended June 30,
(In millions)	2016		2015		2017		2016
Production and severance	$	25	$	40	$	23	$	25
Ad valorem	5		15		1		5
Other	9		23		21		5
Total	$	39	$	78	$	45	$	35

General and administrative expenses decreased ~~$36~~$38 million primarily due to ~~lower~~a decrease in pension settlement charges related to workforce reductions which were reduced in the second quarter of ~~2016, which totaled $31~~2017 to $3 million compared to ~~$64~~$31 million for the same period in ~~the prior year.~~

~~Net interest and other~~ increased $28 million primarily due to increased interest expense associated with our June 2015 debt issuance. See Note 16 to the consolidated financial statements for discussion of the June 2015 debt issuance.2016.

Provision (benefit) for income taxes reflects an effective tax rate from continuing operations of ~~29%~~37% in the second quarter of ~~2016,~~2017, as compared to 2%a benefit of 28% in the second quarter of ~~2015.~~2016. We placed a full valuation allowance on our federal deferred tax assets in the fourth quarter of 2016 and expect to realize no tax benefit on any federal deferred tax assets generated in 2017. See Note 9 to the consolidated financial statements for more detail discussion concerning the rate changes.

Discontinued operations are presented net of tax. See Note 6 to the consolidated financial statements for financial information concerning our discontinued operations.

Segment Income(Loss)

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

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


	Three Months Ended June 30,						Three Months Ended June 30,
(In millions)	2016			2015			2017			2016
North America E&P	$	(70	)	$	(45	)
United States E&P							$	(107	)	$	(70	)
International E&P	55			41			59			55
Oil Sands Mining	(38		)	(77		)
Segment income (loss)	(53		)	(81		)	(48		)	(15		)
Items not allocated to segments, net of income taxes	(117		)	(305		)	(105		)	(123		)
Income (loss) from continuing operations							(153		)	(138		)
Income (loss) from discontinued operations ^(a)							14			(32		)
Net income (loss)	$	(170	)	$	(386	)	$	(139	)	$	(170	)

^(a)We entered into an agreement to sell our Canadian business in the first quarter of 2017. The Canadian business is reflected as discontinued operations in all periods presented.

~~North America~~United States E&P segment loss increased ~~$25~~$37 million after-tax in the second quarter of 2017 primarily due to ~~lower price realizations~~a decrease in the income tax benefit which resulted from U.S. valuation allowances in the current period and ~~sales volumes, which~~an increase in DD&A expenses due to the completion of projects and acquisitions. This was partially offset by ~~the impact of~~higher price realizations and lower ~~net sales volumes to DD&A,~~ production costs ~~and taxes other than income; and lower exploration expenses.~~due to non-core asset dispositions.

International E&P segment income increased ~~$14~~$4 million after-tax in the second quarter of 2017 primarily due to ~~decreased exploration expenses~~higher price realizations and an increase in sales volumes in E.G. and Libya and an increase in income from equity ~~investments, which were partially~~investments. This was nearly completely offset by ~~lower price realizations.~~

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

Results of Operations

Six Months Ended June 30, ~~2016~~2017 vs. Six Months Ended June 30, ~~2015~~2016

Consolidated Results of Operation

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


	Six Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015			2017		2016
Sales and other operating revenues, including related party
North America E&P	$	1,110		$	1,843
United States E&P							$	1,369	$	1,110
International E&P	255			393			423		255
Oil Sands Mining	333			372
Segment sales and other operating revenues, including related party	$	1,698		$	2,608		$	1,792	$	1,365
Unrealized loss on commodity derivative instruments	(114		)	(21		)
Unrealized gain (loss) on commodity derivative instruments							120		(114		)
Sales and other operating revenues, including related party	$	1,584		$	2,587		$	1,912	$	1,251


	Six Months Ended		Increase (Decrease) Related to						Six Months Ended			Six Months Ended		Increase (Decrease) Related to					Six Months Ended
(In millions)	June 30, 2015		Price Realizations			Net Sales Volumes			June 30, 2016			June 30, 2016		Price Realizations		Net Sales Volumes			June 30, 2017
North America E&P Price-Volume Analysis ^(a)
United States E&P Price-Volume Analysis ^(a)											United States E&P Price-Volume Analysis ^(a)
Liquid hydrocarbons	$	1,633	$	(394	)	$	(279	)	$	960		$	960	$	313	$	(101	)	$	1,172
Natural gas	188		(51		)	(24		)	113			113		61		3			177
Realized gain on commodity
derivative instruments	5		19						24			24							17
Other sales	17								13			13							3
Total	$	1,843							$	1,110		$	1,110						$	1,369
International E&P Price-Volume Analysis
Crude oil and condensate
Natural gas liquids
Liquid hydrocarbons	$	310	$	(90	)	$	(26	)	$	194		$	194	$	92	$	73		$	359
Natural gas	60		(17		)	—			43			43		—		5			48
Other sales	23								18			18							16
Total	$	393							$	255		$	255						$	423
Oil Sands Mining Price-Volume Analysis
Synthetic crude oil	$	355	$	(112	)	$	81		$	324
Other sales	17								9
Total	$	372							$	333

^(a)Six months ~~ended~~ending June 30, ~~2016~~2017 includes a net sales volume reduction from June 30, 2016 of 1721 mboed ~~related~~primarily consisting of the disposition of Wyoming and certain non-operated assets in West Texas and New Mexico in 2016. See Note 6 to ~~dispositions in~~ the ~~Gulf of Mexico and other conventional onshore U.S. production.~~consolidated financial statements for further information.

Marketing revenues for the first six months of ~~2016~~2017 decreased by ~~$240~~$53 million. Marketing activities include the purchase of commodities from third parties for resale and serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points. ~~Because~~Since the volume of marketing activity is based on market dynamics, it can fluctuate from period to period. The decrease is related primarily to lower marketed volumes in ~~North America, which were further compounded by a lower commodity price environment.~~the United States E&P segment due to non-core asset dispositions.

Income from equity method investments ~~decreased $11 million. The decrease is~~increased $69 million for the first six months of 2017 primarily due to ~~lower~~higher price realizations from LPG at our Alba plant and methanol at our AMPCO methanol facility. Also contributing to the increase was improvement in net sales volumes ~~as a result of planned downtime at E.G. as a result~~primarily driven by the completion of the Alba field compression project ~~which impacted our equity method plants, which was partially offset by planned turnaround and maintenance activities at~~in E.G. during the ~~Alba field and E.G. LNG facilities in 2015. Also impacting the first six months~~second half of ~~2016 were lower price realizations for LPG at our Alba plant.~~2016.

Net gain (loss) on disposal of assets decreased $227 million for the first six months of ~~2016~~2017. This decrease was primarily related to the sale of ~~our~~non-core assets in the first half of 2016 in Wyoming, ~~upstream and midstream assets and~~ West Texas ~~acreage.~~and New Mexico, and the Gulf of Mexico. See Note 6 to the consolidated financial statements for information about dispositions.

Production expenses for the first six months of ~~2016~~2017 decreased by ~~$216~~$45 million compared to the same period ~~of 2015. North America~~in 2016. United States E&P declined ~~$118~~$36 million primarily due to ~~lower operational, maintenance and labor costs, coupled with~~ the disposition of our ~~producing~~non-core assets in Wyoming during the ~~Gulf~~second half of ~~Mexico~~2016 partially offset by our Gunflint field beginning production in the second half of 2016 and ~~East Texas, North Louisiana~~the acquisitions of our Oklahoma STACK and ~~Wilburton, Oklahoma gas~~Northern Delaware assets. International E&P declined ~~$22~~$9 million ~~largely due to~~primarily as a result of lower ~~operational~~planned maintenance costs in the ~~U.K. OSM decreased $76 million primarily due~~first six months of 2017 in E.G. compared to ~~continued cost management, specifically staffing and contract labor, lower turnaround costs, and a favorable exchange rate on expenses denominated~~the same period in ~~the Canadian Dollar.~~2016.

The first six months of ~~2016~~2017 production expense rate (expense per boe) for ~~North America~~United States E&P was lower as costs declined, primarily due to ~~cost reductions that occurred at a rate faster than our production decline.~~dispositions, and as sales volumes were marginally lower. The International E&P expense rate decreased in the first six months of ~~2016~~2017 primarily due to ~~reduced~~an increase in sales volumes in E.G. and Libya, combined with lower planned maintenance ~~and project~~ costs in ~~the U.K. The OSM expense rate decreased~~E.G. due to planned maintenance in the first ~~six months~~half of ~~2016 primarily due to higher production coupled with lower operational costs.~~2016.


	Six Months Ended June 30,				Six Months Ended June 30,
($ per boe)	2016		2015		2017		2016
Production Expense Rate
North America E&P		$6.22		$7.57
United States E&P						$5.82		$6.22
International E&P		$5.53		$6.45		$4.22		$5.53
Oil Sands Mining ^(a)		$33.42		$50.06


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

Marketing costs decreased ~~$241~~$49 million in the first six months of ~~2016~~2017 from the comparable ~~2015~~2016 period, consistent with the marketing revenues changes discussed above.

Exploration expenses ~~were $12~~include unproved property impairments, dry well costs, geological and geophysical, and other, which decreased $148 million ~~higher~~ in the first six months of ~~2016 than in~~2017 versus the comparable ~~2015 period primarily due to higher unproved property impairments, which were partially offset by lower dry well costs.~~2016 period. Unproved property impairments ~~were higher in 2016~~decreased primarily as a result of our decision in 2016 not to drill any of our remaining Gulf of Mexico leases that we decided not to drill. Dry well costs for the first six months of 2015 primarily consist of costs associated with the Sodalita West #1 well in E.G., the Key Largo well in the Gulf of Mexico, and suspended well costs related to Birchwood in-situ.undeveloped leases. The following table summarizes the components of exploration expenses:


	Six Months Ended June 30,				Six Months Ended June 30,
(In millions)	2016		2015		2017		2016
Exploration Expenses
Unproved property impairments	$	144	$	49	$	45	$	144
Dry well costs	22		99		—		15
Geological and geophysical	—		15		1		—
Other	47		38		12		47
Total exploration expenses	$	213	$	201	$	58	$	206

Depreciation, depletion and amortization~~(“DD&A”) decreased $402~~ increased $87 million in the first six months of ~~2016~~2017 from the comparable ~~2015~~2016 period primarily as a result of ~~production volume decreases and a higher proved reserve base~~an increase of $47 million in ~~Eagle Ford~~the United States E&P due to our Gunflint field beginning production in the second half of ~~2015.~~2016 and sales volumes from the acquisitions and development in the Oklahoma STACK and Northern Delaware. Also contributing to this higher expense was an increase of $46 million in our International E&P segment resulting from higher sales volumes in E.G. due to the completion and start-up of our Alba field compression project in mid-2016, and increased U.K. asset retirement expenses due to changes in timing and cost estimates for abandonment that occurred at year-end 2016. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, volumes have an impact on DD&A expense.

The DD&A rate (expense per boe), which is impacted by field-level changes in sales volumes, reserves and capitalized costs, can also cause changes to our DD&A. The DD&A rate for United States E&P increased primarily due to the increased rate in the Gulf of Mexico as a result of the Gunflint field achieving first production in mid-2016 and our Oklahoma STACK acquisition. The DD&A rate for International E&P increased primarily due to sales volume mix changes between countries in the current quarter, and increased U.K. asset retirement expenses due to changes in timing and cost estimates for abandonment that occurred at year-end 2016. The following table provides DD&A rates for each segment. ~~The DD&A rate for North America E&P decreased primarily as a result of a higher proved reserve base in Eagle Ford in the second half of 2015.~~



	Six Months Ended June 30,
($ per boe)	2017		2016
DD&A Rate
United States E&P		$24.81		$21.79
International E&P		$6.93		$5.98

Six Months Ended June 30,
($ per boe) 2016 2015
DD&A Rate

North America E&P
$21.79

$26.16
International E&P
$5.98

$6.62
Oil Sands Mining
$11.34

$12.58

~~Impairments~~ decreased $43 million in the first six months of 2016 as a result of the second quarter of 2015 non-cash impairment charge related to East Texas, North Louisiana and Wilburton, Oklahoma natural gas assets in anticipation of the sale in 2015. See Note 13 to the consolidated financial statements for discussion of the impairment.

Taxes other than income include production, severance, and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales ~~volumes, decreased $58~~volumes. Taxes other than income increased $6 million in the first six months of ~~2016~~2017 from the comparable ~~2015~~2016 period. The increase in the first six months of 2017 is primarily due to a reserve for non-income tax examinations relating to open tax years. The following table summarizes the components of taxes other than income:


	Six Months Ended June 30,				Six Months Ended June 30,
(In millions)	2016		2015		2017		2016
Production and severance	$	44	$	74	$	48	$	44
Ad valorem	19		31		4		19
Other	24		40		32		15
Total	$	87	$	145	$	84	$	78

General and administrative expenses decreased ~~$56~~$80 million in the first six months of ~~2016~~2017 compared to the same period in ~~2015.~~2016. This decrease was primarily due to ~~cost savings realized from the 2015~~a decrease in pension settlement charges related to workforce reductions ~~and corresponding severance expenses.~~which were reduced in the first six months of 2017 to $17 million compared to $79 million for the same period in 2016.

Provision (benefit) for income taxes ~~reflect~~reflects an effective tax ~~rates~~rate from continuing operations of ~~37%~~59% in the first six months of ~~2016,~~2017, as compared to ~~18%~~a benefit of 38% from the comparable ~~2015~~2016 period. We placed a full valuation allowance on our federal deferred tax assets in the fourth quarter of 2016 and expect to realize no tax benefit on any federal deferred tax assets generated in 2017. See Note 9 to the consolidated financial statements for discussion of the effective tax rate.

Discontinued operations are presented net of tax. See the preceding Operations section and Note 6 to the consolidated financial statements for financial information concerning our 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~~A portion of 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, pension settlement losses, or other items that affect comparability also are not allocated to operating segments.

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


	Six Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015			2017			2016
North America E&P	$	(265	)	$	(206	)
United States E&P							$	(186	)	$	(265	)
International E&P	59			64			152			59
Oil Sands Mining	(86		)	(96		)
Segment income (loss)	(292		)	(238		)	(34		)	(206		)
Items not allocated to segments, net of income taxes	(285		)	(424		)	(169		)	(292		)
Income (loss) from continuing operations							(203		)	(498		)
Income (loss) from discontinued operations ^(a)							(4,893		)	(79		)
Net income (loss)	$	(577	)	$	(662	)	$	(5,096	)	$	(577	)

^(a)We entered into an agreement to sell our Canadian business in the first quarter of 2017. The Canadian business is reflected as discontinued operations in all periods presented.

~~North America~~United States E&P segment loss ~~increased $59~~decreased $79 million after-tax in the first six months of ~~2016~~2017 from the comparable ~~2015~~2016 period primarily due to ~~lower~~higher price realizations and lower production costs as a result of dispositions and lower sales ~~volumes, which~~volumes. This was partially offset by a decrease in the ~~impact~~income tax benefit which resulted from U.S. valuation allowances in the current period, an increase in DD&A expenses due to the completion of ~~lower net~~projects and a decrease in our sales volumes primarily due to ~~DD&A, production costs and taxes other than income; and lower exploration expenses.~~dispositions.

International E&P segment income ~~decreased $5~~increased $93 million after-tax in the first six months of ~~2016~~2017 from the comparable ~~2015 period primarily due to lower liquid hydrocarbon price realizations. These declines were partially offset by lower exploration, production and DD&A expenses.~~

~~Oil Sands Mining segment lossdecreased $10 million after-tax in the first six months of~~ 2016 ~~from the comparable 2015~~ period primarily due to higher price realizations and an increase in sales volumes in E.G. and ~~lower production expenses,~~Libya, and an increase in income from equity investments. This was partially offset by ~~lower price realizations~~an increase in DD&A and ~~higher DD&A expense.~~income tax 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 disclosed in our Form 10-K for the year ended December 31, ~~2015,~~2016, 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.~~level, as of June 30, 2017 we have $115 million of goodwill associated with our International E&P reporting unit. We performed our annual impairment test in April ~~2016~~2017 and concluded no impairment was required. ~~While~~As of the date of our last impairment assessment, the fair value of our International E&P reporting unit exceeded its 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~~by over 40%. See Note 13 to the ~~first day of each month within the 12-month period ("SEC pricing"). The table below provides the 2015 SEC pricing~~consolidated financial statements for ~~certain benchmark prices as well as the unweighted average for the first eight months of 2016:~~

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

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

Accounting Standards Not Yet Adopted

See Note 2 to the consolidated financial statements.

Cash Flows

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


	Six Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015			2017			2016
Sources of cash and cash equivalents
Operating activities	$	252		$	717
Operating activities - continuing operations							$	923		$	267
Disposals of assets	758			2			1,726			758
Borrowings	—			1,996
Common stock issuance	1,236			—			—			1,236
Other	39			43			49			39
Total sources of cash and cash equivalents	$	2,285		$	2,758		$	2,698		$	2,300
Uses of cash and cash equivalents
Cash additions to property, plant and equipment	$	(753	)	$	(2,320	)	$	(775	)	$	(728	)
Deposit for acquisition	(89		)	—
Purchases of short-term investments	—			(925		)
Debt issuance costs	—			(19		)
Debt repayments	—			(34		)
Acquisitions, net of cash acquired							(1,828		)	—
Deposits for acquisitions							—			(89		)
Dividends paid	(77		)	(285		)	(85		)	(77		)
Purchases of common stock							(10		)	(4		)
Other	(3		)	(1		)	(6		)	—
Total uses of cash and cash equivalents	$	(922	)	$	(3,584	)	$	(2,704	)	$	(898	)

Cash flows generated from operating activities in the first six months of ~~2016 were lower~~2017 was higher as ~~the downturn in the~~ commodity ~~cycle continued. This continued downward pressure on price realizations, coupled with the lower net sales volumes, continues~~prices improved compared to ~~negatively impact our cash flows from operating activities. In~~ the first six months of ~~2016, consolidated average oil and NGL~~2016. This drove an increase in price realizations ~~were down~~in the first six months of 2017. Consolidated average liquid hydrocarbon price realizations increased by ~~approximately 27% and consolidated net sales volumes declined by 9%~~more than 35% during the first six months of 2017 as compared to the prior ~~year.~~period. This increase in price realization coupled with our continued focus on cost reduction, including production expense and general & administrative expense, resulted in our increased cash flows generated from operating activities.

Proceeds from the disposals of assets for the first six months of 2017 are ~~primarily~~ from the ~~sale~~disposal of our ~~Wyoming upstream and midstream assets;~~Canadian business; see Note 6 to the consolidated financial statements for further information concerning dispositions. Common stock issuance reflects net proceeds received in March 2016 from our public sale of common stock. See ~~Liquidity and Capital Resources below~~Note 18 to the consolidated financial statements for additional information.

Additions to property, plant and equipment ~~are our most significant use of cash and cash equivalents and were lower~~ in the first ~~half~~six months of ~~2016~~2017 were consistent with ~~a reduced~~our Capital ~~Program as compared to the prior year.~~Program. The following table shows capital expenditures related to continuing operations by segment and reconciles to additions to property, plant and equipment as presented in the consolidated statements of cash ~~flows (the table excludes an $89 million deposit paid into escrow related to~~flows:



	Six Months Ended June 30,
(In millions)	2017			2016
United States E&P	$	924		$	468
International E&P	23			44
Corporate	11			8
Total capital expenditures	958			520
Decrease (increase) in capital expenditure accrual	(183		)	208
Total use of cash and cash equivalents for property, plant and equipment	$	775		$	728

In the second quarter of 2017 we closed on our acquisition of ~~PayRock~~the Northern Delaware assets ~~- see~~for a purchase price of $1.8 billion, subject to closing adjustments. See Note 5 to the consolidated financial statements for ~~further information related to this acquisition):~~

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

The Board of Directors approved a $0.05 per share dividend for the first quarter of ~~2016,~~2017, which was paid in the second quarter of ~~2016.~~2017. See Capital Requirements below for additional information about the second quarter dividend.

Liquidity and Capital Resources

~~In March 2016,~~On July 24, 2017, we issued ~~166,750,000 shares~~$1 billion of 4.4% senior unsecured notes that will mature on July 15, 2027. Interest on the senior notes is payable semi-annually beginning January 15, 2018. We will use the net proceeds plus existing cash on hand to redeem the following senior notes:

$682 million 6.0% Notes Due in 2017

$854 million 5.9% Notes Due in 2018

$228 million 7.5% Notes Due in 2019

The new issuance together with the redemption will result in a reduction in total gross debt of approximately $750 million in the third quarter of 2017. In July 2017, we gave notice that we will redeem during the third quarter of 2017, $1.76 billion of the senior unsecured notes discussed above in accordance with their make-whole call provisions. As a result of this notice we expect to recognize into earnings an estimated loss of approximately $40 to $50 million, in loss on extinguishment of debt, during the third quarter of 2017. See Note 14 for detail relating to the proceeds of $54 million, which will result in a gain of approximately $47 million into earnings in the third quarter of 2017, on the termination of our common stock, par value $1 per share, at a price of $7.65 per share, excluding underwriting discounts and commissions, for net proceeds of $1,236 million. The proceeds were used to strengthen our balance sheet and for general corporate purposes, including funding a portionforward starting interest rate swaps associated with this issuance.

In June 2017, we extended the maturity date of our ~~Capital Program.~~

~~Also in March 2016,~~Credit Facility from May 28, 2020 to May 28, 2021, and maintained the Credit Facility at $3.3 billion. In July 2017, we increased our $3$3.3 billion unsecured Credit Facility by ~~$300~~$93 million to a total of ~~$3.3~~$3.4 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the ~~increase.~~increase and term extension. We have the ability to request two additional one-year extensions and an option to increase the commitment amount by up to an additional $107 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.

Our main sources of liquidity are cash and cash equivalents, ~~sales of non-core assets,~~ internally generated cash flow from operations, sales of non-core assets, capital market transactions, and our revolving credit facility. At June 30, 2017, we had approximately $5.9 billion of liquidity consisting of $2.6 billion in cash and cash equivalents and $3.3 billion ~~Credit Facility.~~available under our revolving credit facility. Our working capital requirements are supported by these sources and we may draw on our ~~$3.3 billion Credit Facility~~revolving credit facility to meet short-term cash requirements, or issue debt or equity securities through the shelf registration statement discussed below as part of our longer-term liquidity and capital ~~management.~~management program. Because of the alternatives available to us as discussed above, we believe that our short-term and long-term liquidity isare adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, and other amounts that may ultimately be paid in connection with contingencies.

~~Due~~General economic conditions, commodity prices, and financial, business and other factors could affect our operations and our ability to ~~decreases in crude oil and U.S. natural gas prices, credit rating agencies reviewed companies in~~access the ~~industry earlier this year, including us. During the first quarter of 2016, our~~capital markets. Our corporate credit ~~rating was downgraded by:~~ratings as of June 30, 2017 are: Standard & Poor's Ratings Services to BBB- (stable) ~~from BBB (stable)~~; by Fitch Ratings to BBB (negative) ~~from BBB+ (stable)~~; and by Moody's Investor Services, Inc. to Ba1 ~~(negative) from Baa1~~ (stable). ~~Any further rating downgrades~~A downgrade in our credit ratings could increase our future cost of financing or limit our ability to access capital, and result in additional collateral requirements. See Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, ~~2015~~2016 for a discussion of how a further downgrade in our credit ratings could affect us.

The June 23, 2016 referendum by British voters to exit the European Union (“Brexit”) provided uncertainty and potential volatility around European currencies, and resulted in a decline in the value of the British pound, as compared to the U.S. dollar and other currencies. Volatility in exchange rates may continue in the short term as the U.K. negotiates its exit from the European Union. A weaker British pound compared to the U.S. dollar during a reporting period causes local currency results of our U.K. operations to be translated into fewer U.S. dollars. For our U.K. operations a majority of our revenues are tied to global crude oil prices which are denominated in U.S. dollars while a significant portion of our operating and capital costs are denominated in British pounds. In addition, our U.K. operations have an asset retirement obligation, which represents a future cash commitment. In the longer term, any impact from Brexit on our U.K. operations will depend, in part, on the outcome of tariff, trade, regulatory, and other negotiations.

Capital Resources

Credit Arrangements and Borrowings

At June 30, ~~2016,~~2017, we had no borrowings against our revolving credit facility.

At June 30, ~~2016,~~2017, we had $7.3 billion in long-term debt ~~outstanding, with our next~~outstanding. As a result of the debt ~~maturity in~~issuance discussed above, we reclassified $990 million of the ~~amount of $682 million~~6.0% senior notes due in 2017 and 5.9% senior notes due in 2018 to long-term debt as we have the ~~fourth quarter~~intent and ability to redeem them with the net proceeds received from the debt issuance. Therefore, as of ~~2017.~~June 30, 2017, we had long-term debt due within one year of $548 million.

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~~debt and ~~debt~~equity securities.

Asset ~~Disposals~~Disposal

~~During~~In the second quarter of 2017 we ~~announced~~closed on the sale of our ~~Wyoming upstream~~Canadian business for $2.5 billion, excluding closing adjustments. Under the terms of the agreement, $1.8 billion was paid to us upon closing and ~~midstream assets for~~the remaining proceeds of ~~$870~~$750 million ~~before closing adjustments, of which approximately $690 million was received~~will be paid to us in the ~~second quarter. The remaining asset sales are subject~~first quarter of 2018. See Note 6 to the ~~receipt of certain tribal consents and are expected to close before year end. The proceeds~~consolidated financial statements for ~~the remaining asset sales were deposited into an escrow account by the buyer.~~

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

additional information.

Cash-Adjusted Debt-To-Capital Ratio

Our cash-adjusted debt-to-capital ratio (total debt-minus-cash and cash equivalents to total debt-plus-equity-minus-cash and cash equivalents) was ~~20%~~27% at June 30, ~~2016,~~2017, compared to ~~25%~~21% at December 31, ~~2015.~~2016.


	June 30,			December 31,			June 30,			December 31,
(In millions)	2016			2015			2017			2016
Long-term debt due within one year	$	1		$	1		$	548		$	686
Long-term debt	7,280			7,276			6,715			6,581
Total debt	$	7,281		$	7,277		$	7,263		$	7,267
Cash and cash equivalents	$	2,584		$	1,221		$	2,614		$	2,488
Equity	$	19,153		$	18,553		$	12,405		$	17,541
Calculation:
Total debt	$	7,281		$	7,277		$	7,263		$	7,267
Minus cash and cash equivalents	2,584			1,221			2,614			2,488
Total debt minus cash, cash equivalents	$	4,697		$	6,056		$	4,649		$	4,779
Total debt	$	7,281		$	7,277		$	7,263		$	7,267
Plus equity	19,153			18,553			12,405			17,541
Minus cash and cash equivalents	2,584			1,221			2,614			2,488
Total debt plus equity minus cash, cash equivalents	$	23,850		$	24,609		$	17,054		$	22,320
Cash-adjusted debt-to-capital ratio	20		%	25		%	27		%	21		%

Capital Requirements

~~We closed on our purchase agreement~~Capital Spending

As a result of ~~PayRock for $888 million, as discussed~~strong operational performance in ~~Note 5 to~~ the ~~consolidated financial statements. We~~first half of the year and continued efficiency gains we expect our Capital Program for full-year ~~2016~~2017 to ~~be $1.3~~decrease from $2.4 billion ~~or $100 million lower than the original budget, which includes the increased activity from the PayRock acquisition.~~to a range of $2.1 to $2.2 billion.

Other Expected Cash Outflows

On July ~~27, 2016,~~26, 2017, our Board of Directors approved a dividend of $0.05 per share for the second quarter of ~~2016~~2017 payable September ~~12, 2016~~11, 2017 to stockholders of record at the close of business on August ~~17, 2016.~~16, 2017.

As of June 30, ~~2016,~~2017, we plan to make contributions of up to ~~$34~~$33 million to our funded pension plans during the remainder of ~~2016.~~2017.

into earnings an estimated loss of approximately $40 to $50 million, in loss on extinguishment of debt, during the third quarter of 2017.

Contractual Cash Obligations

As of June 30, ~~2016,~~2017, there are no material changes to our consolidated cash obligations to make future payments under existing contracts, as disclosed in our ~~2015~~2016 Annual Report on Form 10-K, except for cash obligations primarily relating to the ~~agreement we entered into~~sale of our Canadian business. See Note 6 to ~~acquire PayRock as described above, which was paid with cash on hand.~~

~~During~~ the ~~third quarter we executed an agreement to terminate our Gulf of Mexico deepwater drilling rig contract, as~~consolidated financial statements for additional information. As a result, ~~we expect~~as of June 30, 2017, our consolidated contractual cash obligations from our continuing operations has decreased by $1,239 million from December 31, 2016 primarily due to ~~make a termination payment~~obligations relating to the sale of ~~$113~~our Canadian business. Our purchase obligations under oil and gas activities decreased by $45 million, ~~during the third quarter of~~service and materials contracts decreased $646 million and transportation and related contracts decreased $270 million when comparing June 30, 2017 to December 31, 2016.

Environmental Matters and Other Contingencies

In July 2015, we received a request for information from the EPA under Section 114 of the Clean Air Act regarding several tank batteries used in our Bakken operations. ~~Beginning~~We executed a settlement agreement with the North Dakota Department of Health relating to this matter in the ~~second~~fourth quarter of 2016 ~~we have been in settlement discussions with~~that includes a base penalty of $294,000 that will be reduced under the State of North Dakota’s Department of Health regarding potential noncompliance with the Clean Air Act, North Dakota Century Code Air Pollution Control provisions, and implementing regulations. To date, no federal or state enforcement action has been commenced in connection with this matter. We anticipate that resolution of this matter will result in civil or administrative penalties of an undetermined amount and require us to undertaketerms by mitigating corrective ~~actions which may increase our development and/or operating costs.~~actions. We do not believe that any penalties or corrective action expenditures that may result from this matter will have a material adverse effect on our financial position, results of operation or cash flows.

See Note 20 to the consolidated financial statements for a description of 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"~~“Exchange Act”). All statements other than statements of historical fact, including without limitation statements regarding our future performance, business strategy, reserve estimates, asset quality, production guidance, drilling plans, capital plans, cost and expense estimates, ~~assets~~asset acquisitions and ~~sales,~~dispositions, future financial position, future payments for our Canadian disposition and other plans and objectives for future operations, are forward-looking statements. Words such as “anticipate,” “believe,” ~~"could,"~~“could,” “estimate,” “expect,” “forecast,” ~~"guidance,~~“guidance,” “intend," ~~"intend," "may,"~~“may,” “plan,” “project,” “seek,” “should,” ~~"target," "will,"~~“target,” “will,” “would” or similar words may be used to identify forward-looking statements; however, the absence of these words does not mean that the statements are not forward-looking. While we believe our assumptions concerning future events are reasonable, a number of factors could cause results to differ materially from those projected, including, but not limited to:

conditions in the oil and gas industry, including ~~supply/~~supply and demand levels for crude oil and condensate, NGLs and natural gas and the resulting impact on price;

changes in expected reserve or production levels;

changes in political and economic conditions in the jurisdictions in which we operate, including changes in foreign currency exchange rates, interest rates, inflation rates, and global and domestic market conditions;

risks related to our hedging activities;

capital available for exploration and development;

~~risks related~~the inability of any party to satisfy closing conditions with respect to our ~~hedging activities;~~

~~our level of success in integrating acquisitions;~~

~~well production timing;~~asset disposition;

drilling and operating risks;

well production timing;

availability of drilling rigs, materials and ~~labor;~~labor, including the costs associated therewith;

difficulty in obtaining necessary approvals and permits;

non-performance by third parties of contractual obligations;

unforeseen hazards such as weather ~~conditions;~~

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

cyber-attacks;

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

other geological, operating and economic considerations; and

the risk factors, forward-looking statements and challenges and uncertainties described in our ~~2015~~2016 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other filings with the SEC.

All forward-looking statements included in this report are based on information available to us on the date of this report. WeExcept as required by law, we undertake no 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 ~~2015~~2016 Annual Report on Form 10-K. Notes 13 and 14 to the consolidated financial statements include additional disclosures regarding our open derivative positions, including underlying notional quantities, how they are reported in our consolidated financial statements and how their fair values are measured.

Commodity Price Risk During the first six months of ~~2016,~~2017, 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~~United States E&P sales. The following tables provide a summary of open positions as of June 30, ~~2016~~2017 and the weighted average price for those contracts:

								Crude Oil
			Year Ending December 31,	2017		2018
	Third Quarter	Fourth Quarter	2017	Third Quarter	Fourth Quarter	First Quarter	Second Quarter
Three-Way Collars(a)	Three-Way Collars(a)			Three-Way Collars(a)
Volume (Bbls/day)	47,000		—	50,000	50,000	20,000	20,000
Price per Bbl:
Weighted average price per Bbl:
Ceiling	$55.37		—	$60.37	$60.37	$57.86	$57.86
Floor	$50.23		—	$54.80	$54.80	$53.00	$53.00
Sold put	$40.96		—	$47.80	$47.80	$47.00	$47.00
Sold call options ^(a)(b)
Volume (Bbls/day)	10,000		35,000	35,000	35,000	—	—
Price per Bbl	$72.39		$61.91
Two-way Collars
Volume (Bbls/day)	10,000		—
Price per Bbl:			—
Ceiling	$50.00
Floor	$41.55
Weighted average price per Bbl				$61.91	$61.91	—	—


^(a)	Subsequent to June 30, 2017, we entered into 20,000 Bbls/day of three-way collars for January - December 2018 with an average ceiling price of $55.09, a floor price of $50.00, and a sold put price of $43.00.


^(b)	Call options settle monthly.


^(a)	On our 2016 collars, the 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.



Natural Gas
	2017		2018
	Third Quarter	Fourth Quarter	First Quarter	Second Quarter	Third Quarter	Fourth Quarter
Three-Way Collars
Volume (MMBtu/day)	120,000	120,000	200,000	160,000	160,000	160,000
Weighted average price per MMBtu:
Ceiling	$3.58	$3.71	$3.79	$3.61	$3.61	$3.61
Floor	$3.09	$3.14	$3.08	$3.00	$3.00	$3.00
Sold put	$2.55	$2.60	$2.55	$2.50	$2.50	$2.50
Swaps
Volume (MMBtu/day)	20,000	20,000	—	—	—	—
Weighted average price per MMBtu	$2.93	$2.93	—	—	—	—

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, ~~2016.~~2017.


(In millions)	Hypothetical Price Increase of 10%			Hypothetical Price Decrease of 10%		Hypothetical Price Increase of 10%			Hypothetical Price Decrease of 10%

Crude oil derivatives	$	(32	)	$	73	$	(30	)	$	18
Natural gas derivatives	(5		)	5		(15		)	13
Total	$	(37	)	$	78	$	(45	)	$	31

Interest Rate Risk Sensitivity analysis of the incremental effect of a hypothetical 10% ~~change~~decrease in interest rates on financial assets and liabilities as of June 30, ~~2016,~~2017, 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
Interest rate fair value hedges								$	1		^(b)	$	1
Interest rate swaps								$	53		^(b)	$	(15	)
Long term debt, including amounts due within one year	$	(7,186	)	^(b)(c)	$	(287	)	$	(7,451	)	^(b)(c)	$	(254	)


^(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.


^(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, ~~2016.~~2017.

During the ~~second quarter~~first six months of ~~2016,~~2017, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II – OTHER INFORMATION

Item 1. Legal ~~and Administrative~~ Proceedings

We are a defendant in a number of 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.

See Note 20 to the consolidated financial statements included in Part I, Item I for a description of such legal and administrative proceedings.

The following is a summary of certain proceedings involving us that were pending or contemplated as of June 30, 2017 under federal, state and international environmental laws:

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 ~~2015~~2016 Annual Report on Form 10-K.

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

The following table provides information about repurchases by Marathon Oil of its common stock during the quarter ended June 30, ~~2016.~~2017.

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

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



Period	Total Number of Shares Purchased^(a)	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs^(b)	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs^(b)
04/01/17 - 04/30/17	66,785	$16.23	—	$	1,500,285,529
05/01/17 - 05/31/17	123,405	$14.83	—	$	1,500,285,529
06/01/17 - 06/30/17	493	$13.18	—	$	1,500,285,529
Total	190,683	$15.32	—


^(a)	~~245,651~~190,683 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

^(b)

In January 2006, we announced a $2.0 billion share repurchase program. Our Board of directors subsequently increased the authorization for repurchases under the program by $500 million in January 2007, by $500 million in May 2007, by $2.0 billion in July 2007, and by $1.2 billion in December 2013, for a total authorized amount of $6.2 billion. The remaining share repurchase authorization as of June 30, 2017 is $1.5 billion. No repurchases were made under the program in the second quarter of 2017.

Item 6. Exhibits

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

SIGNATURES

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



August ~~4, 2016~~3, 2017		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
3.1 Restated Certificate of Incorporation of Marathon Oil Corporation 10-Q 3.1 8/8/2013
3.2 Marathon Oil Corporation By-laws (Amended and restated as of February 24, 2016)*
3.3 Specimen of Common Stock Certificate 10-K 3.3 2/28/2014
4.1 Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the SEC upon its request 10-K 4.1 2/28/2014
10.1 Marathon Oil Corporation 2016 Incentive Compensation Plan 14A App. A 4/07/2016
12.1 Computation of Ratio of Earnings to Fixed Charges*
31.1 Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934*
31.2 Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934*
32.1 Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350*
32.2 Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350*
101.INS XBRL Instance Document*
101.SCH XBRL Taxonomy Extension Schema*
101.CAL XBRL Taxonomy Extension Calculation Linkbase*
101.DEF XBRL Taxonomy Extension Definition Linkbase*
101.LAB XBRL Taxonomy Extension Label Linkbase*
101.PRE XBRL Taxonomy Extension Presentation Linkbase*
* Filed herewith.



		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	4.2	2/28/2014
10.1	Second Amendment, dated as of June 22, 2017, to the Amended and Restated Credit Agreement dated as of May 28, 2014, as amended by the First Amendment dated as of May 5, 2015, and supplemented by the Incremental Commitments Supplement dated as of March 4, 2016, among Marathon Oil Corporation, as borrower, the lenders party thereto, The Royal Bank of Scotland Plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, and JPMorgan Chase Bank, N.A., as administrative agent.	8-K	99.1	6/23/2017
10.2*	Incremental Commitment Supplement, dated as of July 11, 2017, to the Amended and Restated Credit Agreement dated as of May 28, 2014, as amended by the First Amendment dated as of May 5, 2015, supplemented by the Incremental Commitments Supplement dated as of March 4, 2016, and amended by the Second Amendment dated as of June 22, 2017, among Marathon Oil Corporation, as borrower, the lenders party thereto, The Royal Bank of Scotland Plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, and JPMorgan Chase Bank, N.A., as administrative agent.
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	1925
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3740
Item 4.	Controls and Procedures	3841
Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	3942
Item 1A.	Risk Factors	3942
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3942
Item 6.	Exhibits	3942
	Signatures	4043



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



		Gain (Loss)
		Three Months Ended June 30,					Six Months Ended June 30,
(In millions)	Income Statement Location	2016		2015			2016			2015
Derivative
Interest rate	Net interest and other	$	—	$	(2	)	$	4		$	3
Hedged Item
Long-term debt	Net interest and other	$	—	$	2		$	(4	)	$	(3	)



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



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