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~~March 31, 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~~Smaller reporting companyo	Emerging growth company o
	(Do not check if a smaller reporting company)		~~Smaller reporting 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~~849,991,741 shares of Marathon Oil Corporation common stock outstanding as of ~~July 31, 2016.~~April 30, 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 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
	June 30,						June 30,						March 31,
(In millions, except per share data)	2016			2015			2016			2015			2017			2016
Revenues and other income:
Sales and other operating revenues, including related party	$	870		$	1,307		$	1,584		$	2,587		$	954		$	566
Marketing revenues	89			183			147			387			34			46
Income from equity method investments	37			26			51			62			69			14
Net gain (loss) on disposal of assets	294			—			234			1			1			(60		)
Other income	12			15			16			26			14			4
Total revenues and other income	1,302			1,531			2,032			3,063			1,072			570
Costs and expenses:
Production	350			450			678			894			151			187
Marketing, including purchases from related parties	88			182			146			387			34			46
Other operating	95			81			204			188			89			103
Exploration	189			111			213			201			28			24
Depreciation, depletion and amortization	561			751			1,170			1,572			556			549
Impairments	—			44			1			44			4			1
Taxes other than income	39			78			87			145			39			43
General and administrative	132			168			283			339			109			151
Total costs and expenses	1,454			1,865			2,782			3,770			1,010			1,104
Income (loss) from operations	(152		)	(334		)	(750		)	(707		)	62			(534		)
Net interest and other	(86		)	(58		)	(171		)	(105		)	(78		)	(79		)
Income (loss) before income taxes	(238		)	(392		)	(921		)	(812		)
Income (loss) from continuing operations before income taxes													(16		)	(613		)
Provision (benefit) for income taxes	(68		)	(6		)	(344		)	(150		)	34			(253		)
Income (loss) from continuing operations													(50		)	(360		)
Income (loss) from discontinued operations													(4,907		)	(47		)
Net income (loss)	$	(170	)	$	(386	)	$	(577	)	$	(662	)	$	(4,957	)	$	(407	)
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													$	(0.06	)	$	(0.49	)
Income (loss) from discontinued operations													$	(5.78	)	$	(0.07	)
Net income (loss)													$	(5.84	)	$	(0.56	)
Per diluted share:
Income (loss) from continuing operations													$	(0.06	)	$	(0.49	)
Income (loss) from discontinued operations													$	(5.78	)	$	(0.07	)
Net income (loss)													$	(5.84	)	$	(0.56	)
Dividends per share	$	0.05		$	0.21		$	0.10		$	0.42		$	0.05		$	0.05
Weighted average common shares outstanding:
Basic	848			677			790			676			849			730
Diluted	848			677			790			676			849			730

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

MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income (Unaudited)


	Three Months Ended						Six Months Ended						Three Months Ended
	June 30,						June 30,						March 31,
(In millions)	2016			2015			2016			2015			2017			2016
Net income (loss)	$	(170	)	$	(386	)	$	(577	)	$	(662	)	$	(4,957	)	$	(407	)
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	19			86			(5		)	162			4			(24		)
Income tax provision (benefit)	(7		)	(30		)	2			(57		)	—			9
Postretirement and postemployment plans, net of tax	12			56			(3		)	105			4			(15		)
Other, net of tax	(2		)	—			(2		)	—
Derivative hedges
Net unrecognized gain													1			—
Income tax provision													—			—
Derivative hedges, net of tax													1			—
Foreign currency hedges
Net recognized gain reclassified to discontinued operations													34			—
Income tax benefit (provision)													(4		)	—
Foreign currency hedges, net of tax													30			—

Other comprehensive income (loss)	10			56			(5		)	105			35			(15		)
Comprehensive income (loss)	$	(160	)	$	(330	)	$	(582	)	$	(557	)	$	(4,922	)	$	(422	)

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)


	June 30,			December 31,			March 31,			December 31,
(In millions, except per share data)	2016			2015			2017			2016
Assets
Current assets:
Cash and cash equivalents	$	2,584		$	1,221		$	2,490		$	2,488
Receivables, less reserve of $4 and $4	822			912
Receivables, less reserve of $5 and $6							751			748
Inventories	272			313			145			136
Other current assets	76			144			134			66
Current assets held for sale							223			227
Total current assets	3,754			2,590			3,743			3,665
Equity method investments	944			1,003			906			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 $20,692 and $20,255							16,533			16,727
Goodwill	115			115			115			115
Other noncurrent assets	2,057			1,542			698			558
Noncurrent assets held for sale							2,542			9,098
Total assets	$	32,527		$	32,311		$	24,537		$	31,094
Liabilities
Current liabilities:
Accounts payable	$	953		$	1,313		$	1,081		$	967
Payroll and benefits payable	114			133			70			129
Accrued taxes	85			132			81			94
Other current liabilities	229			150			222			243
Long-term debt due within one year	1			1			1,541			686
Current liabilities held for sale							104			121
Total current liabilities	1,382			1,729			3,099			2,240
Long-term debt	7,280			7,276			5,723			6,581
Deferred tax liabilities	2,392			2,441			800			769
Defined benefit postretirement plan obligations	409			403			365			345
Asset retirement obligations	1,597			1,601			1,622			1,602
Deferred credits and other liabilities	314			308			221			225
Noncurrent liabilities held for sale							123			1,791
Total liabilities	13,374			13,758			11,953			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							(3,314		)	(3,431		)
Additional paid-in capital	7,433			6,498			7,336			7,446
Retained earnings	14,320			14,974			7,673			12,672
Accumulated other comprehensive loss	(140		)	(135		)	(48		)	(83		)
Total stockholders' equity	19,153			18,553			12,584			17,541
Total liabilities and stockholders' equity	$	32,527		$	32,311		$	24,537		$	31,094

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)



	Three Months Ended
	March 31,
(In millions)	2017			2016
Operating activities:
Net income (loss)	$	(4,957	)	$	(407	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations	4,907			47
Depreciation, depletion and amortization	556			549
Impairments	4			1
Unproved property impairments	20			11
Net (gain) loss on disposal of assets	(1		)	60
Deferred income taxes	14			(295		)
Net (gain) loss on derivative instruments	(77		)	2
Net cash received (paid) in settlement of derivative instruments	(7		)	32
Pension and other postretirement benefits, net	(9		)	14
Stock based compensation	14			13
Equity method investments, net	13			30
Changes in:
Current receivables	(1		)	106
Inventories	(10		)	4
Current accounts payable and accrued liabilities	(1		)	(107		)
All other operating, net	36			9
Net cash provided by operating activities from continuing operations	501			69
Investing activities:
Additions to property, plant and equipment	(283		)	(441		)
Deposits for acquisitions	(180		)	—
Equity method investments - return of capital	12			14
All other investing, net	1			19
Net cash used in investing activities from continuing operations	(450		)	(408		)
Financing activities:
Common stock issuance	—			1,232
Purchases of common stock	(7		)	—
Dividends paid	(42		)	(34		)
All other financing, net	(1		)	—
Net cash provided by (used in) financing activities	(50		)	1,198
Cash Flow from Discontinued Operations:
Operating activities	95			5
Investing activities	(9		)	(13		)
Changes in cash included in current assets held for sale	(86		)	8
Net increase in cash and cash equivalents of discontinued operations	—			—
Effect of exchange rate on cash and cash equivalents	1			—
Net increase (decrease) in cash and cash equivalents	2			859
Cash and cash equivalents at beginning of period	2,488			1,119
Cash and cash equivalents at end of period	$	2,490		$	1,978

Six Months Ended
June 30,
(In millions) 2016 2015
Increase (decrease) in cash and cash equivalents
Operating activities:

Net income (loss) $ (577 ) $ (662 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Deferred income taxes (392 ) (185 )
Depreciation, depletion and amortization 1,170
1,572
Impairments 1
44
Net (gain) loss on derivative instruments 88
17
Net cash received (paid) in settlement of derivative instruments 46
4
Pension and other postretirement benefits, net 14
14
Exploratory dry well costs and unproved property impairments 166
148
Net (gain) loss on disposal of assets (234 ) (1 )
Equity method investments, net 22
37
Changes in:
Current receivables 88
534
Inventories 30
21
Current accounts payable and accrued liabilities (211 ) (770 )
All other operating, net 41
(56 )
Net cash provided by operating activities 252
717
Investing activities:

Additions to property, plant and equipment (753 ) (2,320 )
Disposal of assets 758
2
Investments - return of capital 37
31
Purchases of short-term investments —
(925 )
Deposit for acquisition (89 ) —
All other investing, net 2
(1 )
Net cash used in investing activities (45 ) (3,213 )
Financing activities:

Borrowings —
1,996
Debt issuance costs —
(19 )
Debt repayments —
(34 )
Common stock issuance 1,236
—
Dividends paid (77 ) (285 )
All other financing, net —
11
Net cash provided by (used in) financing activities 1,159
1,669
Effect of exchange rate on cash and cash equivalents (3 ) 1
Net increase (decrease) in cash and cash equivalents 1,363
(826 )
Cash and cash equivalents at beginning of period 1,221
2,398
Cash and cash equivalents at end of period $ 2,584
$ 1,572

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

1. Basis of Presentation

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

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

As a result of the announcement to divest of our Canadian business in the first quarter of 2017, we have reflected this business as discontinued operations in all periods presented. 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. Assets and liabilities are presented as held for sale in the consolidated balance sheets. This divestiture is discussed in further detail in Note 6.

During the current period, 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 March 31, 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.

We have reclassified certain prior year amounts 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 Annual Report on Form 10-K. The results of operations for the second quarter and first six months of 2016 are not necessarily indicative of the results to be expected for the full year.

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 will 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. We are evaluating the provisions of this accounting standards update and assessing the impact it will have on our consolidated results of operations, financial position or cash flows.

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. We are evaluating the provisions of this accounting standards update and assessing the impact it will have on our consolidated results of operations, financial position or cash flows.

In 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 is effective for us in the first quarter of 2019 and should be applied using a modified retrospective approach at the beginning of the earliest period presented in the financial statements. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it will have on our consolidated results of operations, financial position or cash flows.

In January 2016, the FASB issued an accounting standards update that addresses certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. This standard is effective for us in the first quarter of 2018. Early adoption is allowed for certain provisions. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

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

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

~~MARATHON OIL CORPORATION~~

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

In May 2014 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.~~2018 using the modified retrospective method. We continue to ~~evaluate certain provisions of~~assess our contracts that will be subject to this ~~accounting standards update~~standard and ~~are assessing~~assess the impact it will have on our consolidated results of operations, financial position or cash flows.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Recently Adopted

In ~~May 2015,~~March 2016, the FASB issued ana new accounting standards update that ~~removes the~~changes several aspects of accounting for share-based payment transactions, including a requirement to ~~categorize within~~recognize all excess tax benefits and tax deficiencies as income tax expense or benefit in the ~~fair value hierarchy all investments for which fair value is measured using~~income statement, classification of awards as either equity or liabilities, and classification on the net asset value per share practical expedient. The amendment also removes certain disclosure requirements regarding all investments that are eligible to be measured using the net asset value per share practical expedient and only requires certain disclosures on those investments for which an entity elects to use the net asset value per share expedient.statement of cash flows. This standard iswas effective for us in the first quarter of ~~2016 and was applied~~2017. The new standard requires a company to make a policy election on ~~a retrospective basis. This~~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 ~~only modifies disclosure requirements; as such, there was no impact~~has on the presentation of our ~~consolidated results of operations,~~ financial ~~position or cash flows.~~statements.

In ~~February~~July 2015, the FASB issued an ~~amendment to the guidance for determining whether~~update that requires an entity ~~is a variable interest entity ("VIE"). The standard does not add~~to measure inventory at the lower of cost and net realizable value. This excludes inventory measured using LIFO or ~~remove any of~~ the five characteristics that determine 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.retail inventory method. This standard iswas effective for us in the first quarter of ~~2016. The adoption~~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 of the Athabasca Oil Sands Project (AOSP), in which we hold a 20% undivided interest, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton, Alberta, Canada. Costs under this contract are accrued and recorded on a monthly basis, with current liabilities of $2 million recorded at ~~June 30, 2016~~March 31, 2017 and December 31, ~~2015.~~2016. This contract qualifies as a variable interest contractual arrangement, and the Corridor Pipeline qualifies as a VIE. We hold a variable interest but are not the primary beneficiary because our shipments are only 20% of the total; therefore, the Corridor Pipeline is not consolidated by us. Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was ~~$468~~$472 million as of ~~June 30, 2016.~~March 31, 2017. The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term. This contract will be transferred to the purchaser of our Canadian business upon closing in mid-2017. See Note 6 regarding dispositions. The accrued contract costs are reported within current liabilities held for sale.

~~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 1412 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~~months periods ended ~~June 30, 2015~~March 31, 2017 and March 31, 2016 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 March 31,
(In millions, except per share data)	2017			2016
Income (loss) from operations	$	(50	)	$	(360	)
Income (loss) from discontinued operations	(4,907		)	(47		)
Net income (loss)	$	(4,957	)	$	(407	)

Weighted average common shares outstanding	849			730
Per basic share:
Income (loss) from continuing operations	$	(0.06	)	$	(0.49	)
Income (loss) from discontinued operations	$	(5.78	)	$	(0.07	)
Net income	$	(5.84	)	$	(0.56	)
Per diluted share:
Income (loss) from continuing operations	$	(0.06	)	$	(0.49	)
Income (loss) from discontinued operations	$	(5.78	)	$	(0.07	)
Net income	$	(5.84	)	$	(0.56	)

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

5. Acquisitions

In ~~June 2016,~~March 2017, we entered into separate agreements to acquire approximately 91,000 net acres in the Permian basin, including over 70,000 net acres in the Northern Delaware basin of New Mexico. We executed a purchase agreement with BC Operating, Inc. and other entities for $1.1 billion in cash, excluding closing adjustments, to acquire ~~PayRock Energy Holdings, LLC ("PayRock"), a portfolio company of EnCap Investments, which closed on August 1, 2016 for $888 million, subject to closing adjustments. PayRock has~~ approximately ~~61,000~~70,000 net surface acres and current production of approximately ~~9,000~~5,000 net barrels of oil ~~equivalent~~equivalent. We executed purchase agreements with Black Mountain Oil & Gas and other private sellers for $700 million in cash, excluding closing adjustments, to acquire approximately 21,000 net surface acres. In March 2017, we paid $180 million in aggregate deposits into escrow related to these acquisitions. We closed on the ~~oil window of the Anadarko Basin STACK play~~acquisition from BC Operating, Inc. and other entities with cash on hand on May 1, 2017 and expect to close our remaining acquisition from Black Mountain Oil & Gas and other private sellers in ~~Oklahoma. In~~ the second quarter of ~~2016 an $89 million deposit was paid into escrow related to the acquisition. The purchase price was paid~~2017 with cash on hand. ~~We accounted for this transaction as an asset acquisition, with the majority of the purchase price allocated to property, plant and equipment.~~


6.	Dispositions

~~2016 -~~ Oil Sands Mining Segment

In March 2017 we entered into an agreement to sell our Canadian business, which includes our 20 percent non-operated interest in the AOSP to Shell and Canadian Natural Resources Limited for $2.5 billion in cash, excluding closing adjustments. Under the terms of the agreement, $1.75 billion, subject to closing adjustments, will be paid to us upon closing and the remaining proceeds will be paid in the first quarter of 2018. The sale is expected to close in mid-2017 concurrent with a related transaction between Shell and Canadian Natural Resources Limited. In the first quarter of 2017, we recorded a non-cash impairment charge of $4.96 billion after-tax primarily related to the property, plant and equipment of our Canadian business.

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 March 31,
(In millions)		2017			2016
Total revenues and other income		$	258		$	160
Costs and expenses:
Production expenses		151			141
Depreciation, depletion and amortization		39			60
Impairments		6,636			—
Other		13			29
Total costs and expenses		6,839			230
Pretax income (loss) from discontinued operations		(6,581		)	(70		)
Provision (benefit) for income taxes		(1,674		)	(23		)
Income (loss) from discontinued operations		$	(4,907	)	$	(47	)

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 March 31, 2017 and December 31, 2016:



	March 31,		December 31,
(In millions)	2017		2016
Assets held for sale
Current assets:
Cash and cash equivalents	$	87	$	1
Accounts receivables	111		129
Inventories	21		91
Other	3		5
Total current assets held for sale—discontinued operations	222		226
Total current assets held for sale—continuing operations	1		1
Total current assets held for sale	$	223	$	227

Noncurrent assets:
Property, plant and equipment, net	$	2,449	$	8,991
Other	92		106
Total noncurrent assets held for sale—discontinued operations	2,541		9,097
Total noncurrent assets held for sale—continuing operations	1		1
Total noncurrent assets held for sale	$	2,542	$	9,098

Liabilities associated with assets held for sale
Current liabilities:
Accounts payable	$	90	$	111
Other	14		10
Total current liabilities held for sale—discontinued operations	$	104	$	121
Total current liabilities held for sale—continuing operations	—		—
Total current liabilities held for sale	$	104	$	121

Noncurrent liabilities:
Asset retirement obligations	$	96	$	95
Deferred tax liabilities	—		1,669
Other	20		20
Total noncurrent liabilities held for sale—discontinued operations	116		1,784
Total noncurrent liabilities held for sale—continuing operations	7		7
Total noncurrent liabilities held for sale	$	123	$	1,791

North America E&P Segment

~~During the quarter,~~As disclosed above we ~~announced the sale~~entered into an agreement to sell our Canadian business in March of 2017. This agreement includes interests in our ~~Wyoming upstream and midstream assets for proceeds of $870 million, before closing adjustments, of~~exploration stage in-situ leases which approximately $690 million was received in the second quarter. A pre-tax gain of $266 million was recognized in the second quarter 2016. The remaining asset sales are subject to the receipt of certain tribal consentswere included within our North America E&P Segment. These interests have been reflected as discontinued operations and are ~~expected~~included within the disclosure above.

MARATHON OIL CORPORATION

Notes 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 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~~in the ~~six months ended June 30, 2016. The~~second quarter of 2016, with the remaining Piceance basin asset ~~sales are~~sale expected to close ~~by year-end.~~

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

Inin 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. During the second quarter of 2015, we recorded a non-cash impairment charge of $44 million related to these assets as a result of the anticipated sale (see Note 13).

2017.

~~MARATHON OIL CORPORATION~~

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

7. Segment Information

We have ~~three~~2 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.

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

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

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

Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”). Segment income (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 entered into an agreement to sell our Canadian business in March 2017. The Canadian business is reflected as discontinued operations and is excluded from segment information in all periods presented.


	Three Months Ended June 30, 2016																Three Months Ended March 31, 2017
										Not Allocated												Not Allocated
(In millions)	N.A. E&P			Int'l E&P			OSM			to Segments				Total			N.A. E&P			Int'l E&P		to Segments				Total
Sales and other operating revenues	$	617		$	159		$	185		$	(91	)	^(c)	$	870		$	674		$	203	$	77		^(c)	$	954
Marketing revenues	53			23			13			—				89			6			28		—				34
Total revenues	670			182			198			(91		)		959			680			231		77				988
Income from equity method investments	—			37			—			—				37			—			69		—				69
Net gain on disposal of assets and other income	2			7			1			296			^(d)	306			5			10		—				15
Less:
Production expenses	129			56			165			—				350			109			42		—				151
Marketing costs	52			23			13			—				88			7			27		—				34
Exploration expenses	37			4			7			141			^(e)	189			26			2		—				28
Depreciation, depletion and amortization	433			68			49			11				561			472			75		9				556
Impairments																	4			—		—				4
Other expenses ^(a)	97			22			9			99			^(f)	227			107			21		70			^(d)	198
Taxes other than income	35			—			4			—				39			39			—		—				39
Net interest and other	—			—			—			86				86			—			—		78				78
Income tax benefit	(41		)	(2		)	(10		)	(15		)		(68		)
Segment income (loss) / Net income (loss)	$	(70	)	$	55		$	(38	)	$	(117	)		$	(170	)
Income tax provision (benefit)																	—			50		(16		)		34
Segment income (loss) / Income (loss) from continuing operations																	$	(79	)	$	93	$	(64	)		$	(50	)
Capital expenditures ^(b)	$	153		$	12		$	7		$	5			$	177		$	349		$	9	$	1			$	359


^(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 $14 million. See Note 8.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



	Three Months Ended March 31, 2016
							Not Allocated
(In millions)	N.A. E&P			Int'l E&P			to Segments				Total
Sales and other operating revenues	$	493		$	96		$	(23	)	^(c)	$	566
Marketing revenues	31			15			—				46
Total revenues	524			111			(23		)		612
Income from equity method investments	—			14			—				14
Net gain (loss) on disposal of assets and other income	1			6			(63		)	^(d)	(56		)
Less:
Production expenses	134			53			—				187
Marketing costs	32			14			—				46
Exploration expenses	18			6			—				24
Depreciation, depletion and amortization	487			50			12				549
Impairments	1			—			—				1
Other expenses ^(a)	118			16			120			^(e)	254
Taxes other than income	42			—			1				43
Net interest and other	—			—			79				79
Income tax provision (benefit)	(112		)	(12		)	(129		)		(253		)
Segment income (loss) / Income (loss) from continuing operations	$	(195	)	$	4		$	(169	)		$	(360	)
Capital expenditures ^(b)	$	315		$	32		$	3			$	350


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


^(b)	Includes accruals.


^(c)	Unrealized loss on commodity derivative instruments.


^(d)	~~Primarily related~~Related to ~~partial sale~~the net loss on disposal of ~~Wyoming upstream and midstream~~ assets. ~~(See note~~See Note 6.)

^(e)Includes pension settlement loss of $48 million and severance related expenses associated with workforce reductions of $7 million. See Note 8.



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



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

~~MARATHON OIL CORPORATION~~

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

Three 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 $ 993
$ 211
$ 147
$ (44 )
^(c)
$ 1,307
Marketing revenues 110
30
43
—
183
Total revenues 1,103
241
190
(44 ) 1,490
Income from equity method investments —
26
—
—
26
Net gain on disposal of assets and other income 11
4
—
—
15
Less:
Production expenses 179
64
207
—
450
Marketing costs 112
29
41
—
182
Exploration expenses 91
20
—
—
111
Depreciation, depletion and amortization 634
71
35
11
751
Impairments —
—
—
44
^(d)
44
Other expenses ^(a)
99
19
9
122
^(e)
249
Taxes other than income 67
—
5
6
78
Net interest and other —
—
—
58
58
Income tax provision (benefit) (23 ) 27
(30 ) 20
^(f)
(6 )
Segment income (loss) / Net income (loss) $ (45 ) $ 41
$ (77 ) $ (305 ) $ (386 )
Capital expenditures ^(b)
$ 551
$ 99
$ 16
$ 12
$ 678


^(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 March 31,
	Pension Benefits						Other Benefits						Pension Benefits						Other Benefits
(In millions)	2016			2015			2016			2015			2017			2016			2017			2016
Service cost	$	6		$	12		$	1		$	1		$	6		$	6		$	1		$	1
Interest cost	10			13			2			2			8			11			2			3
Expected return on plan assets	(13		)	(17		)	—			—			(12		)	(15		)	—			—
Amortization:
– prior service cost (credit)	(3		)	(2		)	(1		)	(1		)	(2		)	(2		)	(2		)	(1		)
– actuarial loss	4			7			—			—			2			3			—			—
Net settlement loss ^(a)	31			64			—			—			14			48			—			—
Net curtailment loss ^(b)	—			—			—			2
Net periodic benefit cost	$	35		$	77		$	2		$	4		$	16		$	51		$	1		$	3

Six Months Ended June 30,
Pension Benefits Other Benefits
(In millions) 2016 2015 2016 2015
Service cost $ 12
$ 24
$ 2
$ 2
Interest cost 21
27
5
5
Expected return on plan assets (28 ) (36 ) —
—
Amortization:

– prior service cost (credit) (5 ) (1 ) (2 ) (2 )
– actuarial loss 7
14
—
—
Net settlement loss ^(a)
79
81
—
—
Net curtailment loss (gain) ^(b)
—
1
—
(4 )
Net periodic benefit cost $ 86

$ 110

$ 5

$ 1


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


^(b) MARATHON OIL CORPORATION Notes to Consolidated Financial Statements (Unaudited)	~~Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans.~~

During the first ~~six~~three 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~~three months of ~~2016,~~2017, we made contributions of ~~$30~~$13 million to our funded pension ~~plans. We~~plans and we expect to make additional contributions up to an estimated ~~$34~~$47 million ~~to our funded pension plans~~ over the remainder of ~~2016.~~2017. During the first ~~six~~three months of ~~2016,~~2017, we made payments of ~~$37~~$7 million and ~~$10~~$6 million related to unfunded pension plans and other postretirement benefit plans, respectively.

9. Income Taxes

Effective Tax Rate

The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The difference between the total provision 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 three-month periods in 2017 and 2016, our effective income tax rates on continuing operations was as follows:



	Three Months Ended March 31,
(In millions)	2017			2016
Total pre-tax income (loss) from continuing operations	$	(16	)	$	(613	)
Total income tax expense (benefit)	$	34		$	(253	)
Effective income tax expense (benefit) rate on continuing operations	213		%	(41		)%

Income taxes at the statutory tax rate of 35%	$	(6	)	$	(214	)
Effects of foreign operations	(4		)	(34		)
Adjustments to valuation allowances	57			—
State income taxes	(13		)	(6		)
Other federal tax effects	—			1
Effective income tax expense (benefit) on continuing operations	$	34		$	(253	)

The rate change between years for the first ~~six months~~quarter was driven by our assessment of ~~2016~~the realizability of federal deferred tax assets being generated in the quarter, the impact of foreign operations, and ~~2015 were 37%~~the settlement of our 2011-2013 Alaska audit.

We expect to be in a cumulative loss position in 2017, for tax purposes, and ~~18%.~~as a result have placed a full valuation allowance on our federal deferred tax assets for the quarter totaling $57 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.

In the first quarter, we also settled our 2011-2013 Alaska income tax audit. The settlement of the audit resulted in the recognition of a tax benefit totaling $13 million.

The impact of foreign operations for the quarter was primarily related to a tax benefit on currency remeasurement impacts totaling $3 million. The foreign tax expense impacts related to our Libya, E.G. and U.K. operations in the first quarter of 2017 are largely offset by deferred tax benefits being generated in the U.K. associated with tax refunds related to future decommissioning 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~~income (loss) was

~~MARATHON OIL CORPORATION~~

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

recorded as a discrete item in the first ~~six~~three months of ~~2016~~2017 and ~~2015.~~2016. For the first ~~six~~three months of ~~2016~~2017 and ~~2015,~~2016, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss). Excluding Libya, the effective income tax expense (benefit) rates would be ~~36%~~(16)% and ~~15%~~(40)% for the first ~~six~~three months of ~~2016~~2017 and ~~2015. The change was driven by a shift in jurisdictional income and tax legislation enacted by the Alberta government on June 29, 2015~~2016.

MARATHON OIL CORPORATION

Notes to ~~increase the provincial corporate tax rate from 10% to 12%. As a result of this legislation, we recorded additional non-cash deferred tax expense of $135 million in the second quarter of 2015.~~ Consolidated Financial Statements (Unaudited)

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, assessment of future business assumptions and applicable tax planning strategies. Negative evidence includes losses in recent years as well as the forecasts of future income (loss) in the realizable period. 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 during ~~the carryforward period.~~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,		March 31,		December 31,
(In millions)	2016		2015		2017		2016
Liquid hydrocarbons, natural gas and bitumen	$	31	$	35
Crude oil and natural gas					$	6	$	6
Supplies and other items	241		278		139		130
Inventories, at cost	$	272	$	313
Inventories					$	145	$	136

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


	June 30,		December 31,		March 31,		December 31,
(In millions)	2016		2015		2017		2016
North America E&P	$	13,965	$	15,226	$	14,025	$	14,158
International E&P	2,479		2,533		2,419		2,470
Oil Sands Mining	9,101		9,197
Corporate	112		105		89		99
Net property, plant and equipment	$	25,657	$	27,061	$	16,533	$	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 quarter of ~~future production and sales levels.~~2017, except for a brief interruption in March 2017 due to civil unrest.

As of ~~June 30, 2016,~~March 31, 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~~was $118 ~~million and $85~~ million as of ~~June 30, 2016~~both March 31, 2017 and December 31, ~~2015. The $33 million increase primarily relates~~2016. In April 2017, we received host government approval 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 will begin depreciation during the second quarter of 2017.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

12. Impairments and Exploration Expenses

The following table summarizes impairment charges of proved properties:



	Three Months Ended March 31,
(in millions)	2017		2016
Total impairments	$	4	$	1

2017 - 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 March 31,
(In millions)	2017		2016
Exploration Expenses
Unproved property impairments	$	20	$	11
Geological and geophysical	1		—
Other	7		13
Total exploration expenses	$	28	$	24

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~~March 31, 2017 and December 31, ~~2015~~2016 by fair value hierarchy level.


	June 30, 2016								March 31, 2017
(In millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity^(a)	$	—	$	6	$	—	$	6	$	—	$	19	$	—	$	19
Interest rate	—		12		—		12		—		67		—		67
Derivative instruments, assets	$	—	$	18	$	—	$	18	$	—	$	86	$	—	$	86
Derivative instruments, liabilities
Commodity^(a)	$	—	$	70	$	—	$	70	$	—	$	2	$	—	$	2
Derivative instruments, liabilities	$	—	$	70	$	—	$	70	$	—	$	2	$	—	$	2


^(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.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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~~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. We estimate the fair value of our International E&P reporting unit using a combination of market and income approaches. The market approach referenced observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value, and valuation multiples of us and our peers from the investor analyst community. The income approach utilized discounted cash flows, which were based on forecasted assumptions. Key assumptions to the income approach include future liquid hydrocarbon and natural gas pricing, estimated quantities of liquid hydrocarbons and natural gas proved and probable reserves, estimated timing of production, discount rates, future capital requirements and operating expenses and tax rates. The assumptions used in the income approach

~~MARATHON OIL CORPORATION~~

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

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

~~Fair~~ Values- Nonrecurring

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



	Three Months Ended March 31,
	2017				2016
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	—	$	4	$	—	$	1

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~~March 31, 2017 and December 31, ~~2015.~~2016.


	June 30, 2016				December 31, 2015				March 31, 2017				December 31, 2016
	Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount		Value		Amount		Value		Amount
Financial assets
Other current assets									$	10	$	10	$	7	$	7
Other noncurrent assets	$	198	$	206	$	104	$	118	284		287		105		108
Total financial assets	$	198	$	206	$	104	$	118	$	294	$	297	$	112	$	115
Financial liabilities
Other current liabilities	$	25	$	24	$	34	$	33	$	64	$	75	$	68	$	75
Long-term debt, including current portion^(a)	7,186		7,291		6,723		7,291		7,535		7,293		7,449		7,292
Deferred credits and other liabilities	121		117		97		95		112		106		114		107
Total financial liabilities	$	7,332	$	7,432	$	6,854	$	7,419	$	7,711	$	7,474	$	7,631	$	7,474

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

~~MARATHON OIL CORPORATION~~

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

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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							March 31, 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	$	2	$	—	$	2	Other current assets
Cash Flow Hedges
Interest rate								$	65	$	—	$	65	Other current assets
Total Designated Hedges	$	12	$	—	$	12		$	67	$	—	$	67

	June 30, 2016
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location
Not Designated as Hedges
Commodity	$	6	$	39	$	33	Other current liabilities	$	16	$	—	$	16	Other current assets
Commodity	—		31		31		Deferred credits and other liabilities	3		2		1		Other noncurrent assets
Total Not Designated as Hedges	$	6	$	70	$	64		$	19	$	2	$	17
Total								$	86	$	2	$	84



	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

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				March 31, 2017				December 31, 2016
	Aggregate Notional Amount		Weighted Average, LIBOR-Based,		Aggregate Notional Amount		Weighted Average, LIBOR-Based,		Aggregate Notional Amount		Weighted Average, LIBOR-Based,		Aggregate Notional Amount		Weighted Average, LIBOR-Based,
Maturity Dates	(in millions)		Floating Rate		(in millions)		Floating Rate		(in millions)		Floating Rate		(in millions)		Floating Rate
October 1, 2017	$	600	4.94	%	$	600	4.73	%	$	600	5.27	%	$	600	5.10	%
March 15, 2018	$	300	4.77	%	$	300	4.66	%	$	300	5.24	%	$	300	5.04	%

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The pretax effects of derivative instruments designated as hedges of fair value in our consolidated statements of income ~~are summarized~~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.

Derivatives Designated as Cash Flow Hedges

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 is probable to be refinanced by us in 2018, specifically interest rate risk associated with future changes in the benchmark treasury rate. The occurrence of the forecasted transaction is probable and each respective derivative contract can be tied to an anticipated underlying dollar notional amount. At conclusion of the hedge in the first quarter of 2018, the final value will be reclassified from accumulated other comprehensive income into earnings. At March 31, 2017, the forward starting interest rate swaps continued to qualify as an effective hedge and the ineffective portion was not significant in the quarter.

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

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 )



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

The following table sets forth the net impact of the derivatives designated as cash flow hedges on other comprehensive income (loss).



	Three Months Ended March 31,
(In millions)	2017		2016
Cash Flow Hedges
Beginning balance	$	60	$	—
Change in fair value recognized in other comprehensive income	1		—
Reclassification from other comprehensive income	—		—
Ending balance	$	61	$	—

At March 31, 2017, accumulated other comprehensive income included deferred gains of $61 million related to interest rate cash flow hedges. We expect to reclassify this amount into earnings as an adjustment to net interest and other at the conclusion of the hedge in the first quarter of 2018.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Derivatives not Designated as Hedges

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 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~~March 31, 2017 and the weighted average prices for those contracts:

							Crude Oil
			Year Ending December 31,	2017
	Third Quarter	Fourth Quarter	2017	Second Quarter	Third Quarter	Fourth Quarter
Three-Way Collars	Three-Way Collars			Three-Way Collars
Volume (Bbls/day)	47,000		—	53,000	50,000
Price per Bbl:
Ceiling	$55.37		—	$58.45	$60.37
Floor	$50.23		—	$50.51	$54.80
Sold put	$40.96		—	$43.70	$47.80
Sold call options ^(a)
Volume (Bbls/day)	10,000		35,000	35,000
Price per Bbl	$72.39		$61.91	$61.91
Two-way Collars
Volume (Bbls/day)	10,000		—
Price per Bbl:			—
Ceiling	$50.00
Floor	$41.55


^(a)	Call options settle monthly.

~~MARATHON OIL CORPORATION~~

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

								Natural Gas
			Year Ending December 31,	2017			2018
	Third Quarter	Fourth Quarter	2017	Second Quarter	Third Quarter	Fourth Quarter
Three-Way Collars ^(a)
Volume (MMBtu/day)	20,000		40,000	120,000			90,000
Price per MMBtu
Ceiling	$2.93		$3.28	$3.58		$3.71	$3.61
Floor	$2.50		$2.75	$3.09		$3.14	$3.00
Sold put	$2.00		$2.25	$2.55		$2.60	$2.50
Swaps
Volume (MMBtu/day)				20,000			—
Price per MMBtu				$2.93			—

^(a)

~~On our 2016~~Subsequent to March 31, 2017, we entered into 70,000 MMBTU/day of three-way collars ~~the counterparty has the option to execute fixed-price swaps (swaptions) at~~for January - December 2018 with a ~~weighted average~~ceiling price of ~~$2.93 per MMBtu indexed to NYMEX Henry Hub, which is exercisable on December 22, 2016. If counterparty exercises, the term~~$3.62, a floor price of ~~the fixed-price swaps would be~~$3.00, and a sold put price of $2.50 and 40,000 MMBTU/day of three-way collars for ~~the calendar year 2017~~January - March 2018 with a ceiling price of $4.47, a floor price of $3.40, and ~~if all such options are exercised, 20,000 MMBtu per day.~~a sold put price of $2.75.

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 month period ended March 31, 2017 and ~~six month periods ended June 30,~~ 2016, respectively. The first quarter 2017 impact was a net ~~loss~~gain of ~~$88 million and $90~~$81 million compared to a net loss of ~~$43 million and $17~~$2 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~~period ended ~~June 30, 2016~~March 31, 2017 was ~~$14 million and $46~~$4 million compared to $4$22 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~~three 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	694,142		^(a)		$15.87	3,787,316			$16.39
Options Exercised/Stock Vested	—			—		(1,148,953	)		$32.29	—			—		(1,447,787	)		$9.57
Canceled	(973,295	)			$25.76	(557,051	)		$23.20	(500,612	)			$29.18	(156,244	)		$16.57
Outstanding at June 30, 2016	13,372,124				$27.42	7,545,324			$15.23
Outstanding at March 31, 2017										12,109,063				$26.97	9,116,818			$15.99

^(a) The weighted average grant date fair value of stock option awards granted was ~~$1.97~~$6.10 per share.

Stock-based performance unit awards

During the first ~~six~~three 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,~~March 31, 2017, we had no borrowings against our $3.3 billion revolving credit facility (the ~~"Credit Facility"~~“Credit Facility”), as described below.

InAs of March ~~2016,~~31, 2017 we ~~increased our $3.0 billion~~had long-term debt due within one year of $1.5 billion. This includes $682 million of 6.0% senior unsecured ~~Credit Facility by $300~~notes due in the fourth quarter of 2017 and $854 million ~~to a total~~ of ~~$3.3 billion.~~ 5.9% senior unsecured notes due in the first quarter of 2018.

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,~~March 31, 2017, we were in compliance with this covenant with a debt-to-capitalization ratio of ~~28%~~37%.

~~MARATHON OIL CORPORATION~~

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

~~Debt Issuance~~

In the second quarter of 2015, we issued $2 billion aggregate principal amount of unsecured senior notes and used the aggregate net proceeds to repay our $1 billion 0.90% senior notes November 1, 2015, and for general corporate purposes.

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 March 31,
(In millions)	2016			2015			2016			2015			Income Statement Line	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	)	$	(3	)	General and administrative
Net settlement loss	(31		)	(64		)	(79		)	(81		)	General and administrative	(14		)	(48		)	General and administrative
Net curtailment gain (loss)	—			(2		)	—			3			General and administrative
	(35		)	(73		)	(86		)	(92		)	Income (loss) from operations	(16		)	(51		)	Income (loss) from operations
	13			25			29			32			Provision (benefit) for income taxes	—			19			Benefit for income taxes
Total reclassifications to expense, net of tax														(16		)	(32		)	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)	$	(46	)	$	(32	)	Net income (loss)

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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,						Three Months Ended March 31,
(In millions)	2016			2015			2017			2016
Net cash (used in) operating activities:
Interest paid (net of amounts capitalized)	$	(177	)	$	(143	)	$	(64	)	$	(55	)
Income taxes paid to taxing authorities	(61		)	(165		)	(15		)	(15		)
Noncash investing activities:
Noncash investing activities, related to continuing operations:
Asset retirement cost increase	$	2		$	6		$	4		$	2
Asset retirement obligations assumed by buyer	83			—			—			54
Increase in capital expenditure accrual							76			—

20. Commitments and Contingencies

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 focused on U.S. unconventional resource plays with operations in North America, ~~Europe and~~ Africa and ~~a focus on U.S. unconventional resource plays.~~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~~$25 billion at ~~June 30,~~March 31, 2017.

As discussed in Note 6 to the consolidated financial statements, we entered into an agreement for the sale of our Canadian business, which has been reflected as discontinued operations and is excluded from operations in all periods presented. Assets and liabilities of this business are presented as held for sale in the consolidated balance sheets as of March 31, 2017 and December 31, 2016.

~~Our significant~~Execution on our strategic actions and financial results include the following:

~~Strengthened balance sheet~~Simplifying and concentrating portfolio

Entered into an agreement for the sale of our Canadian business to Shell and Canadian Natural Resources Limited for $2.5 billion, excluding closing adjustments

Announced acquisitions of approximately 91,000 net acres in the Permian basin for $1.8 billion, excluding closing adjustments, to be funded with cash on hand

Relentless focus on costs

North America E&P production expenses rate decreased 6% to $5.79 per boe and production cost are down nearly 20% compared to the same quarter of last year

Eagle Ford's average completed well costs were $4 million in the first quarter of 2017 compared to $4.3 million in the same quarter of last year

Operational updates

Net sales volumes from continuing operations are 334 mboed which is flat versus the same quarter last year, this includes 208 mboed sales volumes in our North America E&P segment

Ended the first quarter of 2017 with 20 rigs operating in the U.S. resource plays, an increase of over 100% compared to the first quarter of 2016

First Company-operated STACK Meramec black oil spacing pilot online and performing in line with expectations

Our Eagle Ford wells were drilled at an average rate of 2,500 feet per day during the quarter with one of our wells setting a new Company-record at more than 4,000 feet per day

Financial results

Ended the first quarter of 2017 with $2.5 billion of cash on hand

Cash provided by operating activities from continuing operations of $501 million for the first three months of 2017, primarily driven by our average crude oil and condensate price realizations of $48.93 per bbl

Improving our net loss per share from continuing operations to $0.06 in the first quarter of 2017 as compared to a net loss per share from continuing operations of $0.49 in the same period last year


◦	AtIncluded in the ~~end~~first quarter 2017 net loss is an increase in sales and other operating revenues of ~~the second quarter~~approximately 70% to $954 million while seeing a reduction in production and other operating expenses 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~~17%


◦	~~Cash-adjusted debt-to-capital ratio~~Commodity derivative instruments generated a mark-to-market net gain of ~~20% at June 30, 2016, as compared with 25% at December 31, 2015~~$81 million in the first quarter of 2017

~~Focused~~Incurred a $4.9 billion after-tax net loss on ~~cost reductions~~


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


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


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

~~Simplifying and concentrating portfolio~~


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


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

~~Major Project updates~~


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


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

~~Financial results~~


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


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


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


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


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

~~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~~charge during the ~~second~~first 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.2017

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~~



	Three Months Ended March 31,
Net Sales Volumes	2017	2016	Increase (Decrease)
North America E&P (mboed)	208	239	(13)%
International E&P (mboed)	126	96	31%
Total Continuing Operations (mboed)	334	335	—%

North America E&P

Net sales volumes in the segment were lower in the ~~second~~first quarter ~~and first six months~~ of ~~2016~~2017 primarily as a result of ~~decreased drilling~~a reduction of 22 mboed mainly consisting of the disposition of Wyoming and ~~completion activity resulting~~certain 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 ~~and East Texas, North Louisiana and Wilburton, Oklahoma) during the second half of 2015.~~in 2016. 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,			Three Months Ended March 31,
Net Sales Volumes	2016	2015	Increase (Decrease)	2016	2015	Increase (Decrease)	2017	2016	Increase (Decrease)
Equivalent Barrels (mboed)
Oklahoma Resource Basins							44	27	63%
Eagle Ford	109	135	(19)%	114	141	(19)%	99	121	(18)%
Oklahoma Resource Basins	27	24	13%	27	24	13%
Bakken	53	61	(13)%	55	59	(7)%	48	57	(16)%
Other North America ^(a)	35	54	(35)%	36	54	(33)%	17	34	(50)%
Total North America E&P	224	274	(18)%	232	278	(17)%	208	239	(13)%

^(a)~~Includes 17~~Three months ended March 31, 2017 includes a net sales volume reduction from March 31, 2016 of 22 mboed primarily consisting of ~~Gulf~~the disposition of ~~Mexico~~Wyoming and ~~other conventional onshore U.S. production, which was disposed of during the sale of non-core~~certain non-operated assets in ~~the second half of 2015.~~West Texas and New Mexico in 2016.

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

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



	Three Months Ended March 31, 2017
Sales Mix - U.S. Resource Plays	Oklahoma Resource Basins	Eagle Ford	Bakken	Total
Crude oil and condensate	27%	60%	82%	58%
Natural gas liquids	30%	20%	10%	20%
Natural gas	43%	20%	8%	22%

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

~~Eagle Ford~~ – Of the 30 gross operated wells brought to 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 well in the second quarter 2016, spud-to-total depth, was 8 days, a decrease from 11 days in the same quarter last year as efficiency gains in drilling continued. Wells were drilled at an average rate of 2,400 feet per day.



	Three Months Ended March 31,
	2017	2016
Gross Operated

Oklahoma Resource Basins:
Wells drilled to total depth	15	5
Wells brought to sales	12	3
Eagle Ford:
Wells drilled to total depth	45	58
Wells brought to sales	47	50
Bakken:
Wells drilled to total depth	12	3
Wells brought to sales	4	6

Oklahoma Resource Basins – Of the 512 gross operated wells brought to sales in the ~~second~~first quarter of ~~2016, 3 were in the SCOOP Woodford; 2~~2017, 11 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~~one well was in the SCOOP ~~and 6 were in the STACK.~~Woodford. The SCOOP Woodford well that was brought to sales was an extended lateral.

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~~ – Of the 412 gross operated wells brought to sales in the ~~second~~first quarter of ~~2016,~~2017, five were part of our first operated STACK infill spacing test, the Yost pilot, and the others were focused primarily on STACK lease retention and delineation. The Yost pilot, located in the normally pressured black oil window in central Kingfisher County, successfully tested 107-acre well spacing with completions of approximately 2,500 pounds of proppant per lateral foot during the first quarter of 2017. Rig activity increased from five to seven drilling rigs in the STACK/SCOOP during the first quarter of 2017. We expect to average approximately 10 drilling rigs in 2017.

Eagle Ford – During the first quarter of 2017, we brought 47 gross operated wells to sales, of which 33 were Lower Eagle Ford, 12 were Upper Eagle Ford and 2 were Austin Chalk. We held our activity levels flat from year end 2016 with six rigs drilling in Karnes, Atascosa, Live Oak and Gonzales counties.

During the ~~Middle~~ quarter, wells were drilled at an average rate of 2,500 feet per day and one of our wells achieved a new Company-record at more than 4,000 feet per day. We ended the quarter with six drilling rigs and expect to maintain an average of six drilling rigs in 2017.

Bakken ~~formation and 2~~– Of the four gross operated wells brought to sales in East Myrmidon during the first quarter of 2017, three were in the Three Forks formation ~~all with higher intensity completions. We do not currently have an active drilling rig~~and one in the ~~Bakken.~~Middle Bakken formation. In the first quarter we increased our rig activity from one to seven drilling rigs, and expect to average approximately six drilling rigs in 2017.

Other North America – Net sales volumes declined in the ~~second~~first 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~~first quarter of 2017 compared to the first quarter of 2016 due primarily ~~as a result~~to the completion and start-up of our E.G. Alba field compression project in mid-2016 and planned ~~turnaround and~~ maintenance activities atwhich occurred during the ~~Alba field and E.G. LNG facilities in the second~~first quarter of ~~2015.~~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 March 31,
Net Sales Volumes	2016	2015	Increase (Decrease)	2016	2015	Increase (Decrease)	2017	2016	Increase (Decrease)
Equivalent Barrels (mboed)
Equatorial Guinea	101	89	13%	93	93	—%	103	84	23%
United Kingdom^(a)	19	19	—%	15	19	(21)%	11	12	(8)%
Libya							12	—	100%
Total International E&P	120	108	11%	108	112	(4)%	126	96	31%
Equity Method Investees
LNG (mtd)	5,797	4,991	16%	5,060	5,629	(10)%	6,147	4,322	42%
Methanol (mtd)	1,303	673	94%	1,292	778	66%	1,307	1,280	2%
Condensate & LPG (boed)	11,306	8,586	32%	10,757	10,892	(1)%	14,546	10,208	42%


^(a)	Includes natural gas acquired for injection and subsequent resale of 57 mmcfd and ~~7 mmcfd for the second quarters of 2016 and 2015, and~~ 5 ~~mmcfd and 9~~ mmcfd for the first ~~six months~~quarters of ~~2016~~2017 and ~~2015.~~2016.

Equatorial Guinea – ~~Second~~First 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~~in mid-2016 and planned maintenance activities which occurred during the first ~~gas in July, which is expected~~quarter of 2016. In April 2017, we received host government approval to ~~maintain~~develop Block D offshore E.G. through unitization with the ~~production plateau for an additional two years and extend field life up to eight years.~~Alba field.

United Kingdom – Net sales volumes in the first ~~six~~three months of 2017 were marginally lower compared to the first quarter 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 ~~continued~~ civil ~~unrest, there were no~~unrest. In late 2016, liftings resumed from the Es Sider crude oil terminal. Sales volumes and production continued during the first quarter ~~or any period presented. Earlier this year, an Internationally-backed Unity Government was established~~of 2017, except for a brief interruption in ~~Tripoli. During the second quarter, the two National Oil Companies agreed~~March 2017 due 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.civil unrest.

Discontinued Operations - Oil Sands Mining

In March 2017, we entered into an agreement to sell our Canadian business, including our OSM segment, to Shell and Canadian Natural Resources Limited for $2.5 billion in cash, excluding closing adjustments. We expect to close the sale in mid-2017 with an effective date of January 1, 2017.

The oil sands mining business is excluded from the segment results and is reported as discontinued operations for all periods presented. Our net synthetic crude oil sales volumes were ~~49 mbbld and 54~~60 mbbld in the ~~second~~first quarter ~~and first six months~~ of ~~2016~~2017 compared to ~~29 mbbld and 44~~59 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~~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~~NGL benchmarks increased in the ~~second~~first quarter ~~and first six months~~ of ~~2016~~2017 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~~As additional detail on market conditions, including our average price realizations and benchmarks for crude oil, NGLs and natural gas relative to our operating segments, follows.

North America E&P

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


	Three Months Ended June 30,			Six Months Ended June 30,						Three Months Ended March 31,
	2016	2015	Decrease	2016		2015		Increase (Decrease)		2017	2016	Increase
Average Price Realizations ^(a)
Crude Oil and Condensate (per bbl) ^(b)	$40.77	$52.63	(23)%	$34.21		$47.11		(27	)%	$48.46	$28.21	72%
Natural Gas Liquids (per bbl)	14.84	14.77	—%	11.43		14.60		(22	)%	19.33	8.12	138%
Total Liquid Hydrocarbons (per bbl)	35.07	45.96	(24)%	29.32		41.37		(29	)%	41.13	24.00	71%
Natural Gas (per mcf)(c)	1.96	2.76	(29)%	1.99		2.88		(31	)%	3.02	2.02	50%
Benchmarks
WTI crude oil (per bbl)	$45.64	$57.95	(21)%		$39.78		$53.34	(25	)%	$51.78	$33.63	54%
LLS crude oil (per bbl)	47.35	62.94	(25)%	41.49		57.97		(28	)%	53.39	35.33	51%
Mont Belvieu NGLs (per bbl)^(c)(d)	17.52	17.65	(1)%	15.78		18.02		(12	)%	22.93	13.95	64%
Henry Hub natural gas (per mmbtu)	1.95	2.64	(26)%	2.02		2.81		(28	)%	3.32	2.09	59%


^(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~~$0.34 per bbl and ~~$0.06 per bbl for the second quarter 2016 and 2015, and $0.91 per bbl and $0.14~~$1.64 per bbl for the first ~~six months of 2016~~quarter 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~~first quarter ~~and first six months~~ of ~~2016~~2017 and ~~2015~~2016.


	Three Months Ended June 30,			Six Months Ended June 30,						Three Months Ended March 31,
	2016	2015	Increase (Decrease)	2016		2015		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	)%	$50.41	$30.95	63%
Natural Gas Liquids (per bbl)	2.65	3.10	(15)%	2.45		3.29		(26	)%	3.86	2.20	75%
Liquid Hydrocarbons (per bbl)	32.11	44.70	(28)%	28.11		41.06		(32	)%	38.64	22.66	71%
Natural Gas (per mcf)	0.53	0.78	(32)%	0.56		0.78		(28	)%	0.55	0.60	(8)%
Benchmark
Brent (Europe) crude oil (per bbl) ^(a)	$45.52	$61.69	(26%)		$39.61		$57.81	(31	)%	$53.68	$33.70	59%


^(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 ~~which receives lower~~and gas. Condensate is sold at market prices. The Alba Plant extracts NGLs and secondary condensate from gas, leaving dry natural gas. The processed NGLs are sold by Alba Plant at market prices, ~~than crude oil.~~

~~Our NGL and~~with our share of its income/loss reflected in Income from equity method investments. 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;~~long-term contracts at fixed prices; therefore, our reported average realized prices for 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.~~

~~Oil Sands Mining~~

~~The Oil Sands Mining segment produces~~Income. Although uncommon, any dry gas not sold is returned offshore and ~~sells various qualities of synthetic crude oil. Output mix can be impacted by operational reliability or planned unit outages at~~re-injected into the ~~mines or upgrader. Sales prices~~Alba field 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.~~later production.

~~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~~March 31, 2017 vs. Three Months Ended ~~June 30, 2015~~March 31, 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 March 31,
(In millions)	2016			2015			2017		2016
Sales and other operating revenues, including related party
North America E&P	$	617		$	993		$	674	$	493
International E&P	159			211			203		96
Oil Sands Mining	185			147
Segment sales and other operating revenues, including related party	$	961		$	1,351		$	877	$	589
Unrealized (loss) gain on commodity derivative instruments	(91		)	(44		)
Unrealized gain (loss) on commodity derivative instruments							77		(23		)
Sales and other operating revenues, including related party	$	870		$	1,307		$	954	$	566

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			March 31, 2016		Price Realizations			Net Sales Volumes			March 31, 2017
North America E&P Price-Volume Analysis ^(a)	North America E&P Price-Volume Analysis ^(a)											North America E&P Price-Volume Analysis ^(a)
Liquid hydrocarbons		$	893	$	(172	)	$	(170	)	$	551		$	408	$	243		$	(67	)	$	584
Natural gas		90		(22		)	(13		)	55			57		28			(2		)	83
Realized gain on commodity
derivative instruments		1		2						3			22								4
Other sales		9								8			6								3
Total		$	993							$	617		$	493							$	674
International E&P Price-Volume Analysis
Liquid hydrocarbons		$	172	$	(50	)	$	7		$	129		$	66	$	71		$	35		$	172
Natural gas		28		(10		)	4			22			21		(2		)	4			23
Other sales		11								8			9								8
Total		$	211							$	159		$	96							$	203
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~~March 31, 2017 includes a net sales volume reduction of 1722 mboed ~~related to dispositions~~primarily consisting of the disposition of Wyoming and certain non-operated assets in ~~the Gulf of~~West Texas and New Mexico ~~and other conventional onshore U.S. production.~~in 2016.

Marketing revenuesdecreased ~~$94~~$12 million in the ~~second~~first 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.~~America.

Income from equity method investments increased ~~$11~~$55 million in the ~~second~~first 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~~primarily driven by the completion of ~~planned turnaround and maintenance activities at~~ the Alba field compression project in E.G. during the second half of 2016. Also contributing to the increase was higher price realizations from LPG at our Alba plant and ~~E.G. LNG facilities.~~methanol at our AMPCO methanol facility.

Net gain (loss) on disposal of assets increased$61 million in the ~~second~~first quarter of ~~2016 was primarily~~2017 related to the sale of ~~our Wyoming upstream and midstream~~non-core assets ~~and West Texas acreage. See Note 6 to~~in the ~~consolidated financial statements for information about dispositions.~~first quarter of 2016 in the Gulf of Mexico.

Production expenses decreased ~~$100 million.~~$36 million in the first quarter of 2017 versus the same period in 2016. North America E&P declined ~~$50~~$25 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 and East Texas, North Louisiana and Wilburton, Oklahoma gas assets.~~2016. International E&P declined $8$11 million primarily as a result of lower ~~project and labor~~planned maintenance costs in the first quarter of 2017 in E.G. and U.K. ~~and 2015 also includes costs arising from planned flowline maintenance at~~Additionally, contributing to the ~~outside operated Foinaven field; these declines were partially offset by increased costs resulting from higher net sales volumes. OSM~~U.K. decrease was a more favorable exchange rate on expenses.

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

The ~~second~~first quarter of ~~2016~~2017 production expense rate (expense per boe) for North America E&P declined as cost reductions, due to the commodity price environment, occurred at a rate faster than our production ~~decline.~~declined. 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~~E.G. and ~~lower production expenses, as discussed above.~~U.K.

The following table provides production expense rates for each segment:


	Three Months Ended June 30,				Three Months Ended March 31,
($ per boe)	2016		2015		2017		2016
Production Expense Rate
North America E&P		$6.28		$7.19		$5.79		$6.17
International E&P		$5.09		$6.51		$3.72		$6.08
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~~Exploration expenses includes unproved property impairments, dry well costs, geological and geophysical, and other which ~~decreased $94~~increased $4 million in the ~~second~~first quarter of ~~2016 from the comparable 2015 period, consistent with the marketing revenues changes discussed above.~~

~~Exploration expenses~~2017. Unproved property impairments increased ~~$78 million~~ primarily as a result of more lease expirations and our decision to not drill ~~any of our remaining Gulf of Mexico undeveloped leases.~~certain leases in Eagle Ford and Oklahoma. The following table summarizes the components of exploration expenses:


	Three Months Ended June 30,				Three Months Ended March 31,
(In millions)	2016		2015		2017		2016
Exploration Expenses
Unproved property impairments	$	133	$	40	$	20	$	11
Dry well costs	22		41
Geological and geophysical	—		12		1		—
Other	34		18		7		13
Total exploration expenses	$	189	$	111	$	28	$	24

Depreciation, depletion and amortization ~~decreased $190~~increased $7 million primarily as a result of an increase of $25 million in International E&P due to increased sales volumes in E.G. and increased U.K. asset retirement costs due to changes in timing and costs of abandonment activities that occurred at year-end 2016. This increase was partially offset by a decrease of $15 million in North America E&P as a result of production volume decreases ~~a higher proved reserve base in Eagle Ford in the second half of 2015~~ and ~~as a result of the~~ non-core asset ~~dispositions in 2015.~~dispositions. 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 North America E&P DD&A rate increased in the first 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. 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 costs due to changes in timing and costs of abandonment activities 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 March 31,
($ per boe)	2017		2016
DD&A Rate
North America E&P		$25.15		$22.39
International E&P		$6.61		$5.68

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~~$4 million in the ~~second~~first quarter of 2017 versus the same period in 2016. The following table summarizes the components of taxes other than income:


	Three Months Ended June 30,				Three Months Ended March 31,
(In millions)	2016		2015		2017		2016
Production and severance	$	25	$	40	$	25	$	19
Ad valorem	5		15		3		13
Other	9		23		11		11
Total	$	39	$	78	$	39	$	43

General and administrative expenses decreased ~~$36~~$42 million primarily due to ~~lower~~a decrease in pension settlement charges which were reduced in the ~~second quarter~~first three months of ~~2016, which totaled $31~~2017 to $14 million compared to ~~$64~~$48 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%~~213% in the ~~second~~first quarter of ~~2016,~~2017, as compared to 2%(41)% in the ~~second~~first quarter of ~~2015.~~2016. See Note 9 to the consolidated financial statements for more detail discussion concerning the rate changes.

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 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 March 31,
(In millions)	2016			2015			2017			2016
North America E&P	$	(70	)	$	(45	)	$	(79	)	$	(195	)
International E&P	55			41			93			4
Oil Sands Mining	(38		)	(77		)
Segment income (loss)	(53		)	(81		)	14			(191		)
Items not allocated to segments, net of income taxes	(117		)	(305		)	(64		)	(169		)
Income (loss) from continuing operations							(50		)	(360		)
Income (loss) from discontinued operations ^(a)							(4,907		)	(47		)
Net income (loss)	$	(170	)	$	(386	)	$	(4,957	)	$	(407	)

^(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 E&P segment loss ~~increased $25~~decreased $116 million after-tax primarily due to ~~lower~~higher price realizations, lower production costs, and a reduction in DD&A expenses due to lower net sales volumes ~~which~~in the current period. This was partially offset by a decrease in the ~~impact of lower net sales volumes to DD&A, production costs and taxes other than income; and lower exploration expenses.~~income tax benefit which resulted from U.S. valuation allowances in the current period.

International E&P segment income increased ~~$14~~$89 million after-tax 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 offset by lower price realizations.~~

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

~~Results of Operations~~

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

~~Consolidated Results of Operation~~

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

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

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

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

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

~~Income from equity method investmentsdecreased $11 million. The decrease is primarily~~ due to lower ~~net sales volumes as a result of~~ planned ~~downtime at E.G. as a result of the Alba field compression project which impacted our equity method plants, which~~maintenance activities. This was partially offset by ~~planned turnaround and maintenance activities at the Alba field and E.G. LNG facilities~~an increase in ~~2015. Also impacting the first six months of 2016 were lower price realizations for LPG at our Alba plant.~~

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

~~Production expenses~~ for the first six months of 2016 decreased by $216 million compared to the same period of 2015. North America E&P declined $118 million due to lower operational, maintenance and labor costs, coupled with the disposition of our producing assets in the Gulf of Mexico and East Texas, North Louisiana and Wilburton, Oklahoma gas assets. International E&P declined $22 million largely due to lower operational costs in the U.K. OSM decreased $76 million primarily due to continued cost management, specifically staffing and contract labor, lower turnaround costs, and a favorable exchange rate on expenses denominated in the Canadian Dollar.

The first six months of 2016 production expense rate (expense per boe) for North America E&P declined primarily due to cost reductions that occurred at a rate faster than our production decline. The International E&P expense rate decreased in the first six months of 2016 primarily due to reduced maintenance and project costs in the U.K. The OSM expense rate decreased in the first six months of 2016 primarily due to higher production coupled with lower operational costs.

Six Months Ended June 30,
($ per boe) 2016 2015
Production Expense Rate
North America E&P
$6.22

$7.57
International E&P
$5.53

$6.45
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 million in the first six months of 2016 from the comparable 2015 period, consistent with the marketing revenues changes discussed above.~~

~~Exploration expenses~~were $12 million higher in the first six months of 2016 than in the comparable 2015 period primarily due to higher unproved property impairments, which were partially offset by lower dry well costs. Unproved property impairments were higher in 2016 primarily as a result of 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. The following table summarizes the components of exploration expenses:

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

~~Depreciation, depletion and amortization~~(“DD&A”) decreased $402 million in the first six months of 2016 from the comparable 2015 period primarily as a result of production volume decreases and a higher proved reserve base in Eagle Ford in the second half of 2015. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, volumes have an impact on DD&A expense.

The DD&A rate (expense per boe), which is impacted by field-level changes in sales volumes, reserves and capitalized costs, can also cause changes to our DD&A. The following table provides DD&A rates for each segment. The DD&A rate for North America E&P decreased primarily as a result of a higher proved reserve base in Eagle Ford in the second half of 2015.

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 million in the first six months of 2016 from the comparable 2015 period. The following table summarizes the components of taxes other than income:

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

~~General and administrative expenses~~decreased $56 million in the first six months of 2016 compared to the same period in 2015. This decrease was primarily due to cost savings realized from the 2015 workforce reductions and corresponding severance expenses.

~~Provision (benefit) for income taxes~~ reflect effective tax rates of 37% in the first six months of 2016, as compared to 18% from the comparable 2015 period. See Note 9 to the consolidated financial statements for discussion of the effective tax rate.

~~Segment Income(Loss)~~

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

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

Six Months Ended June 30,
(In millions) 2016 2015
North America E&P $ (265 ) $ (206 )
International E&P 59
64
Oil Sands Mining (86 ) (96 )
Segment income (loss) (292 ) (238 )
Items not allocated to segments, net of income taxes (285 ) (424 )
Net income (loss) $ (577 ) $ (662 )

~~North America E&P segment loss~~ increased $59 million after-tax in the first six months of 2016 from the comparable 2015 period primarily due to lower price realizations and sales volumes, which was partially offset by the impact of lower net sales volumes to DD&A, production costs and taxes other than income; and lower exploration expenses.

~~International E&P segment income~~decreased $5 million after-tax in the first six months of 2016 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 loss~~decreased $10 million after-tax in the first six months of 2016 from the comparable 2015 period primarily due to higher sales volumes and lower production expenses, partially offset by lower price realizations and higher DD&A expense.

Critical Accounting Estimates

There have been no material changes or developments in the evaluation of the accounting estimates and the underlying assumptions or methodologies pertaining to our Critical Accounting Estimates disclosed in our Form 10-K for the year ended December 31, ~~2015, except as discussed below.~~2016.

~~Fair Value Estimates - Goodwill~~

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

~~Estimated Quantities of Net Reserves~~

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

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

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

Accounting Standards Not Yet Adopted

See Note 2 to the consolidated financial statements.

Cash Flows

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


	Six Months Ended June 30,						Three Months Ended March 31,
(In millions)	2016			2015			2017			2016
Sources of cash and cash equivalents
Operating activities	$	252		$	717
Disposals of assets	758			2
Borrowings	—			1,996
Operating activities - continuing operations							$	501		$	69
Common stock issuance	1,236			—			—			1,232
Other	39			43			14			33
Total sources of cash and cash equivalents	$	2,285		$	2,758		$	515		$	1,334
Uses of cash and cash equivalents
Cash additions to property, plant and equipment	$	(753	)	$	(2,320	)	$	(283	)	$	(441	)
Deposit for acquisition	(89		)	—
Purchases of short-term investments	—			(925		)
Debt issuance costs	—			(19		)
Debt repayments	—			(34		)
Deposits for acquisitions							(180		)	—
Dividends paid	(77		)	(285		)	(42		)	(34		)
Purchases of common stock							(7		)	—
Other	(3		)	(1		)	(1		)	—
Total uses of cash and cash equivalents	$	(922	)	$	(3,584	)	$	(513	)	$	(475	)

Cash flows generated from operating activities in the first ~~six~~three months of ~~2016~~2017 were ~~lower~~higher as commodity prices improved compared to the ~~downturn~~first quarter of 2016. This drove an increase in price realizations in the ~~commodity cycle continued. This continued downward pressure on~~first three months of 2017. Consolidated average liquid hydrocarbon price realizations ~~coupled with the lower net sales volumes, continues to negatively impact our cash flows from operating activities. In~~increased by more than 65% during the first ~~six months~~quarter of ~~2016, consolidated average oil and NGL price realizations were down by approximately 27% and consolidated net sales volumes declined by 9%~~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 disposals of assets are primarily from the sale of our Wyoming upstream and midstream assets; see Note 6 to the consolidated financial statements for further information concerning dispositions. Common stock issuance reflects net proceeds received in March 2016 from 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~~three 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 below excludes ~~an $89~~$180 million ~~deposit~~of aggregate deposits paid into escrow related to the acquisition of ~~PayRock~~Permian assets - see Note 5 to the consolidated financial statements for further information related to this acquisition):


	Six Months Ended June 30,				Three Months Ended March 31,
(In millions)	2016		2015		2017			2016
North America E&P	$	468	$	1,484	$	349		$	315
International E&P	44		245		9			32
Oil Sands Mining	16		37
Corporate	8		14		1			3
Total capital expenditures	536		1,780		359			350
Decrease in capital expenditure accrual	217		540
Decrease (increase) in capital expenditure accrual					(76		)	91
Total use of cash and cash equivalents for property, plant and equipment	$	753	$	2,320	$	283		$	441

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

Liquidity and Capital Resources

Also in March 2016, we increased our $3 billion unsecured Credit Facility by $300 million to a total of $3.3 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the increase.

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 $3.3 billion ~~Credit Facility.~~revolving credit facility. At March 31, 2017, we had approximately $5.8 billion of liquidity consisting of $2.5 billion in cash and cash equivalents and $3.3 billion 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. 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 March 31, 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,~~March 31, 2017, we had no borrowings against our revolving credit facility.

At ~~June 30, 2016,~~March 31, 2017, we had $7.3 billion in long-term debt ~~outstanding, with our~~outstanding. Our next debt maturity in the amount of $682 million is due in the fourth quarter of ~~2017.~~2017 and $854 million is due in the first quarter of 2018.

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.

Pending Asset ~~Disposals~~Disposal

~~During~~In March 2017, we entered into an agreement to sell our Canadian business for $2.5 billion. Under the ~~quarter, we announced~~terms of the ~~sale of our Wyoming upstream and midstream assets for proceeds of $870 million, before~~agreement, $1.75 billion, subject to closing adjustments, ~~of which approximately $690 million was received~~will be paid to us upon closing and the remaining proceeds will be paid in the ~~second quarter.~~first quarter of 2018. The ~~remaining asset sales are subject to the receipt of certain tribal consents and are~~sale is expected to close ~~before year end. The proceeds~~in mid-2017 concurrent with a related transaction between Shell and Canadian Natural Resources. See Note 6 to the consolidated financial statements for ~~the remaining asset sales were deposited into an escrow account by the buyer.~~additional information.

Pending Asset Acquisitions

In March ~~and April 2016,~~2017, we entered into separate agreements to ~~sell our 10% working interest~~acquire approximately 91,000 net acres in the ~~outside-operated Shenandoah discovery~~Permian basin, including over 70,000 net acres in the ~~Gulf~~Northern Delaware basin of New 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~~$1.8 billion, excluding closing adjustments. We paid $180 million in aggregate deposits into escrow related to these acquisitions during the first quarter of 2017. We closed on ~~certain of~~ the ~~asset sales during the six months ended June 30, 2016. The remaining asset sales are expected~~acquisition from BC Operating, Inc. and other entities with cash on hand on May 1, 2017 and expect to close ~~by year-end.~~our remaining acquisition from Black Mountain Oil & Gas and other private sellers in the second quarter of 2017 with cash on hand. See Note 5 to the consolidated financial statements for 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%~~28% at ~~June 30, 2016,~~March 31, 2017, compared to ~~25%~~21% at December 31, ~~2015.~~2016.


	June 30,			December 31,			March 31,			December 31,
(In millions)	2016			2015			2017			2016
Long-term debt due within one year	$	1		$	1		$	1,541		$	686
Long-term debt	7,280			7,276			5,723			6,581
Total debt	$	7,281		$	7,277		$	7,264		$	7,267
Cash and cash equivalents	$	2,584		$	1,221		$	2,490		$	2,488
Equity	$	19,153		$	18,553		$	12,584		$	17,541
Calculation:
Total debt	$	7,281		$	7,277		$	7,264		$	7,267
Minus cash and cash equivalents	2,584			1,221			2,490			2,488
Total debt minus cash, cash equivalents	$	4,697		$	6,056		$	4,774		$	4,779
Total debt	$	7,281		$	7,277		$	7,264		$	7,267
Plus equity	19,153			18,553			12,584			17,541
Minus cash and cash equivalents	2,584			1,221			2,490			2,488
Total debt plus equity minus cash, cash equivalents	$	23,850		$	24,609		$	17,358		$	22,320
Cash-adjusted debt-to-capital ratio	20		%	25		%	28		%	21		%

Capital Requirements

Capital Spending

We ~~closed on our~~entered into agreements to purchase ~~agreement of PayRock~~Permian assets for ~~$888 million, as~~$1.8 billion, excluding closing adjustments, discussed in more detail in Note 5 to the consolidated financial statements. ~~We expect~~As a result, we increased our approved Capital Program for ~~full-year 2016~~2017 from $2.2 billion to ~~be $1.3~~approximately $2.4 billion ~~or $100 million lower than the original budget, which includes the increased activity from the PayRock acquisition.~~as a result of these acquisitions.

Other Expected Cash Outflows

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

As of ~~June 30, 2016,~~March 31, 2017, we plan to make contributions of up to ~~$34~~$47 million to our funded pension plans during the remainder of ~~2016.~~2017.

Contractual Cash Obligations

As of ~~June 30, 2016,~~March 31, 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 the ~~agreement~~agreements we entered into to acquire ~~PayRock as described above, which was paid with cash on hand.~~

~~During~~Permian acreage for $1.8 billion, excluding closing adjustments. See Note 5 to the ~~third quarter~~consolidated financial statements for additional information. Additionally, in March 2017, we ~~executed~~entered into an agreement to ~~terminate~~sell our ~~Gulf of Mexico deepwater drilling rig contract, as~~Canadian business for $2.5 billion. The sale is expected to close in mid-2017 concurrent with a related transaction between Shell and Canadian Natural Resources. See Note 6 to the consolidated financial statements for additional information. As a result, ~~we expect~~our Canadian business is reflected as discontinued operations in the consolidated financial statements for all periods presented. As of March 31, 2017, our consolidated contractual cash obligations from our continuing operations has decreased by $1,107 million from December 31, 2016 primarily due to ~~make a termination payment~~obligations relating to the announced sale of ~~$113~~our Canadian business. Our purchase obligations under oil and gas activities decreased by $67 million, ~~during the third quarter of~~service and materials contracts decreased $628 million and transportation and related contracts decreased $281 million when comparing March 31, 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.

‘Notice of Intent to Impose a Civil Penalty’ from BEIS for the self-disclosed underreporting of CO2 emissions. The letter advised that the penalty for this event had initially been set at €946,360, however BEIS had reduced the amount to €630,906 in recognition of our self-reporting and proactive cooperation with the investigation. In February 2017 we received the final letter from BEIS, the ‘Civil Penalty Notice’ that confirmed the penalty. The fixed penalty is set by European Union legislation and is calculated in Euros. The payment is made to the U.K. regulator in GBP using conversion tables also defined by the European Union. The actual sum paid in April 2017 was £537,295.

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, 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, natural gas and synthetic crude oil 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 acquisitions and dispositions;

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~~three 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 E&P sales. The following tables provide a summary of open positions as of ~~June 30, 2016~~March 31, 2017 and the weighted average price for those contracts:

							Crude Oil
			Year Ending December 31,	2017
	Third Quarter	Fourth Quarter	2017	Second Quarter	Third Quarter	Fourth Quarter
Three-Way Collars	Three-Way Collars			Three-Way Collars
Volume (Bbls/day)	47,000		—	53,000	50,000
Price per Bbl:
Ceiling	$55.37		—	$58.45	$60.37
Floor	$50.23		—	$50.51	$54.80
Sold put	$40.96		—	$43.70	$47.80
Sold call options ^(a)
Volume (Bbls/day)	10,000		35,000	35,000
Price per Bbl	$72.39		$61.91	$61.91
Two-way Collars
Volume (Bbls/day)	10,000		—
Price per Bbl:			—
Ceiling	$50.00
Floor	$41.55


^(a)	Call options settle monthly.


Natural Gas	Natural Gas			Natural Gas
			Year Ending December 31,	2017			2018
	Third Quarter	Fourth Quarter	2017	Second Quarter	Third Quarter	Fourth Quarter
Three-Way Collars ^(a)
Volume (MMBtu/day)	20,000		40,000	120,000			90,000
Price per MMBtu
Ceiling	$2.93		$3.28	$3.58		$3.71	$3.61
Floor	$2.50		$2.75	$3.09		$3.14	$3.00
Sold put	$2.00		$2.25	$2.55		$2.60	$2.50
Swaps
Volume (MMBtu/day)				20,000			—
Price per MMBtu				$2.93			—

^(a)

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.~~March 31, 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	$	(46	)	$	36
Natural gas derivatives	(5		)	5		(14		)	12
Total	$	(37	)	$	78	$	(60	)	$	48

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,~~March 31, 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 cash flow hedges								$	65		^(b)	$	(17	)
Interest rate fair value hedges								$	2		^(b)	$	1
Long term debt, including amounts due within one year	$	(7,186	)	^(b)(c)	$	(287	)	$	(7,535	)	^(b)(c)	$	(257	)


^(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.~~March 31, 2017.

During the ~~second~~first quarter 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.

The following is a summary of certain proceedings involving us that were pending or contemplated as of March 31, 2017 under federal, state and international environmental laws:

In March 2016 we proactively notified the U.K. environmental regulator Business, Energy and Industrial Strategy (“BEIS”) that we had recognized an error in our carbon dioxide (“CO2”) emissions reporting. In December 2016 we received a ‘Notice of Intent to Impose a Civil Penalty’ from BEIS for the self-disclosed underreporting of CO2 emissions. The letter advised that the penalty for this event had initially been set at €946,360, however BEIS had reduced the amount to €630,906 in recognition of our self-reporting and proactive cooperation with the investigation. In February 2017 we received the final letter from BEIS, the ‘Civil Penalty Notice’ that confirmed the penalty. The fixed penalty is set by European Union legislation and is calculated in Euros. The payment is made to the U.K. regulator in GBP using conversion tables also defined by the European Union. The actual sum paid in April 2017 was £537,295.

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.~~March 31, 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)
01/01/17 - 01/31/17	5,334	$17.68	—	$	1,500,285,529
02/01/17 - 02/28/17	23,190	$15.87	—	$	1,500,285,529
03/01/17 - 03/31/17	347,569	$16.38	—	$	1,500,285,529
Total	376,093	$16.37	—


^(a)	~~245,651~~376,093 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 March 31, 2017 is $1.5 billion. No repurchases were made under the program in the first 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~~May 5, 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*	Share Purchase Agreement, dated as of March 8, 2017, by and among Marathon Oil Dutch Holdings B.V., as Seller, and 10084751 Canada Limited, as a Buyer and Canadian Natural Resources Limited, as a Buyer, in respect of Marathon Oil Canada Corporation.
10.2	Form of Separation Agreement with Sylvia J. Kerrigan	8-K	10.1	3/31/2017
10.3	Consulting Services Agreement with Sylvia J. Kerrigan	8-K	10.2	3/31/2017
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	1921
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3734
Item 4.	Controls and Procedures	3835
Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	3936
Item 1A.	Risk Factors	3936
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3936
Item 6.	Exhibits	3936
	Signatures	4037



	Three 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	$	993		$	211	$	147		$	(44	)	^(c)	$	1,307
Marketing revenues	110			30		43			—				183
Total revenues	1,103			241		190			(44		)		1,490
Income from equity method investments	—			26		—			—				26
Net gain on disposal of assets and other income	11			4		—			—				15
Less:
Production expenses	179			64		207			—				450
Marketing costs	112			29		41			—				182
Exploration expenses	91			20		—			—				111
Depreciation, depletion and amortization	634			71		35			11				751
Impairments	—			—		—			44			^(d)	44
Other expenses ^(a)	99			19		9			122			^(e)	249
Taxes other than income	67			—		5			6				78
Net interest and other	—			—		—			58				58
Income tax provision (benefit)	(23		)	27		(30		)	20			^(f)	(6		)
Segment income (loss) / Net income (loss)	$	(45	)	$	41	$	(77	)	$	(305	)		$	(386	)
Capital expenditures ^(b)	$	551		$	99	$	16		$	12			$	678



	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



	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	—