MRO 10-Q Quarterly Report Sept. 30, 2017

MARATHON OIL CORP

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10-Q 1 mro-20170930x10q.htm 10-Q Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended September 30, 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 þ 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 þ No o

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



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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

There were 849,663,522 shares of Marathon Oil Corporation common stock outstanding as of October 31, 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” in our 2016 Annual Report on Form 10-K.



	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	30
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	47
Item 4.	Controls and Procedures	48
Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49
Item 6.	Exhibits	49
	Signatures	50

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions, except per share data)	2017			2016			2017			2016
Revenues and other income:
Sales and other operating revenues, including related party	$	1,114		$	781		$	3,026		$	2,032
Marketing revenues	48			80			117			202
Income from equity method investments	63			59			183			110
Net gain on disposal of assets	19			47			26			281
Other income	8			23			31			38
Total revenues and other income	1,252			990			3,383			2,663
Costs and expenses:
Production	194			160			521			532
Marketing, including purchases from related parties	49			80			121			201
Other operating	109			183			309			373
Exploration	294			83			352			289
Depreciation, depletion and amortization	641			522			1,789			1,583
Impairments	201			47			205			48
Taxes other than income	44			35			128			113
General and administrative	97			104			299			386
Total costs and expenses	1,629			1,214			3,724			3,525
Income (loss) from operations	(377		)	(224		)	(341		)	(862		)
Net interest and other	(35		)	(89		)	(199		)	(256		)
Loss on early extinguishment of debt	(46		)	—			(46		)	—
Income (loss) from continuing operations before income taxes	(458		)	(313		)	(586		)	(1,118		)
Provision (benefit) for income taxes	141			(107		)	216			(414		)
Income (loss) from continuing operations	(599		)	(206		)	(802		)	(704		)
Income (loss) from discontinued operations	—			14			(4,893		)	(65		)
Net income (loss)	$	(599	)	$	(192	)	$	(5,695	)	$	(769	)
Per basic share:
Income (loss) from continuing operations	$	(0.70	)	$	(0.24	)	$	(0.94	)	$	(0.87	)
Income (loss) from discontinued operations	$	—		$	0.01		$	(5.76	)	$	(0.08	)
Net income (loss)	$	(0.70	)	$	(0.23	)	$	(6.70	)	$	(0.95	)
Per diluted share:
Income (loss) from continuing operations	$	(0.70	)	$	(0.24	)	$	(0.94	)	$	(0.87	)
Income (loss) from discontinued operations	$	—		$	0.01		$	(5.76	)	$	(0.08	)
Net income (loss)	$	(0.70	)	$	(0.23	)	$	(6.70	)	$	(0.95	)
Dividends per share	$	0.05		$	0.05		$	0.15		$	0.15
Weighted average common shares outstanding:
Basic	850			847			850			809
Diluted	850			847			850			809

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

MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income (Unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2017			2016			2017			2016
Net income (loss)	$	(599	)	$	(192	)	$	(5,695	)	$	(769	)
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	5			—			17			(5		)
Income tax provision	19			—			19			2
Postretirement and postemployment plans, net of tax	24			—			36			(3		)
Derivative hedges
Net unrecognized gain (loss)	—			2			(13		)	2
Reclassification of gains on terminated derivative hedges	(46		)	—			(47		)	—
Income tax provision	21			—			21			—
Derivative hedges, net of tax	(25		)	2			(39		)	2
Foreign currency hedges
Net recognized loss reclassified to discontinued operations	—			—			34			—
Income tax provision (benefit)	—			—			(4		)	—
Foreign currency hedges, net of tax	—			—			30			—
Other, Net of Tax	1			1			2			(1		)
Other comprehensive income (loss)	—			3			29			(2		)
Comprehensive income (loss)	$	(599	)	$	(189	)	$	(5,666	)	$	(771	)

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)



	September 30,			December 31,
(In millions, except per share data)	2017			2016
Assets
Current assets:
Cash and cash equivalents	$	1,795		$	2,488
Receivables, less reserve of $7 and $6	945			748
Notes receivable	745			—
Inventories	132			136
Other current assets	62			66
Current assets held for sale	11			227
Total current assets	3,690			3,665
Equity method investments	836			931
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $21,669 and $20,255	17,645			16,727
Goodwill	115			115
Other noncurrent assets	607			558
Noncurrent assets held for sale	54			9,098
Total assets	$	22,947		$	31,094
Liabilities
Current liabilities:
Accounts payable	$	1,313		$	967
Payroll and benefits payable	99			129
Accrued taxes	162			94
Other current liabilities	188			243
Long-term debt due within one year	—			686
Current liabilities held for sale	—			121
Total current liabilities	1,762			2,240
Long-term debt	6,488			6,581
Deferred tax liabilities	844			769
Defined benefit postretirement plan obligations	330			345
Asset retirement obligations	1,522			1,602
Deferred credits and other liabilities	217			225
Noncurrent liabilities held for sale	9			1,791
Total liabilities	11,172			13,553
Commitments and contingencies
Stockholders’ Equity
Preferred stock – no shares issued or outstanding (no par value, 26 million shares authorized)	—			—
Common stock:
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	(3,324		)	(3,431		)
Additional paid-in capital	7,367			7,446
Retained earnings	6,849			12,672
Accumulated other comprehensive loss	(54		)	(83		)
Total stockholders' equity	11,775			17,541
Total liabilities and stockholders' equity	$	22,947		$	31,094

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)



	Nine Months Ended
	September 30,
(In millions)	2017			2016
Operating activities:
Net income (loss)	$	(5,695	)	$	(769	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations	4,893			65
Depreciation, depletion and amortization	1,789			1,583
Impairments	205			48
Exploratory dry well costs and unproved property impairments	294			196
Net (gain) loss on disposal of assets	(26		)	(281		)
Deferred income taxes	44			(476		)
Net (gain) loss on derivative instruments	(162		)	48
Net cash received in settlement of derivative instruments	88			51
Stock based compensation	38			37
Equity method investments, net	46			26
Changes in:
Current receivables	(192		)	125
Inventories	4			69
Current accounts payable and accrued liabilities	189			(212		)
All other operating, net	(28		)	16
Net cash provided by operating activities from continuing operations	1,487			526
Investing activities:
Additions to property, plant and equipment	(1,305		)	(949		)
Acquisitions, net of cash acquired	(1,828		)	(902		)
Disposal of assets, net of cash transferred to buyer	1,757			837
Equity method investments - return of capital	49			47
All other investing, net	(26		)	2
Net cash used in investing activities from continuing operations	(1,353		)	(965		)
Financing activities:
Borrowings	988			—
Debt repayments	(1,764		)	(1		)
Debt extinguishment costs	(46		)	—
Common stock issuance	—			1,236
Purchases of common stock	(10		)	(5		)
Dividends paid	(128		)	(119		)
Net cash provided by (used in) financing activities	(960		)	1,111
Cash Flow from Discontinued Operations:
Operating activities	141			97
Investing activities	(13		)	(34		)
Changes in cash included in current assets held for sale	2			(63		)
Net increase in cash and cash equivalents of discontinued operations	130			—
Effect of exchange rate on cash and cash equivalents	3			(3		)
Net increase (decrease) in cash and cash equivalents	(693		)	669
Cash and cash equivalents at beginning of period	2,488			1,119
Cash and cash equivalents at end of period	$	1,795		$	1,788

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.

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

During the first quarter of 2017, we adopted the accounting standards update issued by the FASB in March 2016 pertaining to share-based payment transactions. 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 nine months ended September 30, 2016. Excess tax benefits will be classified as an operating activity within the statement of cash flows on a prospective basis; as such, prior periods were not adjusted. See Note 2 for additional discussion.

2 . Accounting Standards

Not Yet Adopted

In 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 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 (“modified retrospective method”). We will adopt this new standard in the first quarter of 2018 using the modified retrospective method. Based on our assessment to date, we do not expect the adoption of this ASU to have a material impact on our consolidated results of operations, financial position or cash flows. However, we do expect to change our presentation of future marketing revenues and marketing expenses from the current gross presentation to a net presentation for a portion of our international contracts. For the nine months ended September 30, 2017, we estimate this impact to be approximately $90 million in marketing revenue and expenses in our consolidated results of operations. We continue to evaluate the disclosure requirements, are developing accounting policies, and assessing changes to the relevant business processes and the control activities as a result of this standard.

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. We will adopt this standard in the first quarter of 2018 on a retrospective basis. Early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it will have on our results of operations, financial position, or cash flows.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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 will adopt this standard in the first quarter of 2018 on a retrospective basis. 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 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. We plan to adopt this standard in the first quarter of 2018 on a retrospective basis. 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 February 2017, the FASB issued a new accounting standards update that clarifies the accounting for the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. The standard also clarifies that the derecognition of all businesses (except those related to conveyances of oil and gas mineral rights or contracts with customers) should be accounted for in accordance with the derecognition and deconsolidation guidance in Subtopic 810-10. This standard is effective for us in the first quarter of 2018 and will be applied using the modified retrospective approach. Early adoption is permitted. We plan to adopt this new standard in the first quarter of 2018 concurrently with the new revenue recognition standard. We are evaluating the provisions of this accounting standards update and assessing the impact it may have on our consolidated results of operations, financial position or cash flows.

In January 2017, the FASB issued a new accounting standards update that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities would not represent a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue guidance. This standard is effective for us in the first quarter of 2018 and shall be applied on a prospective basis. Early adoption is permitted for certain transactions as described in the guidance. Since we will adopt the standard on a prospective basis, we do not expect an impact on our consolidated results of operations, financial position or cash flows for prior periods.

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

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

In August 2017, the FASB issued a new accounting standards update that amends the hedge accounting model to enable entities to hedge certain financial and nonfinancial risk attributes previously not allowed. The amendment also reduces the overall complexity of documenting, assessing and measuring hedge effectiveness. This standard is effective for us in the first quarter of 2019. Early adoption is permitted in any interim or annual period. The amendment mandates modified retrospective adoption when accounting for hedge relationships in effect as of the adoption date. We are evaluating the provisions of this accounting standards update, including transition requirements, and are assessing the impact it may have on our 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. Since we will adopt the standard on a prospective basis, we do not expect an impact on our consolidated results of operations, financial position or cash flows for prior periods.

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

Recently Adopted

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 was effective for us in the first quarter of 2017. The new standard requires a company to make a policy election on how it accounts for forfeitures; we elected to continue estimating forfeitures using the same methodology practiced prior to adoption of this standard. See Note 1 for the impact this standard has on the presentation of our financial statements.

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

3 . Variable Interest Entity

During the second quarter of 2017 we closed on the sale of our Canadian business, which included our 20% undivided interest in the Athabasca Oil Sands Project (AOSP). The owners of the AOSP contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton, Alberta, Canada. This contract was transferred to the purchaser of our Canadian business upon closing of the sale in the second quarter of 2017. Historically, this contract qualified as a variable interest contractual arrangement, and the Corridor Pipeline qualified as a VIE. Prior to the closing of the sale of our Canadian business, we held this variable interest but were not the primary beneficiary because our shipments were only 20% of the total; therefore, the Corridor Pipeline was not consolidated by us. See Note 6 for further discussion regarding dispositions.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


4 .	Income (Loss) per Common Share

Basic income (loss) per share is based on the weighted average number of common shares outstanding. Diluted income per share assumes exercise of stock options in all years, provided the effect is not antidilutive. The per share calculations below exclude 10 million and 11 million stock options for the three and nine month periods ended September 30, 2017 and 13 million stock options for the three and nine month periods ended September 30, 2016 that were antidilutive.



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions, except per share data)	2017			2016			2017			2016
Income (loss) from operations	$	(599	)	$	(206	)	$	(802	)	$	(704	)
Income (loss) from discontinued operations	—			14			(4,893		)	(65		)
Net income (loss)	$	(599	)	$	(192	)	$	(5,695	)	$	(769	)

Weighted average common shares outstanding	850			847			850			809
Per basic share:
Income (loss) from continuing operations	$	(0.70	)	$	(0.24	)	$	(0.94	)	$	(0.87	)
Income (loss) from discontinued operations	$	—		$	0.01		$	(5.76	)	$	(0.08	)
Net income	$	(0.70	)	$	(0.23	)	$	(6.70	)	$	(0.95	)
Per diluted share:
Income (loss) from continuing operations	$	(0.70	)	$	(0.24	)	$	(0.94	)	$	(0.87	)
Income (loss) from discontinued operations	$	—		$	0.01		$	(5.76	)	$	(0.08	)
Net income	$	(0.70	)	$	(0.23	)	$	(6.70	)	$	(0.95	)

5 . Acquisitions

2017 - United States E&P

In October 2017, we executed a purchase agreement to acquire additional acreage in the Northern Delaware basin of New Mexico from a private seller for $63 million in cash, excluding closing adjustments. We expect the acquisition to close in the fourth quarter of 2017 with cash on hand.

In the second quarter of 2017, we closed on our acquisitions 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. On May 1, 2017, we closed on our acquisition with BC Operating, Inc. and other entities for $1.1 billion in cash, subject to post-closing adjustments, to acquire approximately 70,000 net surface acres and current production of approximately 5,000 net barrels of oil equivalent per day. On June 1, 2017, we closed on our acquisition with Black Mountain Oil & Gas and other private sellers for approximately $700 million in cash, subject to post-closing adjustments, to acquire approximately 21,000 net surface acres. The purchase price for these acquisitions was paid with cash on hand. We accounted for these transactions as asset acquisitions, with substantially all of the purchase price allocated to unproved property within property, plant and equipment. Although the purchase price allocation has not been finalized, we do not expect to record any material adjustments to the preliminary purchase price allocation.

2016 - United States E&P

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


6 .	Dispositions

Oil Sands Mining Segment

On May 31, 2017 we closed on the sale of our Canadian business, which included our 20 % non-operated interest in the AOSP to Shell and Canadian Natural Resources Limited (“CNRL”) for $2.5 billion , excluding closing adjustments. Under the terms of the agreement, $1.8 billion was paid to us upon closing and the remaining proceeds will be paid in the first quarter of 2018. At closing we received two notes receivable for the remaining proceeds, each with a face value of $375 million . We initially recorded these notes receivable at fair value and, in subsequent periods, will report them at amortized cost. See Note 14 for fair value measurements. Our notes receivable are with 10084751 Canada Limited (“Canada Limited”), an affiliate of Shell Canada Limited, and CNRL. The Canada Limited note receivable is guaranteed by Shell Canada Limited and the CNRL note receivable is guaranteed by Toronto Dominion Bank. In the first quarter of 2017, we recorded an after-tax non-cash impairment charge of $4.96 billion primarily related to the property, plant and equipment of our Canadian business. As the effective date of the transaction is January 1, 2017, we recorded a loss on sale of $43 million during the second quarter of 2017 due to second quarter results of operations from our Canadian business that were recorded in our financial statements but transferred to the buyer upon closing.

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



	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions)		2017		2016		2017			2016
Total sales and other revenues and other income		$	—	$	239	$	431		$	598
Net gain (loss) on disposal of assets		—		—		(43		)	—
Total revenues and other income		—		239		388			598
Costs and expenses:
Production expenses		—		135		254			441
Depreciation, depletion and amortization		—		72		40			181
Impairments		—		—		6,636			—
Other		—		9		25			69
Total costs and expenses		—		216		6,955			691
Pretax income (loss) from discontinued operations		—		23		(6,567		)	(93		)
Provision (benefit) for income taxes		—		9		(1,674		)	(28		)
Income (loss) from discontinued operations		$	—	$	14	$	(4,893	)	$	(65	)

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 September 30, 2017 and December 31, 2016:



	September 30,		December 31,
(In millions)	2017		2016
Assets held for sale
Current assets:
Cash and cash equivalents	$	—	$	2
Accounts receivables	—		129
Inventories	—		91
Other	—		4
Total current assets held for sale—discontinued operations	—		226
Total current assets held for sale—continuing operations	11		1
Total current assets held for sale	$	11	$	227

Noncurrent assets:
Property, plant and equipment, net	$	—	$	8,991
Other	—		106
Total noncurrent assets held for sale—discontinued operations	—		9,097
Total noncurrent assets held for sale—continuing operations	54		1
Total noncurrent assets held for sale	$	54	$	9,098

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

Noncurrent liabilities:
Asset retirement obligations	$	—	$	95
Deferred tax liabilities	—		1,669
Other	—		20
Total noncurrent liabilities held for sale—discontinued operations	—		1,784
Total noncurrent liabilities held for sale—continuing operations	9		7
Total noncurrent liabilities held for sale	$	9	$	1,791

United States E&P Segment

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

In July 2017, we entered into an agreement to sell certain conventional assets in Oklahoma. We closed on the sale in September 2017 for proceeds of $25 million , subject to closing adjustments, and recognized a pre-tax gain of $21 million .

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

In September 2016, we entered into an agreement to sell certain non-operated CO2 and waterflood assets in West Texas and New Mexico. The sale closed in late October for proceeds of $235 million , and we recognized a total pre-tax gain of $63 million . During the third quarter 2016, we sold certain non-operated assets primarily in West Texas and New Mexico to multiple purchasers for combined proceeds of approximately $67 million , and recognized a total pre-tax gain of $55 million .

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

In March and April 2016, we entered into separate agreements to sell our 10% working interest in the outside-operated Shenandoah discovery in the Gulf of Mexico, operated natural gas assets in the Piceance basin in Colorado and certain undeveloped acreage in West Texas and New Mexico, for a combined total of approximately $80 million in proceeds. We closed on certain of the asset sales and recognized a net pre-tax loss on sale of $48 million in the second quarter of 2016. In October 2017 we closed on the remaining Piceance basin asset sale and expect to recognize a pre-tax gain of approximately $30 million in the fourth quarter of 2017.

International E&P Segment

In the third quarter of 2017, we entered into separate agreements to sell certain non-core properties in our International E&P segment for combined proceeds of $53 million , before closing adjustments. Certain of these assets are classified as held for sale in the consolidated balance sheet as of September 30, 2017, with total assets of $63 million and total liabilities of $2 million . We expect these transactions to close within one year. See Note 13 for further detail on impairment expenses recognized concurrently with these agreements.

7 . Segment Information

We have two reportable operating segments. Both of these segments are organized and managed based upon geographic location and the nature of the products and services offered.


•	U.S. E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in the United States


•	Int’l E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of the United States and produces and markets products manufactured from natural gas, such as LNG and methanol, in Equatorial Guinea (“E.G.”)

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, unrealized gains or losses on commodity derivative instruments, pension settlement losses or other items (as determined by the CODM) are not allocated to operating segments.

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



	Three Months Ended September 30, 2017
						Not Allocated
(In millions)	U.S. E&P			Int'l E&P		to Segments				Total
Sales and other operating revenues	$	806		$	364	$	(56	)	^(c)	$	1,114
Marketing revenues	12			36		—				48
Total revenues	818			400		(56		)		1,162
Income from equity method investments	—			63		—				63
Net gain on disposal of assets and other income	4			—		23			^(d)	27
Less:
Production expenses	121			73		—				194
Marketing costs	14			35		—				49
Exploration expenses	41			3		250			^(e)	294
Depreciation, depletion and amortization	531			102		8				641
Impairments	—			—		201			^(f)	201
Other expenses ^(a)	109			40		57			^(g)	206
Taxes other than income	44			—		—				44
Net interest and other	—			—		35			^(h)	35
Loss on early extinguishment of debt	—			—		46			⁽ⁱ⁾	46
Income tax provision (benefit)	—			106		35				141
Segment income (loss) / Income (loss) from continuing operations	$	(38	)	$	104	$	(665	)		$	(599	)
Capital expenditures ^(b)	$	541		$	4	$	9			$	554


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


^(b)	Includes accruals.


^(c)	Unrealized loss on commodity derivative instruments.


^(d)	Primarily related to the sale of certain conventional assets in Oklahoma. (See Note 6 .)


^(e)	Primarily related to unproved property impairments associated with certain non-core properties within our International E&P segment. (See Note 13 .)


^(f)	Primarily related to proved property impairments associated with certain non-core properties within our International E&P segment. (See Note 13 .)


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


^(h)	Includes a gain of $47 million resulting from the termination of our forward starting interest rate swaps. (See Note 15 .)


⁽ⁱ⁾	Primarily related to the make-whole call provisions paid upon redemption of our senior unsecured notes. (See Note 17 .)

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



	Three Months Ended September 30, 2016
						Not Allocated
(In millions)	U.S. E&P			Int'l E&P		to Segments				Total
Sales and other operating revenues	$	604		$	152	$	25		^(c)	$	781
Marketing revenues	44			36		—				80
Total revenues	648			188		25				861
Income from equity method investments	—			59		—				59
Net gain on disposal of assets and other income	19			7		44			^(d)	70
Less:
Production expenses	113			47		—				160
Marketing costs	45			35		—				80
Exploration expenses	35			10		38				83
Depreciation, depletion and amortization	443			66		13				522
Impairments	—			—		47			^(e)	47
Other expenses ^(a)	85			18		184			^(f)	287
Taxes other than income	35			—		—				35
Net interest and other	—			—		89				89
Income tax provision (benefit)	(30		)	19		(96		)		(107		)
Segment income (loss) / Income (loss) from continuing operations	$	(59	)	$	59	$	(206	)		$	(206	)
Capital expenditures ^(b)	$	216		$	18	$	3			$	237


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


^(b)	Includes accruals.


^(c)	Unrealized gain on commodity derivative instruments.


^(d)	Primarily related to certain non-operated assets in West Texas and New Mexico. (See Note 6 .)


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


^(f)	Includes termination payment on our Gulf of Mexico deepwater drilling rig contract of $113 million and pension settlement loss of $14 million . (See Note 8 .)

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



	Nine Months Ended September 30, 2017
						Not Allocated
(In millions)	U.S. E&P			Int'l E&P		to Segments				Total
Sales and other operating revenues	$	2,175		$	787	$	64		^(c)	$	3,026
Marketing revenues	25			92		—				117
Total revenues	2,200			879		64				3,143
Income from equity method investments	—			183		—				183
Net gain on disposal of assets and other income	11			14		32			^(d)	57
Less:
Production expenses	348			173		—				521
Marketing costs	30			91		—				121
Exploration expenses	97			5		250			^(e)	352
Depreciation, depletion and amortization	1,498			266		25				1,789
Impairments	4			—		201			^(f)	205
Other expenses ^(a)	342			83		183			^(g)	608
Taxes other than income	116			—		12				128
Net interest and other	—			—		199			^(h)	199
Loss on early extinguishment of debt	—			—		46			⁽ⁱ⁾	46
Income tax provision (benefit)	—			202		14				216
Segment income (loss) / Income (loss) from continuing operations	$	(224	)	$	256	$	(834	)		$	(802	)
Capital expenditures ^(b)	$	1,465		$	27	$	20			$	1,512


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


^(b)	Includes accruals.


^(c)	Unrealized gain on commodity derivative instruments.


^(d)	Primarily related to the sale of certain conventional assets in Oklahoma. (See Note 6 .)


^(e)	Primarily related to unproved property impairments associated with certain non-core properties within our International E&P segment. (See Note 13 .)


^(f)	Primarily related to proved property impairments associated with certain non-core properties within our International E&P segment. (See Note 13 .)


^(g)	Includes pension settlement loss of $25 million . (See Note 8 .)


^(h)	Includes a gain of $47 million resulting from the termination of our forward starting interest rate swaps. (See Note 15 .)


⁽ⁱ⁾	Primarily related to the make-whole call provisions paid upon redemption of our senior unsecured notes. (See Note 17 .)

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



	Nine Months Ended September 30, 2016
						Not Allocated
(In millions)	U.S. E&P			Int'l E&P		to Segments				Total
Sales and other operating revenues	$	1,714		$	407	$	(89	)	^(c)	$	2,032
Marketing revenues	128			74		—				202
Total revenues	1,842			481		(89		)		2,234
Income from equity method investments	—			110		—				110
Net gain on disposal of assets and other income	22			20		277			^(d)	319
Less:
Production expenses	376			156		—				532
Marketing costs	129			72		—				201
Exploration expenses	90			20		179			^(e)	289
Depreciation, depletion and amortization	1,363			184		36				1,583
Impairments	1			—		47			^(f)	48
Other expenses ^(a)	300			56		403			^(g)	759
Taxes other than income	112			—		1				113
Net interest and other	—			—		256				256
Income tax provision (benefit)	(183		)	5		(236		)		(414		)
Segment income (loss) / Income (loss) from continuing operations	$	(324	)	$	118	$	(498	)		$	(704	)
Capital expenditures ^(b)	$	684		$	62	$	11			$	757


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


^(b)	Includes accruals.


^(c)	Unrealized loss on commodity derivative instruments.


^(d)	Primarily related to net gain on disposal of assets. (See Note 6 .)


^(e)	Impairments primarily associated with decision to not drill remaining Gulf of Mexico undeveloped leases. (See Note 13 .)


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


^(g)	Includes termination payment on our Gulf of Mexico deepwater drilling rig contract of $113 million and pension settlement loss of $93 million and severance related expenses associated with workforce reductions of $8 million . (See Note 8 .)

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 September 30,
	Pension Benefits						Other Benefits
(In millions)	2017			2016			2017			2016
Service cost	$	5		$	6		$	—		$	1
Interest cost	7			9			2			3
Expected return on plan assets	(10		)	(12		)	—			—
Amortization:
– prior service cost (credit)	(3		)	(2		)	(2		)	(1		)
– actuarial loss	3			4			—			—
Net settlement loss ^(a)	8			14			—			—
Net periodic benefit cost	$	10		$	19		$	—		$	3



	Nine Months Ended September 30,
	Pension Benefits						Other Benefits
(In millions)	2017			2016			2017			2016
Service cost	$	16		$	18		$	1		$	3
Interest cost	22			30			6			8
Expected return on plan assets	(32		)	(40		)	—			—
Amortization:
– prior service cost (credit)	(7		)	(7		)	(5		)	(3		)
– actuarial loss	7			11			—			—
Net settlement loss ^(a)	25			93			—			—
Net periodic benefit cost	$	31		$	105		$	2		$	8


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

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

During the first nine months of 2017 , we made contributions of $45 million to our funded pension plans and we expect to make additional contributions up to an estimated $8 million over the remainder of 2017 . During the first nine months of 2017 , we made payments of $10 million and $16 million related to unfunded pension plans and other postretirement benefit plans, respectively.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

9 . Income Taxes

Effective Tax Rate

The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The difference between the total provision and the sum of the amounts allocated to segments is reported in the “Not Allocated to Segments” column of the tables in Note 7 . For the third quarter and first nine months of 2017 and 2016, our effective income tax rates on continuing operations were as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2017			2016			2017			2016
Total pre-tax income (loss) from continuing operations	$	(458	)	$	(313	)	$	(586	)	$	(1,118	)
Total income tax expense (benefit)	$	141		$	(107	)	$	216		$	(414	)
Effective income tax expense (benefit) rate on continuing operations	31		%	(34		)%	37		%	(37		)%

Income taxes at the statutory tax rate of 35%	$	(160	)	$	(109	)	$	(205	)	$	(390	)
Effects of foreign operations	31			(8		)	29			(39		)
Adjustments to valuation allowances	228			11			361			17
State income taxes	—			(2		)	(13		)	(4		)
Other federal tax effects	42			1			44			2
Income tax expense (benefit) on continuing operations	$	141		$	(107	)	$	216		$	(414	)

Income tax expense for the third quarter and first nine months of 2017 was impacted by a full valuation allowance on our net federal deferred tax assets generated in 2017 and increased sales volumes in our Libyan operations where the statutory income tax rate is in excess of 90% . Our Libya income tax expense was $102 million in the third quarter and $179 million in the first nine months of 2017 compared to a benefit of $16 million and $39 million for the same periods last year. Additionally, for the third quarter and first nine months of 2017, income tax expense was impacted by a onetime, non-cash deferred tax charge of $41 million related to a reclassification of the valuation allowance on our net federal deferred tax assets between other comprehensive income and income from continuing operations.

In the first nine months of 2017 we settled our 2011-2013 Alaska income tax audit, which resulted in the recognition of a tax benefit totaling $13 million . As of September 30, 2017 there are no uncertain tax positions for which it is reasonably possible that the amount would significantly increase or decrease in the next twelve months. However, as discussed in Note 21 , we may be required to adjust the timing of our tax deduction for decommissioning costs and make a payment to the U.K. tax authorities of approximately $130 million in the next twelve months, which would be recovered as future decommissioning activities are performed and deductions claimed. We estimate that any revisions to current and deferred tax liabilities, if we do not prevail, would have no cumulative adverse earnings impact in our consolidated results of operations. While we believe that it is more likely than not that we will prevail in the Tribunal, if we do not, we have the option to seek appeal.

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

The impact of foreign operations for the third quarter and first nine months of 2017 totaled tax expense of $31 million for three months ended September 30, 2017 and $29 million for the first nine months of 2017 due to income tax rate differentials from the U.S. statutory rate of 35% associated with foreign operations in Libya, E.G. and the U.K. This was offset by deferred tax benefits being generated in the U.K. related to future tax refunds associated with abandonment costs.

In Libya, reliable estimates of 2017 and 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 impacts applicable to Libyan ordinary income (loss) were recorded as a discrete item in the third quarter and the first nine months of 2017 and 2016. For the third quarter and the first nine months of 2017 and 2016, estimated annual effective tax rates were calculated excluding Libya and applied to consolidated ordinary income (loss). Excluding Libya, the effective income tax expense and benefit rates would be an expense of 7% and benefit of 31% for the third quarter of 2017 and 2016. Excluding Libya, the effective income tax expense and benefit rates would be an expense of 5% and a benefit of 35% for the first nine months of 2017 and 2016.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

In the U.S. we expect to be in a cumulative loss position in 2017, and as a result we have placed a full valuation allowance on our net federal deferred tax assets. In the third quarter and first nine months of 2017 this valuation allowance was $228 million and $361 million . During 2017 we expect to realize no tax benefit on any net federal deferred tax assets generated. See Deferred Tax Assets section below for further detail.

Deferred Tax Assets

In connection with our assessment of the realizability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of our deferred tax assets will not be realized. In the event it is more likely than not that some portion or all of our deferred taxes will not be realized, such assets are reduced by a valuation allowance. The estimated realizability of the benefit of our deferred tax asset is assessed considering a preponderance of evidence. This assessment requires analysis of all available positive and 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. As of the fourth quarter of 2016, we expected to be in a cumulative loss position in 2017, which constitutes significant objective negative evidence as to the future realizability of the value of our federal deferred tax assets. Due to this negative evidence, we placed a full valuation allowance on our net federal deferred tax assets in the fourth quarter of 2016 and expect to realize no tax benefit on any net federal deferred tax assets generated in 2017.

10 . Inventories

Crude oil and natural gas are recorded at weighted average cost and carried at the lower of cost or 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.



	September 30,		December 31,
(In millions)	2017		2016
Crude oil and natural gas	$	9	$	6
Supplies and other items	123		130
Inventories	$	132	$	136

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



	September 30,		December 31,
(In millions)	2017		2016
United States E&P	$	15,783	$	14,158
International E&P	1,772		2,470
Corporate	90		99
Net property, plant and equipment	$	17,645	$	16,727

Our Libya operations have been interrupted in recent years due to civil unrest. On September 14, 2016, Force Majeure was lifted and production resumed in October 2016 at our Waha concession. During December 2016, liftings resumed from the Es Sider crude oil terminal. Sales volumes and production continued during the first nine months of 2017, except for a brief interruption in March 2017 due to civil unrest.

As of September 30, 2017 , our net property, plant and equipment investment in Libya is $764 million , and total proved reserves (unaudited) in Libya as of December 31, 2016 are 206 million barrels of oil equivalent (“mmboe”). 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 $764 million by a significant amount.

Exploratory well costs capitalized greater than one year after completion of drilling were $32 million and $118 million as of September 30, 2017 and December 31, 2016 . The decrease in costs of $86 million during the first nine months of 2017 was primarily due to $64 million in exploratory well costs being expensed as a result of our agreement to sell our Diaba License G4-223 in the Republic of Gabon in August of 2017, see Note 6 for further information about the divestment of certain non-core properties in our International E&P segment. Additionally, in April 2017 we received approval by the host government in

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

E.G. to develop Block D offshore E.G. through unitization with the Alba field resulting in $22 million exploratory well costs associated with the Corona well no longer being deferred.

12 . Asset Retirement Obligations

Asset retirement obligations primarily consist of estimated costs to remove, dismantle and restore land or seabed at the end of oil and gas production operations. Changes in asset retirement obligations for the nine months ended were as follows:



	September 30,			September 30,
(In millions)	2017			2016
Beginning balance	$	1,653		$	1,544
Incurred liabilities, including acquisitions	19			5
Settled liabilities, including dispositions	(40		)	(61		)
Accretion expense (included in depreciation, depletion and amortization)	65			60
Revisions of estimates	(113		)	(2		)
Held for sale	(2		)	(13		)
Ending balance	$	1,582		$	1,533

September 30, 2017


•	Settled liabilities include dispositions, primarily related to the sale of certain conventional assets in Oklahoma as well as retirements in the U.K. and the Gulf of Mexico.


•	Revisions of estimates were primarily due to changes in U.K. estimated costs as well as timing of abandonment activities in the U.K.


•	Ending balance includes $60 million classified as short-term at September 30, 2017.

September 30, 2016


•	Settled liabilities include dispositions, primarily related to the Gulf of Mexico and Wyoming as well as retirements in the Gulf of Mexico.


•	Ending balance includes $21 million classified as short-term at September 30, 2016 .

13 . Impairments and Exploration Expenses

Impairments

As a result of our announced disposition of our Canadian business in the first quarter of 2017, we recorded a pre-tax non-cash impairment charge of $6.6 billion primarily related to property, plant and equipment. This impairment in 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 summarizes impairment charges of proved properties from continuing operations:



	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2017		2016		2017		2016
Total impairments	$	201	$	47	$	205	$	48

•

2017 - Impairments for the three and nine months ended September 30, 2017 were primarily a result of lower forecasted long-term commodity prices and the anticipated sales of certain non-core proved properties in our International E&P segment of $136 million . Additionally, included in proved property impairments was $65 million relating to the Gulf of Mexico as a result of lower forecasted long-term commodity prices.


•	2016 - Impairments for the three and nine months ended September 30, 2016 consisted primarily of conventional non-core proved properties in Oklahoma as a result of lower forecasted long-term commodity prices.

See Note 6 for relevant detail regarding dispositions, Note 7 for further detail regarding segment presentation and Note 14 for fair value measurements related to impairments of proved properties and long-lived assets.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The following table summarizes the components of exploration expenses:



	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2017		2016		2017		2016
Exploration Expenses
Unproved property impairments	$	172	$	28	$	217	$	172
Dry well costs	77		9		77		24
Geological and geophysical	2		1		3		1
Other	43		45		55		92
Total exploration expenses	$	294	$	83	$	352	$	289

Unproved property impairment and Dry well costs

•

2017 - As a result of lower forecasted long-term commodity prices and the anticipated sales of certain non-core properties in our International E&P segment, we recorded a non-cash charge of $159 million comprised of $95 million in unproved property impairments and $64 million in dry well costs related to our Diaba License G4-223 in the Republic of Gabon. Also, because of our decision not to develop the Tchicuate offshore Block in the Republic of Gabon, we recorded a non-cash impairment charge of $43 million to unproved property.


•	2016 - Unproved property impairments for the nine months ended September 30, 2016 primarily consist of non-cash charges of $118 million as a result of our decision to not drill any of our remaining Gulf of Mexico undeveloped leases.

See Note 6 for relevant detail regarding dispositions and Note 7 for further detail regarding segment presentation.

14 . Fair Value Measurements

Fair Values - Recurring

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



	September 30, 2017
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity ^(a)	$	—	$	10	$	—	$	10
Interest rate	—		—		—		—
Derivative instruments, assets	$	—	$	10	$	—	$	10
Derivative instruments, liabilities
Commodity ^(a)	$	2	$	3	$	—	$	5
Derivative instruments, liabilities	$	2	$	3	$	—	$	5


^(a)	Derivative instruments are recorded on a net basis in our balance sheet. See Note 15 .



	December 31, 2016
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity ^(a)	$	—	$	—	$	—	$	—
Interest rate	—		68		—		68
Derivative instruments, assets	$	—	$	68	$	—	$	68
Derivative instruments, liabilities
Commodity ^(a)	$	—	$	60	$	—	$	60
Derivative instruments, liabilities	$	—	$	60	$	—	$	60


^(a)	Derivative instruments are recorded on a net basis in our balance sheet. See Note 15 .

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Commodity derivatives include three-way collars, call options, swaps, swaptions, and basis swaps. These instruments are measured at fair value using either a Black-Scholes or a modified Black-Scholes Model. For swaps and basis swaps, inputs to the models include only commodity prices and are categorized as Level 1 because all assumptions and inputs are observable in active markets throughout the term of the instruments. For three-way collars, swaptions and call options, inputs to the models include commodity prices, and implied volatility and are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.

Historically, both our interest rate swaps and forward starting interest rate swaps were measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs. See Note 15 for additional discussion of the types of derivative instruments we used.

Fair Values - Goodwill

Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. As of September 30, 2017, we have $115 million of goodwill associated with our International E&P reporting unit. We estimate the fair value of our International E&P reporting unit using a combination of market and income approaches. The market approach referenced observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value, and valuation multiples of us and our peers from the investor analyst community. The income approach utilized discounted cash flows, which were based on forecasted assumptions. Key assumptions to the income approach include future liquid hydrocarbon and natural gas pricing, estimated quantities of liquid hydrocarbons and natural gas proved and probable reserves, estimated timing of production, discount rates, future capital requirements, operating expenses and tax rates. The assumptions used in the income approach are consistent with those that management uses to make business decisions. These valuation methodologies represent Level 3 fair value measurements. We performed our annual impairment test in the second quarter of 2017 and concluded no impairment was required. As of the date of our last impairment assessment, the fair value of our International E&P reporting unit exceeded its book value by over 40% . While the fair value of our International E&P reporting unit exceeded the book value, subsequent variations in the above assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated.

Fair Values- Nonrecurring

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



	Three Months Ended September 30,
	2017				2016
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets	$	169	$	201	$	15	$	47



	Nine Months Ended September 30,
	2017				2016
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets	$	169	$	205	$	15	$	48

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

United States E&P

In the third quarter of 2017, impairments of $65 million were recorded consisting of certain proved properties in the Gulf of Mexico as a result of lower forecasted long-term commodity prices, to an aggregate fair value of $66 million .

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

In the third quarter of 2016, impairments of $47 million were recorded primarily consisting of conventional non-core proved properties in Oklahoma as a result of lower forecasted long-term commodity prices, to an aggregate fair value of $15 million .

International E&P

In the third quarter of 2017, we recorded proved property impairments of $136 million , to an aggregate fair value of $103 million , on certain non-core properties in our International E&P segment primarily as a result of lower forecasted long-term commodity prices and as a result of the anticipated sales of certain non-core international assets. The fair values were measured using the market approach, based upon either anticipated sales proceeds less costs to sell or a market comparable sales price per boe. This resulted in a Level 2 classification. See Note 6 for further information about the divestment of certain non-core properties in our International E&P segment.

Canadian discontinued operations

As a result of our announced disposition of our Canadian business in the first quarter of 2017, we recorded a pre-tax non-cash impairment charge of $6.6 billion primarily related to property, plant and equipment. This impairment was recorded for excess net book value over anticipated sales proceeds less costs to sell. Fair values of assets held for sale were determined based upon the anticipated sales proceeds less costs to sell, which resulted in a Level 2 classification. See Note 6 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 September 30, 2017 and December 31, 2016 .



	September 30, 2017				December 31, 2016
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Current assets ^(a)	$	755	$	754	$	7	$	7
Other noncurrent assets	127		128		105		108
Total financial assets	$	882	$	882	$	112	$	115
Financial liabilities
Other current liabilities	$	44	$	55	$	68	$	75
Long-term debt, including current portion ^(b)	6,781		6,527		7,449		7,292
Deferred credits and other liabilities	112		105		114		107
Total financial liabilities	$	6,937	$	6,687	$	7,631	$	7,474

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

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

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

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

15 . Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note 14 . All of our commodity derivatives and historical interest rate 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.



	September 30, 2017
(In millions)	Asset		Liability		Net Asset (Liability)			Balance Sheet Location
Not Designated as Hedges
Commodity	$	10	$	1	$	9		Other current assets
Commodity	—		4		(4		)	Deferred credits and other liabilities
Total Not Designated as Hedges	$	10	$	5	$	5
Total	$	10	$	5	$	5



	December 31, 2016
(In millions)	Asset		Liability		Net Asset (Liability)			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

Derivatives Designated as Fair Value Hedges

During the third quarter of 2017, we terminated all of our interest rate swaps designated as fair value hedges. The pretax effects of derivative instruments designated as hedges of fair value in our consolidated statements of income has a gross impact that is not material to net interest and other in all periods presented. Additionally, there is no ineffectiveness related to fair value hedges in all periods presented.

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.



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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Derivatives Not Designated as Hedges

Interest Rate Swaps

During the third quarter of 2016, we entered into forward starting interest rate swaps to hedge the variations in cash flows related to fluctuations in long term interest rates from debt that were probable to be refinanced by us in 2018, specifically interest rate risk associated with future changes in the benchmark treasury rate. We designated these derivative instruments as cash flow hedges. During the second quarter of 2017, we de-designated the forward starting interest rate swaps previously designated as cash flow hedges. In the third quarter of 2017, the forecasted transaction consummated and we issued $1 billion in senior unsecured notes. See Note 17 for further detail. As a result, we terminated our forward starting interest rate swaps receiving proceeds of $54 million . We recognized a gain of $47 million , of which $46 million is related to deferred gains reclassified from accumulated other comprehensive income, in net interest and other in the third quarter of 2017.

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



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

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



	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions)	2017			2016		2017			2016
Interest Rate Swaps
Beginning balance	$	46		$	—	$	60		$	—
Change in fair value recognized in other comprehensive income	—			2		(13		)	2
Reclassification from other comprehensive income	(46		)	—		(47		)	—
Ending balance	$	—		$	2	$	—		$	2

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Commodity Derivatives

We have entered into multiple crude oil and natural gas derivatives indexed to NYMEX WTI and Henry Hub related to a portion of our forecasted United States E&P sales through December 2018. These commodity derivatives consist of three-way collars, swaps, swaptions, basis swaps, and call 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 September 30, 2017 and the weighted average prices for those contracts:



Crude Oil
	2017	2018
	Fourth Quarter	First Quarter	Second Quarter	Third Quarter	Fourth Quarter
Three-Way Collars ^(a)
Volume (Bbls/day)	50,000	75,000	75,000	62,000	62,000
Weighted average price per Bbl:
Ceiling	$60.37	$56.24	$56.24	$56.08	$56.08
Floor	$54.80	$51.33	$51.33	$50.50	$50.50
Sold put	$47.80	$44.73	$44.73	$43.61	$43.61
Swaps ^(b)(c)
Volume (Bbls/day)	20,000	—	—	—	—
Weighted average price per Bbl	$51.37	—	—	—	—
Sold call options ^(d)
Volume (Bbls/day)	35,000	—	—	—	—
Weighted average price per Bbl	$61.91	—	—	—	—
Basis Swaps ^(e)
Volume (Bbls/day)	—	5,000	5,000	10,000	10,000
Weighted average price per Bbl	—	$(0.60)	$(0.60)	$(0.67)	$(0.67)


^(a)	Between September 30, 2017 and October 30, 2017, we entered into 10,000 Bbls/day of three-way collars for July - December 2018 with an average ceiling price of $58.07 , a floor price of $53.70 , and a sold put price of $47.00 .


^(b)	The counterparties have the option to execute fixed-price swaps (swaptions) at a weighted average price of $52.67 per Bbl indexed to NYMEX WTI, which is exercisable on December 29, 2017. If the counterparties exercise, the term of the fixed-price swaps would be from January - June 2018 and, if all such options are exercised, for 10,000 Bbls/day.


^(c)	Between September 30, 2017 and October 30, 2017, we entered into 40,000 Bbls/day of fixed-price swaps for November - December 2017 with a weighted average price of $54.11 .


^(d)	Call options settle monthly.


^(e)	The basis differential price is between WTI Midland and WTI Cushing.



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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The mark-to-market impact and settlement of these commodity derivative instruments appears in sales and other operating revenues in our consolidated statements of income for the three and nine month periods ended September 30, 2017 and 2016, respectively. The three and nine month periods ended September 30, 2017 impact was a net loss of $22 million and a net gain $115 million compared to a net gain of $42 million and a net loss of $48 million for the same respective period in 2016. Net settlements of commodity derivative instruments for the three and nine month periods ended September 30, 2017 were gains of $34 million and $51 million compared to gains of $ 17 million and $41 million for the respective period in 2016.

16 . Incentive Based Compensation

Stock options, restricted stock awards and restricted stock units

The following table presents a summary of activity for the first nine months of 2017 :



	Stock Options					Restricted Stock Awards & Units
	Number of Shares			Weighted Average Exercise Price		Awards		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2016	11,915,533				$27.71	6,933,533			$14.44
Granted	799,591		^(a)		$15.80	4,062,520			$16.20
Options Exercised/Stock Vested	(8,666	)			$7.22	(2,254,525	)		$17.76
Canceled	(2,298,820	)			$33.32	(946,431	)		$15.16
Outstanding at September 30, 2017	10,407,638				$25.57	7,795,097			$14.31

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

Stock-based performance unit awards

During the first nine months of 2017 , we granted 563,631 stock-based performance units to certain officers. The grant date fair value per unit was $17.75 .

17 . Debt

Revolving Credit Facility

As of September 30, 2017 , we had no borrowings against our $3.4 billion revolving credit facility (the “Credit Facility”), as described below.

In June 2017, we extended the maturity date of our Credit Facility from May 28, 2020 to May 28, 2021. In July 2017, we increased our $3.3 billion unsecured Credit Facility by $93 million to a total of $3.4 billion . Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the increase and term extension. We have the ability to request two additional one -year extensions and an option to increase the commitment amount by up to an additional $107 million , subject to the consent of any increasing lenders. The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million , respectively.

The Credit Facility includes a covenant requiring that our ratio of total debt to total capitalization not exceed 65% as of the last day of each fiscal quarter. If an event of default occurs, the lenders holding more than half of the commitments may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility. As of September 30, 2017 , we were in compliance with this covenant with a debt-to-capitalization ratio of 36% .

Long-term debt

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


•	$682 million 6.0% Notes Due in 2017


•	$854 million 5.9% Notes Due in 2018


•	$228 million 7.5% Notes Due in 2019

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

During the third quarter of 2017, as a result of the above redemption of $1.76 billion in senior unsecured notes, we recognized a loss on early extinguishment of debt of $46 million , primarily due to make-whole call provisions. In connection with the redemption of the senior unsecured notes, we terminated our forward starting interest rate swaps, which resulted in proceeds of $54 million and a gain of approximately $47 million into earnings in the third quarter of 2017. See Note 15 for further detail on our forward starting interest rate swaps.

18 . Reclassifications Out of Accumulated Other Comprehensive Loss

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



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2017			2016			2017			2016			Income Statement Line

Postretirement and postemployment plans
Amortization of actuarial loss	$	(3	)	$	(4	)	$	(7	)	$	(11	)	General and administrative
Net settlement loss	(8		)	(14		)	(25		)	(93		)	General and administrative
Derivative hedges
Recognized gain on terminated derivative hedge	46			—			46			—			Net interest and other
Ineffective portion of derivative hedge	—			—			1			—			Net interest and other
	35			(18		)	15			(104		)	Income (loss) from operations
	(40		)	6			(40		)	38			(Provision) benefit for income taxes
Total reclassifications to expense, net of tax	(5		)	(12		)	(25		)	(66		)	Income (loss) from continuing operations
Foreign currency hedges
Net recognized loss in discontinued operations, net of tax	—			—			(30		)	—			Income (loss) from discontinued operations
Total reclassifications to expense	$	(5	)	$	(12	)	$	(55	)	$	(66	)	Net income (loss)

19 . 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.

20 . Supplemental Cash Flow Information



	Nine Months Ended September 30,
(In millions)	2017			2016
Net cash (used in) operating activities:
Interest paid (net of amounts capitalized)	$	(269	)	$	(243	)
Income taxes paid to taxing authorities	(101		)	(68		)
Noncash investing activities, related to continuing operations:
Changes in asset retirement costs	$	(94	)	$	3
Asset retirement obligations assumed by buyer	14			86
Increase in capital expenditure accrual	207			—
Notes receivable for disposal of assets	745			—

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

21 . Commitments and Contingencies

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

We are continuously undergoing examination of our U.S. federal income tax returns by the IRS. These audits have been completed through the 2014 tax year, except for tax years 2010 and 2011. During the third quarter of 2017, we received a partnership adjustment notification related to the 2010 and 2011 tax years, for which we intend to file a Tax Court Petition in the fourth quarter of 2017. We believe that it is more likely than not that we will prevail.

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.

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

Executive Overview

Operations

Market Conditions

Results of Operations

Critical Accounting Estimates

Accounting Standards Not Yet Adopted

Cash Flows

Liquidity and 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 exploration and production company based in Houston, Texas focused on U.S. unconventional resource plays with operations in the United States , Africa and Europe. Total proved reserves were 1.4 billion boe at December 31, 2016, excluding our Canadian business, and total assets were $22.9 billion at September 30, 2017 .

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

Key highlights include the following:

Liquidity and corporate financing


•	At the end of the third quarter of 2017, we had $5.2 billion of liquidity, comprised of $1.8 billion in cash and an undrawn $3.4 billion revolving credit facility.


•	In July of 2017, we expanded the capacity of the revolving credit facility from $3.3 billion to $3.4 billion.


•	In the third quarter of 2017, we issued $1 billion of 4.4% senior unsecured notes due in 2027 and redeemed approximately $1.8 billion of debt due in 2017, 2018 and 2019. This offering and redemption reduced total long-term debt by $775 million and reduced annual interest expense by approximately $60 million.

Simplifying our portfolio


•	We entered into separate agreements to sell certain non-core properties in our International E&P segment for combined proceeds of $53 million , before closing adjustments.


•	We closed on the sale of certain conventional non-core assets in Oklahoma, with sales volumes of 2 mboed in the third quarter of 2017, for proceeds of $25 million resulting in a pre-tax gain of $21 million .

Financial and Operational results


•	Total net sales volumes from continuing operations are 409 mboed, including Libya, which is 20% higher compared to the same quarter last year. This includes an 18% increase in sales volumes from the U.S resource plays to 227 mboed within our United States E&P segment.


•	Wells to sales in the first nine months of 2017 increased over 35% in the U.S. resource plays in our United States E&P segment.


•	Cash provided by operating activities from continuing operations of $ 1,487 million for the first nine months of 2017 is primarily a result of increased sales volumes, lower unit production expense and improved capital efficiency.


•	Our net loss per share from continuing operations was $0.70 in the third quarter of 2017 as compared to a net loss per share of $0.24 in the same period last year. Included in the third quarter 2017 net loss are:


◦	An increase in sales and other operating revenues of approximately 40% to $1,114 million , including a commodity derivative net loss of $22 million compared to a net gain of $42 million in the comparable quarter last year.


◦	Production expense in our United States E&P segment increased 7% while our sales volumes increased 13% . In our International E&P segment, production expense increased $26 million primarily due to timing of our U.K. liftings.


◦	Exploration and impairment expenses increased a combined $365 million to $495 million primarily due to non-cash impairment charges on proved and unproved properties as a result of the anticipated sales of certain non-core international assets and due to lower forecasted long-term commodity prices.


◦	Loss on early extinguishment of debt of $46 million was offset by a gain on the termination of interest rate swaps of $47 million, in net interest and other, as a result of the issuance and redemption of debt in the third quarter 2017.


◦	Our provision for income taxes was $ 141 million in the third quarter of 2017 compared to a benefit of $ 107 million in the same quarter last year primarily resulting from tax expense in Libya due to the resumption of production and no tax benefit due to the full valuation allowance on our net federal deferred tax assets in the current quarter.

Operations

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



	Three Months Ended September 30,			Nine Months Ended September 30,
Net Sales Volumes	2017	2016	Increase (Decrease)	2017	2016	Increase (Decrease)
United States E&P (mboed)	244	216	13%	225	226	—%
International E&P ^(a) (mboed)	165	126	31%	142	114	25%
Total Continuing Operations (mboed)	409	342	20%	367	340	8%


^(a)	Three and nine months ended September 30, 2017 includes net sales volumes relating to Libya of 23 and 15 mboed, respectively.

United States E&P

Net sales volumes in the segment were higher in the third quarter 2017 primarily as a result of new wells to sales across all U.S. resource plays, as well as our acquisition in Northern Delaware. The following tables provide details regarding net sales volumes, sales mix and operational drilling activity for our significant operations within this segment:



	Three Months Ended September 30,			Nine Months Ended September 30,
Net Sales Volumes (a)	2017	2016	Increase (Decrease)	2017	2016	Increase (Decrease)
Equivalent Barrels (mboed)
Oklahoma Resource Basins	58	41	41%	50	32	56%
Eagle Ford	101	97	4%	100	109	(8)%
Bakken	59	54	9%	52	55	(5)%
Northern Delaware	9	—	100%	4	—	100%
Other United States ^(b)	17	24	(29)%	19	30	(37)%
Total United States E&P	244	216	13%	225	226	—%


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

^(b) Three and nine months ended September 30, 2017 includes a net sales volume reduction from September 30, 2016 of 7 mboed and 17 mboed, respectively, primarily consisting of the disposition of Wyoming and certain non-operated CO2 and waterflood assets in West Texas and New Mexico in 2016. See Note 6 to the consolidated financial statements for further disposition information.



	Three Months Ended September 30, 2017
Sales Mix - U.S. Resource Plays	Oklahoma Resource Basins	Eagle Ford	Bakken	Northern Delaware	Total
Crude oil and condensate	29%	57%	83%	68%	57%
Natural gas liquids	25%	22%	10%	2%	19%
Natural gas	46%	21%	7%	30%	24%



	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
Gross Operated - U.S. Resource Plays

Oklahoma Resource Basins:
Wells drilled to total depth	27	9	65	20
Wells brought to sales	15	12	47	20
Eagle Ford:
Wells drilled to total depth	43	33	141	131
Wells brought to sales	36	36	124	116
Bakken:
Wells drilled to total depth	27	—	72	3
Wells brought to sales	20	3	26	13
Northern Delaware
Wells drilled to total depth	11	—	13	—
Wells brought to sales	5	—	7	—


•	Oklahoma Resource Basins – Our net sales volumes in the third quarter increased by more than 40% from the year ago quarter, with net sales volumes of 58 mboed in third quarter of 2017. During the quarter, our activity was concentrated in the STACK, and was focused on leasehold capture, additional delineation drilling and infill spacing pilots.


•	Eagle Ford – Our net sales volumes were 101 mboed in the third quarter of 2017 which was 4% higher compared to the prior year quarter. Our sales volumes for the quarter increased as a result of new wells to sales and our ability to safely and efficiently return the asset to pre-storm production rates following landfall of Hurricane Harvey.


•	Bakken – Our net sales volumes were 59 mboed compared to 54 mboed in the prior year quarter. In third quarter of 2017, we brought 20 gross operated wells to sales across Myrmidon and Hector, while successfully executing completion trials with strong well results.


•	Northern Delaware – Our net sales volumes were 9 mboed in the third quarter of 2017, reflecting the first full quarter of production since the close of our acquisitions in the second quarter of 2017. During the third quarter of 2017, we brought 5 wells to sales in the Northern Delaware Wolfcamp and Bone Spring formations, while drilling our first multi-well pad.


•	Other United States – Net sales volumes declined in the third quarter of 2017 primarily due to the disposition of Wyoming and certain non-operated conventional assets in West Texas and New Mexico in 2016. See Note 6 to the consolidated financial statements for information about dispositions.

International E&P

Net sales volumes were higher in the third quarter of 2017 compared to the third quarter of 2016 primarily due to the resumption of sales volumes and production in Libya and timing of our Brae liftings in the U.K. The following table provides details regarding net sales volumes for our significant operations within this segment.



	Three Months Ended September 30,			Nine Months Ended September 30,
Net Sales Volumes	2017	2016	Increase (Decrease)	2017	2016	Increase (Decrease)
Equivalent Barrels (mboed)
Equatorial Guinea	119	115	3%	109	100	9%
United Kingdom ^(a)	20	11	82%	16	14	14%
Libya	23	—	100%	15	—	100%
Other International	3	—	100%	2	—	100%
Total International E&P	165	126	31%	142	114	25%
Equity Method Investees
LNG (mtd)	6,943	6,620	5%	6,447	5,584	15%
Methanol (mtd)	1,366	1,529	(11)%	1,285	1,371	(6)%
Condensate & LPG (boed)	17,216	16,766	3%	14,467	12,775	13%


^(a)	Includes natural gas acquired for injection and subsequent resale.


•	Equatorial Guinea – Net sales volumes in the first nine months of 2017 were higher than the first nine months of 2016 as a result of the completion and start-up of our Alba field compression project in mid-2016 and the timing of liftings.


•	United Kingdom – Third quarter 2017 net sales volumes were higher compared to the third quarter of 2016 due to the timing of our Brae liftings resulting in an increase in our U.K. sales volumes.


•	Libya – Our Libya operations have been interrupted in recent years due to civil unrest. In late 2016, liftings resumed from the Es Sider crude oil terminal. Sales volumes and production continued without interruption during the third quarter of 2017.

Market Conditions

Crude oil, natural gas and NGL benchmarks increased in the third quarter and first nine months of 2017 as compared to the same period in 2016 ; as a result, we experienced increased price realizations associated with those benchmarks. Additional detail on market conditions, including our average price realizations and benchmarks for crude oil, NGLs and natural gas relative to our operating segments, follows.

United States E&P

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



	Three Months Ended September 30,			Nine Months Ended September 30,
	2017	2016	Increase (Decrease)	2017	2016	Increase (Decrease)
Average Price Realizations ^(a)
Crude Oil and Condensate (per bbl) ^(b)	$46.65	$41.35	13%	$46.93	$36.37	29%
Natural Gas Liquids (per bbl)	20.86	12.44	68%	19.32	11.79	64%
Total Liquid Hydrocarbons (per bbl)	40.48	34.00	19%	40.20	30.79	31%
Natural Gas (per mcf) ^(c)	2.71	2.67	1%	2.91	2.22	31%
Benchmarks
WTI crude oil (per bbl)	$48.20	$44.94	7%	$49.36	$41.53	19%
LLS crude oil (per bbl)	51.61	46.52	11%	51.72	43.19	20%
Mont Belvieu NGLs (per bbl) ^(d)	23.91	17.04	40%	22.61	16.21	39%
Henry Hub natural gas (per mmbtu)	3.00	2.81	7%	3.17	2.29	38%


^(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 $2.42 per bbl and $1.55 per bbl for the third quarter 2017 and 2016 , and $1.35 per bbl and $1.10 per bbl for the first nine months of 2017 and 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 for the third quarter and first nine months of 2017 and 2016 .



	Three Months Ended September 30,			Nine Months Ended September 30,
	2017	2016	Increase (Decrease)	2017	2016	Increase (Decrease)
Average Price Realizations
Crude Oil and Condensate ( per bbl )	$51.23	$41.45	24%	$49.81	$38.99	28%
Natural Gas Liquids ( per bbl )	2.25	1.93	17%	2.63	2.25	17%
Liquid Hydrocarbons ( per bbl )	43.69	30.40	44%	40.40	28.96	40%
Natural Gas ( per mcf )	0.51	0.46	11%	0.54	0.52	4%
Benchmark
Brent (Europe) crude oil ( per bbl ) ^(a)	$52.11	$45.79	14%	$51.82	$41.67	24%


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

Our U.K. liquid hydrocarbon production is generally sold in relation to the Brent crude benchmark. Our production from the Alba field in E.G. is condensate and gas. Condensate is sold at market prices and the gas is shipped to the onshore Alba Plant. The Alba Plant extracts NGLs and secondary condensate, which have been supplied under a long-term contract at a fixed price, leaving dry natural gas. The extracted NGLs and secondary condensate are sold by Alba Plant at market prices, with our share of its income/loss reflected in income from equity method investments, and the dry natural gas from Alba Plant is supplied to AMPCO and EGHoldings under long-term contracts at fixed prices. Therefore, our reported average realized prices for condensate, NGLs and natural gas will not fully track market price movements. 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 methanol, which are sold at market prices, with our share of their income/loss reflected in the income from equity method investments line item on the Consolidated Statements of Income. Although uncommon, any dry gas not sold is returned offshore and re-injected into the Alba field for later production.

Results of Operations

Three Months Ended September 30, 2017 vs. Three Months Ended September 30, 2016

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



	Three Months Ended September 30,
(In millions)	2017			2016
Sales and other operating revenues, including related party
United States E&P	$	806		$	604
International E&P	364			152
Segment sales and other operating revenues, including related party	$	1,170		$	756
Unrealized gain (loss) on commodity derivative instruments	(56		)	25
Sales and other operating revenues, including related party	$	1,114		$	781

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



	Three Months Ended		Increase (Decrease) Related to				Three Months Ended
(In millions)	September 30, 2016		Price Realizations		Net Sales Volumes		September 30, 2017
United States E&P Price-Volume Analysis
Liquid hydrocarbons	$	508	$	110	$	62	$	680
Natural gas	78		1		13		92
Realized gain on commodity
derivative instruments	17						34
Other sales	1						—
Total	$	604					$	806
International E&P Price-Volume Analysis
Liquid hydrocarbons	$	125	$	99	$	101	$	325
Natural gas	20		2		1		23
Other sales	7						16
Total	$	152					$	364

Marketing revenues decreased $32 million in the third quarter of 2017 from the comparable 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 decrease is primarily related to lower marketed volumes in the United States due to non-core asset dispositions.

Net gain on disposal of assets decreased $28 million in the third quarter of 2017 primarily related to the gain on sale of certain non-operated assets primarily in West Texas and New Mexico in the third quarter of 2016. See Note 6 to the consolidated financial statements for further information.

Production expenses increased $34 million in the third quarter of 2017 versus the same period in 2016 due to higher sales volumes. United States E&P increased $8 million primarily due to new wells to sales across all U.S. resource plays, as well as our acquisition and development of Northern Delaware. This was partially offset by the disposition of our non-core assets in Wyoming during the second half of 2016. International E&P increased $26 million primarily due to the timing of our Brae liftings resulting in an increase in our U.K. sales volumes in the third quarter of 2017.

The third quarter of 2017 production expense rate (expense per boe) for United States E&P was lower due to sales volumes increasing at a higher rate than our production costs. The expense rate for International E&P increased due to an increase in sales volumes in U.K. and Libya.

The following table provides production expense rates for each segment:



	Three Months Ended September 30,
($ per boe)	2017		2016
Production Expense Rate
United States E&P		$5.38		$5.70
International E&P		$4.82		$4.05

Marketing costs decreased $ 31 million in the third quarter of 2017 from the comparable 2016 period, consistent with the marketing revenues changes discussed above.

Other operating expenses decreased $ 74 million in the third quarter of 2017 primarily due to the termination payment of our Gulf of Mexico deepwater drilling rig in the third quarter of 2016.

Exploration expenses include unproved property impairments, dry well costs, geological and geophysical, and other, which increased $211 million in the third quarter of 2017 . Exploration expenses in certain non-core properties in our International E&P segment increased $159 million primarily as a result of our anticipated sales and lower forecasted long-term commodity prices. Additionally, our decision not to develop the Tchicuate offshore Block in the Republic of Gabon resulted in an increase to exploration expenses of $43 million during the third quarter of 2017. See Note 13 to the consolidated financial statements for further information.

The following table summarizes the components of exploration expenses:



	Three Months Ended September 30,
(In millions)	2017		2016
Exploration Expenses
Unproved property impairments	$	172	$	28
Dry well costs	77		9
Geological and geophysical	2		1
Other	43		45
Total exploration expenses	$	294	$	83

Depreciation, depletion and amortization increased $119 million in the third quarter of 2017 primarily as a result of an increase of $88 million in the United States E&P due to higher sales volumes across all U.S. resource plays, as well as our acquisition and development of Northern Delaware. In our International E&P segment, we had an increase of $36 million primarily due to timing of our Brae liftings which resulted in an increase in our U.K. sales volumes, increased U.K. asset retirement expenses due to changes in timing and cost estimates for abandonment that occurred at year-end 2016, and the resumption of sales volumes and production in Libya. 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 changes in reserves, capitalized costs, and sales volume mix by field, can also cause changes to our DD&A. Our United States E&P DD&A rate increased in the third quarter of 2017 primarily due to our acquisition and development in Northern Delaware and a reduction to Eagle Ford proved developed reserve base in the fourth quarter of 2016. The DD&A rate for International E&P increased primarily due to sales volume mix changes between countries in the current quarter. The following table provides DD&A rates for each segment.



	Three Months Ended September 30,
($ per boe)	2017		2016
DD&A Rate
United States E&P		$23.64		$22.37
International E&P		$6.68		$5.72

Impairments increased $154 million in the third quarter of 2017 from the comparable 2016 period. This increase was primarily consisting of $136 million of proved property impairments in certain non-core properties in our International E&P segment as a result of our anticipated sales and lower forecasted long-term commodity prices Additionally, included in proved property impairments was $65 million relating to certain properties in the Gulf of Mexico as a result of lower forecasted long-term commodity prices in the third quarter of 2017.

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. Taxes other than income increased $ 9 million in the third quarter of 2017 versus the same period in 2016. The increase in the third quarter of 2017 is primarily due to an increase in sales volumes in the third quarter of 2017. The following table summarizes the components of taxes other than income:



	Three Months Ended September 30,
(In millions)	2017		2016
Taxes other than income
Production and severance	$	32	$	23
Ad valorem	3		3
Other	9		9
Total taxes other than income	$	44	$	35

Net interest and other decreased $54 million in the third quarter of 2017 versus the same period in 2016. This decrease was primarily due to the termination of our forward starting interest rate swaps, which resulted in a gain of $47 million . See Note 15 to the consolidated financial statements for further detail.

Loss on early extinguishment of debt recognized $46 million in the third quarter of 2017 primarily due to make-whole call provisions paid upon redemption of $1.76 billion in senior unsecured notes. See Note 17 to the consolidated financial statements for further detail.

Provision (benefit) for income taxes reflects an effective tax rate from continuing operations of 31% in the third quarter of 2017 , as compared to a benefit of 34% in the third quarter of 2016 . We placed a full valuation allowance on our net federal deferred tax assets in the fourth quarter of 2016 and expect to realize no tax benefit on any net federal deferred tax assets generated in 2017. See Note 9 to the consolidated financial statements for more detail discussion concerning the rate changes.

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

Segment Income (Loss)

Segment income (loss) represents income (loss) from operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. 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 September 30,
(In millions)	2017			2016
United States E&P	$	(38	)	$	(59	)
International E&P	104			59
Segment income (loss)	66			—
Items not allocated to segments, net of income taxes	(665		)	(206		)
Income (loss) from continuing operations	(599		)	(206		)
Income (loss) from discontinued operations ^(a)	—			14
Net income (loss)	$	(599	)	$	(192	)

^(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.

United States E&P segment loss decreased $21 million after-tax in the third quarter of 2017 primarily due to higher price realizations and higher sales volumes, which resulted in an increase in production expenses, DD&A and taxes other than income which partially offset the increase to revenues. This was partially offset by a decrease in the income tax benefit which resulted from U.S. valuation allowances in the current period.

International E&P segment income increased $45 million after-tax in the third quarter of 2017 primarily due to higher price realizations and an increase in sales volumes in U.K. and Libya. This resulted in an increase in production expense, DD&A and income tax provision which partially offset the increase to revenues.

Results of Operations

Nine Months Ended September 30, 2017 vs. Nine Months Ended September 30, 2016

Consolidated Results of Operation

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



	Nine Months Ended September 30,
(In millions)	2017		2016
Sales and other operating revenues, including related party
United States E&P	$	2,175	$	1,714
International E&P	787		407
Segment sales and other operating revenues, including related party	$	2,962	$	2,121
Unrealized gain (loss) on commodity derivative instruments	64		(89		)
Sales and other operating revenues, including related party	$	3,026	$	2,032



	Nine Months Ended		Increase (Decrease) Related to					Nine Months Ended
(In millions)	September 30, 2016		Price Realizations		Net Sales Volumes			September 30, 2017
United States E&P Price-Volume Analysis ^(a)
Liquid hydrocarbons	$	1,468	$	434	$	(50	)	$	1,852
Natural gas	191		64		14			269
Realized gain on commodity
derivative instruments	41							51
Other sales	14							3
Total	$	1,714						$	2,175
International E&P Price-Volume Analysis
Liquid hydrocarbons	$	319	$	193	$	172		$	684
Natural gas	63		3		5			71
Other sales	25							32
Total	$	407						$	787

^(a) Nine months ending September 30, 2017 includes a net sales volume reduction from September 30, 2016 of 17 mboed primarily consisting of the disposition of Wyoming and certain non-operated assets in West Texas and New Mexico in 2016. See Note 6 to the consolidated financial statements for further information.

Marketing revenues for the first nine months of 2017 decreased by $85 million , primarily related to lower marketed volumes in the United States E&P segment due to non-core asset dispositions. 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.

Income from equity method investments increased $73 million for the first nine months of 2017 primarily due to higher price realizations from LPG at our Alba plant and methanol at our AMPCO methanol facility. Also contributing to the increase was improvement in net sales volumes primarily driven by the completion of the Alba field compression project in E.G. during the second half of 2016.

Net gain on disposal of assets decreased $255 million for the first nine months of 2017 . This decrease was primarily related to the sale of non-core assets in the first half of 2016 in Wyoming, West Texas and New Mexico, and the Gulf of Mexico. See Note 6 to the consolidated financial statements for information about dispositions.

Production expenses for the first nine months of 2017 decreased by $11 million compared to the same period in 2016 . United States E&P declined $28 million primarily due to the disposition of our non-core assets in Wyoming during the second half of 2016 which was partially offset by our acquisitions and development in the Oklahoma STACK and Northern Delaware. International E&P increased $17 million primarily due to the timing of our Brae liftings resulting in an increase in our U.K. sales volumes in the first nine months of 2017 .

The first nine months of 2017 production expense rate (expense per boe) for United States E&P was lower due to the disposition of non-core assets in Wyoming as volumes remained flat. The International E&P expense rate decreased in the first nine months of 2017 primarily due to an increase in sales volumes in E.G. and Libya, combined with lower planned maintenance costs in E.G. due to planned maintenance in the first half of 2016.



	Nine Months Ended September 30,
($ per boe)	2017		2016
Production Expense Rate
United States E&P		$5.66		$6.06
International E&P		$4.45		$4.98

Marketing costs decreased $80 million in the first nine months of 2017 from the comparable 2016 period, consistent with the marketing revenues changes discussed above.

Exploration expenses include unproved property impairments, dry well costs, geological and geophysical, and other, which increased $63 million in the first nine months of 2017 versus the comparable 2016 period. Exploration expenses in

certain non-core properties in our International E&P segment increased $159 million primarily as a result of our anticipated sales and lower forecasted long-term commodity prices. Additionally, our decision not to develop the Tchicuate offshore Block in the Republic of Gabon resulted in an increase to exploration expenses of $43 million during the third quarter of 2017. See Note 13 to the consolidated financial statements for further information.

The following table summarizes the components of exploration expenses:



	Nine Months Ended September 30,
(In millions)	2017		2016
Exploration Expenses
Unproved property impairments	$	217	$	172
Dry well costs	77		24
Geological and geophysical	3		1
Other	55		92
Total exploration expenses	$	352	$	289

Depreciation, depletion and amortization increased $206 million in the first nine months of 2017 from the comparable 2016 period primarily as a result of an increase of $135 million in the United States E&P due to the acquisitions and development in the Oklahoma STACK and Northern Delaware and our Gunflint field beginning production in the second half of 2016. Also contributing to this higher expense was an increase of $82 million in our International E&P segment resulting from the completion and start-up of our Alba field compression project in mid-2016, the resumption of sales volumes and production in Libya and increased U.K. asset retirement expenses due to changes in timing and cost estimates for abandonment that occurred at year-end 2016. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore, volumes have an impact on DD&A expense.

The DD&A rate (expense per boe), which is impacted by field-level changes in sales volumes, reserves and capitalized costs, can also cause changes to our DD&A. The DD&A rate for United States E&P increased primarily due to the increased rate in the Gulf of Mexico as a result of the Gunflint field achieving first production in mid-2016 and our Oklahoma STACK acquisition. Also contributing to the increase was a reduction to the Eagle Ford proved developed reserve base in the fourth quarter of 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 expenses due to changes in timing and cost estimates for abandonment that occurred at year-end 2016. The following table provides DD&A rates for each segment.



	Nine Months Ended September 30,
($ per boe)	2017		2016
DD&A Rate
United States E&P		$24.38		$21.98
International E&P		$6.83		$5.89

Impairments increased $157 million in the first nine months of 2017 from the comparable 2016 period. This increase was primarily consisting of $136 million of proved property impairments in certain non-core properties in our International E&P segment as a result of our anticipated sales and lower forecasted long-term commodity prices. Additionally, included in proved property impairments was $65 million relating to certain properties in the Gulf of Mexico as a result of lower forecasted long-term commodity prices in the third quarter of 2017.

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. Taxes other than income increased $15 million in the first nine months of 2017 from the comparable 2016 period. The increase in the first nine months of 2017 is primarily due to a reserve for non-income tax examinations relating to open tax years. The following table summarizes the components of taxes other than income:



	Nine Months Ended September 30,
(In millions)	2017		2016
Taxes other than income
Production and severance	$	79	$	68
Ad valorem	8		22
Other	41		23
Total taxes other than income	$	128	$	113

General and administrative expenses decreased $87 million in the first nine months of 2017 compared to the same period in 2016 . This decrease was primarily due to pension settlement charges, which were reduced in the first nine months of 2017 to $25 million compared to $93 million for the same period in 2016.

Net interest and other decreased $57 million in the first nine months of 2017 versus the same period in 2016. This decrease was primarily due to the termination of our forward starting interest rate swaps, which resulted in a gain of $47 million . See Note 15 to the consolidated financial statements for further detail.

Loss on early extinguishment of debt recognized $46 million in the first nine months of 2017 primarily due to make-whole call provisions paid upon redemption of $1.76 billion in senior unsecured notes. See Note 17 to the consolidated financial statements for further detail.

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

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

Segment Income (Loss)

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



	Nine Months Ended September 30,
(In millions)	2017			2016
United States E&P	$	(224	)	$	(324	)
International E&P	256			118
Segment income (loss)	32			(206		)
Items not allocated to segments, net of income taxes	(834		)	(498		)
Income (loss) from continuing operations	(802		)	(704		)
Income (loss) from discontinued operations ^(a)	(4,893		)	(65		)
Net income (loss)	$	(5,695	)	$	(769	)

^(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.

United States E&P segment loss decreased $100 million after-tax in the first nine months of 2017 from the comparable 2016 period primarily due to higher price realizations and higher sales volumes, which resulted in an increase in DD&A partially offsetting the increase to revenues. This was partially offset by a decrease in the income tax benefit, which resulted from U.S. valuation allowances in the current period.

International E&P segment income increased $138 million after-tax in the first nine months of 2017 from the comparable 2016 period primarily due to higher price realizations, an increase in sales volumes in E.G. and Libya and an increase in income from equity investments. This was partially offset by an increase in production expense, DD&A and income tax expense as a result of the increase to sales volumes.

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, 2016 , except as discussed below.

Asset Retirement Obligations

Estimates of retirement costs are developed for each property based on numerous factors, such as the scope of the dismantlement, timing of settlement, interpretation of legal, regulatory and contractual requirements, type of production and processing structures, depth of water (if applicable), reservoir characteristics, depth of the reservoir, market demand for equipment, currently available dismantlement and restoration procedures and consultations with construction and engineering professionals. Currency exchange rates, inflation rates and credit-adjusted-risk-free interest rates are then applied to estimate the fair values of the obligations. During the third quarter of 2017 we made revisions to these estimates and reduced the recognized liability by $110 million . This downward revision was primarily due to changes in U.K. estimated costs as well as timing of abandonment activities in the U.K. See Note 12 to the consolidated financial statements for further information.

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, and as of September 30, 2017 , we have $ 115 million of goodwill associated with our International E&P reporting unit. We performed our annual impairment test in the second quarter of 2017 and concluded no impairment was required. As of the date of our last impairment assessment, the fair value of our International E&P reporting unit exceeded its book value by over 40%. See Note 14 to the consolidated financial statements for further information.

Fair Value Estimates - Impairment Assessments of Long-Lived Assets

The continued low commodity price environment resulted in a downward revision of our long-term commodity price assumptions which triggered an assessment of certain of our long-lived assets related to oil and gas producing properties for impairment. We estimated the fair values using an income approach and recognized impairments of $65 million during the third quarter of 2017 in the Gulf of Mexico of our United States E&P segment. Additionally, due to the anticipated sale of certain of our non-core long-lived assets in our International E&P segment and the downward revision of our long-term commodity price assumptions, we assessed certain non-core international long-lived assets for impairment. The fair values were measured using the market approach, based upon either anticipated sales proceeds less costs to sell or a market comparable sales price per boe, resulting in impairments of $136 million during the third quarter of 2017. See Note 14 to the consolidated financial statements for further information.

Accounting Standards Not Yet Adopted

See Note 2 to the consolidated financial statements.

Cash Flows

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



	Nine Months Ended September 30,
(In millions)	2017			2016
Sources of cash and cash equivalents
Operating activities - continuing operations	$	1,487		$	526
Disposals of assets	1,757			837
Borrowings	988			—
Common stock issuance	—			1,236
Other	49			49
Total sources of cash and cash equivalents	$	4,281		$	2,648
Uses of cash and cash equivalents
Cash additions to property, plant and equipment	$	(1,305	)	$	(949	)
Acquisitions, net of cash acquired	(1,828		)	(902		)
Debt repayments	(1,764		)	(1		)
Debt extinguishment costs	(46		)	—
Dividends paid	(128		)	(119		)
Purchases of common stock	(10		)	(5		)
Other	(26		)	—
Total uses of cash and cash equivalents	$	(5,107	)	$	(1,976	)

Cash flows generated from operating activities in the first nine months of 2017 was higher as commodity prices improved compared to the first nine months of 2016. This drove an increase in price realizations in the first nine months of 2017 . Consolidated average liquid hydrocarbon price realizations increased by more than 30% during the first nine months of 2017 as compared to the prior period. This increase in price realization coupled with our increased sales volumes and continued focus on cost reduction resulted in our increased cash flows generated from operating activities.

Proceeds from the disposals of assets for the first nine months of 2017 are from the disposal of our Canadian business; see Note 6 to the consolidated financial statements for further information concerning dispositions. Borrowings during the first nine months of 2017 are a result of the issuance of $1 billion of 4.4% senior unsecured notes due in 2027; see Note 17 to the consolidated financial statements for further detail. Common stock issuance reflects net proceeds received in March 2016 from our public sale of common stock; see Note 19 to the consolidated financial statements for additional information.

Additions to property, plant and equipment in the first nine months of 2017 were consistent with our Capital 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:



	Nine Months Ended September 30,
(In millions)	2017			2016
United States E&P	$	1,465		$	684
International E&P	27			62
Corporate	20			11
Total capital expenditures	1,512			757
Decrease (increase) in capital expenditure accrual	(207		)	192
Total use of cash and cash equivalents for property, plant and equipment	$	1,305		$	949

In the second quarter of 2017, we closed on our acquisition of the Northern Delaware assets for a purchase price of $1.8 billion, subject to closing adjustments. See Note 5 to the consolidated financial statements for additional information.

During the third quarter of 2017, we used the net proceeds of the borrowing disclosed above plus existing cash on hand to redeem $1.76 billion in senior unsecured notes resulting in a recognized loss on early extinguishment of debt of $46 million , primarily due to make-whole call provisions.

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

Liquidity and Capital Resources

In June 2017, we extended the maturity date of our Credit Facility from May 28, 2020, to May 28, 2021. In July 2017, we increased our $3.3 billion unsecured Credit Facility by $93 million to a total of $3.4 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Credit Facility, remain unaffected by the increase and term extension. We have the ability to request two additional one-year extensions and an option to increase the commitment amount by up to an additional $107 million, subject to the consent of any increasing lenders. The sub-facilities for swing-line loans and letters of credit remain unchanged allowing up to an aggregate amount of $100 million and $500 million, respectively.

Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, sales of non-core assets, capital market transactions, and our revolving credit facility. At September 30, 2017 , we had approximately $5.2 billion of liquidity consisting of $1.8 billion in cash and cash equivalents and $3.4 billion available under our revolving credit facility. Our working capital requirements are supported by these sources and we may draw on our 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 program. Because of the alternatives available to us as discussed above, we believe that our short-term and long-term liquidity are 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.

General economic conditions, commodity prices, and financial, business and other factors could affect our operations and our ability to access the capital markets. Our corporate credit ratings remained unchanged during the third quarter and as of September 30, 2017 are: Standard & Poor's Ratings Services BBB- (stable); Fitch Ratings BBB (negative); and Moody's Investor Services, Inc. Ba1 (stable). 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, 2016 for a discussion of how a further downgrade in our credit ratings could affect us.

Capital Resources

Credit Arrangements and Borrowings

At September 30, 2017 , we had no borrowings against our revolving credit facility.

At September 30, 2017 , we had $6.5 billion in long-term debt outstanding, with our next debt maturity in the amount of $600 million due in 2020. 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 debt and equity securities.

Asset Disposal

In the second quarter of 2017, we closed on the sale of our Canadian business for $2.5 billion, excluding closing adjustments. Under the terms of the agreement, $1.8 billion was paid to us upon closing and the remaining proceeds of $750 million will be paid to us in the first quarter of 2018.

In the third quarter of 2017, we entered into agreements to sell certain non-core properties in our International E&P segment for combined proceeds of $53 million , before closing adjustments.

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 28% at September 30, 2017 , compared to 21% at December 31, 2016 .



	September 30,			December 31,
(In millions)	2017			2016
Long-term debt due within one year	$	—		$	686
Long-term debt	6,488			6,581
Total debt	$	6,488		$	7,267
Cash and cash equivalents	$	1,795		$	2,488
Equity	$	11,775		$	17,541
Calculation:
Total debt	$	6,488		$	7,267
Minus cash and cash equivalents	1,795			2,488
Total debt minus cash, cash equivalents	$	4,693		$	4,779
Total debt	$	6,488		$	7,267
Plus equity	11,775			17,541
Minus cash and cash equivalents	1,795			2,488
Total debt plus equity minus cash, cash equivalents	$	16,468		$	22,320
Cash-adjusted debt-to-capital ratio	28		%	21		%

Capital Requirements

On October 25, 2017, our Board of Directors approved a dividend of $0.05 per share for the third quarter of 2017 payable December 11, 2017 to stockholders of record at the close of business on November 15, 2017.

As of September 30, 2017 , we plan to make contributions of up to $8 million to our funded pension plans during the remainder of 2017.

Contractual Cash Obligations

As of September 30, 2017 , there are no material changes to our consolidated cash obligations to make future payments under existing contracts, as disclosed in our 2016 Annual Report on Form 10-K, except for cash obligations primarily relating to the sale of our Canadian business and the issuance of $1 billion of 4.4% senior unsecured notes due in 2027 and redemption of approximately $1.8 billion of debt due in 2017, 2018 and 2019. See Note 6 and Note 17 to the consolidated financial statements for additional information. As a result, as of September 30, 2017, our consolidated contractual cash obligations from our continuing operations has decreased by $1,392 million from December 31, 2016. Our short and long term debt (including

interest) decreased $633 million , purchase obligations under oil and gas activities decreased by $54 million , and service and materials contracts decreased $642 million when comparing September 30, 2017 to December 31, 2016.

Environmental Matters and Other Contingencies

In July 2015, we received a request for information from the EPA under Section 114 of the Clean Air Act regarding several tank batteries used in our Bakken operations. We executed a settlement agreement with the North Dakota Department of Health relating to this matter in the fourth quarter of 2016 that includes a base penalty of $294,000, which was reduced to $130,500 under the terms of the settlement agreement by mitigating corrective actions. We paid the penalty in September 2017 and do not believe that any penalties or corrective action expenditures that may result from this matter will have a material adverse effect on our financial position, results of operation or cash flows.

See Note 21 to the consolidated financial statements for a description of other contingencies.

Forward-Looking Statements

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). 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, asset acquisitions and dispositions, future financial position, future payments for our Canadian disposition and other plans and objectives for future operations, are forward-looking statements. Words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “guidance,” “intend," “may,” “plan,” “project,” “seek,” “should,” “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 and demand levels for crude oil and condensate, NGLs and natural gas and the resulting impact on price;


•	changes in expected reserve or production levels;


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


•	risks related to our hedging activities;


•	capital available for exploration and development;


•	the inability of any party to satisfy closing conditions with respect to our Canadian disposition;


•	drilling and operating risks;


•	well production timing;


•	availability of drilling rigs, materials and 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, 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 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. Except 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 2016 Annual Report on Form 10-K. Notes 14 and 15 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 nine months of 2017, we entered into crude oil and natural gas derivatives, indexed to NYMEX WTI and Henry Hub, related to a portion of our forecasted United States E&P sales. The following tables provide a summary of open positions as of September 30, 2017 and the weighted average price for those contracts:



Crude Oil
	2017	2018
	Fourth Quarter	First Quarter	Second Quarter	Third Quarter	Fourth Quarter
Three-Way Collars ^(a)
Volume (Bbls/day)	50,000	75,000	75,000	62,000	62,000
Weighted average price per Bbl:
Ceiling	$60.37	$56.24	$56.24	$56.08	$56.08
Floor	$54.80	$51.33	$51.33	$50.50	$50.50
Sold put	$47.80	$44.73	$44.73	$43.61	$43.61
Swaps ^(b)(c)
Volume (Bbls/day)	20,000	—	—	—	—
Weighted average price per Bbl	$51.37	—	—	—	—
Sold call options ^(d)
Volume (Bbls/day)	35,000	—	—	—	—
Weighted average price per Bbl	$61.91	—	—	—	—
Basis Swaps ^(e)
Volume (Bbls/day)	—	5,000	5,000	10,000	10,000
Weighted average price per Bbl	—	$(0.60)	$(0.60)	$(0.67)	$(0.67)


^(a)	Between September 30, 2017 and October 30, 2017, we entered into 10,000 Bbls/day of three-way collars for July - December 2018 with an average ceiling price of $58.07 , a floor price of $53.70 , and a sold put price of $47.00 .


^(b)	The counterparties have the option to execute fixed-price swaps (swaptions) at a weighted average price of $52.67 per Bbl indexed to NYMEX WTI, which is exercisable on December 29, 2017. If the counterparties exercise, the term of the fixed-price swaps would be from January - June 2018 and, if all such options are exercised, for 10,000 Bbls/day.


^(c)	Between September 30, 2017 and October 30, 2017, we entered into 40,000 Bbls/day of fixed-price swaps for November - December 2017 with a weighted average price of $54.11 .


^(d)	Call options settle monthly.


^(e)	The basis differential price is between WTI Midland and WTI Cushing.



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

The following table provides a sensitivity analysis of the projected incremental effect on income (loss) from operations of a hypothetical 10% change in NYMEX WTI and Henry Hub prices on our open commodity derivative instruments as of September 30, 2017 .



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

Crude oil derivatives	$	(112	)	$	92
Natural gas derivatives	(12		)	11
Total	$	(124	)	$	103

Interest Rate Risk Sensitivity analysis of the incremental effect of a hypothetical 10% decrease in interest rates on financial assets and liabilities as of September 30, 2017 , is provided in the following table.



(In millions)	Fair Value				Incremental Change in Fair Value
Financial assets (liabilities): ^(a)
Long term debt, including amounts due within one year	$	(6,781	)	^(b)(c)	$	(283	)


^(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 September 30, 2017 .

During the first nine months of 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 Proceedings

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

See Note 21 to the consolidated financial statements included in Part I, Item I for a description of such legal and administrative proceedings.

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

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. There have been no material changes to the risk factors under Item 1A. Risk Factors in our 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 September 30, 2017 .



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)
07/01/17 - 07/31/17	775	$12.08	—	$	1,500,285,529
08/01/17 - 08/31/17	476	$12.05	—	$	1,500,285,529
09/01/17 - 09/30/17	89	$11.21	—	$	1,500,285,529
Total	1,340	$12.01	—


^(a)	1,340 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 September 30, 2017 is $1.5 billion . No repurchases were made under the program in the third 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.



November 2, 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)	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
4.2	Terms of the 4.400% Senior Notes due 2027	8-K	4.2	7/24/2017
4.3	Form of 4.400% Senior Notes due 2027	8-K	4.3	7/24/2017
10.2	Incremental Commitment Supplement, dated as of July 11, 2017, to the Amended and Restated Credit Agreement dated as of May 28, 2014, as amended by the First Amendment dated as of May 5, 2015, supplemented by the Incremental Commitments Supplement dated as of March 4, 2016, and amended by the Second Amendment dated as of June 22, 2017, among Marathon Oil Corporation, as borrower, the lenders party thereto, The Royal Bank of Scotland Plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, and JPMorgan Chase Bank, N.A., as administrative agent.	10-Q	10.2	8/3/2017
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

Part I - Financial Informationprint Item 1. Financial Statementsprint Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operationsprint Item 3. Quantitative and Qualitative Disclosures About Market Riskprint Item 4. Controls and Proceduresprint Part II Other Informationprint Item 1. Legal Proceedingsprint Item 1A. Risk Factorsprint Item 2. Unregistered Sales Of Equity Securities and Use Of Proceedsprint Item 6. Exhibitsprint

Exhibits

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,datedas of February26, 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 4.2 Terms of the 4.400% Senior Notes due 2027 8-K 4.2 7/24/2017 4.3 Form of 4.400% Senior Notes due 2027 8-K 4.3 7/24/2017 10.2 Incremental Commitment Supplement, dated as of July 11, 2017, to the Amended and Restated Credit Agreement dated as of May 28, 2014, as amended by the First Amendment dated as of May 5, 2015, supplemented by the Incremental Commitments Supplement dated as of March 4, 2016, and amended by the Second Amendment dated as of June 22, 2017, among Marathon Oil Corporation, as borrower, the lenders party thereto, The Royal Bank of Scotland Plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, and JPMorgan Chase Bank, N.A., as administrative agent. 10-Q 10.2 8/3/2017 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

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MRO 10-Q Quarter ended Sept. 30, 2017

Exhibits