Edgar Filing: MARATHON OIL CORP

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, 2018



[ ]	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 every Interactive Data File required to be submitted 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 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
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 831,275,876 shares of Marathon Oil Corporation common stock outstanding as of October 31, 2018.

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 2017 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
	Consolidated Statements of Stockholders' Equity	6
	Notes to Consolidated Financial Statements (Unaudited)	7
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	49
Item 4.	Controls and Procedures	49
Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	50
Item 1A.	Risk Factors	50
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50
Item 6.	Exhibits	50
	Signatures	51

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)	2018			2017			2018			2017
Revenues and other income:
Revenues from contracts with customers	$	1,538		$	1,136		$	4,522		$	2,911
Net gain (loss) on commodity derivatives	(70		)	(22		)	(324		)	115
Marketing revenues	—			48			—			117
Income from equity method investments	64			63			161			183
Net gain (loss) on disposal of assets	16			19			323			26
Other income	119			8			135			31
Total revenues and other income	1,667			1,252			4,817			3,383
Costs and expenses:
Production	215			197			637			528
Marketing, including purchases from related parties	—			49			—			121
Shipping, handling and other operating	152			109			408			309
Exploration	56			294			173			352
Depreciation, depletion and amortization	626			641			1,828			1,789
Impairments	8			201			50			205
Taxes other than income	86			44			215			128
General and administrative	101			89			306			276
Total costs and expenses	1,244			1,624			3,617			3,708
Income (loss) from operations	423			(372		)	1,200			(325		)
Net interest and other	(58		)	(35		)	(168		)	(199		)
Other net periodic benefit costs	(8		)	(5		)	(11		)	(16		)
Loss on early extinguishment of debt	—			(46		)	—			(46		)
Income (loss) from continuing operations before income taxes	357			(458		)	1,021			(586		)
Provision (benefit) for income taxes	103			141			315			216
Income (loss) from continuing operations	254			(599		)	706			(802		)
Income (loss) from discontinued operations	—			—			—			(4,893		)
Net income (loss)	$	254		$	(599	)	$	706		$	(5,695	)
Per basic share:
Income (loss) from continuing operations	$	0.30		$	(0.70	)	$	0.83		$	(0.94	)
Income (loss) from discontinued operations	$	—		$	—		$	—		$	(5.76	)
Net income (loss)	$	0.30		$	(0.70	)	$	0.83		$	(6.70	)
Per diluted share:
Income (loss) from continuing operations	$	0.30		$	(0.70	)	$	0.83		$	(0.94	)
Income (loss) from discontinued operations	$	—		$	—		$	—		$	(5.76	)
Net income (loss)	$	0.30		$	(0.70	)	$	0.83		$	(6.70	)
Weighted average common shares outstanding:
Basic	848			850			852			850
Diluted	849			850			853			850

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)	2018		2017			2018		2017
Net income (loss)	$	254	$	(599	)	$	706	$	(5,695	)
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	20		5			37		17
Income tax provision (benefit)	—		19			—		19
Postretirement and postemployment plans, net of tax	20		24			37		36
Derivative hedges
Net unrecognized gain (loss)	—		—			—		(13		)
Reclassification of gains on terminated derivative hedges	—		(46		)	—		(47		)
Income tax provision (benefit)	—		21			—		21
Derivative hedges, net of tax	—		(25		)	—		(39		)
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			4		2
Other comprehensive income (loss)	20		—			41		29
Comprehensive income (loss)	$	274	$	(599	)	$	747	$	(5,666	)

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)	2018			2017
Assets
Current assets:
Cash and cash equivalents	$	1,564		$	563
Receivables, less reserve of $8 and $12	1,335			1,082
Notes receivable	—			748
Inventories	110			126
Other current assets	31			36
Current assets held for sale	25			11
Total current assets	3,065			2,566
Equity method investments	757			847
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $22,358 and $21,564	16,899			17,665
Goodwill	97			115
Other noncurrent assets	912			764
Noncurrent assets held for sale	48			55
Total assets	$	21,778		$	22,012
Liabilities
Current liabilities:
Accounts payable	$	1,479		$	1,395
Payroll and benefits payable	127			108
Accrued taxes	128			177
Other current liabilities	405			288
Current liabilities held for sale	3			—
Total current liabilities	2,142			1,968
Long-term debt	5,498			5,494
Deferred tax liabilities	215			833
Defined benefit postretirement plan obligations	286			362
Asset retirement obligations	1,243			1,428
Deferred credits and other liabilities	340			217
Noncurrent liabilities held for sale	10			2
Total liabilities	9,734			10,304
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, 1.925 billion shares authorized at September 30, 2018 and 1.1 billion shares authorized at December 31, 2017)	937			937
Held in treasury, at cost – 99 million and 87 million shares	(3,455		)	(3,325		)
Additional paid-in capital	7,226			7,379
Retained earnings	7,357			6,779
Accumulated other comprehensive loss	(21		)	(62		)
Total stockholders' equity	12,044			11,708
Total liabilities and stockholders' equity	$	21,778		$	22,012

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)	2018			2017
Operating activities:
Net income (loss)	$	706		$	(5,695	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations	—			4,893
Depreciation, depletion and amortization	1,828			1,789
Impairments	50			205
Exploratory dry well costs and unproved property impairments	144			294
Net (gain) loss on disposal of assets	(323		)	(26		)
Deferred income taxes	62			44
Net (gain) loss on derivative instruments	324			(162		)
Net settlements of derivative instruments	(255		)	88
Pension and other postretirement benefits, net	(60		)	(38		)
Stock-based compensation	44			38
Equity method investments, net	42			46
Changes in:
Current receivables	(389		)	(192		)
Inventories	(11		)	4
Current accounts payable and accrued liabilities	334			189
All other operating, net	(117		)	10
Net cash provided by operating activities from continuing operations	2,379			1,487
Investing activities:
Additions to property, plant and equipment	(2,069		)	(1,305		)
Additions to other assets	(135		)	(23		)
Acquisitions, net of cash acquired	(25		)	(1,828		)
Disposal of assets, net of cash transferred to buyer	1,249			1,757
Equity method investments - return of capital	48			49
All other investing, net	11			(3		)
Net cash provided by (used in) investing activities from continuing operations	(921		)	(1,353		)
Financing activities:
Borrowings	—			988
Debt repayments	—			(1,764		)
Debt extinguishment costs	—			(46		)
Purchases of common stock	(349		)	(10		)
Dividends paid	(128		)	(128		)
All other financing, net	22			—
Net cash provided by (used in) financing activities	(455		)	(960		)
Net increase in cash and cash equivalents of discontinued operations (Note 5)	—			130
Effect of exchange rate on cash and cash equivalents	(2		)	3
Net increase (decrease) in cash and cash equivalents	1,001			(693		)
Cash and cash equivalents at beginning of period	563			2,488
Cash and cash equivalents at end of period	$	1,564		$	1,795

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

MARATHON OIL CORPORATION

Consolidated Statements of Stockholders’ Equity (Unaudited)



	Total Equity of Marathon Oil Stockholders
(In millions)	Preferred Stock		Common Stock		Treasury Stock			Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Loss			Total Equity
Nine Months Ended September 30, 2017
December 31, 2016 Balance	$	—	$	937	$	(3,431	)	$	7,446		$	12,672		$	(83	)	$	17,541
Shares issued - stock-based compensation	—		—		116			(51		)	—			—			65
Shares repurchased	—		—		(9		)	—			—			—			(9		)
Stock-based compensation	—		—		—			(28		)	—			—			(28		)
Net loss	—		—		—			—			(5,695		)	—			(5,695		)
Other comprehensive income	—		—		—			—			—			29			29
Dividends paid (per share amount of $0.15)	—		—		—			—			(128		)	—			(128		)
September 30, 2017 Balance	$	—	$	937	$	(3,324	)	$	7,367		$	6,849		$	(54	)	$	11,775

Nine Months Ended September 30, 2018
December 31, 2017 Balance	$	—	$	937	$	(3,325	)	$	7,379		$	6,779		$	(62	)	$	11,708
Shares issued - stock-based compensation	—		—		219			(115		)	—			—			104
Shares repurchased	—		—		(349		)	—			—			—			(349		)
Stock-based compensation	—		—		—			(38		)	—			—			(38		)
Net income	—		—		—			—			706			—			706
Other comprehensive income	—		—		—			—			—			41			41
Dividends paid (per share amount of $0.15)	—		—		—			—			(128		)	—			(128		)
September 30, 2018 Balance	$	—	$	937	$	(3,455	)	$	7,226		$	7,357		$	(21	)	$	12,044

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 2017 Annual Report on Form 10-K. The results of operations for the third quarter and first nine months of 2018 are not necessarily indicative of the results to be expected for the full year.

As a result of the sale of our Canadian business in 2017, we reflected this business as discontinued operations in all historical periods presented. Disclosures in this report related to results of operations and cash flows are presented on the basis of continuing operations unless otherwise stated. See Note 5 for discussion of this divestiture in further detail.

Reclassifications

In the first quarter of 2018 we adopted the new Accounting Standards Codification ("ASC") Topic 606, Revenue from Contracts with Customers using the modified retrospective method. To conform the historical presentation to our current presentation, we reclassified gains/losses arising from our commodity derivatives out of the revenues from contracts with customers line into a separate line, net gain (loss) on commodity derivatives, on the consolidated statements of income. Additionally, in the first quarter of 2018 we adopted the new pension accounting standards update on a retrospective basis, and reclassified the required cost elements from general and administrative expense into production expense, exploration expense, and other net periodic benefit costs. See Note 2 for further discussion of the adoption of these accounting standards.

2. Accounting Standards

Not Yet Adopted

Lease accounting standard

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.

In July 2018, the FASB issued a new transition option that allows entities to adopt the new lease accounting standard using the modified retrospective transition method by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption rather than in the earliest period presented. We plan to elect this new transition option and continue to apply the legacy guidance in ASC 840, Leases, including its disclosure requirements, in the comparative periods presented in the year of adoption.

We will adopt the new standard in the first quarter of 2019 using a modified retrospective approach and will recognize a right of use asset and lease liability on the adoption date. We plan to apply practical expedients provided in the standard that allow, amongst others, not to reassess contracts that commenced prior to the adoption. We also anticipate to elect a policy not to recognize right of use assets and lease liabilities related to short-term leases.

We continue to evaluate our contracts and are gathering the necessary data to determine the financial impact of this standard on our consolidated financial statements and related disclosures. We installed and are in the process of configuring software that we believe will facilitate the adoption of the standard. We are also evaluating our processes and internal control environment concurrent with the adoption of this standard. While we have yet to finalize the estimated impact this standard will have on our consolidated financial statements, the adoption is anticipated to result in an increase in both assets and liabilities related to our leases.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Hedge accounting standard

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. None of our derivative instruments are currently designated as hedges; as a result we do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

Goodwill standard

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

Financial instruments - credit losses

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

Revenue recognition standard

On January 1, 2018, we adopted the new ASC Topic 606, Revenue from Contracts with Customers and all the related amendments ("new revenue standard") using the modified retrospective method. We evaluated the effect of transition by applying the provisions of the new revenue standard to contracts with remaining obligations as of January 1, 2018. No cumulative adjustment to retained earnings was necessary as a result of adopting this standard.

Results for reporting periods beginning after January 1, 2018 are presented under the new revenue standard, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting policies. The primary change relates to the presentation of marketing revenues and marketing expenses from the historical gross presentation to the current net presentation, included within revenues from contracts with customers, for a portion of our international contracts.

We concluded that the adoption of the new revenue standard did not result in any significant changes to our consolidated balance sheet or statement of cash flows. The following tables summarize the impacts of adopting the new revenue standard on our consolidated income statement for the three and nine month periods ended September 30, 2018.



	Three Months Ended September 30, 2018
(In millions)	As reported		Adjustments			Presentation without adoption of ASC Topic 606
Revenues and other income:
Revenues from contracts with customers	$	1,538	$	(2	)	$	1,536
Marketing revenues	—		47			47
Other income	119		(1		)	118
Costs and expenses:
Marketing, including purchases from related parties	$	—	$	46		$	46
Shipping, handling and other operating	152		(2		)	150

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



	Nine Months Ended September 30, 2018
(In millions)	As reported		Adjustments			Presentation without adoption of ASC Topic 606
Revenues and other income:
Revenues from contracts with customers	$	4,522	$	(4	)	$	4,518
Marketing revenues	—		122			122
Other income	135		(3		)	132
Costs and expenses:
Marketing, including purchases from related parties	$	—	$	122		$	122
Shipping, handling and other operating	408		(7		)	401

Pension accounting standard

In the first quarter of 2018, we adopted the new accounting standards update that changes how employers that sponsor defined pension and/or other postretirement benefit plans present the net periodic benefit cost in the income statement. As a result, employers are required to 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. We adopted this standard on a retrospective basis, and reclassified the required cost elements from general and administrative expense into production expense, exploration expense, and other net periodic benefit costs. The adoption of this standard did not have a significant impact on our consolidated balance sheet or statement of cash flows. The following tables summarize the impacts of adopting this standard on our historical consolidated income statement for the three and nine month periods ended September 30, 2017.



	Three Months Ended September 30, 2017
(In millions)	Previously Reported			As reclassified			Effect of Change Higher/(Lower)
Production	$	194		$	197		$	3
Exploration	294			294			—
General and administrative	97			89			(8		)
Income (loss) from operations	(377		)	(372		)	5
Other net periodic benefit costs ^(a)	—			5			5



	Nine Months Ended September 30, 2017
(In millions)	Previously Reported			As reclassified			Effect of Change Higher/(Lower)
Production	$	521		$	528		$	7
Exploration	352			352			—
General and administrative	299			276			(23		)
Income from operations	(341		)	(325		)	16
Other net periodic benefit costs ^(a)	—			16			16

^(a)Includes net settlement loss and other net periodic benefit costs, excluding service costs (See Note 18).

Classification in the statement of cash flows

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 was effective for us in the first quarter of 2018, and was applied retrospectively. Adoption of this standard did not have a significant impact on our consolidated statements of cash flows.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Presentation of restricted cash in the statement of cash flows

In November 2016, the FASB issued a new accounting standards update that requires entities to show the changes in the total of cash, cash equivalents and restricted cash in the statement of cash flows. As a result, we no longer present transfers between cash and cash equivalents and restricted cash in the statement of cash flows. When cash, cash equivalents, and restricted cash are presented in more than one line item on the balance sheet, the standard requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. This reconciliation can be presented either on the face of the statement of cash flows or in the notes to the financial statements. This standard was effective for us in the first quarter of 2018, and was applied retrospectively. Adoption of this standard did not have a significant impact on our consolidated statements of cash flows.

Accounting for sale or transfer of nonfinancial assets

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 was effective for us in the first quarter of 2018, and was applied using the modified retrospective approach. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

Definition of a business

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 us 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 was effective for us in the first quarter of 2018, 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.

Financial instruments updates

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


3.	Income (Loss) and Dividends 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 periods, provided the effect is not antidilutive. The per share calculations below exclude 5 million and 6 million of stock options for the three and nine months period ended September 30, 2018 and 10 million and 11 million stock options for the three and nine months period ended September 30, 2017 that were antidilutive.



	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions, except per share data)	2018		2017			2018		2017
Income (loss) from continuing operations	$	254	$	(599	)	$	706	$	(802	)
Income (loss) from discontinued operations	—		—			—		(4,893		)
Net income (loss)	$	254	$	(599	)	$	706	$	(5,695	)

Weighted average common shares outstanding	848		850			852		850
Effect of dilutive securities	1		—			1		—
Weighted average common shares, diluted	849		850			853		850
Per basic share:
Income (loss) from continuing operations	$	0.30	$	(0.70	)	$	0.83	$	(0.94	)
Income (loss) from discontinued operations	$	—	$	—		$	—	$	(5.76	)
Net income (loss)	$	0.30	$	(0.70	)	$	0.83	$	(6.70	)
Per diluted share:
Income (loss) from continuing operations	$	0.30	$	(0.70	)	$	0.83	$	(0.94	)
Income (loss) from discontinued operations	$	—	$	—		$	—	$	(5.76	)
Net income (loss)	$	0.30	$	(0.70	)	$	0.83	$	(6.70	)
Dividends per share	$	0.05	$	0.05		$	0.15	$	0.15

4. Acquisitions

In the second quarter of 2017, we closed on two acquisitions which included approximately 91,000 net acres in the Permian basin of New Mexico. The first acquisition with BC Operating, Inc. and other entities closed for approximately $1.1 billion in cash and the second acquisition with Black Mountain Oil & Gas and other private sellers closed for approximately $700 million in cash. These acquisitions were paid with cash on hand and accounted for as asset acquisitions, with substantially all of the purchase price allocated to unproved property within property, plant and equipment.


5.	Dispositions

United States E&P Segment

In the third quarter of 2018, we closed on the sale of non-core, non-operated conventional properties, primarily in the Gulf of Mexico, for combined net proceeds of $16 million, before closing adjustments. A pre-tax gain of $32 million was recognized in the third quarter of 2018.

In the third quarter of 2017, we closed on the sale of certain conventional assets in Oklahoma for proceeds of $25 million, subject to closing adjustments, and recognized a pre-tax gain of $21 million.

International E&P Segment

In the second quarter of 2018, we entered into an agreement to sell a non-core property for proceeds of $56 million, before closing adjustments. This property is classified as held for sale in the consolidated balance sheet at September 30, 2018, with total assets of $73 million, total liabilities of $13 million and is expected to close before year-end.

In the first quarter of 2018, we closed on the sale of our subsidiary, Marathon Oil Libya Limited, which held our 16.33% non-operated interest in the Waha concessions in Libya, to a subsidiary of Total S.A. (Elf Aquitaine SAS) for proceeds of approximately $450 million, excluding closing adjustments, and recognized a pre-tax gain of $255 million.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

In the third quarter of 2017, we entered into separate agreements to sell certain non-core properties for combined proceeds of $53 million, before closing adjustments. We closed on one of the asset sales in the fourth quarter of 2017 and recognized no pre-tax gain or loss on sale. We closed on the remaining asset sale during the third quarter of 2018 for a pre-tax loss of $18 million.

Canadian Business - Discontinued Operations

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 for $2.5 billion, excluding closing adjustments. Under the terms of the agreement, $1.8 billion was paid to us upon closing. At closing we received two notes receivable for a combined $750 million for the remaining proceeds, which was received in the first quarter of 2018. In the first quarter of 2017, we recorded a non-cash impairment charge of $6.6 billion (after-tax of $4.96 billion) primarily related to the property, plant and equipment of our Canadian business. 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. As the effective date of the transaction was January 1, 2017, we recorded a loss on sale of $43 million during the second quarter of 2017 due to results of operations from our Canadian business that were 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 historical consolidated statements of income and consolidated statements of cash flows as discontinued operations:



	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions)		2018		2017		2018		2017
Total revenue and other income		$	—	$	—	$	—	$	431
Net gain (loss) on disposal of assets		—		—		—		(43		)
Total revenues and other income		—		—		—		388
Costs and expenses:
Production		—		—		—		254
Depreciation, depletion and amortization		—		—		—		40
Impairments		—		—		—		6,636
Other		—		—		—		25
Total costs and expenses		—		—		—		6,955
Pretax income (loss) from discontinued operations		—		—		—		(6,567		)
Provision (benefit) for income taxes		—		—		—		(1,674		)
Income (loss) from discontinued operations		$	—	$	—	$	—	$	(4,893	)



	Nine Months Ended September 30,
(In millions)	2018		2017

Cash flow from discontinued operations:
Operating activities	$	—	$	141
Investing activities	—		(13		)
Changes in cash included in current assets held for sale	—		2
Net increase in cash and cash equivalents of discontinued operations	$	—	$	130

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


6.	Revenues

The majority of our revenues are derived from the sale of crude oil and condensate, natural gas liquids ("NGLs") and natural gas under spot and term agreements with our customers in the U.S. and various international locations.

The following tables present our revenues from contracts with customers disaggregated by product type and geographic areas.



	Three Months Ended September 30, 2018
United States E&P							Northern
(In millions)	Eagle Ford		Bakken		Oklahoma		Delaware		Other U.S.		Total
Crude oil and condensate	$	436	$	447	$	114	$	59	$	34	$	1,090
Natural gas liquids	70		19		48		12		3		152
Natural gas	36		9		46		6		5		102
Other	—		—		—		—		3		3
Revenues from contracts with customers	$	542	$	475	$	208	$	77	$	45	$	1,347



	Three Months Ended September 30, 2018
International E&P							Other
(In millions)	E.G.		U.K.		Libya		International		Total
Crude oil and condensate	$	100	$	41	$	—	$	20	$	161
Natural gas liquids	1		1		—		—		2
Natural gas	9		11		—		—		20
Other	—		8		—		—		8
Revenues from contracts with customers	$	110	$	61	$	—	$	20	$	191



	Nine Months Ended September 30, 2018
United States E&P							Northern
(In millions)	Eagle Ford		Bakken		Oklahoma		Delaware		Other U.S.		Total
Crude oil and condensate	$	1,196	$	1,182	$	340	$	173	$	131	$	3,022
Natural gas liquids	157		51		130		24		8		370
Natural gas	102		27		127		13		17		286
Other	3		—		—		—		12		15
Revenues from contracts with customers	$	1,458	$	1,260	$	597	$	210	$	168	$	3,693



	Nine Months Ended September 30, 2018
International E&P							Other
(In millions)	E.G.		U.K.		Libya		International		Total
Crude oil and condensate	$	271	$	207	$	187	$	65	$	730
Natural gas liquids	3		4		—		—		7
Natural gas	28		31		9		—		68
Other	—		24		—		—		24
Revenues from contracts with customers	$	302	$	266	$	196	$	65	$	829

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The pricing in our hydrocarbon sales agreements are variable, determined using various published benchmarks which are adjusted for negotiated quality and location differentials. As a result, revenue collected under our agreements with customers is highly dependent on the market conditions and may fluctuate considerably as the hydrocarbon market prices rise or fall. Typically, our customers pay us monthly, within a short period of time after we deliver the hydrocarbon products. As such, we do not have any financing element associated with our contracts. We do not have any issues related to returns or refunds, as product specifications are standardized for the industry and are typically measured when transferred to a common carrier or midstream entity, and other contractual mechanisms (e.g., price adjustments) are used when products do not meet those specifications.

In limited cases, we may also collect advance payments from customers as stipulated in our agreements; payments in excess of recognized revenue are recorded as contract liabilities on our consolidated balance sheet.

Under our hydrocarbon sales agreements, the entire consideration amount is variable either due to pricing and/or volumes. We recognize revenue in the amount of variable consideration allocated to distinct units of hydrocarbons transferred to a customer. Such allocation reflects the amount of total consideration we expect to collect for completed deliveries of hydrocarbons and the terms of variable payment relate specifically to our efforts to satisfy the performance obligations under these contracts. Our performance obligations under our hydrocarbon sales agreements are to deliver either the entire production from the dedicated wells or specified contractual volumes of hydrocarbons.

We often serve as the operator for jointly owned oil and gas properties. As part of this role, we perform activities to explore, develop and produce oil and gas properties in accordance with the joint operating arrangement and collective decisions of the joint parties. Other working interest owners reimburse us for costs incurred based on our agreements. We determined that these activities are not performed as part of customer relationships, in accordance with the new revenue standard, and such reimbursements will continue to not be recorded as revenues within the scope of the new revenue standard.

In addition, we commonly market the share of production belonging to other working interest owners as the operator of jointly owned oil and gas properties. We concluded that those marketing activities are carried out as part of the collaborative arrangement, and we do not purchase or otherwise obtain control of other working interest owners’ share of production. Therefore, we act as a principal only in regards to the sale of our share of production and recognize revenue for the volumes associated with our net production.

Crude oil and condensate

For the crude sales agreements, we satisfy our performance obligations and recognize revenue once customers take control of the crude at the designated delivery points, which include pipelines, trucks or vessels.

Natural gas and NGLs

When selling natural gas and NGLs, we engage midstream entities to process our production stream by separating natural gas from the NGLs. Frequently, these midstream entities also purchase our natural gas and NGLs under the same agreements. In these situations, we determined the performance obligation is complete and satisfied at the tailgate of the processing plant when the natural gas and NGLs become identifiable and measurable products. We determined the plant tailgate is the point in time where control, as defined in the new revenue standard, is transferred to midstream entities and they are entitled to significant risks and rewards of ownership of the natural gas and NGLs.

The amounts due to midstream entities for gathering and processing services are recognized as shipping and handling cost, since we make those payments in exchange for distinct services. Under some of our natural gas processing agreements, we have an option to take the processed natural gas and NGLs in-kind and sell to customers other than the processing company. In those circumstances, our performance obligations are complete after delivering the processed hydrocarbons to the customer at the designated delivery points, which may be the tailgate of the processing plant or an alternative delivery point requested by the customer.

We have “percentage-of-proceeds” arrangements with some midstream entities where they retain a percentage of the proceeds collected for selling our processed natural gas and NGLs as compensation for their processing and marketing services. We recognize revenue for the gross sales volumes and recognize the proceeds retained by midstream companies as shipping and handling cost.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Contract receivables and liabilities

The following table provides information about receivables and contract assets (liabilities) from contracts with customers.



(In millions)	September 30, 2018			January 1, 2018
Receivables from contracts with customers, which are included in receivables, less reserves	$	937		$	811
Contract asset (liability)	$	(1	)	$	—

The contract liability primarily relates to the advance consideration received from customers for crude oil sales and processing services in the U.K. A contract asset would represent crude oil delivered in the U.K. to a customer for which payment will be collected over time as it becomes due under the pricing terms stipulated in the sales agreement. As a practical expedient, when the balance of this U.K. customer is a contract asset, we do not adjust revenue for the effects of a significant financing element as the period between when crude oil is delivered to the customer and when payment is expected to be received is one year or less at contract inception.

Significant changes in the contract asset (liability) balance during the period are as follows.



	Nine Months Ended
(In millions)	September 30, 2018
Contract asset balance as of January 1, 2018	$	—
Revenue recognized as performance obligations are satisfied	85
Amounts invoiced to customers	(86		)
Contract asset (liability) balance as of September 30, 2018	$	(1	)

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 it offers.


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


•	International E&P ("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 our operating segments, net of income taxes. A portion of our corporate and operations general and administrative support 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.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



	Three Months Ended September 30, 2018
							Not Allocated
(In millions)	U.S. E&P			Int'l E&P			to Segments				Total
Revenues from contracts with customers	$	1,347		$	191		$	—			$	1,538
Net gain (loss) on commodity derivatives	(89		)	—			19			^(b)	(70		)
Income from equity method investments	—			64			—				64
Net gain (loss) on disposal of assets	—			—			16			^(c)	16
Other income	2			4			113			^(d)	119
Less costs and expenses:
Production	172			43			—				215
Shipping, handling and other operating	136			16			—				152
Exploration	55			1			—				56
Depreciation, depletion and amortization	571			49			6				626
Impairments	—			—			8			^(e)	8
Taxes other than income	86			—			—				86
General and administrative	37			7			57				101
Net interest and other	—			—			58				58
Other net periodic benefit costs	—			(3		)	11			^(f)	8
Income tax provision (benefit)	2			30			71				103
Segment income (loss) / Income (loss) from continuing operations	$	201		$	116		$	(63	)		$	254
Capital expenditures ^(a)	$	691		$	6		$	7			$	704


^(a)	Includes accruals.


^(b)	Unrealized gain on commodity derivative instruments (See Note 13).


^(c)	Sales of certain non-core proved properties in our International and United States E&P segments (See Note 5).


^(d)	Reduction of our asset retirement obligation in our International E&P segment (See Note 12).


^(e)	Due to the anticipated sale of non-core property in our International E&P segment (See Note 11).


^(f)	Includes pension settlement loss of $10 million (See Note 18).

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
Revenues from contracts with customers	$	772		$	364	$	—			$	1,136
Net gain (loss) on commodity derivatives	34			—		(56		)	^(b)	(22		)
Marketing revenues	12			36		—				48
Income from equity method investments	—			63		—				63
Net gain on disposal of assets	1			—		18			^(c)	19
Other income	3			—		5				8
Less costs and expenses:
Production	121			76		—				197
Marketing costs	14			35		—				49
Shipping, handling and other operating	80			31		(2		)		109
Exploration	41			3		250			^(d)	294
Depreciation, depletion and amortization	531			102		8				641
Impairments	—			—		201			^(e)	201
Taxes other than income	44			—		—				44
General and administrative	29			6		54				89
Net interest and other	—			—		35			^(f)	35
Other net periodic benefit costs	—			—		5			^(g)	5
Loss on early extinguishment of debt	—			—		46			^(h)	46
Income tax provision (benefit)	—			106		35				141
Segment income (loss) / Income (loss) from continuing operations	$	(38	)	$	104	$	(665	)		$	(599	)
Capital expenditures ^(a)	$	541		$	4	$	9			$	554


^(a)	Includes accruals.


^(b)	Unrealized loss on commodity derivative instruments (See Note 13).


^(c)	Primarily related to the sale of certain conventional assets in Oklahoma (See Note 5).


^(d)	Primarily related to unproved property impairments associated with certain non-core properties within our International E&P segment (See Note 11).


^(e)	Primarily related to proved property impairments associated with certain non-core properties within our International E&P segment (See Note 11).


^(f)	Includes a gain of $46 million resulting from the termination of our forward starting interest rate swaps (See Note 13).


^(g)	Includes pension settlement loss of $8 million (See Note 18.)


^(h)	Primarily related to the make-whole call provisions paid upon redemption of our senior unsecured notes (See Note 15).

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



	Nine Months Ended September 30, 2018
							Not Allocated
(In millions)	U.S. E&P			Int'l E&P			to Segments				Total
Revenues from contracts with customers	$	3,693		$	829		$	—			$	4,522
Net gain (loss) on commodity derivatives	(255		)	—			(69		)	^(b)	(324		)
Income from equity method investments	—			161			—				161
Net gain (loss) on disposal of assets	—			—			323			^(c)	323
Other income	7			7			121			^(d)	135
Less costs and expenses:
Production	476			162			(1		)		637
Shipping, handling and other operating	364			45			(1		)		408
Exploration	170			3			—				173
Depreciation, depletion and amortization	1,655			153			20				1,828
Impairments	—			—			50			^(e)	50
Taxes other than income	218			—			(3		)		215
General and administrative	108			25			173				306
Net interest and other	—			—			168				168
Other net periodic benefit costs	—			(7		)	18			^(f)	11
Income tax provision (benefit)	5			226			84				315
Segment income (loss) / Income (loss) from continuing operations	$	449		$	390		$	(133	)		$	706
Capital expenditures ^(a)	$	1,943		$	28		$	17			$	1,988


^(a)	Includes accruals.


^(b)	Unrealized loss on commodity derivative instruments (See Note 13).


^(c)	Primarily related to the gain on sale of our Libya subsidiary (See Note 5).


^(d)	Reduction of our asset retirement obligation in our International E&P segment (See Note 12).


^(e)	Due to the anticipated sales of certain non-core proved properties in our International and United States E&P segments (See Note 11).


^(f)	Includes pension settlement loss of $16 million (See Note 18).

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
Revenue from contracts with customers	$	2,124		$	787		$	—			$	2,911
Net gain (loss) on commodity derivatives	51			—			64			^(b)	115
Marketing revenues	25			92			—				117
Income from equity method investments	—			183			—				183
Net gain (loss) on disposal of assets	2			—			24			^(c)	26
Other income	9			14			8				31
Less costs and expenses:
Production	348			180			—				528
Marketing costs	30			91			—				121
Shipping, handling and other operating	250			59			—				309
Exploration	97			5			250			^(d)	352
Depreciation, depletion and amortization	1,498			266			25				1,789
Impairments	4			—			201			^(e)	205
Taxes other than income	116			—			12				128
General and administrative	92			21			163				276
Net interest and other	—			—			199			^(f)	199
Other net periodic benefit costs	—			(4		)	20			^(g)	16
Loss on early extinguishment of debt	—			—			46			^(h)	46
Income tax provision (benefit)	—			202			14				216
Segment income (loss) / Income (loss) from continuing operations	$	(224	)	$	256		$	(834	)		$	(802	)
Capital expenditures ^(a)	$	1,465		$	27		$	20			$	1,512


^(a)	Includes accruals.


^(b)	Unrealized gain on commodity derivative instruments (See Note 13).


^(c)	Primarily related to the sale of certain conventional assets in Oklahoma (See Note 5).


^(d)	Primarily related to unproved property impairments associated with certain non-core properties within our International E&P segment (See Note 11).


^(e)	Primarily related to proved property impairments associated with certain non-core properties within our International E&P segment (See Note 11).


^(f)	Includes a gain of $46 million resulting from the termination of our forward starting interest rate swaps (See Note 13).


^(g)	Includes pension settlement loss of $25 million (See Note 18).


^(h)	Primarily related to the make-whole call provisions paid upon redemption of our senior unsecured notes (See Note 15).

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

8. Income Taxes

Effective Tax Rate

The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The difference between the total provision 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 three and nine months ended September 30, 2018 and 2017, our effective income tax rates from continuing operations were as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Effective income tax expense (benefit) rate from continuing operations^*	29	%	31	%	31	%	37	%

^{* In all periods presented, we maintained our valuation allowance on our net federal deferred tax assets in the U.S.}

The following items caused the effective tax rates from continuing operations to be different from our U.S. statutory tax rate of 21% and 35% for 2018 and 2017:


•	Income taxes for the third quarter 2018 were impacted by a $76 million deferred tax expense due to the reduction in estimated costs relating to our U.K. asset retirement obligation, see Note 12 for further detail.


•	During the nine months ended September 30, 2018 income taxes were impacted by tax expense in Libya of $162 million and the reduction in estimated costs relating to our U.K. asset retirement obligation.


•	Income taxes for the third quarter 2017 were impacted by tax expense in Libya of $102 million. During the nine months ended September 30, 2017, we incurred tax expense in Libya of $179 million and settled our 2011-2013 Alaska income tax audit resulting in a tax benefit of $13 million.

Excluding Libya, the effective income tax expense rates from continuing operations were an expense of 17% and an expense of 5% for the nine months ended September 30, 2018 and 2017. As a result of the sale of our Libya subsidiary in the first quarter of 2018, see Note 5 for further detail, we do not expect to incur further tax expense related to our Libya subsidiary. During 2018 and 2017, income taxes for Libya were recorded as a discrete item due to the uncertainty around the timing of future production and sales volumes.

As a result of progression in the 2010-2011 IRS Federal Tax Audit (“IRS Audit”), during the third quarter of 2018 we have established a receivable classified in other noncurrent assets on the consolidated balance sheet of $136 million related to corporate alternative minimum tax (“AMT") credits. Due to the repeal of corporate AMT with the enactment of the Tax Cuts and Jobs Act (the “Tax Reform Legislation”), discussed below, AMT credits are refundable. We do not currently consider the IRS Audit effectively settled as it is still subject to Joint Committee review. As a result, we have established an uncertain tax position for the same amount resulting in no impact to the consolidated statement of income in the third quarter of 2018.

We are under income tax examination in various jurisdictions in which we operate. We believe it is reasonably possible there could be a change in our uncertain tax positions resulting from the progression of examination or appeals activity, which could impact our annual effective tax rate, in the next 12 months.

On December 22, 2017, the U.S. enacted the Tax Reform Legislation. Tax Reform Legislation significantly changes U.S. corporate income tax laws by, among other things, reducing the U.S. corporate income tax rate to 21% starting in 2018, and repeal of the corporate AMT, and a one-time deemed repatriation of accumulated foreign earnings. In the fourth quarter of 2017, we remeasured our deferred taxes at 21%, in accordance with U.S. GAAP standards. We plan to finalize our tax positions taken with respect to Tax Reform Legislation in the fourth quarter of 2018 as we await further guidance from U.S. Treasury, and conclude whether any further adjustments are required to our net tax position as of December 31, 2017. Any adjustments to these provisional amounts will be reported as a component of income tax expense (benefit) in the reporting period in which any such adjustments are determined. As of the third quarter of 2018, there are no material impacts on tax expense with respect to the finalization of tax positions taken due to Tax Reform Legislation.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

9. 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)	2018		2017
Crude oil and natural gas	$	11	$	9
Supplies and other items	99		117
Inventories	$	110	$	126

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



	September 30,		December 31,
(In millions)	2018		2017
United States E&P	$	16,011	$	15,867
International E&P	805		1,710
Corporate	83		88
Net property, plant and equipment	$	16,899	$	17,665

Exploratory well costs capitalized greater than one year after completion of drilling are associated with one project in E.G. with costs of $32 million as of both September 30, 2018 and December 31, 2017.

11. Impairments

The following table summarizes impairment charges of proved properties from continuing operations. Additionally, it presents 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,
	2018				2017
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets	$	39	$	8	$	169	$	201



	Nine Months Ended September 30,
	2018				2017
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets	$	108	$	50	$	169	$	205

•

2018 - During the first nine months of 2018 we recorded pre-tax non-cash proved property impairments of $50 million, to a fair value of $108 million, primarily as a result of anticipated sales proceeds for certain non-core proved properties in our International and United States E&P segments. The related fair value measurement utilized the market approach, based upon anticipated sales proceeds less costs to sell which resulted in a Level 2 classification. See Note 5 for discussion of the divestitures in further detail.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

•

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. 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.

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. The fair values were measured using an income approach based upon internal estimates of future production levels, prices and discount rate. 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. These inputs resulted in a Level 3 classification.

The following table summarizes impairment charges of unproved properties included as a component of exploration expenses:



	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions)	2018			2017		2018		2017
Exploration Expenses
Unproved property impairments	$	50		$	172	$	131	$	217
Dry well costs	1			77		13		77
Geological and geophysical	(1		)	2		13		3
Other	6			43		16		55
Total exploration expenses	$	56		$	294	$	173	$	352

•

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 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.

See Note 5 for relevant detail regarding the disposition of assets.

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)	2018			2017
Beginning balance as of January 1, 2018 and 2017	$	1,483		$	1,653
Incurred liabilities, including acquisitions	10			19
Settled liabilities, including dispositions	(105		)	(40		)
Accretion expense (included in depreciation, depletion and amortization)	53			65
Revisions of estimates	(130		)	(113		)
Held for sale	(10		)	(2		)
Ending balance	$	1,301		$	1,582

September 30, 2018


•	Settled liabilities include dispositions, primarily related to the sale of non-core, non-operated conventional properties in the Gulf of Mexico as well as retirements in the U.K.


•	Revisions of estimates were primarily due to the acceleration of U.K. abandonment activities to capture favorable market conditions and lower estimated abandonment costs.


•	Ending balance includes $58 million classified as short-term at September 30, 2018.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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 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.

13. 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 along with where they appear on the consolidated balance sheets.



	September 30, 2018
(In millions)	Asset		Liability		Net Asset (Liability)			Balance Sheet Location
Not Designated as Hedges
Commodity	—		196		$	(196	)	Other current liabilities
Commodity	—		14		$	(14	)	Deferred credits and other liabilities
Total Not Designated as Hedges	$	—	$	210	$	(210	)



	December 31, 2017
(In millions)	Asset		Liability		Net Asset (Liability)			Balance Sheet Location
Not Designated as Hedges
Commodity	$	—	$	138	$	(138	)	Other current liabilities
Commodity	—		2		(2		)	Deferred credits and other liabilities
Total Not Designated as Hedges	$	—	$	140	$	(140	)

Derivatives Not Designated as Hedges

Terminated 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. 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. As a result, in the third quarter of 2017 we terminated our forward starting interest rate swaps for proceeds of $54 million. We recognized a gain of $46 million, related to deferred gains reclassified from accumulated other comprehensive income, in net interest and other during the third quarter of 2017.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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)	2018		2017			2018		2017
Interest Rate Swaps
Beginning balance	$	—	$	46		$	—	$	60
Change in fair value recognized in other comprehensive income	—		—			—		(13		)
Reclassification from other comprehensive income	—		(46		)	—		(47		)
Ending balance	$	—	$	—		$	—	$	—

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 2020. These commodity derivatives consist of three-way collars, basis swaps and NYMEX roll basis swaps. 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, 2018 and the weighted average prices for those contracts:



Crude Oil	4Q 2018	FY 2019	FY 2020
Three-Way Collars
Volume (Bbls/day)	95,000	60,000	—
Weighted average price per Bbl:
Ceiling	$57.65	$73.18	—
Floor	$52.11	$56.67	—
Sold put	$45.21	$49.59	—
Basis Swaps ^(a)
Volume (Bbls/day)	10,000	10,000	15,000
Weighted average price per Bbl	$(0.67)	$(0.82)	$(0.94)
NYMEX Roll Basis Swaps
Volume (Bbls/day)	—	60,000	—
Weighted average price per Bbl	—	$0.38	—
Natural Gas
Three-Way Collars ^(b)
Volume (MMBtu/day)	160,000	—	—
Weighted average price per MMBtu:
Ceiling	$3.61	—	—
Floor	$3.00	—	—
Sold put	$2.50	—	—


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


^(b)	Subsequent to September 30, 2018, we entered into 100,000 MMBTU/day of three-way collars for January - March 2019 with a ceiling price of $3.75, a floor price of $3.00, and a sold put price of $2.50.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The mark-to-market impact and settlement of these commodity derivative instruments appears in net gain (loss) on commodity derivatives in our consolidated statements of income. The mark-to-market impact for the three and nine month periods ended September 30, 2018 was a gain of $19 million and a loss of $69 million compared to a loss of $56 million and gain of $64 million for the same respective periods in 2017. Net settlements of commodity derivative instruments for the three and nine month periods ended September 30, 2018 was a loss of $89 million and $255 million compared to a gain of $34 million and $51 million for the respective periods in 2017.

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, 2018 and December 31, 2017 by fair value hierarchy level.



	September 30, 2018
(In millions)	Level 1		Level 2			Level 3		Total
Derivative instruments, assets
Commodity ^(a)	$	19	$	—		$	—	$	19
Derivative instruments, assets	$	19	$	—		$	—	$	19
Derivative instruments, liabilities
Commodity ^(a)	$	—	$	(229	)	$	—	$	(229	)
Derivative instruments, liabilities	$	—	$	(229	)	$	—	$	(229	)


^(a)	Derivative instruments are recorded on a net basis in our consolidated balance sheet. See Note 13.



	December 31, 2017
(In millions)	Level 1			Level 2			Level 3		Total
Derivative instruments, assets
Derivative instruments, assets	$	—		$	—		$	—	$	—
Derivative instruments, liabilities
Commodity ^(a)	$	(20	)	$	(120	)	$	—	$	(140	)
Derivative instruments, liabilities	$	(20	)	$	(120	)	$	—	$	(140	)


^(a)	Derivative instruments are recorded on a net basis in our consolidated balance sheet. See Note 13.

Commodity derivatives include three-way collars, basis swaps and NYMEX roll basis swaps. These instruments are measured at fair value using either a Black-Scholes or a modified Black-Scholes Model. For basis swaps and NYMEX roll basis swaps, inputs to the models include only commodity prices and interest rates 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, 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 13 for additional discussion of the types of derivative instruments we used.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Fair Values - Goodwill

As of September 30, 2018, our consolidated balance sheet included goodwill of $97 million. Goodwill is tested for impairment on an annual basis, or between annual tests when events or changes in circumstances indicate the fair value may have been reduced below its carrying value. Goodwill is tested for impairment at the reporting unit level. Our reporting units are the same as our reporting segments, of which only International E&P includes goodwill. We first assess the qualitative factors in order to determine whether the fair value of our International E&P reporting unit is more likely than not less than its carrying amount. Certain qualitative factors used in our evaluation include, among other things, the results of the most recent quantitative assessment of the goodwill impairment test, macroeconomic conditions; industry and market conditions (including commodity prices and cost factors); overall financial performance; and other relevant entity-specific events. If, after considering these events and circumstances we determined that it is more likely than not the fair value of the International E&P reporting unit is less than its carrying amount, a quantitative goodwill test is performed.

During the second quarter of 2018, we performed our annual impairment test of goodwill using the qualitative assessment. Our qualitative assessment considered the significant excess fair value over carrying value in our most recent step 1 test (second quarter 2017) and noted a general improvement in the qualitative factors above. After assessing the totality of the qualitative factors which could have a positive or negative impact on goodwill, our assessment did not indicate that it is more likely than not that the fair value is less than its carrying value. As a result, we concluded that no impairment to goodwill was required for our International E&P reporting unit.

Fair Values – Nonrecurring

See Note 5 and Note 11 for detail on our fair values for nonrecurring items, such as impairments.

Fair Values – Financial Instruments

Our current assets and liabilities include financial instruments, the most significant of which are receivables, the current portion of 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, 2018 and December 31, 2017.



	September 30, 2018				December 31, 2017
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Current assets ^(a)	$	15	$	15	$	762	$	761
Other noncurrent assets	82		86		135		137
Total financial assets	$	97	$	101	$	897	$	898
Financial liabilities
Other current liabilities	$	32	$	46	$	32	$	43
Long-term debt, including current portion ^(b)	5,777		5,528		5,976		5,526
Deferred credits and other liabilities	97		92		110		103
Total financial liabilities	$	5,906	$	5,666	$	6,118	$	5,672


^(a)	December 31, 2017 fair value and carrying amounts included our two notes receivable relating to the sale of our Canadian business; both were paid during the first quarter of 2018, see Note 5 for further information.

^(b) Excludes capital leases and debt issuance costs.

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.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

All 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 our debt.

15. Debt

Revolving Credit Facility

As of September 30, 2018, we had no borrowings against our $3.4 billion revolving credit facility (the “Credit Facility”), as described below.

In October 2018, we extended the maturity date of our Credit Facility from May 28, 2021 to May 28, 2022. Fees on the unused commitment to the lenders, as well as the borrowing options under the Credit Facility, remain unaffected by the term extension. We retain the ability to request two 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, 2018, we were in compliance with this covenant with a debt-to-capitalization ratio of 31%.

Long-term debt

As of September 30, 2018 we had $5.5 billion in long-term debt outstanding, with our next debt maturity in the amount of $600 million due in 2020.

In the third quarter 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. 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

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 $46 million into earnings in the third quarter 2017. See Note 13 for further detail on our historical forward starting interest rate swaps.

16. Stockholders' Equity

In the third quarter of 2018 we acquired 16 million of common shares at a cost of $338 million under our share repurchase program. As of September 30, 2018 the total remaining share repurchase authorization was $1.2 billion. Purchases under the program are made at our discretion and may be in either open market transactions, including block purchases, or in privately negotiated transactions using cash on hand, cash generated from operations, proceeds from potential asset sales or cash from available borrowings to acquire shares. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. Shares repurchased as of September 30, 2018 were held as treasury stock.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

17. 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 2018:



	Stock Options					Restricted Stock Awards & Units
	Number of Shares			Weighted Average Exercise Price		Awards		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2017	10,330,776				$25.52	7,572,845			$14.24
Granted	856,890		^(a)		$14.52	4,741,961			$14.72
Options Exercised/Stock Vested	(1,756,797	)			$13.69	(2,783,504	)		$15.84
Canceled	(1,783,223	)			$30.27	(756,491	)		$14.03
Outstanding at September 30, 2018	7,647,646				$25.89	8,774,811			$14.01

^(a) The weighted average grant date fair value of stock option awards granted was $5.82 per share.

Stock-based performance unit awards

During the first nine months of 2018, we granted 754,140 stock-based performance units to certain officers. The grant date fair value per unit was $17.02.

18. 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)	2018			2017			2018			2017
Service cost	$	4		$	5		$	—		$	—
Interest cost	7			7			2			2
Expected return on plan assets	(9		)	(10		)	—			—
Amortization:
– prior service cost (credit)	(2		)	(3		)	(2		)	(2		)
– actuarial loss	3			3			—			—
Net settlement loss ^(a)	10			8			—			—
Net periodic benefit cost	$	13		$	10		$	—		$	—



	Nine Months Ended September 30,
	Pension Benefits						Other Benefits
(In millions)	2018			2017			2018			2017
Service cost	$	13		$	16		$	1		$	1
Interest cost	20			22			6			6
Expected return on plan assets	(26		)	(32		)	—			—
Amortization:
– prior service cost (credit)	(7		)	(7		)	(6		)	(5		)
– actuarial loss	9			7			1			—
Net settlement loss ^(a)	16			25			—			—
Net periodic benefit cost	$	25		$	31		$	2		$	2


^(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.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

During the first nine months of 2018, we recorded the effects of settlements of our U.S. pension plans. As required, we remeasured the plans’ assets and liabilities as of the applicable balance sheet dates. The cumulative effects of these events are included in the remeasurement and reflected in both the pension liability and net periodic benefit cost.

During the first nine months of 2018, we made contributions of $58 million to our funded pension plans and we expect to make additional contributions up to an estimated $6 million over the remainder of 2018. During the first nine months of 2018, we made payments of $12 million and $17 million related to unfunded pension plans and other postretirement benefit plans.

19. Reclassifications Out of Accumulated Other Comprehensive Income (Loss)

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



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2018			2017			2018			2017			Income Statement Line

Postretirement and postemployment plans
Amortization of prior service credit	$	4		$	5		$	13		$	12		Other net periodic benefit costs
Amortization of actuarial loss	(3		)	(3		)	(10		)	(7		)	Other net periodic benefit costs
Net settlement loss	(10		)	(8		)	(16		)	(25		)	Other net periodic benefit costs

Derivative hedges
Recognized gain on terminated derivative hedge	—			46			—			46			Net interest and other
Ineffective portion of derivative hedge	—			—			—			1			Net interest and other
	(9		)	40			(13		)	27			Income (loss) from continuing operations before income taxes
	—			(40		)	—			(40		)	(Provision) benefit for income taxes
Total reclassifications to expense, net of tax	(9		)	—			(13		)	(13		)	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	$	(9	)	$	—		$	(13	)	$	(43	)	Net income (loss)

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

20. Supplemental Cash Flow Information



	Nine Months Ended September 30,
(In millions)	2018			2017
Net cash used in operating activities:
Interest paid, net of amounts capitalized	$	(187	)	$	(269	)
Income taxes paid to taxing authorities	(298		)	(101		)
Noncash investing activities, related to continuing operations:
Increase (decrease) in asset retirement costs	$	12		$	(94	)
Asset retirement obligations assumed by buyer	82			14
Notes receivable for disposal of assets	—			745

Other noncash investing activities include accrued capital expenditures as of September 30, 2018 and 2017 of $238 million and $361 million.

21. Equity Method Investments

During the periods ended September 30, 2018 and December 31, 2017 our equity method investees were considered related parties and included:


•	EGHoldings, in which we have a 60% noncontrolling interest. EGHoldings is engaged in LNG production activity.

•Alba Plant LLC, in which we have a 52% noncontrolling interest. Alba Plant LLC processes LPG.


•	AMPCO, in which we have a 45% interest. AMPCO is engaged in methanol production activity.

Our equity method investments are summarized in the following table:



	Ownership as of	September 30,		December 31,
(In millions)	September 30, 2018	2018		2017
EGHoldings	60%	$	402	$	456
Alba Plant LLC	52%	170		214
AMPCO	45%	185		177
Total		$	757	$	847

Summarized financial information for equity method investees is as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2018		2017		2018		2017
Income data:
Revenues and other income	$	238	$	243	$	664	$	681
Income from operations	151		147		391		412
Net income	129		125		331		360

22. 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 the fourth quarter of 2017, we received notification from the U.K.’s First-tier Tribunal that the decommissioning cost deductions, which we had claimed, were not allowable. In accordance with U.K. regulations, in the fourth quarter of 2017, we paid the amount of tax and interest in question, approximately $108 million, prior to our appeal. As of October 2018 we no longer intend to progress our appeal against this decision and estimate that any revisions to current and deferred tax liabilities would have no cumulative adverse earnings impact on our consolidated results of operations.

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 have filed a Tax Court Petition in the fourth quarter of 2017. We believe that it is more likely than not that we will prevail.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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 offset by the prices we receive for 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, Europe and Africa. Total proved reserves were 1.4 billion boe at December 31, 2017, and total assets were $21.8 billion at September 30, 2018. During the third quarter 2018, we continued our outstanding operational execution across our multi-basin U.S. portfolio, maintained a strong balance sheet and delivered solid financial results.

Key highlights include the following:

Simplifying and concentrating our portfolio


•	In Northern Delaware we acquired 1,800 net acres in New Mexico for $105 million from the Bureau of Land Management lease sale, which is synergistic with our existing footprint in the resource play.


•	In July we closed on the sale of non-core, non-operated conventional assets in the U.S. E&P segment for a pre-tax gain of $32 million, including three in the Gulf of Mexico, further concentrating and simplifying our portfolio.


•	In August we closed on the previously announced sale of a non-core asset in the International E&P segment for a pre-tax loss of $18 million.


•	Resource play leasing and exploration capital expenditures totaled $46 million for the quarter and $294 million for the year, which were more than fully funded through the divestiture proceeds received in the first quarter 2018.

Strengthened balance sheet and liquidity


•	Reduced estimated cost of our U.K. asset retirement obligations by $125 million, primarily by accelerating abandonment timing to capture favorable market conditions.


•	In the first nine months of 2018, cash provided by operating activities from continuing operations increased by 60%, compared to the same period last year, to $2,379 million as a result of increased price realizations and increased net sales volumes in our U.S. resource plays.


•	Returned additional capital to shareholders by executing $500 million of share repurchases through October 31, 2018, including $338 million in third quarter 2018, with $1.0 billion of repurchase authorization remaining.


•	At the end of the third quarter 2018, we had approximately $5.0 billion of liquidity, comprised of $1.6 billion in cash and an undrawn $3.4 billion revolving credit facility.

Financial and operational results


•	Total net sales volumes for the quarter were 415 mboed, including 293 mboed in the U.S. resource plays. Our U.S. resource plays net sales volumes increased over 25% compared to the same quarter last year.


•	Wells to sales for the quarter increased 16% in the U.S. resource plays compared to the same quarter last year.


•	Our net income per share from continuing operations was $0.30 in the third quarter of 2018 as compared to a net loss per share of $0.70 in the same period last year. Included in net income results for the current quarter:


◦	An increase in revenues of approximately 35% to $1,538 million, compared to the same quarter last year, as a result of increased price realizations and increased net sales volumes in our U.S. resource plays.


◦	Net loss on commodity derivatives was $70 million compared to a net loss of $22 million in the same quarter last year due to the increases in current quarter index pricing as well as higher forecast long-term commodity prices.


◦	Total costs and expenses from operations decreased $380 million during the quarter compared to the same quarter last year primarily as a result of lower proved and unproved property impairments. See Note 11 for further detail.

Operations

The following table presents a summary of our sales volumes for each of our segments. Refer to the 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	2018	2017	Increase (Decrease)	2018	2017	Increase (Decrease)
United States E&P (mboed)	303	244	24%	296	225	32%
International E&P ^(a) (mboed)	112	165	(32)%	126	142	(11)%
Total continuing operations (mboed)	415	409	1%	422	367	15%


^(a)	We closed on the sale of our subsidiary, Marathon Oil Libya Limited, which held our 16.33% non-operated interest in the Waha concessions in Libya in the first quarter of 2018. Three months ended September 30, 2017 includes net sales volumes relating to Libya of 23 mboed. Nine months ended September 30, 2018 and 2017 includes net sales volumes relating to Libya of 10 mboed and 15 mboed.

United States E&P

Net sales volumes in the segment were higher in the third quarter 2018 primarily as a result of new wells to sales across all U.S. resource plays. 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	2018	2017	Increase (Decrease)	2018	2017	Increase (Decrease)
Equivalent Barrels (mboed)
Eagle Ford	115	101	14%	108	100	8%
Bakken	84	59	42%	81	52	56%
Oklahoma	73	58	26%	76	50	52%
Northern Delaware	21	9	133%	18	4	350%
Other United States ^(a)	10	17	(41)%	13	19	(32)%
Total United States E&P	303	244	24%	296	225	32%


^(a)	The three and nine months ended September 30, 2018 includes decreases of 8 mboed and 4 mboed, relating to the disposition of certain assets in the Gulf of Mexico and conventional assets in Oklahoma in July 2018 and September 2017 and Colorado in October 2017.



	Three Months Ended September 30, 2018
Sales Mix - U.S. Resource Plays	Eagle Ford	Bakken	Oklahoma	Northern Delaware	Total
Crude oil and condensate	57%	86%	24%	56%	57%
Natural gas liquids	23%	7%	28%	20%	20%
Natural gas	20%	7%	48%	24%	23%



	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Gross Operated - U.S. Resource Plays

Eagle Ford:
Wells drilled to total depth	26	43	93	141
Wells brought to sales	38	36	111	124
Bakken:
Wells drilled to total depth	20	27	63	72
Wells brought to sales	21	20	53	26
Oklahoma:
Wells drilled to total depth	14	27	37	65
Wells brought to sales	11	15	45	47
Northern Delaware:
Wells drilled to total depth	18	11	59	13
Wells brought to sales	18	5	40	7

•

Eagle Ford – Our net sales volumes were 115 mboed in the third quarter of 2018 which was 14% higher compared to the prior year quarter. We brought 38 gross company-operated wells sales in the quarter, including 12 wells to sales in the Atascosa County extended core. We continued to generate strong cash flow in the quarter through a combination of well performance and oil realizations above WTI due to strong LLS-based pricing.

•

Bakken – Our net sales volumes of 84 mboed represent a 42% increase over the prior year quarter of 59 mboed. We brought 21 gross company-operated wells to sales in the third quarter 2018 with continued impressive well results. Our basin leading performance continues with a six well pad in West Myrmidon achieving strong results, with three of these wells establishing new Three Forks Williston Basin records. We are in full compliance with state gas capture requirements, and anticipate no impact to forward development plans.

•

Oklahoma – Our net sales volumes in the third quarter 2018 increased by 26% from the year ago quarter, with net sales volumes of 73 mboed. We brought 11 gross company-operated wells to sales in the quarter which is consistent with our successful transition from leasehold drilling to primarily multi-well pad development. In the STACK, we brought on two Meramec overpressured pads at different equivalent well spacing that illustrate the consistency and predictability of optimized development at the drill spacing unit (DSU) level.

•

Northern Delaware – Our net sales volumes were 21 mboed in the third quarter 2018, while bringing 18 gross company-operated wells to sales in the Malaga and Red Hills areas. During the quarter we made important midstream advancements to protect flow assurance, improve realizations and reduce expenses. We executed a two-year term oil sales agreement with a strategic buyer at attractive terms and signed a gas gathering and processing agreement covering the vast majority of Lea and Eddy county acreage. Additionally, we continue to benefit from our Midland-Cushing basis swaps, with open positions that include 10,000 bopd hedged through the remainder of 2018 and all of 2019, and 15,000 bopd hedged for full-year 2020, all at a discount of less than $1 to WTI. See Note 13 to the consolidated financial statements for further information.

International E&P

Net sales volumes were lower in the third quarter of 2018 compared to the third quarter of 2017 primarily due to the sale of our subsidiary in Libya and timing of our liftings in E.G. and 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	2018	2017	Increase (Decrease)	2018	2017	Increase (Decrease)
Equivalent Barrels (mboed)
Equatorial Guinea	100	119	(16)%	99	109	(9)%
United Kingdom^(a)	9	20	(55)%	13	16	(19)%
Libya	—	23	(100)%	10	15	(33)%
Other International	3	3	—%	4	2	100%
Total International E&P	112	165	(32)%	126	142	(11)%
Equity Method Investees
LNG (mtd)	6,152	6,943	(11)%	5,947	6,447	(8)%
Methanol (mtd)	1,334	1,366	(2)%	1,282	1,285	—%
Condensate & LPG (boed)	11,942	17,216	(31)%	12,347	14,467	(15)%


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


•	Equatorial Guinea – Net sales volumes in the third quarter 2018 were lower compared to the same period in 2017 as a result of the timing of liftings and planned maintenance activities.


•	United Kingdom – Third quarter 2018 net sales volumes were lower compared to the third quarter of 2017 primarily due to the timing of liftings in the third quarter of 2018.


•	Libya – During the first quarter of 2018 we closed on the sale of our subsidiary in Libya, see Note 5 to the consolidated financial statements for further information.

Market Conditions

Crude oil and condensate and NGLs benchmarks increased in the third quarter and first nine months of 2018 as compared to the same period in 2017; as a result, we experienced increased price realizations associated with those benchmarks.

United States E&P

The following table presents our average price realizations and the related benchmarks for crude oil and condensate, NGLs and natural gas for the third quarter and first nine months of 2018 and 2017.



	Three Months Ended September 30,			Nine Months Ended September 30,
	2018	2017	Increase (Decrease)	2018	2017	Increase (Decrease)
Average Price Realizations ^(a)
Crude oil and condensate (per bbl) ^(b)	$68.51	$46.65	47%	$65.66	$46.93	40%
Natural gas liquids (per bbl)	28.07	20.86	35%	24.47	19.32	27%
Natural gas (per mcf) ^(c)	2.55	2.71	(6)%	2.44	2.91	(16)%
Benchmarks
WTI crude oil average of daily prices (per bbl)	$69.43	$48.20	44%	$66.79	$49.36	35%
LLS crude oil average of daily prices (per bbl)	75.10	51.61	46%	71.19	51.72	38%
Mont Belvieu NGLs (per bbl)^(d)	33.30	23.91	39%	29.30	22.61	30%
Henry Hub natural gas settlement date average (per mmbtu)	2.90	3.00	(3)%	2.90	3.17	(9)%


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


^(b)	Inclusion of realized gains (losses) on crude oil derivative instruments would have increased (decreased) crude oil and condensate average price realizations by $(5.70) per bbl and $2.42 per bbl for the third quarter 2018 and 2017 and $(5.71) and $1.35 per bbl for the first nine months of 2018 and 2017.


^(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 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 2018 and 2017.



	Three Months Ended September 30,			Nine Months Ended September 30,
	2018	2017	Increase (Decrease)	2018	2017	Increase (Decrease)
Average Price Realizations
Crude oil and condensate (per bbl)	$64.08	$51.23	25%	$65.71	$49.81	32%
Natural gas liquids (per bbl)	2.04	2.25	(9)%	2.28	2.63	(13)%
Natural gas (per mcf)	0.50	0.51	(2)%	0.56	0.54	4%
Benchmark
Brent (Europe) crude oil (per bbl) ^(a)	$75.22	$52.11	44%	$72.18	$51.82	39%


^(a)	Average of monthly prices obtained from the United States Energy Information Agency website.

United Kingdom

Crude oil and condensate – Our production is generally sold in relation to the Brent crude benchmark.

Equatorial Guinea

Crude oil and condensate – Our production from the Alba Field is primarily condensate and generally sold in relation to the Brent crude benchmark. The Alba Plant processes the rich hydrocarbon gas which is supplied by the Alba Field under a fixed price long term contract. The Alba Plant extracts NGL’s and secondary condensate which is sold by Alba Plant at market prices, with our share of the revenue reflected in the income from equity method investments on the consolidated statements of income.

Natural gas liquids – Wet gas is sold to Alba Plant at a fixed-price term contact resulting in realized prices not fully tracking market price. Alba Plant extracts NGLs, which are sold at market price, with our share of income from Alba Plant being reflected in the income from equity method investments on the consolidated statements of income.

Natural gas – Dry natural gas is sold to EG Holdings and AMPCO at fixed-price long term contracts resulting in realized prices not fully tracking market price. We derive additional value from the equity investment in our downstream gas processing units EG LNG and AMPCO that market LNG and Methanol respectively at market prices.

Results of Operations

Three Months Ended September 30, 2018 vs. Three Months Ended September 30, 2017

Revenues from contracts with customers are presented by segment in the table below:



	Three Months Ended September 30,
(In millions)	2018		2017
Revenues from contracts with customers
United States E&P	$	1,347	$	772
International E&P	191		364
Segment revenues from contracts with customers	$	1,538	$	1,136

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.



			Increase (Decrease) Related to
(In millions)	Three Months Ended September 30, 2017		Price Realizations			Net Sales Volumes			Three Months Ended September 30, 2018
United States E&P Price-Volume Analysis
Crude oil and condensate	$	596	$	348		$	146		$	1,090
Natural gas liquids	84		39			29			152
Natural gas	92		(6		)	16			102
Other sales	—								3
Total	$	772							$	1,347
International E&P Price-Volume Analysis
Crude oil and condensate	$	322	$	32		$	(193	)	$	161
Natural gas liquids	3		(1		)	—			2
Natural gas	23		—			(3		)	20
Other sales	16								8
Total	$	364							$	191

Net loss on commodity derivatives increased $48 million in the third quarter of 2018 compared to the same period in 2017. We have multiple crude oil and natural gas derivative contracts indexed to NYMEX WTI and Henry Hub. We record commodity derivative gains/losses as the index pricing and forward curves change each period. See Note 13 to the consolidated financial statements for further information.

Marketing revenues decreased $48 million in the third quarter of 2018 from the comparable 2017 period. This decrease is the result of adopting the new revenue standard, ASC Topic 606, Revenue from Contracts with Customers during the first quarter of 2018. As a result of this standard, we have changed our presentation of marketing revenues and marketing expenses from the historical gross presentation to a net presentation. See Note 2 to the consolidated financial statements for further information.

Other income increased $111 million in the third quarter of 2018 primarily as a result of the reduction of our U.K. asset retirement obligation. See Note 12 for discussion of the asset retirement obligation in further detail.

Production expenses increased $18 million in the third quarter of 2018 versus the same period in 2017 primarily due to higher sales volumes across our U.S. E&P segment. United States E&P increased $51 million primarily due to new wells to sales across all U.S. resource plays. International E&P decreased $33 million primarily as a result of lower U.K. and E.G. liftings during the third quarter 2018 and as a result of the sale of our subsidiary in Libya in the first quarter 2018.

The third quarter of 2018 production expense rate (expense per boe) for United States E&P was higher primarily due to higher costs as a result of increased activity in our developing Northern Delaware asset. The expense rate for International E&P decreased due to timing of our U.K. and E.G. liftings.

The following table provides production expense rates for each segment:



	Three Months Ended September 30,
($ per boe)	2018		2017
Production Expense Rate
United States E&P		$6.14		$5.38
International E&P		$4.22		$4.98

Marketing costs decreased $49 million in the third quarter of 2018 from the comparable 2017 period. This decrease is the result of adopting the new revenue standard, ASC Topic 606, Revenue from Contracts with Customers during the first quarter of 2018. As a result of this standard, we have changed our presentation of marketing revenues and marketing expenses from the historical gross presentation to a net presentation. See Note 2 to the consolidated financial statements for further information.

Shipping, handling and other operating expenses increased $43 million in the third quarter of 2018 primarily as a result of increased sales volumes in our United States E&P segment.

Exploration expenses include unproved property impairments, dry well costs, geological and geophysical, and other, which decreased $238 million in the third quarter of 2018. The decrease was primarily due to impairments in third quarter 2017 totaling $159 million as a result of anticipated sales and lower forecasted long-term commodity prices in our International E&P segment. Additionally, our decision not to develop the Tchicuate offshore Block in the Republic of Gabon resulted in an increase to other exploration expenses of $43 million during the third quarter of 2017. See Note 11 for discussion of the impairments in further detail.

The following table summarizes the components of exploration expenses:



	Three Months Ended September 30,
(In millions)	2018			2017
Exploration Expenses
Unproved property impairments	$	50		$	172
Dry well costs	1			77
Geological and geophysical	(1		)	2
Other	6			43
Total exploration expenses	$	56		$	294

Depreciation, depletion and amortization decreased $15 million in the third quarter of 2018. United States E&P DD&A expense increased by $40 million primarily due to higher sales volumes across all U.S. resource plays. In our International E&P segment, we had a decrease of $53 million primarily due to the timing of U.K. liftings and the sale of non-core properties in 2018, both contributing to decreased net sales volumes during the current period. 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 impact our DD&A. Our United States E&P DD&A rate decreased in the third quarter of 2018 primarily due to an increase in proved developed reserves in our U.S. resource plays in late 2017; as well as the sale of non-operated conventional assets in the United States E&P, including two in the Gulf of Mexico this year. The DD&A rate for our International E&P decreased as a result of the reduction of our estimated U.K. asset retirement costs in the second half of 2017.

The following table provides DD&A rates for each segment:



	Three Months Ended September 30,
($ per boe)	2018		2017
DD&A Rate
United States E&P		$20.47		$23.64
International E&P		$4.71		$6.68

Impairments decreased $193 million in the third quarter of 2018. This decrease was primarily a result of third quarter 2017 proved property impairments as follows: $136 million in certain non-core properties in our International E&P segment as a result of anticipated sales and lower forecasted long-term commodity prices; and $65 million relating to certain properties in the Gulf of Mexico as a result of lower forecasted long-term commodity prices. See Note 11 for discussion of the impairments in further detail.

Taxes other than income includes production, severance, and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. U.S. sales volumes and revenues increased during the third quarter of 2018, which resulted in an increase of $42 million versus the same period in 2017.

The following table summarizes the components of taxes other than income:



	Three Months Ended September 30,
(In millions)	2018		2017
Taxes other than income
Production and severance	$	61	$	32
Ad valorem	5		3
Other	20		9
Total taxes other than income	$	86	$	44

General and administrative increased $12 million in the third quarter of 2018 versus the same period in 2017. This was primarily the result of improved performance of stock-based performance units tied to our stock price and total shareholder return ("TSR") as compared to our peer group.

Net interest and other increased $23 million in the third quarter of 2018 versus the same period in 2017. This increase was primarily due to the termination of our forward starting interest rate swaps in the third quarter of 2017, which resulted in a gain of $46 million. See Note 13 to the consolidated financial statements for further detail.

Loss on early extinguishment of debt decreased $46 million in the third quarter of 2018, primarily due to make-whole call provisions paid upon redemption of $1.76 billion in senior unsecured notes in the third quarter of 2017. See Note 15 to the consolidated financial statements for further detail.

Provision (benefit) for income taxes reflects an effective tax rate from continuing operations of 29% in the third quarter of 2018, as compared to an effective tax rate of 31% in the third quarter of 2017. See Note 8 to the consolidated financial statements for more detail discussion concerning the rate changes.

Discontinued operations are presented net of tax. See Note 5 to the consolidated financial statements for financial information concerning our discontinued operations.

Segment Income (Loss)

Segment income (loss) represents income (loss) from continuing operations excluding certain items not allocated to operating segments, net of income taxes. A portion of our corporate and operations general and administrative support 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 (as determined by the CODM) are not allocated to operating segments.

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



	Three Months Ended September 30,
(In millions)	2018			2017
United States E&P	$	201		$	(38	)
International E&P	116			104
Segment income (loss)	317			66
Items not allocated to segments, net of income taxes	(63		)	(665		)
Income (loss) from continuing operations	254			(599		)
Net income (loss)	$	254		$	(599	)

United States E&P segment income increased $239 million after-tax in the third quarter of 2018 primarily due to higher price realizations and an increase in net sales volumes, which resulted in increased revenues. This increase in net sales volumes resulted in a corresponding increase to production expenses, DD&A, taxes other than income, and shipping, handling and other operating expenses which partially offset the increase to revenues.

International E&P segment income increased $12 million after-tax in the third quarter of 2018 primarily due to higher price realizations partially offset by a decrease in net sales volumes. This decrease in net sales volumes resulted in lower production and DD&A expense. Additionally, our income tax provision decreased as a result of the sale of our Libya subsidiary in the first quarter of 2018, see Note 5 to the consolidated financial statements for further information.

Results of Operations

Nine Months Ended September 30, 2018 vs. Nine Months Ended September 30, 2017

Revenues from contracts with customers are presented by segment in the table below:



	Nine Months Ended September 30,
(In millions)	2018		2017
Revenues from contracts with customers
United States E&P	$	3,693	$	2,124
International E&P	829		787
Segment revenues from contracts with customers	$	4,522	$	2,911



			Increase (Decrease) Related to
(In millions)	Nine Months Ended September 30, 2017		Price Realizations			Net Sales Volumes			Nine Months Ended September 30, 2018
United States E&P Price-Volume Analysis
Crude oil and condensate	$	1,635	$	862		$	525		$	3,022
Natural gas liquids	217		78			75			370
Natural gas	269		(56		)	73			286
Other sales	3								15
Total	$	2,124							$	3,693
International E&P Price-Volume Analysis
Crude oil and condensate	$	675	$	176		$	(121	)	$	730
Natural gas liquids	9		(1		)	(1		)	7
Natural gas	71		2			(5		)	68
Other sales	32								24
Total	$	787							$	829

Net loss on commodity derivatives increased $439 million in the first nine months of 2018 compared to the same period in 2017. We have multiple crude oil and natural gas derivative contracts indexed to NYMEX WTI and Henry Hub. We record commodity derivative gains/losses as the index pricing changes from period to period. See Note 13 to the consolidated financial statements for further information.

Marketing revenues for the first nine months of 2018 decreased by $117 million from the comparable 2017 period. This decrease is the result of adopting the new revenue standard, ASC Topic 606, Revenue from Contracts with Customers during the first quarter of 2018. As a result of this standard, we have changed our presentation of marketing revenues and marketing expenses from the historical gross presentation to a net presentation. See Note 2 to the consolidated financial statements for further information.

Income from equity method investments decreased $22 million for the first nine months of 2018 from the comparable 2017 period. This decrease is the result of lower volumes at our Equatorial Guinea LNG production facility primarily driven by planned maintenance activities during the first quarter 2018.

Net gain on disposal of assets increased $297 million for the first nine months of 2018 primarily related to the gain on sale of our subsidiary Marathon Oil Libya Limited, which holds a 16.33% non-operated interest in the Waha concessions in Libya, during the first quarter of 2018. See Note 5 to the consolidated financial statements for information about dispositions.

Other income increased $104 million in the first nine months of 2018 primarily as a result of the reduction of our U.K. asset retirement obligation in the third quarter of 2018. See Note 12 for discussion of the asset retirement obligation in further detail.

Production expenses for the first nine months of 2018 increased by $109 million compared to the same period in 2017. United States E&P increased $128 million primarily due to new wells to sales across all U.S. resource plays. International E&P decreased $18 million primarily due to the sale of our subsidiary in Libya in the first quarter 2018.

The following table provides production expense rates for each segment:



	Nine Months Ended September 30,
($ per boe)	2018		2017
Production Expense Rate
United States E&P		$5.90		$5.66
International E&P		$4.70		$4.63

Marketing costs decreased $121 million in the first nine months of 2018 from the comparable 2017 period. This decrease is the result of adopting the new revenue standard, ASC Topic 606, Revenue from Contracts with Customers during the first quarter of 2018. As a result of this standard, we have changed our presentation of marketing revenues and marketing expenses from the historical gross presentation to a net presentation. See Note 2 to the consolidated financial statements for further information.

Shipping, handling and other operating expenses increased $99 million in the first nine months of 2018 from the comparable 2017 period, primarily due to an increase in our shipping and handling expenses as a result of increased sales volumes in our United States E&P segment.

Exploration expenses include unproved property impairments, dry well costs, geological and geophysical, and other, which decreased $179 million in the first nine months of 2018. The decrease was primarily due to impairments in third quarter 2017 totaling $159 million as a result of anticipated sales and lower forecasted long-term commodity prices in our International E&P segment. Additionally, our decision not to develop the Tchicuate offshore Block in the Republic of Gabon resulted in an increase to other exploration expenses of $43 million during the third quarter of 2017. See Note 11 for discussion of the impairments in further detail.

The following table summarizes the components of exploration expenses:



	Nine Months Ended September 30,
(In millions)	2018		2017
Exploration Expenses
Unproved property impairments	$	131	$	217
Dry well costs	13		77
Geological and geophysical	13		3
Other	16		55
Total exploration expenses	$	173	$	352

Depreciation, depletion and amortization increased $39 million in the first nine months of 2018 from the comparable 2017 period primarily as a result of an increase of $157 million in the United States E&P segment primarily due to higher sales volumes across all U.S. resource plays. Offsetting this higher expense was a decrease of $113 million in our International E&P segment primarily due to the timing of our U.K. liftings, which resulted in decreased sales volumes during the third quarter 2018. Additionally, asset sales in 2018 and the reduction in U.K. asset retirement costs during the third quarter of 2017 contributed to the decrease in expense. 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 the United States E&P segment decreased primarily due to increased proved developed reserves in our U.S. resource plays in late 2017; as well as reduced capitalized costs relating to the Gulf of Mexico non-cash impairment charge in 2017 and the sale of these assets in 2018. The DD&A rate for International E&P decreased with the reduction of our estimated U.K. asset retirement costs in the second half of 2017.

The following table provides DD&A rates for each segment:



	Nine Months Ended September 30,
($ per boe)	2018		2017
DD&A Rate
United States E&P		$20.53		$24.38
International E&P		$4.43		$6.83

Impairments decreased $155 million in the first nine months of 2018. This decrease was primarily the result of the following third quarter 2017 proved property impairments: $136 million in certain non-core properties in our International E&P segment as a result of anticipated sales and lower forecasted long-term commodity prices; and $65 million relating to certain properties in the Gulf of Mexico as a result of lower forecasted long-term commodity prices. See Note 11 for discussion of the impairments in further detail.

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. U.S. sales volumes and revenues increased in the first nine months of 2018 which resulted in an increase of $87 million versus the comparable 2017 period.

The following table summarizes the components of taxes other than income:



	Nine Months Ended September 30,
(In millions)	2018		2017
Taxes other than income
Production and severance	$	153	$	79
Ad valorem	16		8
Other	46		41
Total taxes other than income	$	215	$	128

General and administrative expenses increased $30 million in the first nine months of 2018 compared to the same period in 2017. This was primarily the result of improved performance of stock-based performance units tied to our stock price and total shareholder return ("TSR") as compared to our peer group.

Net interest and other decreased $31 million in the first nine months of 2018 versus the same period in 2017. This decrease was primarily due to the redemption of approximately $1.76 billion of debt during 2017. See Note 15 to the consolidated financial statements for further detail.

Loss on early extinguishment of debt decreased $46 million in the first nine months of 2018, primarily due to make-whole call provisions paid upon redemption of $1.76 billion in senior unsecured notes in the third quarter of 2017. See Note 15 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 first nine months of 2018, as compared to an effective tax rate of 37% from the comparable 2017 period. See Note 8 to the consolidated financial statements for more detail discussion concerning the rate changes.

Discontinued operations are presented net of tax. See Note 5 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)	2018			2017
United States E&P	$	449		$	(224	)
International E&P	390			256
Segment income (loss)	839			32
Items not allocated to segments, net of income taxes	(133		)	(834		)
Income (loss) from continuing operations	706			(802		)
Income (loss) from discontinued operations ^(a)	—			(4,893		)
Net income (loss)	$	706		$	(5,695	)

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

United States E&P segment income increased $673 million after-tax in the first nine months of 2018 from the comparable 2017 period primarily due to higher price realizations and an increase in net sales volumes. Partially offsetting this increase was the loss related to commodity derivative positions in the first nine months of 2018, as well as increased expenses such as DD&A, production expenses, taxes other than income and shipping, handling and other operating expenses which increase along with sales volumes. Additionally, exploration expense increased as a result of leases that we decided not to drill or extend with near-term expirations and as a result of increasing the number of leases in our portfolio through acquisition.

International E&P segment income increased $134 million after-tax in the first nine months of 2018 from the comparable 2017 period primarily due to higher price realizations which was partially offset by lower net sales volumes. Additionally, DD&A expense decreased in the first nine months of 2018 as a result of lower sales volumes, a reduction to U.K. asset retirement costs during the third quarter of 2017 and the sale of assets in 2018.

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, 2017, 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 2018 we made revisions to these estimates and reduced our U.K. recognized liability by $125 million. This downward revision was primarily due to changes in the estimated costs and timing of abandonment activities. See Note 12 to the consolidated financial statements for further information.

Fair Value Estimates - Goodwill

As of September 30, 2018, our consolidated balance sheet included goodwill of $97 million. Goodwill is tested for impairment on an annual basis, or between annual tests when events or changes in circumstances indicate the fair value may have been reduced below its carrying value. Goodwill is tested for impairment at the reporting unit level. Our reporting units are the same as our reporting segments, of which only International E&P includes goodwill. We first assess the qualitative factors in order to determine whether the fair value of our International E&P reporting unit is more likely than not less than its carrying amount. Certain qualitative factors used in our evaluation include, among other things, the results of the most recent quantitative assessment of the goodwill impairment test, macroeconomic conditions; industry and market conditions (including commodity prices and cost factors); overall financial performance; and other relevant entity-specific events. If, after considering these events and circumstances we determine that it is more likely than not the fair value of the International E&P reporting unit is less than its carrying amount, the quantitative goodwill test is performed.

See Note 14 to the consolidated financial statements for further information regarding our annual goodwill impairment test.

Fair Value Estimates - Impairment Assessments of Long-Lived Assets

Due to the anticipated sales of certain non-core proved properties in our International and United States E&P segments we assessed certain non-core long-lived assets for impairment. The fair values were measured using the market approach based upon anticipated sales proceeds less costs to sell, resulting in impairments of $50 million during the first nine months of 2018. See Note 11 to the consolidated financial statements for further impairment 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 from continuing operations:



	Nine Months Ended September 30,
(In millions)	2018			2017
Sources of cash and cash equivalents
Operating activities - continuing operations	$	2,379		$	1,487
Disposal of assets, net of cash transferred to buyer	1,249			1,757
Borrowings	—			988
Other	81			52
Total sources of cash and cash equivalents	$	3,709		$	4,284
Uses of cash and cash equivalents
Additions to property, plant and equipment	$	(2,069	)	$	(1,305	)
Additions to other assets	(135		)	(23		)
Acquisitions, net of cash acquired	(25		)	(1,828		)
Debt repayments	—			(1,764		)
Debt extinguishment costs	—			(46		)
Dividends paid	(128		)	(128		)
Purchases of common stock	(349		)	(10		)
Other	(2		)	(3		)
Total uses of cash and cash equivalents	$	(2,708	)	$	(5,107	)

Cash flows generated from operating activities in the first nine months of 2018 were 60% higher as both commodity price realizations and net sales volumes improved compared to the first nine months of 2017. Consolidated average crude oil and condensate price realizations increased by approximately 38% and net sales volumes increased 15% during the first nine months of 2018 as compared to the prior period.

Proceeds from the disposals of assets for the first nine months of 2018 are primarily related to our non-operated interest in Libya as well as the remaining proceeds of $750 million from our Canadian business (sold in 2017). Proceeds from the disposal of assets for the first nine months of 2017 are a result of the disposal of our Canadian business. See Note 5 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 15 to the consolidated financial statements for further detail.

Additions to property, plant and equipment in the first nine months of 2018 were consistent with expectations relative to our $2.3 billion Development 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)	2018		2017
United States E&P	$	1,943	$	1,465
International E&P	28		27
Corporate	17		20
Total capital expenditures	1,988		1,512
Change in capital expenditure accrual	81		(207		)
Total use of cash and cash equivalents for property, plant and equipment	$	2,069	$	1,305

Additions to other assets relates to deposits on our resource play leasing and exploration and $105 million relating to our Northern Delaware leases acquired from the Bureau of Land Management. During the first nine months of 2018 our resource play leasing and exploration capital expenditures totaled $294 million, inclusive of costs included within property, plant and equipment, other assets, acquisitions and exploration expense.

In the second quarter of 2017 we closed on two acquisitions relating to our Northern Delaware assets for a purchase price of $1.8 billion. See Note 4 to the consolidated financial statements for further information concerning dispositions.

During the third quarter of 2017 we used the net proceeds of the borrowings (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. See Note 15 to the consolidated financial statements for further detail.

The Board of Directors approved a $0.05 per share dividend for the second quarter of 2018, which was paid in the third quarter of 2018. See Capital Requirements below for additional information about the third quarter dividend.

In the third quarter of 2018 we acquired 16 million of common shares at a cost of $338 million under our share repurchase program, shares purchased were held as treasury stock. See Note 16 to the consolidated financial statements for further detail.

Liquidity and Capital Resources

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, 2018, we had approximately $5 billion of liquidity consisting of $1.6 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 as of September 30, 2018 are: Standard & Poor's Ratings Services BBB- (positive); Fitch Ratings BBB (stable); and Moody's Investor Services, Inc. Ba1 (positive). 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, 2017 for a discussion of how a further downgrade in our credit ratings could affect us.

Capital Resources

Credit Arrangements and Borrowings

At September 30, 2018, we had no borrowings against our revolving credit facility.

At September 30, 2018, we had $5.5 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 2018, we entered into an agreement to sell a non-core property in our International E&P segment for proceeds of $56 million, before closing adjustments. We expect this transaction to close by year-end.

Debt-To-Capital Ratio

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 the fiscal quarter. Our debt-to-capital ratio was 31% at September 30, 2018, compared to 32% at December 31, 2017.



	September 30,			December 31,
(In millions)	2018			2017
Long-term debt due within one year	$	—		$	—
Long-term debt	5,498			5,494
Total debt	$	5,498		$	5,494
Equity	$	12,044		$	11,708
Calculation:
Total debt	$	5,498		$	5,494
Total debt plus equity (total capitalization)	$	17,542		$	17,202
Debt-to-capital ratio	31		%	32		%

Capital Requirements

Other Expected Cash Outflows

On October 30, 2018, our Board of Directors approved a dividend of $0.05 per share for the third quarter of 2018 payable December 10, 2018 to stockholders of record at the close of business on November 21, 2018.

As of September 30, 2018, we plan to make contributions of up to $6 million to our funded pension plans during the remainder of 2018.

Contractual Cash Obligations

As of September 30, 2018, there are no material changes to our consolidated cash obligations to make future payments under existing contracts, as disclosed in our 2017 Annual Report on Form 10-K.

Environmental Matters and Other Contingencies

There have been no significant changes to the environmental, health and safety matters under Item 1. Business or Item 3. Legal Proceedings in our 2017 Annual Report on Form 10-K. See Note 22 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 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;


•	liability resulting from litigation;


•	capital available for exploration and development;


•	the inability of any party to satisfy closing conditions or delays in execution with respect to our asset acquisitions and dispositions;


•	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 2017 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

We are exposed to market risks in the normal course of business including commodity price risk and interest rate risk. We employ various strategies, including the use of financial derivatives to manage the risks related to commodity price fluctuations. See Note 13 and Note 14 to the consolidated financial statements for detail relating to our open commodity 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 As of September 30, 2018, we had various open commodity derivatives related to crude oil and natural gas with a net liability position of $210 million. Based on the September 30, 2018 published NYMEX WTI and Henry Hub futures prices, a hypothetical 10% change (per bbl for crude oil and per MMBtu for natural gas) increases (decreases) the fair values of our net commodity derivative open positions as follows:



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

Crude oil derivatives	$	(156	)	$	130
Natural gas derivatives	(1		)	2
Total	$	(157	)	$	132

Interest Rate Risk At September 30, 2018 our portfolio of long-term debt is comprised of fixed-rate instruments with an outstanding balance of $5.5 billion. Our sensitivity to interest rate movements and corresponding changes in the fair value of our fixed-rate debt portfolio affects our results of operations and cash flows only when we elect to repurchase or otherwise retire fixed-rate debt at prices different than carrying value.

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, 2018.

During the first nine months of 2018, 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

There have been no significant changes to Item 3. Legal Proceedings in our 2017 Annual Report on Form 10-K. See Note 22 to the consolidated financial statements included in Part I, Item I for a description of such legal and administrative proceedings.

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. There have been no material changes to the risk factors under Item 1A. Risk Factors in our 2017 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, 2018.



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)
07/01/2018 - 07/31/2018	5,665	$20.66	—	$	1,500,285,529
08/01/2018 - 08/31/2018	628	$20.33	11,136,297	$	1,273,881,559
09/01/2018 - 09/30/2018	—	$21.29	5,258,025	$	1,161,947,007
Total	6,293	$20.64	16,394,322


^(a)	6,293 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.

As of September 30, 2018, we have repurchased 137 million common shares at a cost of approximately $5.0 billion. Purchases under the program are made at our discretion and may be in either open market transactions, including block purchases, or in privately negotiated transactions using cash on hand, cash generated from operations, proceeds from potential asset sales or cash from available borrowings to acquire shares. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. Shares repurchased as of September 30, 2018 were held as treasury stock.

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 8, 2018		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	8-K	3.1	6/1/2018
3.2	Marathon Oil Corporation By-laws (amended and restated as of February 24, 2016)	10-Q	3.2	8/4/2016
3.3	Specimen of Common Stock Certificate	10-K	3.3	2/28/2014
4.1	Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the SEC upon its request.	10-K	4.2	2/28/2014
10.1	Third Amendment, dated as of October 18, 2018, to the Amended and Restated Credit Agreement dated as of May 28, 2014, as amended by the First Amendment dated as of May 5, 2015 and the Second Amendment dated as of June 22, 2017 and as supplemented by the Incremental Commitments Supplement dated as of March 4, 2016 and Incremental Commitments Supplement dated as July 11, 2017, among Marathon Oil Corporation, as borrower, the lenders party thereto, Mizuho Bank, Ltd, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, and JPMorgan Chase Bank, N.A., as administrative agent	8-K	99.1	10/22/2018
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.