Edgar Filing: MARATHON OIL CORP

Three Months Ended March 31,

Effective income tax expense (benefit) rate from continuing operations

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 March 31, 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

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



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

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

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

There were 853,194,016 shares of Marathon Oil Corporation common stock outstanding as of April 30, 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
	Notes to Consolidated Financial Statements (Unaudited)	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	37
Item 4.	Controls and Procedures	38
Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	39
Item 1A.	Risk Factors	39
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
Item 6.	Exhibits	39
	Signatures	40

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)



	Three Months Ended
	March 31,
(In millions, except per share data)	2018			2017
Revenues and other income:
Revenues from contracts with customers	$	1,537		$	873
Net gain (loss) on commodity derivatives	(102		)	81
Marketing revenues	—			34
Income from equity method investments	37			69
Net gain (loss) on disposal of assets	257			1
Other income	4			14
Total revenues and other income	1,733			1,072
Costs and expenses:
Production	217			153
Marketing, including purchases from related parties	—			34
Other operating	130			89
Exploration	52			28
Depreciation, depletion and amortization	590			556
Impairments	8			4
Taxes other than income	64			39
General and administrative	100			97
Total costs and expenses	1,161			1,000
Income (loss) from operations	572			72
Net interest and other	(45		)	(78		)
Other net periodic benefit costs	(3		)	(10		)
Income (loss) from continuing operations before income taxes	524			(16		)
Provision (benefit) for income taxes	168			34
Income (loss) from continuing operations	356			(50		)
Income (loss) from discontinued operations	—			(4,907		)
Net income (loss)	$	356		$	(4,957	)
Per basic share:
Income (loss) from continuing operations	$	0.42		$	(0.06	)
Income (loss) from discontinued operations	$	—		$	(5.78	)
Net income (loss)	$	0.42		$	(5.84	)
Per diluted share:
Income (loss) from continuing operations	$	0.42		$	(0.06	)
Income (loss) from discontinued operations	$	—		$	(5.78	)
Net income (loss)	$	0.42		$	(5.84	)
Dividends per share	$	0.05		$	0.05
Weighted average common shares outstanding:
Basic	851			849
Diluted	852			849

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

MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income (Unaudited)



	Three Months Ended
	March 31,
(In millions)	2018		2017
Net income (loss)	$	356	$	(4,957	)
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	4		4
Income tax provision	—		—
Postretirement and postemployment plans, net of tax	4		4
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
Other comprehensive income (loss)	4		35
Comprehensive income (loss)	$	360	$	(4,922	)

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)



	March 31,			December 31,
(In millions, except per share data)	2018			2017
Assets
Current assets:
Cash and cash equivalents	$	1,613		$	563
Receivables, less reserve of $9 and $12	1,100			1,082
Notes receivable	—			748
Inventories	110			126
Other current assets	66			36
Current assets held for sale	13			11
Total current assets	2,902			2,566
Equity method investments	806			847
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $21,872 and $21,564	16,931			17,665
Goodwill	98			115
Other noncurrent assets	849			764
Noncurrent assets held for sale	48			55
Total assets	$	21,634		$	22,012
Liabilities
Current liabilities:
Accounts payable	$	1,335		$	1,395
Payroll and benefits payable	85			108
Accrued taxes	128			177
Other current liabilities	359			288
Current liabilities held for sale	2			—
Total current liabilities	1,909			1,968
Long-term debt	5,495			5,494
Deferred tax liabilities	221			833
Defined benefit postretirement plan obligations	331			362
Asset retirement obligations	1,445			1,428
Deferred credits and other liabilities	197			217
Noncurrent liabilities held for sale	2			2
Total liabilities	9,600			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, 1.1 billion shares authorized)	937			937
Held in treasury, at cost – 84 million and 87 million shares	(3,175		)	(3,325		)
Additional paid-in capital	7,237			7,379
Retained earnings	7,093			6,779
Accumulated other comprehensive loss	(58		)	(62		)
Total stockholders' equity	12,034			11,708
Total liabilities and stockholders' equity	$	21,634		$	22,012

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)



	Three Months Ended
	March 31,
(In millions)	2018			2017
Operating activities:
Net income (loss)	$	356		$	(4,957	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations	—			4,907
Depreciation, depletion and amortization	590			556
Impairments	8			4
Exploratory dry well costs and unproved property impairments	42			20
Net (gain) loss on disposal of assets	(257		)	(1		)
Deferred income taxes	(31		)	14
Net (gain) loss on derivative instruments	102			(77		)
Net settlements of derivative instruments	(59		)	(7		)
Stock based compensation	14			14
Equity method investments, net	32			13
Changes in:
Current receivables	(130		)	(1		)
Inventories	(9		)	(10		)
Current accounts payable and accrued liabilities	81			(1		)
All other operating, net	(90		)	27
Net cash provided by operating activities from continuing operations	649			501
Investing activities:
Additions to property, plant and equipment	(662		)	(283		)
Acquisitions, net of cash acquired	(4		)	—
Deposits for acquisitions	—			(180		)
Disposal of assets, net of cash transferred to buyer	1,180			—
Equity method investments - return of capital	9			12
All other investing, net	(74		)	1
Net cash provided by (used in) investing activities from continuing operations	449			(450		)
Financing activities:
Purchases of common stock	(9		)	(7		)
Dividends paid	(42		)	(42		)
All other financing, net	2			(1		)
Net cash provided by (used in) financing activities	(49		)	(50		)
Cash flow from discontinued operations:
Operating activities	—			95
Investing activities	—			(9		)
Changes in cash included in current assets held for sale	—			(86		)
Net increase in cash and cash equivalents of discontinued operations	—			—
Effect of exchange rate on cash and cash equivalents	1			1
Net increase (decrease) in cash and cash equivalents	1,050			2
Cash and cash equivalents at beginning of period	563			2,488
Cash and cash equivalents at end of period	$	1,613		$	2,490

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 first quarter 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 the 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 revenue from contracts with customers line item and 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.

As a result of adoption of this standard, we anticipate to 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 are also evaluating our systems, processes, internal controls, and technology requirements and solutions needed to comply with the requirements of this standard. While we cannot currently estimate the financial impact this standard has on our consolidated financial statements, the adoption is anticipated to result in an increase in both assets and liabilities related to our leases.

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.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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 (i.e., 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 (i.e., measure the charge based on Step 1 under the current guidance). This standard is effective for us in the first quarter of 2020 and shall be applied on a prospective basis. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. Since we plan to adopt the standard on a prospective basis, we do not expect an impact on our consolidated results of operations, financial position or cash flows for prior periods.

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 flow. The following table summarizes the impacts of adopting the new revenue standard on our consolidated income statement for the quarter ended March 31, 2018.



	Three Months Ended March 31, 2018
(In millions)	As reported		Adjustments			Presentation without adoption of ASC Topic 606
Revenues and other income:
Revenues from contracts with customers	$	1,537	$	(104	)	$	1,433
Marketing revenues	—		32			32
Other income	4		(1		)	3
Costs and expenses:
Marketing, including purchases from related parties	$	—	$	32		$	32
Other operating	130		(3		)	127

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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 table summarizes the impacts of adopting this standard on our historical consolidated income statement for the quarter ended March 31, 2017.



	Three Months Ended March 31, 2017
(In millions)	Previously Reported	As reclassified	Effect of Change Higher/(Lower)
Production	151	153	2
Exploration	28	28	—
General and administrative	109	97	(12	)
Income from operations	62	72	10
Other net periodic benefit costs ^(a)	—	10	10


^(a)	Includes net settlement loss and other net periodic benefit costs, excluding service costs (See Note 16).

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.

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.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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.


3.	Income (Loss) per Common Share

Basic income (loss) per share is based on the weighted average number of common shares outstanding. Diluted income per share assumes exercise of stock options in all periods, provided the effect is not antidilutive. The per share calculations below exclude 8 million of stock options for the three months period ended March 31, 2018 and 12 million stock options for the three months period ended March 31, 2017 that were antidilutive.



	Three Months Ended March 31,
(In millions, except per share data)	2018		2017
Income (loss) from continuing operations	$	356	$	(50	)
Income (loss) from discontinued operations	—		(4,907		)
Net income (loss)	$	356	$	(4,957	)

Weighted average common shares outstanding	851		849
Effect of dilutive securities	1		—
Weighted average common shares, diluted	852		849
Per basic share:
Income (loss) from continuing operations	$	0.42	$	(0.06	)
Income (loss) from discontinued operations	$	—	$	(5.78	)
Net income	$	0.42	$	(5.84	)
Per diluted share:
Income (loss) from continuing operations	$	0.42	$	(0.06	)
Income (loss) from discontinued operations	$	—	$	(5.78	)
Net income	$	0.42	$	(5.84	)

4. Acquisitions

In the second quarter of 2017, we closed on our two acquisitions totaling approximately 91,000 net acres in the Permian basin of New Mexico. On May 1, 2017, we closed on our acquisition with BC Operating, Inc. and other entities for $1.1 billion in cash, subject to post-closing adjustments, to acquire approximately 70,000 net surface acres and current production of approximately 5,000 net barrels of oil equivalent per day. On June 1, 2017, we closed on our acquisition with Black Mountain Oil & Gas and other private sellers for approximately $700 million in cash, subject to post-closing adjustments, to acquire approximately 21,000 net surface acres. The purchase price for these acquisitions was paid with cash on hand. We accounted for these transactions as asset acquisitions, with substantially all of the purchase price allocated to unproved property within property, plant and equipment.


5.	Dispositions

International E&P Segment

On March 1, 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.

In the third quarter of 2017, we entered into separate agreements to sell certain non-core properties in our International E&P segment for combined proceeds of $53 million, before closing adjustments. We closed on one of the asset sales in the fourth quarter of 2017 and recognized no net pre-tax gain or loss on sale. The remaining asset sale is expected to close during 2018 and is classified as held for sale in the consolidated balance sheet as of March 31, 2018, with total assets of $61 million and total liabilities of $4 million.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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 and the remaining proceeds were paid in the first quarter of 2018. At closing we received two notes receivable for the remaining proceeds, each with a face value of $375 million, which we received payment for 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. As the effective date of the transaction is January 1, 2017, we recorded a loss on sale of $43 million during the second quarter of 2017 due to second quarter results of operations from our Canadian business that were recorded in our financial statements, but transferred to the buyer upon closing.

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



	Three Months Ended March 31,
(In millions)	2018		2017
Total revenue and other income	$	—	$	258
Costs and expenses:
Production	—		151
Depreciation, depletion and amortization	—		39
Impairments	—		6,636
Other	—		13
Total costs and expenses	—		6,839
Pretax income (loss) from discontinued operations	—		(6,581		)
Provision (benefit) for income taxes	—		(1,674		)
Income (loss) from discontinued operations	$	—	$	(4,907	)

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 March 31, 2018
United States E&P							Northern				Total
(In millions)	Eagle Ford		Bakken		Oklahoma		Delaware		Other U.S.		U.S. E&P
Crude oil and condensate	$	366	$	330	$	115	$	55	$	53	$	919
Natural gas liquids	42		15		37		6		3		103
Natural gas	33		10		43		5		7		98
Other	2		—		—		—		3		5
Revenues from contracts with customers	$	443	$	355	$	195	$	66	$	66	$	1,125

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



	Three Months Ended March 31, 2018
International E&P							Other		Total
(In millions)	E.G.		U.K.		Libya		International		Int'l E&P
Crude oil and condensate	$	71	$	95	$	187	$	23	$	376
Natural gas liquids	1		—		—		—		1
Natural gas	9		8		9		—		26
Other	—		9		—		—		9
Revenues from contracts with customers	$	81	$	112	$	196	$	23	$	412

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, as part of the other operating expense in our consolidated statement of income, 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.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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.

Contract receivables and assets

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



(In millions)	March 31, 2018		January 1, 2018
Receivables from contracts with customers, which are included in receivables, less reserves	$	802	$	811
Contract asset	$	29	$	—

The contract asset represents the crude oil delivered to one of our customers in the U.K. 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 balance during the period are as follows.



	Three Months Ended
(In millions)	March 31, 2018
Contract asset balance as of January 1, 2018	$	—
Revenue recognized as performance obligations are satisfied	48
Amounts invoiced to customers	(19		)
Contract asset balance as of March 31, 2018	$	29

7. Segment Information

We have two reportable operating segments. Both of these segments are organized and managed based upon both 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 March 31, 2018
							Not Allocated
(In millions)	U.S. E&P			Int'l E&P			to Segments				Total
Revenues from contracts with customers	$	1,125		$	412		$	—			$	1,537
Net gain (loss) on commodity derivatives	(59		)	—			(43		)	^(b)	(102		)
Income from equity method investments	—			37			—				37
Net gain (loss) on disposal of assets	—			—			257			^(c)	257
Other income	3			1			—				4
Less:
Production expenses	151			67			(1		)		217
Other operating	111			19			—				130
Exploration	51			1			—				52
Depreciation, depletion and amortization	528			54			8				590
Impairments	—			—			8				8
Taxes other than income	64			—			—				64
General and administrative	36			9			55				100
Net interest and other	—			—			45				45
Other net periodic benefit costs	—			(2		)	5			^(d)	3
Income tax provision (benefit)	3			170			(5		)		168
Segment income (loss) / Income (loss) from continuing operations	$	125		$	132		$	99			$	356
Capital expenditures ^(a)	$	611		$	6		$	5			$	622


^(a)	Includes accruals.


^(b)	Unrealized loss on commodity derivative instruments (See Note 12).


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


^(d)	Includes pension settlement loss of $4 million (See Note 16).

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



	Three Months Ended March 31, 2017
							Not Allocated
(In millions)	U.S. E&P			Int'l E&P			to Segments				Total
Revenue from contracts with customers	$	670		$	203		$	—			$	873
Net gain (loss) on commodity derivatives	4			—			77			^(b)	81
Marketing revenues	6			28			—				34
Income from equity method investments	—			69			—				69
Net gain (loss) on disposal of assets	1			—			—				1
Other income	4			10			—				14
Less:
Production expenses	109			44			—				153
Marketing costs	7			27			—				34
Other operating	74			15			—				89
Exploration	26			2			—				28
Depreciation, depletion and amortization	472			75			9				556
Impairments	4			—			—				4
Taxes other than income	39			—			—				39
General and administrative	33			6			58				97
Net interest and other	—			—			78				78
Other net periodic benefit costs	—			(2		)	12			^(c)	10
Income tax provision (benefit)	—			50			(16		)		34
Segment income (loss) / Income (loss) from continuing operations	$	(79	)	$	93		$	(64	)		$	(50	)
Capital expenditures ^(a)	$	349		$	9		$	1			$	359


^(a)	Includes accruals.


^(b)	Unrealized gain on commodity derivative instruments (See Note 12).


^(c)	Includes pension settlement loss of $14 million (See Note 16).

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 months ended March 31, 2018 and 2017, our effective income tax rates from continuing operations were as follows:

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% respectively for 2018 and 2017:


•	During the three months ended March 31, 2018, we incurred tax expense in Libya of $162 million, and maintained our valuation allowance on our net federal deferred tax assets in the U.S.


•	During the three months ended March 31, 2017, we incurred tax expense in Libya of $45 million, settled our 2011-2013 Alaska income tax audit resulting in a tax benefit of $13 million, and maintained our valuation allowance on our net federal deferred tax assets in the U.S.

Excluding Libya, the effective income tax expense and benefit rates from continuing operations were an expense of 2% and a benefit of 16% for the first quarter of 2018 and 2017, respectively. As a result of the sale of our Libya subsidiary, see Note 5 for further detail, we do not expect to incur further tax expense in 2018 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.

On December 22, 2017, the U.S. enacted the Tax Cuts and Jobs Act (the “Tax Reform Legislation”). Tax Reform Legislation, which is also commonly referred to as “U.S. tax reform”, 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 alternative minimum tax, 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. Once we finalize certain tax positions when we file our 2017 federal tax return, we will be able to 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, which will be no later than the fourth quarter of 2018. As of the first quarter of 2018, there is no impact on tax expense with respect to the finalization of tax positions taken due to Tax Reform Legislation.

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.



	March 31,		December 31,
(In millions)	2018		2017
Crude oil and natural gas	$	10	$	9
Supplies and other items	100		117
Inventories	$	110	$	126

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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



	March 31,		December 31,
(In millions)	2018		2017
United States E&P	$	15,922	$	15,867
International E&P	926		1,710
Corporate	83		88
Net property, plant and equipment	$	16,931	$	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 March 31, 2018 and December 31, 2017.

11. Exploration Expenses

The following table summarizes the components of exploration expenses:



	Three Months Ended March 31,
(In millions)	2018		2017
Exploration Expenses
Unproved property impairments	$	40	$	20
Dry well costs	2		—
Geological and geophysical	6		1
Other	4		7
Total exploration expenses	$	52	$	28

12. Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note 13. 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.



	March 31, 2018
(In millions)	Asset		Liability		Net Asset (Liability)			Balance Sheet Location
Not Designated as Hedges
Commodity	$	3	$	—	$	3		Other current assets
Commodity	—		183		$	(183	)	Other current liabilities
Commodity	—		4		(4		)	Deferred credits and other liabilities
Total Not Designated as Hedges	$	3	$	187	$	(184	)



	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	)

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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, we terminated our forward starting interest rate swaps during the third quarter of 2017.

The following table presents, by maturity date, information about our forward starting interest rate swap agreements, including the rate, which were terminated in the third quarter of 2017.



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

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



	Three Months Ended March 31,
(In millions)	2018		2017
Interest Rate Swaps
Beginning balance	$	—	$	60
Change in fair value recognized in other comprehensive income	—		1
Reclassification from other comprehensive income	—		—
Ending balance	$	—	$	61

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Commodity Derivatives

We have entered into multiple crude oil and natural gas derivatives indexed to NYMEX WTI and Henry Hub related to a portion of our forecasted United States E&P sales through 2020. These commodity derivatives consist of three-way collars, swaps and 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 March 31, 2018 and the weighted average prices for those contracts:



Crude Oil
	2018			2019				2020
	Second Quarter	Third Quarter	Fourth Quarter	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Full Year
Three-Way Collars
Volume (Bbls/day)	85,000	95,000	95,000	40,000	40,000	10,000	10,000	—
Weighted average price per Bbl:
Ceiling	$56.38	$57.65	$57.65	$66.46	$66.46	$70.00	$70.00	—
Floor	$51.65	$52.11	$52.11	$53.50	$53.50	$52.00	$52.00	—
Sold put	$45.00	$45.21	$45.21	$46.25	$46.25	$45.00	$45.00	—
Swaps
Volume (Bbls/day)	20,000	—	—	—	—	—	—	—
Weighted average price per Bbl	$55.12	—	—	—	—	—	—	—
Basis Swaps ^(a)
Volume (Bbls/day)	5,000	10,000	10,000	10,000	10,000	10,000	10,000	5,000
Weighted average price per Bbl	$(0.60)	$(0.67)	$(0.67)	$(0.82)	$(0.82)	$(0.82)	$(0.82)	$(0.25)


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



Natural Gas
	2018
	Second Quarter	Third Quarter	Fourth Quarter
Three-Way Collars
Volume (MMBtu/day)	160,000	160,000	160,000
Weighted average price per MMBtu:
Ceiling	$3.61	$3.61	$3.61
Floor	$3.00	$3.00	$3.00
Sold put	$2.50	$2.50	$2.50

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 for the three month periods ended March 31, 2018 and 2017, respectively. The mark-to-market impact for the three-month period ended March 31, 2018 was a loss of $43 million compared to a gain of $77 million for the same respective period in 2017. Net settlements of commodity derivative instruments for the three-month period ended March 31, 2018 was a loss of $59 million and compared to a gain of $4 million for the respective period in 2017.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

13. Fair Value Measurements

Fair Values - Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of March 31, 2018 and December 31, 2017 by fair value hierarchy level.



	March 31, 2018
(In millions)	Level 1			Level 2			Level 3		Total
Derivative instruments, assets
Commodity ^(a)	$	—		$	—		$	—	$	—
Derivative instruments, assets	$	—		$	—		$	—	$	—
Derivative instruments, liabilities
Commodity ^(a)	$	(2	)	$	(182	)	$	—	$	(184	)
Derivative instruments, liabilities	$	(2	)	$	(182	)	$	—	$	(184	)


^(a)	Derivative instruments are recorded on a net basis in our balance sheet. See Note 12.



	December 31, 2017
(In millions)	Level 1			Level 2			Level 3		Total
Derivative instruments, assets
Interest rate	$	—		$	—		$	—	$	—
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 balance sheet. See Note 12.

Commodity derivatives include three-way collars, swaps, and basis swaps. These instruments are measured at fair value using either a Black-Scholes or a modified Black-Scholes Model. For swaps and basis swaps, inputs to the models include only commodity prices and 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 12 for additional discussion of the types of derivative instruments we used.

Fair Values- Nonrecurring

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



	Three Months Ended March 31,
	2018				2017
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets	$	50	$	8	$	—	$	4

International E&P

We recorded proved property impairments of $8 million, to a fair value of $50 million, on a non-core property in our International E&P segment primarily as a result of anticipated sales proceeds. The fair value was measured using the market approach, based upon anticipated sales proceeds less costs to sell. This resulted in a Level 2 classification. See Note 5 for relevant detail regarding dispositions.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Canadian business discontinued operations

As a result of our announced disposition of our Canadian business in the first quarter of 2017, we recorded a pre-tax non-cash impairment charge of $6.6 billion primarily related to property, plant and equipment. This impairment was recorded for excess net book value over anticipated sales proceeds less costs to sell. Fair values of assets held for sale were determined based upon the anticipated sales proceeds less costs to sell, which resulted in a Level 2 classification. See Note 5 for relevant detail regarding dispositions.

Fair Values – Financial Instruments

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

The following table summarizes financial instruments, excluding receivables, payables and derivative financial instruments, and their reported fair values by individual balance sheet line item at March 31, 2018 and December 31, 2017.



	March 31, 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	129		132		135		137
Total financial assets	$	144	$	147	$	897	$	898
Financial liabilities
Other current liabilities	$	31	$	43	$	32	$	43
Long-term debt, including current portion ^(b)	5,841		5,527		5,976		5,526
Deferred credits and other liabilities	105		103		110		103
Total financial liabilities	$	5,977	$	5,673	$	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, debt issuance costs and interest rate swap adjustments.

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

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.

14. Debt

Revolving Credit Facility

As of March 31, 2018, we had no borrowings against our $3.4 billion revolving credit facility (the “Credit Facility”), as described below.

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 March 31, 2018, we were in compliance with this covenant with a debt-to-capitalization ratio of 31%.

Long-term debt

As of March 31, 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.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

15. Incentive Based Compensation

Stock options, restricted stock awards and restricted stock units

The following table presents a summary of activity for the first three 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	4,560,821			$14.54
Options Exercised/Stock Vested	(158,890	)			$15.04	(2,315,776	)		$13.18
Canceled	(684,410	)			$31.14	(227,555	)		$14.37
Outstanding at March 31, 2018	10,344,366				$24.39	9,590,335			$14.63

^(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 three months of 2018, we granted 754,140 stock-based performance units to certain officers. The grant date fair value per unit was $17.02.

16. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:



	Three Months Ended March 31,
	Pension Benefits						Other Benefits
(In millions)	2018			2017			2018			2017
Service cost	$	4		$	6		$	1		$	1
Interest cost	7			8			2			2
Expected return on plan assets	(9		)	(12		)	—			—
Amortization:
– prior service cost (credit)	(2		)	(2		)	(2		)	(2		)
– actuarial loss	3			2			—			—
Net settlement loss ^(a)	4			14			—			—
Net periodic benefit cost	$	7		$	16		$	1		$	1


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

During the first three 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 three months of 2018, we made contributions of $29 million to our funded pension plans and we expect to make additional contributions up to an estimated $36 million over the remainder of 2018. During the first three months of 2018, we made payments of $8 million and $6 million related to unfunded pension plans and other postretirement benefit plans, respectively.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

17. Reclassifications Out of Accumulated Other Comprehensive Loss

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



	Three Months Ended March 31,
(In millions)	2018			2017			Income Statement Line

Postretirement and postemployment plans
Amortization of actuarial loss	$	(3	)	$	(2	)	Other net periodic benefit costs
Net settlement loss	(4		)	(14		)	Other net periodic benefit costs
	(7		)	(16		)	Income (loss) from continuing operations before income taxes
	—			—			(Provision) benefit for income taxes
Total reclassifications to expense, net of tax	(7		)	(16		)	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	$	(7	)	$	(46	)	Net income (loss)

18. Supplemental Cash Flow Information



	Three Months Ended March 31,
(In millions)	2018			2017
Net cash (used in) operating activities:
Interest paid (net of amounts capitalized)	$	(52	)	$	(64	)
Income taxes paid to taxing authorities	(231		)	(15		)
Noncash investing activities, related to continuing operations:
Increase (decrease) in asset retirement costs	$	4		$	4
Asset retirement obligations assumed by buyer	1			—

Other noncash investing activities include accrued capital expenditures as of March 31, 2018 and 2017 of $279 million and $231 million, respectively.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

19. Equity Method Investments

During the periods ended March 31, 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	March 31,		December 31,
(In millions)	March 31, 2018	2018		2017
EGHoldings	60%	$	426	$	456
Alba Plant LLC	52%	199		214
AMPCO	45%	181		177
Total		$	806	$	847

Summarized financial information for equity method investees is as follows:



	Three Months Ended March 31,
(In millions)	2018		2017
Income data – year:
Revenues and other income	$	198	$	239
Income from operations	97		152
Net income	79		134

20. Commitments and Contingencies

The U.K. tax authorities have challenged the timing of deductibility for certain Brae area decommissioning costs, which we claimed for U.K. corporation tax purposes. The dispute relates to the timing of the deduction and does not dispute the general deductibility of decommissioning costs. In the third quarter of 2017, a hearing took place at the U.K.’s First-tier Tribunal with respect to this tax deduction. In the fourth quarter of 2017, we received notification from the U.K.’s First-tier Tribunal that the judge sided with the U.K. tax authorities with respect to the timing of the decommissioning cost deductions. We intend to appeal this decision and estimate that any revisions to current and deferred tax liabilities, if we do not prevail in the appeals process, would have no cumulative adverse earnings impact on our consolidated results of operations. 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 a result of the negative ruling we no longer consider this position to be more-likely-than-not to be sustained and in the fourth quarter 2017 created an uncertain tax position related to the Brae area decommissioning costs. The payment of the tax and interest to the U.K. tax authorities is not to settle the position, but a regulatory requirement to appeal in the U.K. If we ultimately prevail in appeals, the U.K. tax authorities will refund the tax and interest, however, if we ultimately lose in appeals no material future payments related to this issue will be required.

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.

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

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

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

Executive Overview

Operations

Market Conditions

Results of Operations

Critical Accounting Estimates

Accounting Standards Not Yet Adopted

Cash Flows

Liquidity and Capital Resources

Environmental Matters and Other Contingencies

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

Executive Overview

We are an independent exploration and production company based in Houston, Texas focused on U.S. unconventional resource plays with operations in the United States, Europe and Africa. Total proved reserves were 1.4 billion boe at December 31, 2017, including 199 mmboe in Libya, and total assets were $21.6 billion at March 31, 2018. During the first quarter 2018, we continued our portfolio transformation, maintained a strong balance sheet and delivered solid operational performance across our portfolio.

Key highlights include the following:

Simplifying and concentrating our portfolio


•	On March 1, 2018 we closed on the sale of our Libya subsidiary for proceeds of approximately $450 million resulting in a gain of $255 million.


•	Captured more than 250,000 net acres in multiple new plays in the last year, including a largely contiguous position in the emerging Louisiana Austin Chalk play at a cost of less than $900 per acre.

Liquidity


•	At the end of the first 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.


•	In March of 2018, we received the expected cash proceeds of $750 million from the sale of our Canadian business.

Financial and operational results


•	Total net sales volumes from continuing operations, including Libya are 431 mboed. This represents an increase in net sales volumes of 29% compared to the same quarter last year and includes a 40% increase from the U.S resource plays to 268 mboed.


•	Wells to sales in the first three months of 2018 increased over 10% in the U.S. resource plays.


•	Cash provided by operating activities from continuing operations is $649 million for the first three months of 2018 as a result of increased price realizations and sales volumes.


•	Our net income per share from continuing operations was $0.42 in the first quarter of 2018 as compared to a net loss per share of $0.06 in the same period last year. Included in the first quarter 2018 net income results are:


◦	An increase in revenues of approximately 75% to $1,537 million compared to the same quarter last year as a result of increased price realizations and sales volumes across our portfolio.


◦	Net loss on commodity derivatives was $102 million compared to a net gain of $81 million in the same quarter last year due to the increases in long-term commodity prices during the first quarter 2018.


◦	Net gain on disposal of assets from the sale of our Libya subsidiary for $255 million.


◦	Production expense, DD&A and other operating expenses increased 17% primarily as a result of sales volumes increasing by 29% during the quarter.


◦	Net interest and other decreased by $33 million to $45 million primarily due to the reduction of total debt of approximately $1.75 billion in the second half of 2017.


◦	Our provision for income taxes increased $134 million compared to the same quarter last year primarily due to an increase in Libya tax expense as a result of higher sales volumes.

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 March 31,
Net Sales Volumes	2018	2017	Increase (Decrease)
United States E&P (mboed)	284	208	37%
International E&P ^(a) (mboed)	147	126	17%
Total Continuing Operations (mboed)	431	334	29%


^(a)	Three months ended March 31, 2018 and 2017 includes net sales volumes relating to Libya of 32 mboed and 12 mboed, respectively.

United States E&P

Net sales volumes in the segment were higher in the first quarter 2018 primarily as a result of new wells to sales across all U.S. resource plays, as well as our acquisition in Northern Delaware in 2017. 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 March 31,
Net Sales Volumes	2018	2017	Increase (Decrease)
Equivalent Barrels (mboed)
Eagle Ford	104	99	5%
Bakken	74	48	54%
Oklahoma	74	44	68%
Northern Delaware	16	—	100%
Other United States	16	17	(6)%
Total United States E&P	284	208	37%



	Three Months Ended March 31, 2018
Sales Mix - U.S. Resource Plays	Eagle Ford	Bakken	Oklahoma	Northern Delaware	Total
Crude oil and condensate	61%	82%	28%	63%	58%
Natural gas liquids	20%	10%	24%	19%	18%
Natural gas	19%	8%	48%	18%	24%



	Three Months Ended March 31,
	2018	2017
Gross Operated - U.S. Resource Plays

Eagle Ford:
Wells drilled to total depth	34	45
Wells brought to sales	34	47
Bakken:
Wells drilled to total depth	19	12
Wells brought to sales	11	4
Oklahoma:
Wells drilled to total depth	13	15
Wells brought to sales	17	12
Northern Delaware
Wells drilled to total depth	20	—
Wells brought to sales	9	—

•

Eagle Ford – Our net sales volumes were 104 mboed in the first quarter of 2018 which was 5% higher compared to the prior year quarter. Enhanced completion designs continued to deliver solid results outside of core Karnes County, where the four-well Carpenter Kellner pad and the four-well Guajillo West pad achieved strong well performance. We continued our focus on cash flow in the quarter through a combination of well performance and oil realizations that averaged $1.50 above WTI due to strong LLS-based pricing.

•

Bakken – Our net sales volumes were 74 mboed compared to 48 mboed in the prior year quarter. We brought 11 gross company-operated wells to sales in the first quarter 2018, six of which were in core Hector which achieved strong well results. During the first quarter 2018 our Arkin well in Hector set a new Williston Basin Three Forks record for 30-day IP oil rate. We continue to optimize completion designs to improve well productivity, increase capital efficiency and reduce costs.

•

Oklahoma – Our net sales volumes in the first quarter 2018 increased by more than 65% from the year ago quarter, with net sales volumes of 74 mboed. We brought 17 gross operated wells to sales primarily focused on Meramec leasehold activity in the STACK. This largely completes the STACK leasehold program for the year, and allows for the transition to pad drilling for the remainder of 2018. In the normally pressured STACK, improved drilling efficiencies and optimized completion designs resulted in completed well costs for first quarter standard-lateral Meramec wells averaging $4 million.

•

Northern Delaware – Our net sales volumes were 16 mboed in the first quarter 2018. We brought nine gross company-operated wells to sales across the Malaga, Red Hills and Ranger areas in Eddy and Lea Counties. Two wells from the Cypress infill pilot came to sales ahead of schedule in the last week of the quarter. We are currently benefiting from our Midland-Cushing basis swaps, with open positions that include 10,000 bopd hedged at a discount of less than $1 to WTI for the second half of 2018 and all of 2019. See Note 12 to the consolidated financial statements for further information.

International E&P

Net sales volumes were higher in the first quarter of 2018 compared to the first quarter of 2017 primarily due to the resumption of sales volumes and production in Libya and timing of our liftings in the U.K. The following table provides details regarding net sales volumes for our significant operations within this segment.



	Three Months Ended March 31,
Net Sales Volumes	2018	2017	Increase (Decrease)
Equivalent Barrels (mboed)
Equatorial Guinea	93	103	(10)%
United Kingdom^(a)	17	11	55%
Libya	32	12	167%
Other International	5	—	100%
Total International E&P	147	126	17%
Equity Method Investees
LNG (mtd)	5,541	6,147	(10)%
Methanol (mtd)	1,195	1,307	(9)%
Condensate & LPG (boed)	12,416	14,546	(15)%


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


•	Equatorial Guinea – Net sales volumes in the first three months of 2018 were lower than the first three months of 2017 as a result of planned maintenance activities at our LNG production facility.


•	United Kingdom – First quarter 2018 net sales volumes were higher compared to the first quarter of 2017 primarily due to the timing of liftings, which resulted in an increase in net sales volumes during the first quarter of 2018.


•	Libya – During the first quarter of 2018 we closed on the sale of our operations 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 first quarter of 2018 as compared to the same period in 2017; as a result, we experienced increased price realizations associated with those benchmarks. Additional detail on market conditions, including our average price realizations and benchmarks for crude oil and condensate, NGLs, and natural gas relative to our operating segments, follows.

United States E&P

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



	Three Months Ended March 31,
	2018	2017	Increase (Decrease)
Average Price Realizations ^(a)
Crude oil and condensate (per bbl) ^(b)	$62.22	$48.46	28%
Natural gas liquids (per bbl)	22.95	19.33	19%
Natural gas (per mcf) ^(c)	2.59	3.02	(14)%
Benchmarks
WTI crude oil average of daily prices (per bbl)	$62.89	$51.78	21%
LLS crude oil average of daily prices (per bbl)	65.83	53.39	23%
Mont Belvieu NGLs (per bbl)^(d)	26.26	22.93	15%
Henry Hub natural gas settlement date average (per mmbtu)	3.00	3.32	(10)%


^(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 $(4.33) per bbl and $0.34 per bbl for the first quarter 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 in the U.S. is sold at bid-week prices, or first-of-month indices relative to our specific producing areas.

International E&P

The following table presents our average price realizations and the related benchmark for crude oil for the first quarter of 2018 and 2017.



	Three Months Ended March 31,
	2018	2017	Increase (Decrease)
Average Price Realizations
Crude oil and condensate (per bbl)	$66.23	$50.41	31%
Natural gas liquids (per bbl)	1.83	3.86	(53)%
Natural gas (per mcf)	0.65	0.55	18%
Benchmark
Brent (Europe) crude oil (per bbl) ^(a)	$66.81	$53.68	24%


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

Our U.K. liquid hydrocarbon production is generally sold in relation to the Brent crude benchmark. Our production from the Alba field in E.G. is condensate and gas. Condensate is sold at market prices and the gas is shipped to the onshore Alba Plant. The Alba Plant extracts NGLs and secondary condensate, which have been supplied under a long-term contract at a fixed price, leaving dry natural gas. The extracted NGLs and secondary condensate are sold by Alba Plant at market prices, with our share of its income/loss reflected in income from equity method investments, and the dry natural gas from Alba Plant is supplied to AMPCO and EGHoldings under long-term contracts at fixed prices. Therefore, our reported average realized prices for condensate, NGLs and natural gas will not fully track market price movements. Because of the location and limited local demand for natural gas in E.G., we consider the prices under the contracts with Alba Plant LLC, EGHoldings and AMPCO to be comparable to the price that could be realized from transactions with unrelated parties in this market under the same or similar circumstances. EGHoldings and AMPCO process the gas into LNG and methanol, which are sold at market prices, with our share of their income/loss reflected in the income from equity method investments line item on the consolidated statements of income. Although uncommon, any dry gas not sold is returned offshore and re-injected into the Alba field for later production.

Results of Operations

Three Months Ended March 31, 2018 vs. Three Months Ended March 31, 2017

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



	Three Months Ended March 31,
(In millions)	2018		2017
Revenues from contracts with customers
United States E&P	$	1,125	$	670
International E&P	412		203
Segment revenues from contracts with customers	$	1,537	$	873

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



	Three Months Ended		Increase (Decrease) Related to						Three Months Ended
(In millions)	March 31, 2017		Price Realizations			Net Sales Volumes			March 31, 2018
United States E&P Price-Volume Analysis
Crude oil and condensate	$	515	$	203		$	201		$	919
Natural gas liquids	69		16			18			103
Natural gas	83		(17		)	32			98
Other sales	3								5
Total	$	670							$	1,125
International E&P Price-Volume Analysis
Crude oil and condensate	$	168	$	90		$	118		$	376
Natural gas liquids	4		(2		)	(1		)	1
Natural gas	23		4			(1		)	26
Other sales	8								9
Total	$	203							$	412

Net gain (loss) on commodity derivatives decreased $183 million in the first quarter of 2018 compared to the same period in 2017. We have entered into 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 12 to the consolidated financial statements for further information.

Marketing revenues decreased $34 million in the first 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.

Income from equity method investments decreased $32 million in the first quarter of 2018 from the comparable 2017 period. This decrease is the result of lower volumes at our LNG production facility primarily driven by planned maintenance activities during the first quarter 2018.

Net gain on disposal of assets increased $256 million in the first quarter of 2018 primarily related to the gain on sale of our subsidiary Marathon Oil Libya Limited, which holds our 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 further information.

Production expenses increased $64 million in the first quarter of 2018 versus the same period in 2017 primarily due to higher sales volumes across our U.S. and International E&P segments. United States E&P increased $42 million primarily due to our entry into Northern Delaware in 2017, as wells as new wells to sales across all U.S. resource plays. International E&P increased $23 million primarily due to the timing of our U.K. liftings, which resulted in increased sales volumes during the first quarter 2018.

The first quarter 2018 production expense rate (expense per boe) for International E&P increased due to sales volume mix within our segment.

The following table provides production expense rates for each segment:



	Three Months Ended March 31,
($ per boe)	2018		2017
Production Expense Rate
United States E&P		$5.89		$5.79
International E&P		$5.07		$3.91

Marketing costs decreased $34 million in the first quarter of 2018 from the comparable 2017 period, consistent with the marketing revenues change discussed above.

Other operating expenses increased $41 million in the first quarter of 2018 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 increased $24 million in the first quarter of 2018. The increase in unproved property impairments is primarily a result of the acquisition of Northern Delaware in 2017.

The following table summarizes the components of exploration expenses:



	Three Months Ended March 31,
(In millions)	2018		2017
Exploration Expenses
Unproved property impairments	$	40	$	20
Dry well costs	2		—
Geological and geophysical	6		1
Other	4		7
Total exploration expenses	$	52	$	28

Depreciation, depletion and amortization increased $34 million in the first quarter of 2018. United States E&P DD&A expense increased by $56 million primarily due to higher sales volumes across all U.S. resource plays, as well as our acquisition and development of Northern Delaware in 2017. In our International E&P segment, we had a decrease of $21 million primarily the result of lower estimated U.K. asset retirement costs during the second half of 2017. 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 first quarter of 2018 primarily due to increased proved developed reserves in our U.S. resource plays in 2017; as well as reduced capitalized costs relating to the Gulf of Mexico non-cash impairment charge in 2017. 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.



	Three Months Ended March 31,
($ per boe)	2018		2017
DD&A Rate
United States E&P		$20.66		$25.15
International E&P		$4.13		$6.61

Taxes other than income include production, severance, and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. Taxes other than income increased $25 million in the first quarter of 2018 versus the same period in 2017. The increase is primarily due to an increase in sales volumes during the first quarter 2018. Additionally, during the first quarter of 2018 the State of Oklahoma approved an increase to the gross production tax from 2% to 5% on all existing and new wells for the first thirty-six months, effective July 1, 2018. The following table summarizes the components of taxes other than income:



	Three Months Ended March 31,
(In millions)	2018		2017
Taxes other than income
Production and severance	$	44	$	25
Ad valorem	6		3
Other	14		11
Total taxes other than income	$	64	$	39

Net interest and other decreased $33 million in the first quarter of 2018 versus the same period in 2017. This decrease was primarily due to the reduction of approximately $1.75 billion in net debt during 2017.

Other net periodic benefit costs decreased $7 million during the first quarter of 2018 primarily due to reduced pension settlement charges. See Note 16 to the consolidated financial statements for further information.

Provision (benefit) for income taxes reflects an effective tax rate from continuing operations of 32% in the first quarter of 2018, as compared to an effective tax rate of 213% in the first 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 March 31,
(In millions)	2018		2017
United States E&P	$	125	$	(79	)
International E&P	132		93
Segment income (loss)	257		14
Items not allocated to segments, net of income taxes	99		(64		)
Income (loss) from continuing operations	356		(50		)
Income (loss) from discontinued operations ^(a)	—		(4,907		)
Net income (loss)	$	356	$	(4,957	)

^(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 $204 million after-tax in the first quarter of 2018 primarily due to higher price realizations and an increase in sales volumes. This increase in sales volumes resulted in an increase to production expenses, other operating expenses, DD&A and taxes other than income which partially offset the increase to revenues.

International E&P segment income increased $39 million after-tax in the first quarter of 2018 primarily due to higher price realizations and an increase in sales volumes in the U.K. and Libya. This increase in sales volumes resulted in an increase in production expense and income tax provision which partially offset the increase to revenues.

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.

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:



	Three Months Ended March 31,
(In millions)	2018			2017
Sources of cash and cash equivalents
Operating activities - continuing operations	$	649		$	501
Disposal of assets, net of cash transferred to the buyer	1,180			—
Other	12			14
Total sources of cash and cash equivalents	$	1,841		$	515
Uses of cash and cash equivalents
Cash additions to property, plant and equipment	$	(662	)	$	(283	)
Acquisitions, net of cash acquired	(4		)	—
Deposits for acquisitions	—			(180		)
Dividends paid	(42		)	(42		)
Purchases of common stock	(9		)	(7		)
Other	(74		)	(1		)
Total uses of cash and cash equivalents	$	(791	)	$	(513	)

Cash flows generated from operating activities in the first three months of 2018 were higher as commodity prices and price realizations improved compared to the first three months of 2017. Consolidated average crude oil and condensate price realizations increased by approximately 29% during the first three months of 2018 as compared to the prior period. This increase in price realization and net sales volumes resulted in increased cash flows generated from operating activities.

Proceeds from the disposals of assets for the first three months of 2018 are primarily from the disposal of our non-operated interest in Libya and the remaining proceeds of $750 million from the sale of our Canadian business; see Note 5 to the consolidated financial statements for further information concerning dispositions.

Additions to property, plant and equipment in the first three months of 2018 were consistent with 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:



	Three Months Ended March 31,
(In millions)	2018		2017
United States E&P	$	611	$	349
International E&P	6		9
Corporate	5		1
Total capital expenditures	622		359
Change in capital expenditure accrual	40		(76		)
Total use of cash and cash equivalents for property, plant and equipment	$	662	$	283

In the first quarter of 2017, we paid $180 million of aggregate deposits into escrow related to our acquisition of the Northern Delaware assets. See Note 4 to the consolidated financial statements for additional information.

Included within other uses of cash and cash equivalents is $72 million relating to our resource play leasing and exploration capital expenditures. During the first quarter 2018 our resource play leasing and exploration capital expenditures totaled $94 million, inclusive of costs included within property, plant and equipment and exploration expense.

The Board of Directors approved a $0.05 per share dividend for the fourth quarter of 2017, which was paid in the first quarter of 2018. See Capital Requirements below for additional information about the first quarter dividend.

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 March 31, 2018, we had approximately $5.0 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 remained unchanged as of March 31, 2018: Standard & Poor's Ratings Services BBB- (stable); Fitch Ratings BBB (stable); and Moody's Investor Services, Inc. Ba1 (stable). A downgrade in our credit ratings could increase our future cost of financing or limit our ability to access capital, and result in additional collateral requirements. See Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2017 for a discussion of how a further downgrade in our credit ratings could affect us.

Capital Resources

Credit Arrangements and Borrowings

At March 31, 2018, we had no borrowings against our revolving credit facility.

At March 31, 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 third quarter of 2017, we entered into agreements to sell certain non-core properties in our International E&P segment for combined proceeds of $53 million, before closing adjustments. We have closed on one of the asset sales in 2017, and we expect the remaining asset sale to close during 2018.

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 March 31, 2018, compared to 32% at December 31, 2017.



	March 31,			December 31,
(In millions)	2018			2017
Long-term debt due within one year	$	—		$	—
Long-term debt	5,495			5,494
Total debt	$	5,495		$	5,494
Equity	$	12,034		$	11,708
Calculation:
Total debt	$	5,495		$	5,494
Total debt plus equity (total capitalization)	$	17,529		$	17,202
Debt-to-capital ratio	31		%	32		%

Capital Requirements

Other Expected Cash Outflows

On April 26, 2018, our Board of Directors approved a dividend of $0.05 per share for the first quarter of 2018 payable June 11, 2018 to stockholders of record at the close of business on May 16, 2018.

As of March 31, 2018, we plan to make contributions of up to $36 million to our funded pension plans during the remainder of 2018.

Contractual Cash Obligations

As of March 31, 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

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.

There have been no significant changes to our environmental matters and other contingencies subsequent to December 31, 2017. See Note 20 to the consolidated financial statements for a description of other contingencies.

Forward-Looking Statements

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). 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;


•	capital available for exploration and development;


•	the inability of any party to satisfy closing conditions 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

For a detailed discussion of our risk management strategies and our derivative instruments, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk in our 2017 Annual Report on Form 10-K. Notes 12 and 13 to the consolidated financial statements include additional disclosures regarding our open derivative positions, including underlying notional quantities, how they are reported in our consolidated financial statements and how their fair values are measured.

Commodity Price Risk During the first three months of 2018, we entered into crude oil and natural gas derivatives, indexed to NYMEX WTI and Henry Hub, related to a portion of our forecasted United States E&P sales. The following tables provide a summary of open positions as of March 31, 2018 and the weighted average price for those contracts:



Crude Oil
	2018			2019				2020
	Second Quarter	Third Quarter	Fourth Quarter	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Full Year
Three-Way Collars
Volume (Bbls/day)	85,000	95,000	95,000	40,000	40,000	10,000	10,000	—
Weighted average price per Bbl:
Ceiling	$56.38	$57.65	$57.65	$66.46	$66.46	$70.00	$70.00	—
Floor	$51.65	$52.11	$52.11	$53.50	$53.50	$52.00	$52.00	—
Sold put	$45.00	$45.21	$45.21	$46.25	$46.25	$45.00	$45.00	—
Swaps
Volume (Bbls/day)	20,000	—	—	—	—	—	—	—
Weighted average price per Bbl	55.12	—	—	—	—	—	—	—
Basis Swaps ^(a)
Volume (Bbls/day)	5,000	10,000	10,000	10,000	10,000	10,000	10,000	5,000
Weighted average price per Bbl	$(0.60)	$(0.67)	$(0.67)	$(0.82)	$(0.82)	$(0.82)	$(0.82)	$(0.25)


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



Natural Gas
	2018
	Second Quarter	Third Quarter	Fourth Quarter
Three-Way Collars
Volume (MMBtu/day)	160,000	160,000	160,000
Weighted average price per MMBtu:
Ceiling	$3.61	$3.61	$3.61
Floor	$3.00	$3.00	$3.00
Sold put	$2.50	$2.50	$2.50

The following table provides a sensitivity analysis of the projected incremental effect on income (loss) from operations of a hypothetical 10% change in NYMEX WTI and Henry Hub prices on our open commodity derivative instruments as of March 31, 2018.



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

Crude oil derivatives	$	(174	)	$	154
Natural gas derivatives	(6		)	6
Total	$	(180	)	$	160

Interest Rate Risk Our portfolio of long-term debt is substantially comprised of fixed rate instruments. 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. Sensitivity analysis of the incremental effect of a hypothetical 10% change in interest rates on our financial assets and liabilities as of March 31, 2018, is provided in the following table.



(In millions)	Fair Value				Hypothetical Price Increase of 10%	Hypothetical Price Decrease of 10%
Financial assets (liabilities): ^(a)
Long term debt, including amounts due within one year	$	(5,841	)	^(b)(c)	193	$	(205	)


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


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


^(c)	Excludes capital leases.

Counterparty Risk We are also exposed to financial risk in the event of nonperformance by counterparties. If commodity prices fall below current levels, some of our counterparties may experience liquidity problems and may not be able to meet their financial obligations to us. We review the creditworthiness of counterparties and use master netting agreements when appropriate.

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 March 31, 2018.

During the first three 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

See Note 20 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 March 31, 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)
01/01/18 - 01/31/18	10,701	$17.38	—	$	1,500,285,529
02/01/18 - 02/28/18	43,029	$15.40	—	$	1,500,285,529
03/01/18 - 03/31/18	505,360	$14.54	—	$	1,500,285,529
Total	559,090	$14.66	—


^(a)	559,090 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

^(b)

In January 2006, we announced a $2.0 billion share repurchase program. Our Board of Directors subsequently increased the authorization for repurchases under the program by $500 million in January 2007, by $500 million in May 2007, by $2.0 billion in July 2007, and by $1.2 billion in December 2013, for a total authorized amount of $6.2 billion. The remaining share repurchase authorization as of March 31, 2018 is $1.5 billion. No repurchases were made under the program in the first quarter of 2018.

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.



May 3, 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	10-Q	3.1	8/8/2013
3.2	Marathon Oil Corporation By-laws (amended and restated as of February 24, 2016)	8-K	3.1	3/1/2016
3.3	Specimen of Common Stock Certificate	10-K	3.3	2/28/2014
4.1	Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the SEC upon its request.	10-K	4.2	2/28/2014
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.