10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended June 30, 2018

OR

[   ]	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 filero	Non-accelerated filer o	(Do not check if a smaller reporting company)
Smaller reporting companyo	Emerging growth company o

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

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

There were 854,147,498 shares of Marathon Oil Corporation common stock outstanding as of July 31, 2018.

MARATHON OIL CORPORATION

Unless the context otherwise indicates, references to “Marathon Oil,” “we,” “our,” or “us” in this Form 10-Q are references to Marathon Oil Corporation, including its wholly owned and majority-owned subsidiaries, and its ownership interests in equity method investees (corporate entities, partnerships, limited liability companies and other ventures over which Marathon Oil exerts significant influence by virtue of its ownership interest).

For certain industry specific terms used in this Form 10-Q, please see “Definitions” in our 2017 Annual Report on Form 10-K.

	Table of Contents
		Page
Part I - FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Consolidated Statements of Income (Unaudited)	2
	Consolidated Statements of Comprehensive Income (Unaudited)	3
	Consolidated Balance Sheets (Unaudited)	4
	Consolidated Statements of Cash Flows (Unaudited)	5
	Notes to Consolidated Financial Statements (Unaudited)	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	45
Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 6.	Exhibits	46
	Signatures	47

1

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions, except per share data)	2018			2017			2018			2017
Revenues and other income:
Revenues from contracts with customers	$	1,447		$	902		$	2,984		$	1,775
Net gain (loss) on commodity derivatives	(152		)	56			(254		)	137
Marketing revenues	—			35			—			69
Income from equity method investments	60			51			97			120
Net gain (loss) on disposal of assets	50			6			307			7
Other income	12			9			16			23
Total revenues and other income	1,417			1,059			3,150			2,131
Costs and expenses:
Production	205			178			422			331
Marketing, including purchases from related parties	—			38			—			72
Shipping, handling and other operating	126			111			256			200
Exploration	65			30			117			58
Depreciation, depletion and amortization	612			592			1,202			1,148
Impairments	34			—			42			4
Taxes other than income	65			45			129			84
General and administrative	105			90			205			187
Total costs and expenses	1,212			1,084			2,373			2,084
Income (loss) from operations	205			(25		)	777			47
Net interest and other	(65		)	(86		)	(110		)	(164		)
Other net periodic benefit costs	—			(1		)	(3		)	(11		)
Income (loss) from continuing operations before income taxes	140			(112		)	664			(128		)
Provision (benefit) for income taxes	44			41			212			75
Income (loss) from continuing operations	96			(153		)	452			(203		)
Income (loss) from discontinued operations	—			14			—			(4,893		)
Net income (loss)	$	96		$	(139	)	$	452		$	(5,096	)
Per basic share:
Income (loss) from continuing operations	$	0.11		$	(0.18	)	$	0.53		$	(0.24	)
Income (loss) from discontinued operations	$	—		$	0.02		$	—		$	(5.76	)
Net income (loss)	$	0.11		$	(0.16	)	$	0.53		$	(6.00	)
Per diluted share:
Income (loss) from continuing operations	$	0.11		$	(0.18	)	$	0.53		$	(0.24	)
Income (loss) from discontinued operations	$	—		$	0.02		$	—		$	(5.76	)
Net income (loss)	$	0.11		$	(0.16	)	$	0.53		$	(6.00	)
Dividends per share	$	0.05		$	0.05		$	0.10		$	0.10
Weighted average common shares outstanding:
Basic	854			850			853			850
Diluted	855			850			854			850

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

2

MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income (Unaudited)

	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2018		2017			2018		2017
Net income (loss)	$	96	$	(139	)	$	452	$	(5,096	)
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	13		8			17		12
Postretirement and postemployment plans, net of tax	13		8			17		12
Derivative hedges
Net unrecognized gain (loss)	—		(14		)	—		(13		)
Derivative hedges, net of tax	—		(14		)	—		(13		)
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	4		—			4		—
Other comprehensive income (loss)	17		(6		)	21		29
Comprehensive income (loss)	$	113	$	(145	)	$	473	$	(5,067	)

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

3

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)

	June 30,			December 31,
(In millions, except per share data)	2018			2017
Assets
Current assets:
Cash and cash equivalents	$	1,667		$	563
Receivables, less reserve of $8and $12	1,176			1,082
Notes receivable	—			748
Inventories	117			126
Other current assets	92			36
Current assets held for sale	35			11
Total current assets	3,087			2,566
Equity method investments	788			847
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $22,336 and $21,564	16,881			17,665
Goodwill	98			115
Other noncurrent assets	860			764
Noncurrent assets held for sale	157			55
Total assets	$	21,871		$	22,012
Liabilities
Current liabilities:
Accounts payable	$	1,428		$	1,395
Payroll and benefits payable	109			108
Accrued taxes	99			177
Other current liabilities	405			288
Current liabilities held for sale	3			—
Total current liabilities	2,044			1,968
Long-term debt	5,497			5,494
Deferred tax liabilities	237			833
Defined benefit postretirement plan obligations	311			362
Asset retirement obligations	1,364			1,428
Deferred credits and other liabilities	194			217
Noncurrent liabilities held for sale	92			2
Total liabilities	9,739			10,304
Commitments and contingencies
Stockholders’ Equity
Preferred stock – no shares issued or outstanding (no par value, 26 million shares authorized)	—			—
Common stock:
Issued – 937 million shares and 937 million shares (par value $1 per share, 1.925 billion shares authorized at June 30, 2018 and 1.1 billion shares authorized at December 31, 2017)	937			937
Held in treasury, at cost – 83 million and 87 million shares	(3,137		)	(3,325		)
Additional paid-in capital	7,227			7,379
Retained earnings	7,146			6,779
Accumulated other comprehensive loss	(41		)	(62		)
Total stockholders' equity	12,132			11,708
Total liabilities and stockholders' equity	$	21,871		$	22,012

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

4

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)

	Six Months Ended
	June 30,
(In millions)	2018			2017
Operating activities:
Net income (loss)	$	452		$	(5,096	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations	—			4,893
Depreciation, depletion and amortization	1,202			1,148
Impairments	42			4
Exploratory dry well costs and unproved property impairments	93			45
Net (gain) loss on disposal of assets	(307		)	(7		)
Deferred income taxes	(6		)	38
Net (gain) loss on derivative instruments	254			(140		)
Net settlements of derivative instruments	(166		)	3
Pension and other postretirement benefits, net	(51		)	(25		)
Stock based compensation	28			26
Equity method investments, net	27			61
Changes in:
Current receivables	(256		)	(15		)
Inventories	(17		)	(5		)
Current accounts payable and accrued liabilities	133			(41		)
All other operating, net	(12		)	34
Net cash provided by operating activities from continuing operations	1,416			923
Investing activities:
Additions to property, plant and equipment	(1,300		)	(775		)
Additions to other assets	(129		)	—
Acquisitions, net of cash acquired	(25		)	(1,828		)
Disposal of assets, net of cash transferred to buyer	1,183			1,726
Equity method investments - return of capital	32			49
All other investing, net	7			(5		)
Net cash provided by (used in) investing activities from continuing operations	(232		)	(833		)
Financing activities:
Debt repayments	—			(1		)
Purchases of common stock	(11		)	(10		)
Dividends paid	(85		)	(85		)
All other financing, net	18			—
Net cash provided by (used in) financing activities	(78		)	(96		)
Net increase in cash and cash equivalents of discontinued operations (Note 5)	—			130
Effect of exchange rate on cash and cash equivalents	(2		)	2
Net increase in cash and cash equivalents	1,104			126
Cash and cash equivalents at beginning of period	563			2,488
Cash and cash equivalents at end of period	$	1,667		$	2,614

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

5

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 second quarter and first six months of2018 are not necessarily indicative of the results to be expected for the full year.

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

Reclassifications

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

2.   Accounting Standards

Not Yet Adopted

Lease accounting standard

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

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

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

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.

6

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

Financial instruments - credit losses

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

Recently Adopted

Revenue recognition standard

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

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

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

	Three Months Ended June 30, 2018
(In millions)	As reported		Adjustments			Presentation without adoption of ASC Topic 606
Revenues and other income:
Revenues from contracts with customers	$	1,447	$	—		$	1,447
Marketing revenues	—		43			43
Other income	12		(1		)	11
Costs and expenses:
Marketing, including purchases from related parties	$	—	$	44		$	44
Shipping, handling and other operating	126		(2		)	124

7

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	Six Months Ended June 30, 2018
(In millions)	As reported		Adjustments			Presentation without adoption of ASC Topic 606
Revenues and other income:
Revenues from contracts with customers	$	2,984	$	(2	)	$	2,982
Marketing revenues	—		75			75
Other income	16		(2		)	14
Costs and expenses:
Marketing, including purchases from related parties	$	—	$	76		$	76
Shipping, handling and other operating	256		(5		)	251

Pension accounting standard

In the first quarter of 2018, we adopted the new accounting standards update that changes how employers that sponsor defined pension and/or other postretirement benefit plans present the net periodic benefit cost in the income statement. As a result, employers are required to present the service cost component of net periodic benefit cost in the same income statement line item(s) as other employee compensation costs arising from services rendered during the period. We adopted this standard on a retrospective basis, and reclassified the required cost elements from general and administrative expense into production expense, exploration expense, and other net periodic benefit costs. The adoption of this standard did not have a significant impact on our consolidated balance sheet or statement of cash flows. The following tables summarize the impacts of adopting this standard on our historical consolidated income statement for the three and six months period ended June 30, 2017.

	Three Months Ended June 30, 2017
(In millions)	Previously Reported			As reclassified			Effect of Change Higher/(Lower)
Production	$	176		$	178		$	2
Exploration	30			30			—
General and administrative	93			90			(3		)
Income (loss) from operations	(26		)	(25		)	1
Other net periodic benefit costs (a)	—			1			1

	Six Months Ended June 30, 2017
(In millions)	Previously Reported		As reclassified		Effect of Change Higher/(Lower)
Production	$	327	$	331	$	4
Exploration	58		58		—
General and administrative	202		187		(15		)
Income from operations	36		47		11
Other net periodic benefit costs (a)	—		11		11

^(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.

8

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Presentation of restricted cash in the statement of cash flows

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

Accounting for sale or transfer of nonfinancial assets

In February 2017, the FASB issued a new accounting standards update that clarifies the accounting for the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. The standard also clarifies that the derecognition of all businesses (except those related to conveyances of oil and gas mineral rights or contracts with customers) should be accounted for in accordance with the derecognition and deconsolidation guidance in Subtopic 810-10. This standard was effective for us in the first quarter of 2018, and was applied using the modified retrospective approach. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

Definition of a business

In January 2017, the FASB issued a new accounting standards update that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires us to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities would not represent a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described in the new revenue guidance. This standard was effective for us in the first quarter of 2018, and was applied prospectively. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

Financial instruments updates

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

9

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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 6 million and 8 million of stock options for the three and six months period ended June 30, 2018 and 12 million stock options for the three and six months period ended June 30, 2017 that were antidilutive.

	Three Months Ended June 30,					Six Months Ended June 30,
(In millions, except per share data)	2018		2017			2018		2017
Income (loss) from continuing operations	$	96	$	(153	)	$	452	$	(203	)
Income (loss) from discontinued operations	—		14			—		(4,893		)
Net income (loss)	$	96	$	(139	)	$	452	$	(5,096	)
Weighted average common shares outstanding	854		850			853		850
Effect of dilutive securities	1		—			1		—
Weighted average common shares, diluted	855		850			854		850
Per basic share:
Income (loss) from continuing operations	$	0.11	$	(0.18	)	$	0.53	$	(0.24	)
Income (loss) from discontinued operations	$	—	$	0.02		$	—	$	(5.76	)
Net income	$	0.11	$	(0.16	)	$	0.53	$	(6.00	)
Per diluted share:
Income (loss) from continuing operations	$	0.11	$	(0.18	)	$	0.53	$	(0.24	)
Income (loss) from discontinued operations	$	—	$	0.02		$	—	$	(5.76	)
Net income	$	0.11	$	(0.16	)	$	0.53	$	(6.00	)

4. Acquisitions

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

5. Dispositions

United States E&P Segment

In the second quarter of 2018, we entered into separate agreements to sell non-core, non-operated conventional properties, primarily in the Gulf of Mexico, for combined net proceeds of $16 million, before closing adjustments. These transactions met the criteria for assets held for sale which is reflected in the consolidated balance sheet at June 30, 2018, with total assets of $53 million and total liabilities, relating to asset retirement obligations, of $80 million. These transactions closed during July of 2018.

International E&P Segment

In the second quarter of 2018, we entered into an agreement to sell a non-core property for proceeds of $56 million, before closing adjustments. This property is classified as held for sale in the consolidated balance sheet at June 30, 2018, with total assets of $77 million, total liabilities of $11 million and expected to close during 2018.

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 for combined proceeds of $53 million, before closing adjustments. We closed on one of the asset sales in the fourth quarter of 2017 and recognized no pre-tax gain or loss on sale. The remaining asset sale is expected to close during 2018 and is classified as held for sale in the consolidated balance sheet as of June 30, 2018, with total assets of $62 million and total liabilities of $4 million.

10

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. At closing we received two notes receivable for a combined $750 million for the remaining proceeds, which was received in the first quarter of 2018. In the first quarter of 2017, we recorded a non-cash impairment charge of $6.6 billion (after-tax of $4.96 billion) primarily related to the property, plant and equipment of our Canadian business. This impairment was recorded for excess net book value over anticipated sales proceeds less costs to sell. Fair values of assets held for sale were determined based upon the anticipated sales proceeds less costs to sell, which resulted in a Level 2 classification. As the effective date of the transaction was January 1, 2017, we recorded a loss on sale of $43 million during the second quarter of 2017 due to 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 and consolidated statements of cash flows as discontinued operations:

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)		2018		2017			2018		2017
Total revenue and other income		$	—	$	173		$	—	$	431
Net gain (loss) on disposal of assets		—		(43		)	—		(43		)
Total revenues and other income		—		130			—		388
Costs and expenses:
Production		—		103			—		254
Depreciation, depletion and amortization		—		1			—		40
Impairments		—		—			—		6,636
Other		—		12			—		25
Total costs and expenses		—		116			—		6,955
Pretax income (loss) from discontinued operations		—		14			—		(6,567		)
Provision (benefit) for income taxes		—		—			—		(1,674		)
Income (loss) from discontinued operations		$	—	$	14		$	—	$	(4,893	)

	Six Months Ended June 30,
(In millions)	2018		2017
Cash flow from discontinued operations:
Operating activities	$	—	$	141
Investing activities	—		(13		)
Changes in cash included in current assets held for sale	—		2
Net increase in cash and cash equivalents of discontinued operations	$	—	$	130

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.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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

	Three Months Ended June 30, 2018
United States E&P							Northern
(In millions)	Eagle Ford		Bakken		Oklahoma		Delaware		Other U.S.		Total
Crude oil and condensate	$	394	$	405	$	111	$	59	$	44	$	1,013
Natural gas liquids	45		17		45		6		2		115
Natural gas	33		8		38		2		5		86
Other	1		—		—		—		6		7
Revenues from contracts with customers	$	473	$	430	$	194	$	67	$	57	$	1,221

	Three Months Ended June 30, 2018
International E&P							Other
(In millions)	E.G.		U.K.		Libya		International		Total
Crude oil and condensate	$	100	$	71	$	—	$	22	$	193
Natural gas liquids	1		3		—		—		4
Natural gas	10		12		—		—		22
Other	—		7		—		—		7
Revenues from contracts with customers	$	111	$	93	$	—	$	22	$	226

	Six Months Ended June 30, 2018
United States E&P							Northern
(In millions)	Eagle Ford		Bakken		Oklahoma		Delaware		Other U.S.		Total
Crude oil and condensate	$	760	$	735	$	226	$	114	$	97	$	1,932
Natural gas liquids	87		32		82		12		5		218
Natural gas	66		18		81		7		12		184
Other	3		—		—		—		9		12
Revenues from contracts with customers	$	916	$	785	$	389	$	133	$	123	$	2,346

	Six Months Ended June 30, 2018
International E&P							Other
(In millions)	E.G.		U.K.		Libya		International		Total
Crude oil and condensate	$	171	$	166	$	187	$	45	$	569
Natural gas liquids	2		3		—		—		5
Natural gas	19		20		9		—		48
Other	—		16		—		—		16
Revenues from contracts with customers	$	192	$	205	$	196	$	45	$	638

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

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

midstream entity, and other contractual mechanisms (e.g., price adjustments) are used when products do not meet those specifications.

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

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

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

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

Crude oil and condensate

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

Natural gas and NGLs

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

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

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

Contract receivables and assets

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

(In millions)	June 30, 2018		January 1, 2018
Receivables from contracts with customers, which are included in receivables, less reserves	$	836	$	811
Contract asset	$	33	$	—

The contract asset represents crude oil delivered in the U.K. to a customer for which payment will be collected over time as it becomes due under the pricing terms stipulated in the sales agreement. As a practical expedient, when the balance of this U.K. customer is a contract asset, we do not adjust revenue for the effects of a significant financing element as the period

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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.

	Six Months Ended
(In millions)	June 30, 2018
Contract asset balance as of January 1, 2018	$	—
Revenue recognized as performance obligations are satisfied	86
Amounts invoiced to customers	(53		)
Contract asset balance as of June 30, 2018	$	33

7.    Segment Information

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

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

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

Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”).  Segment income (loss) represents income (loss) which excludes certain items not allocated to our operating segments, net of income taxes. A portion of our corporate and operations general and administrative support costs are not allocated to the operating segments. These unallocated costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Additionally, items which affect comparability such as: gains or losses on dispositions, certain impairments, unrealized gains or losses on commodity derivative instruments, pension settlement losses or other items (as determined by the CODM) are not allocated to operating segments.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	Three Months Ended June 30, 2018
							Not Allocated
(In millions)	U.S. E&P			Int'l E&P			to Segments				Total
Revenues from contracts with customers	$	1,221		$	226		$	—			$	1,447
Net gain (loss) on commodity derivatives	(107		)	—			(45		)	(b)	(152		)
Income from equity method investments	—			60			—				60
Net gain (loss) on disposal of assets	—			—			50				50
Other income	2			2			8				12
Less:
Production expenses	153			52			—				205
Shipping, handling and other operating	117			10			(1		)		126
Exploration	64			1			—				65
Depreciation, depletion and amortization	556			50			6				612
Impairments	—			—			34			(c)	34
Taxes other than income	68			—			(3		)		65
General and administrative	35			9			61				105
Net interest and other	—			—			65				65
Other net periodic benefit costs	—			(2		)	2			(d)	—
Income tax provision (benefit)	—			26			18				44
Segment income (loss) / Income (loss) from continuing operations	$	123		$	142		$	(169	)		$	96
Capital expenditures (a)	$	641		$	16		$	5			$	662

^(a)  Includes accruals.

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

^(c)  Primarily a result of anticipated sales of certain non-core proved properties in our International and United States E&P segments (See Note 11).

^(d)  Includes pension settlement loss of $2 million (See Note 16).

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	Three Months Ended June 30, 2017
							Not Allocated
(In millions)	U.S. E&P			Int'l E&P			to Segments				Total
Revenues from contracts with customers	$	682		$	220		$	—			$	902
Net gain (loss) on commodity derivatives	13			—			43			(b)	56
Marketing revenues	7			28			—				35
Income from equity method investments	—			51			—				51
Net gain on disposal of assets	—			—			6				6
Other income	2			4			3				9
Less:
Production expenses	118			60			—				178
Marketing costs	9			29			—				38
Shipping, handling and other operating	96			13			2				111
Exploration	30			—			—				30
Depreciation, depletion and amortization	495			89			8				592
Taxes other than income	33			—			12				45
General and administrative	30			9			51				90
Net interest and other	—			—			86				86
Other net periodic benefit costs	—			(2		)	3			(c)	1
Income tax provision (benefit)	—			46			(5		)		41
Segment income (loss) / Income (loss) from continuing operations	$	(107	)	$	59		$	(105	)		$	(153	)
Capital expenditures (a)	$	575		$	14		$	10			$	599

^(a)  Includes accruals.

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

^(c)  Includes pension settlement loss of $3 million (See Note 16).

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	Six Months Ended June 30, 2018
							Not Allocated
(In millions)	U.S. E&P			Int'l E&P			to Segments				Total
Revenues from contracts with customers	$	2,346		$	638		$	—			$	2,984
Net gain (loss) on commodity derivatives	(166		)	—			(88		)	(b)	(254		)
Income from equity method investments	—			97			—				97
Net gain (loss) on disposal of assets	—			—			307			(c)	307
Other income	5			3			8				16
Less:
Production expenses	304			119			(1		)		422
Shipping, handling and other operating	228			29			(1		)		256
Exploration	115			2			—				117
Depreciation, depletion and amortization	1,084			104			14				1,202
Impairments	—			—			42			(d)	42
Taxes other than income	132			—			(3		)		129
General and administrative	71			18			116				205
Net interest and other	—			—			110				110
Other net periodic benefit costs	—			(4		)	7			(e)	3
Income tax provision (benefit)	3			196			13				212
Segment income (loss) / Income (loss) from continuing operations	$	248		$	274		$	(70	)		$	452
Capital expenditures (a)	$	1,252		$	22		$	10			$	1,284

^(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)  Primarily a result of anticipated sales of certain non-core proved properties in our International and United States E&P segments (See Note 11).

^(e)  Includes pension settlement loss of $6 million (See Note 16).

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	Six Months Ended June 30, 2017
							Not Allocated
(In millions)	U.S. E&P			Int'l E&P			to Segments				Total
Revenue from contracts with customers	$	1,352		$	423		$	—			$	1,775
Net gain (loss) on commodity derivatives	17			—			120			(b)	137
Marketing revenues	13			56			—				69
Income from equity method investments	—			120			—				120
Net gain (loss) on disposal of assets	1			—			6				7
Other income	6			14			3				23
Less:
Production expenses	227			104			—				331
Marketing costs	16			56			—				72
Shipping, handling and other operating	170			28			2				200
Exploration	56			2			—				58
Depreciation, depletion and amortization	967			164			17				1,148
Impairments	4			—			—				4
Taxes other than income	72			—			12				84
General and administrative	63			15			109				187
Net interest and other	—			—			164				164
Other net periodic benefit costs	—			(4		)	15			(c)	11
Income tax provision (benefit)	—			96			(21		)		75
Segment income (loss) / Income (loss) from continuing operations	$	(186	)	$	152		$	(169	)		$	(203	)
Capital expenditures (a)	$	924		$	23		$	11			$	958

^(a)  Includes accruals.

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

^(c)  Includes pension settlement loss of $17 million (See Note 16).

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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 second quarter and six months ended June 30, 2018 and 2017, our effective income tax rates from continuing operations were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Effective income tax expense (benefit) rate from continuing operations	31	%	37	%	32	%	59	%

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

• Income taxes for the second quarter 2018 were impacted by foreign currency revaluation. During the six months ended June 30, 2018 income taxes were impacted by tax expense in Libya of $162 million, and we maintained our valuation allowance on our net federal deferred tax assets in the U.S.

• Income taxes for the second quarter 2017 were impacted by tax expense in Libya of $32 million. During the six months ended June 30, 2017, we incurred tax expense in Libya of $77 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 10% and a benefit of 1% for the six months ended June 30, 2018 and 2017. As a result of the sale of our Libya subsidiary in the first quarter of 2018, see Note 5 for further detail, we do not expect to incur further tax expense related to our Libya subsidiary. During 2018 and 2017, income taxes for Libya were recorded as a discrete item due to the uncertainty around the timing of future production and sales volumes.

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 ("AMT"), and a one-time deemed repatriation of accumulated foreign earnings. In the fourth quarter of 2017, we remeasured our deferred taxes at 21%, in accordance with U.S. GAAP standards. We plan to finalize certain tax positions when we file our 2017 federal tax return, and subsequently 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 second quarter of 2018, there are no material impacts on tax expense with respect to the finalization of tax positions taken due to Tax Reform Legislation.

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.

	June 30,		December 31,
(In millions)	2018		2017
Crude oil and natural gas	$	11	$	9
Supplies and other items	106		117
Inventories	$	117	$	126

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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

	June 30,		December 31,
(In millions)	2018		2017
United States E&P	$	15,953	$	15,867
International E&P	846		1,710
Corporate	82		88
Net property, plant and equipment	$	16,881	$	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 June 30, 2018 and December 31, 2017.

11. Impairments

The following table summarizes impairment charges of proved properties from continuing operations. Additionally, it presents the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.

	Three Months Ended June 30,
	2018				2017
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets	$	69	$	34	$	—	$	—

	Six Months Ended June 30,
	2018				2017
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets	$	69	$	42	$	—	$	4

• 2018 - During the first six months of 2018 we recorded pre-tax non-cash proved property impairments of $42 million, to a fair value of $69 million, primarily as a result of anticipated sales proceeds for certain non-core proved properties in our International and United States E&P segments. The related fair value measurement utilized the market approach, based upon anticipated sales proceeds less costs to sell which resulted in a Level 2 classification. See Note 5 for discussion of the divestitures in further detail.

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.

	June 30, 2018
(In millions)	Asset		Liability		Net Asset (Liability)			Balance Sheet Location
Not Designated as Hedges
Commodity	$	9	$	—	$	9		Other long-term assets
Commodity	—		231		$	(231	)	Other current liabilities
Commodity	—		6		$	(6	)	Deferred credits and other liabilities
Total Not Designated as Hedges	$	9	$	237	$	(228	)

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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

Derivatives Not Designated as Hedges

Terminated Interest Rate Swaps

During the third quarter of 2016, we entered into forward starting interest rate swaps to hedge the variations in cash flows related to fluctuations in long term interest rates from debt that were probable to be refinanced by us in 2018, specifically interest rate risk associated with future changes in the benchmark treasury rate. During the second quarter of 2017, we de-designated the forward starting interest rate swaps previously designated as cash flow hedges. In the third quarter of 2017, the forecasted transaction consummated and we issued $1 billion in senior unsecured notes. As a result, we terminated our forward starting interest rate swaps during the third quarter of 2017.

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 June 30,					Six Months Ended June 30,
(In millions)	2018		2017			2018		2017
Interest Rate Swaps
Beginning balance	$	—	$	61		$	—	$	60
Change in fair value recognized in other comprehensive income	—		(14		)	—		(13		)
Reclassification from other comprehensive income	—		(1		)	—		(1		)
Ending balance	$	—	$	46		$	—	$	46

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 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 June 30, 2018 and the weighted average prices for those contracts:

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Crude Oil	3Q 2018	4Q 2018	FY 2019	FY 2020
Three-Way Collars
Volume (Bbls/day)	95,000	95,000	50,000	—
Weighted average price per Bbl:
Ceiling	$57.65	$57.65	$71.74	—
Floor	$52.11	$52.11	$56.01	—
Sold put	$45.21	$45.21	$48.91	—
Basis Swaps (a)
Volume (Bbls/day)	10,000	10,000	10,000	15,000
Weighted average price per Bbl	$(0.67)	$(0.67)	$(0.82)	$(0.94)
Natural Gas	3Q 2018	4Q 2018
Three-Way Collars
Volume (MMBtu/day)	160,000	160,000
Weighted average price per MMBtu:
Ceiling	$3.61	$3.61
Floor	$3.00	$3.00
Sold put	$2.50	$2.50

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

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 and six month periods ended June 30, 2018 and 2017. The mark-to-market impact for the three and six month periods ended June 30, 2018 was a loss of $45 million and a loss of $88 million compared to a gain of $43 million and $120 million for the same respective periods in 2017. Net settlements of commodity derivative instruments for the three and six month periods ended June 30, 2018 was a loss of $107 million and $166 million compared to a gain of $13 million and $17 million for the respective periods in 2017.

13.  Fair Value Measurements

 Fair Values - Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of June 30, 2018 and December 31, 2017 by fair value hierarchy level.

	June 30, 2018
(In millions)	Level 1		Level 2			Level 3		Total
Derivative instruments, assets
Commodity (a)	$	48	$	—		$	—	$	48
Derivative instruments, assets	$	48	$	—		$	—	$	48
Derivative instruments, liabilities
Commodity (a)	$	—	$	(276	)	$	—	$	(276	)
Derivative instruments, liabilities	$	—	$	(276	)	$	—	$	(276	)

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

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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

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

Commodity derivatives include three-way collars and basis swaps. These instruments are measured at fair value using either a Black-Scholes or a modified Black-Scholes Model. For 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 - Goodwill

As of June 30, 2018, our consolidated balance sheet included goodwill of $98 million. Goodwill is tested for impairment on an annual basis, or between annual tests when events or changes in circumstances indicate the fair value may have been reduced below its carrying value. Goodwill is tested for impairment at the reporting unit level. Our reporting units are the same as our reporting segments, of which only International E&P includes goodwill. Our policy is to first assess the qualitative factors in order to determine whether the fair value of our International E&P reporting unit is more likely than not less than its carrying amount. Certain qualitative factors used in our evaluation include, among other things, the results of the most recent quantitative assessment of the goodwill impairment test, macroeconomic conditions; industry and market conditions (including commodity prices and cost factors); overall financial performance; and other relevant entity-specific events. If, after considering these events and circumstances we determined that it is more likely than not the fair value of the International E&P reporting unit is less than its carrying amount, a quantitative goodwill test is performed.

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

Fair Values – Nonrecurring

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

Fair Values – Financial Instruments

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

23

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The following table summarizes financial instruments, excluding receivables, payables and derivative financial instruments, and their reported fair values by individual balance sheet line item at June 30, 2018 and December 31, 2017.

	June 30, 2018				December 31, 2017
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Current assets (a)	$	48	$	48	$	762	$	761
Other noncurrent assets	85		89		135		137
Total financial assets	$	133	$	137	$	897	$	898
Financial liabilities
Other current liabilities	$	32	$	44	$	32	$	43
Long-term debt, including current portion (b)	5,791		5,528		5,976		5,526
Deferred credits and other liabilities	100		97		110		103
Total financial liabilities	$	5,923	$	5,669	$	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 June 30, 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 June 30, 2018, we were in compliance with this covenant with a debt-to-capitalization ratio of 31%.

Long-term debt

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

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

15.    Incentive Based Compensation

Stock options, restricted stock awards and restricted stock units

The following table presents a summary of activity for the first six months of 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	4,622,514			$14.57
Options Exercised/Stock Vested	(1,349,984	)			$13.52	(2,757,023	)		$15.87
Canceled	(1,667,972	)			$30.10	(531,203	)		$14.13
Outstanding at June 30, 2018	8,169,710				$25.41	8,907,133			$13.91

^(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 six 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 June 30,
	Pension Benefits						Other Benefits
(In millions)	2018			2017			2018			2017
Service cost	$	5		$	5		$	—		$	—
Interest cost	6			7			2			2
Expected return on plan assets	(8		)	(10		)	—			—
Amortization:
– prior service cost (credit)	(3		)	(2		)	(2		)	(1		)
– actuarial loss	3			2			1			—
Net settlement loss (a)	2			3			—			—
Net periodic benefit cost	$	5		$	5		$	1		$	1

	Six Months Ended June 30,
	Pension Benefits						Other Benefits
(In millions)	2018			2017			2018			2017
Service cost	$	9		$	11		$	1		$	1
Interest cost	13			15			4			4
Expected return on plan assets	(17		)	(22		)	—			—
Amortization:
– prior service cost (credit)	(5		)	(4		)	(4		)	(3		)
– actuarial loss	6			4			1			—
Net settlement loss (a)	6			17			—			—
Net periodic benefit cost	$	12		$	21		$	2		$	2

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

25

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

During the first six 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 six months of 2018, we made contributions of $42 million to our funded pension plans and we expect to make additional contributions up to an estimated $23 million over the remainder of 2018.  During the first six months of 2018, we made payments of $12 million and $11 million related to unfunded pension plans and other postretirement benefit plans.

17.  Reclassifications Out of Accumulated Other Comprehensive Loss

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

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2018			2017			2018			2017			Income Statement Line
Postretirement and postemployment plans
Amortization of prior service credit	$	5		$	3		$	9		$	7		Other net periodic benefit costs
Amortization of actuarial loss	(4		)	(2		)	(7		)	(4		)	Other net periodic benefit costs
Net settlement loss	(2		)	(3		)	(6		)	(17		)	Other net periodic benefit costs
Derivative hedges
Ineffective portion of derivative hedge	—			(1		)	—			(1		)	Net interest and other
	(1		)	(3		)	(4		)	(15		)	Income (loss) from continuing operations before income taxes
	—			—			—			—			(Provision) benefit for income taxes
Total reclassifications to expense, net of tax	(1		)	(3		)	(4		)	(15		)	Income (loss) from continuing operations
Other insignificant, net of tax	(4		)	—			(4		)	—			Net interest and other
Foreign currency hedges
Net recognized loss in discontinued operations, net of tax	—			—			—			(30		)	Income (loss) from discontinued operations
Total reclassifications to expense	$	(5	)	$	(3	)	$	(8	)	$	(45	)	Net income (loss)

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

18.  Supplemental Cash Flow Information

	Six Months Ended June 30,
(In millions)	2018			2017
Net cash (used in) operating activities:
Interest paid, net of amounts capitalized	$	(134	)	$	(193	)
Income taxes paid to taxing authorities	(282		)	(43		)
Noncash investing activities, related to continuing operations:
Notes receivable for disposal of assets	—			742

Other noncash investing activities include accrued capital expenditures as of June 30, 2018 and 2017 of $303 million and $338 million.

19. Equity Method Investments

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

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

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

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

Our equity method investments are summarized in the following table:

	Ownership as of	June 30,		December 31,
(In millions)	June 30, 2018	2018		2017
EGHoldings	60%	$	414	$	456
Alba Plant LLC	52%	189		214
AMPCO	45%	185		177
Total		$	788	$	847

Summarized financial information for equity method investees is as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2018		2017		2018		2017
Income data:
Revenues and other income	$	228	$	199	$	426	$	438
Income from operations	143		113		240		265
Net income	123		101		202		235

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 fourth quarter of 2017, we received notification from the U.K.’s First-tier Tribunal that the decommissioning cost deductions, which we had claimed, were not allowable. We are progressing our appeal against 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.  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

27

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. 

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

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

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

Executive Overview

We are an independent exploration and production company based in Houston, Texas focused on U.S. unconventional resource plays with operations in the United States, Europe and Africa. Total proved reserves were 1.4 billion boe at December 31, 2017, and total assets were $21.9 billion at June 30, 2018. During the second 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

• In July we closed on the sale of non-core, non-operated conventional assets in the U.S. E&P segment, including two in the Gulf of Mexico, further concentrating and simplifying the portfolio.

• We signed an agreement on the sale of our interest in the non-operated Atrush block in Kurdistan for proceeds of $56 million, and expect to close this transaction by the end of 2018 completing a full country exit.

• Resource play leasing and exploration capital expenditures totaled $154 million for the quarter and $248 million for the year, which were more than fully funded through the divestiture proceeds received in the first quarter 2018.

Liquidity

• At the end of the second quarter 2018, we had approximately $5.1 billion of liquidity, comprised of $1.7 billion in cash and an undrawn $3.4 billion revolving credit facility.

• In the first six months of 2018 cash provided by operating activities from continuing operations increased over 50% to $1,416 million as a result of increased price realizations and increased sales volumes in our U.S. resource plays.

Financial and operational results

• Total net sales volumes for the quarter increased to 419 mboed. This represents an increase in net sales volumes of 17% compared to the same quarter last year and includes an increase of over 40% from the U.S resource plays to 285 mboed.

• Wells to sales for the quarter increased over 35% in the U.S. resource plays compared to the same quarter last year.

• Our net income per share from continuing operations was $0.11 in the second quarter of 2018 as compared to a net loss per share of $0.18 in the same period last year. Included in net income results for the current quarter:

◦ An increase in revenues of approximately 60% to $1,447 million compared to the same quarter last year as a result of increased price realizations and increased sales volumes in our U.S. resource plays. Notably, the current quarter increased 60% compared to the same quarter last year even with the sale of our Libyan subsidiary in 2018.

◦ Net loss on commodity derivatives was $152 million compared to a net gain of $56 million in the same quarter last year due to the increases in current quarter index pricing as well as higher forecast long-term commodity prices.

◦ Total costs and expenses from operations, excluding impairments, increased 9% primarily as a result of sales mix and sales volumes which increased 17% during the quarter.

◦ Impairments of $34 million were primarily a result of anticipated sales of certain non-core proved properties in our

29

International and United States E&P segments during the quarter.

◦ Net interest and other decreasedby$21 million in the current quarter to $65 million primarily due to the reduction of total debt of approximately $1.75 billion in the second half of 2017.

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 June 30,			Six Months Ended June 30,
Net Sales Volumes	2018	2017	Increase (Decrease)	2018	2017	Increase (Decrease)
United States E&P (mboed)	298	222	34%	291	215	35%
International E&P (a)(mboed)	121	135	(10)%	133	131	2%
Total Continuing Operations (mboed)	419	357	17%	424	346	23%

^(a)   We closed on the sale of our subsidiary, Marathon Oil Libya Limited, which held our 16.33% non-operated interest in the Waha concessions in Libya in the first quarter of 2018. Three months ended June 30, 2017 includes net sales volumes relating to Libya of 11 mboed. Six months ended June 30, 2018 and 2017 includes net sales volumes relating to Libya of 16 mboedand 12 mboed.

United States E&P

Net sales volumes in the segment were higher in the second quarter 2018 primarily as a result of new wells to sales across all U.S. resource plays. The following tables provide details regarding net sales volumes, sales mix and operational drilling activity for our significant operations within this segment:

	Three Months Ended June 30,			Six Months Ended June 30,
Net Sales Volumes	2018	2017	Increase (Decrease)	2018	2017	Increase (Decrease)
Equivalent Barrels (mboed)
Eagle Ford	106	100	6%	105	100	5%
Bakken	82	49	67%	78	48	63%
Oklahoma	80	49	63%	77	46	67%
Northern Delaware	17	4	325%	17	2	750%
Other United States (a)	13	20	(35)%	14	19	(26)%
Total United States E&P	298	222	34%	291	215	35%

^(a)   The three and six months ended June 30, 2018 includes decreases of 3 mboed, relating to the disposition of certain conventional assets in Oklahoma in September 2017 and Colorado in October 2017.

	Three Months Ended June 30, 2018
Sales Mix - U.S. Resource Plays	Eagle Ford	Bakken	Oklahoma	Northern Delaware	Total
Crude oil and condensate	59%	84%	23%	63%	56%
Natural gas liquids	21%	9%	30%	20%	20%
Natural gas	20%	7%	47%	17%	24%

30

	Three Months Ended June 30,		Six Months Ended June 30,
	2018	2017	2018	2017
Gross Operated - U.S. Resource Plays
Eagle Ford:
Wells drilled to total depth	33	53	67	98
Wells brought to sales	39	41	73	88
Bakken:
Wells drilled to total depth	24	33	43	45
Wells brought to sales	21	2	32	6
Oklahoma:
Wells drilled to total depth	10	23	23	38
Wells brought to sales	17	20	34	32
Northern Delaware
Wells drilled to total depth	21	2	41	2
Wells brought to sales	13	2	22	2

• Eagle Ford– Our net sales volumes were 106 mboed in the second quarter of 2018 which was 6% higher compared to the prior year quarter. We continued to deliver impressive results from core Karnes County, where the six-well Karnes City NE pad delivered strong well results. We continued to generate strong cash flow in the quarter through a combination of well performance and oil realizations above WTI due to strong LLS-based pricing.

• Bakken– Our net sales volumes of 82 mboed represent a 67% increase over the prior year quarter of 49 mboed. We brought 21 gross company-operated wells to sales in the second quarter 2018, twelve of which were in core Hector which delivered strong well results. We continued our efforts to uplift performance outside the Myrmidon and Hector core, with enhanced completion techniques being applied for the first time in Elk Creek with the three-well Bear Den pad achieving impressive well performance. We remain in full compliance with state gas capture requirements, and anticipate no impact to forward development plans.

• Oklahoma– Our net sales volumes in the second quarter 2018 increased by 63% from the year ago quarter, with net sales volumes of 80 mboed. In the SCOOP, we brought on the four-well Woodford Lightner infill pad on 660-foot spacing across a half section, which exceeded expectations. In the STACK, four Meramec wells in the Siegrist infill pad achieved well results which met our expectations with strong oil rates. We also signed a firm transportation agreement for 100 million cubic feet per day, beginning in fourth quarter 2018, to protect near-term natural gas production and bridge to the start-up of the Midship Pipeline on which we are an anchor shipper.

• Northern Delaware – Our net sales volumes were 17 mboed in the second quarter 2018. We brought 13 gross company-operated wells to sales in the Malaga area in Eddy County. Drilling efficiencies enabled us to reduce our rig count from five to four in the second quarter 2018, without changing our full-year estimate of wells to sales. In June 2018, we executed an agreement with San Mateo for water gathering and disposal in Eddy County, which will significantly reduce unit production costs. We continue to benefit from our Midland-Cushing basis swaps, with open positions that include 10,000 bopd hedged for the second half of 2018 and all of 2019, and 15,000 bopd hedged for full-year 2020, all at a discount of less than $1 to WTI . See Note 12 to the consolidated financial statements for further information.

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International E&P

Net sales volumes were lower in the second quarter of 2018 compared to the second quarter of 2017 primarily due to the sale of our subsidiary 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 June 30,			Six Months Ended June 30,
Net Sales Volumes	2018	2017	Increase (Decrease)	2018	2017	Increase (Decrease)
Equivalent Barrels (mboed)
Equatorial Guinea	103	105	(2)%	98	104	(6)%
United Kingdom(a)	14	18	(22)%	15	14	7%
Libya	—	11	(100)%	16	12	33%
Other International	4	1	300%	4	1	300%
Total International E&P	121	135	(10)%	133	131	2%
Equity Method Investees
LNG (mtd)	6,141	6,243	(2)%	5,843	6,195	(6)%
Methanol (mtd)	1,316	1,182	11%	1,256	1,244	1%
Condensate & LPG (boed)	12,689	11,608	9%	12,553	13,069	(4)%

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

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

• United Kingdom – Second quarter2018 net sales volumes were lower compared to the second quarter of 2017 primarily due to the timing of liftings during the second quarter of 2018.

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

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Market Conditions

Crude oil and condensate and NGLs benchmarks increased in the second quarter and first six months of2018 as compared to the same period in 2017.

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 second quarter and first six months of2018 and 2017.

	Three Months Ended June 30,			Six Months Ended June 30,
	2018	2017	Increase (Decrease)	2018	2017	Increase (Decrease)
Average Price Realizations (a)
Crude oil and condensate (per bbl) (b)	$66.03	$45.81	44%	$64.16	$47.09	36%
Natural gas liquids (per bbl)	22.09	17.61	25%	22.49	18.46	22%
Natural gas (per mcf) (c)	2.18	3.05	(29)%	2.38	3.03	(21)%
Benchmarks
WTI crude oil average of daily prices (per bbl)	$67.91	$48.15	41%	$65.46	$49.95	31%
LLS crude oil average of daily prices (per bbl)	72.96	50.18	45%	69.48	51.77	34%
Mont Belvieu NGLs (per bbl) (d)	28.28	20.99	35%	27.29	21.95	24%
Henry Hub natural gas settlement date average (per mmbtu)	2.80	3.18	(12)%	2.90	3.25	(11)%

^(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 $(7.04) per bbl and $1.07 per bbl for the second quarter2018 and 2017 and $(5.71) and $0.72 per bbl for the first six months of 2018 and 2017.

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

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

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

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

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

International E&P

The following table presents our average price realizations and the related benchmark for crude oil for the second quarter and first six months of2018 and 2017.

	Three Months Ended June 30,			Six Months Ended June 30,
	2018	2017	Increase (Decrease)	2018	2017	Increase (Decrease)
Average Price Realizations
Crude oil and condensate (per bbl)	$66.12	$47.04	41%	$66.19	$48.58	36%
Natural gas liquids (per bbl)	2.91	1.77	64%	2.40	2.83	(15)%
Natural gas (per mcf)	0.52	0.57	(9)%	0.59	0.56	5%
Benchmark
Brent (Europe) crude oil (per bbl)(a)	$74.50	$49.67	50%	$70.65	$51.68	37%

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

United Kingdom

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

33

Equatorial Guinea

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

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

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

Results of Operations

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

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

	Three Months Ended June 30,
(In millions)	2018		2017
Revenues from contracts with customers
United States E&P	$	1,221	$	682
International E&P	226		220
Segment revenues from contracts with customers	$	1,447	$	902

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)	June 30, 2017		Price Realizations			Net Sales Volumes			June 30, 2018
United States E&P Price-Volume Analysis
Crude oil and condensate	$	524	$	310		$	179		$	1,013
Natural gas liquids	64		23			28			115
Natural gas	94		(34		)	26			86
Other sales	—								7
Total	$	682							$	1,221
International E&P Price-Volume Analysis
Crude oil and condensate	$	185	$	56		$	(48	)	$	193
Natural gas liquids	2		2			—			4
Natural gas	25		(2		)	(1		)	22
Other sales	8								7
Total	$	220							$	226

Net gain (loss) on commodity derivatives decreased$208 million in the second quarter of 2018 compared to the same period in 2017. We have multiple crude oil and natural gas derivative contracts indexed to NYMEX WTI and Henry Hub. We record commodity derivative gains/losses as the index pricing and forward curves change each period. See Note 12 to the consolidated financial statements for further information.

Marketing revenuesdecreased$35 million in the second 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.

Net gain on disposal of assetsincreased$44 million in the second quarter of 2018 primarily related to a gain on sale associated with an acreage swap in our United States E&P segment.

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Production expensesincreased$27 million in the second quarter of 2018 versus the same period in 2017 primarily due to higher sales volumes across our U.S. E&P segment. United States E&Pincreased$35 million primarily due to our entry into Northern Delaware late in the second quarter 2017, as well as new wells to sales across all U.S. resource plays. International E&P decreased$8 million primarily due to the timing of our U.K. liftings, which resulted in decreased sales volumes during the second quarter 2018.

The following table provides production expense rates for each segment:

	Three Months Ended June 30,
($ per boe)	2018		2017
Production Expense Rate
United States E&P		$5.66		$5.86
International E&P		$4.71		$4.86

Marketing costsdecreased$38 million in the second 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.

Shipping, handling and other operating expensesincreased$15 million in the second 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 expensesinclude unproved property impairments, dry well costs, geological and geophysical, and other, whichincreased$35 million in the second quarter of 2018. The increase in unproved property impairments is primarily due to leases that we decided not to drill or extend with near term expirations and as a result of increasing the number of leases in our portfolio through acquisition.

The following table summarizes the components of exploration expenses:

	Three Months Ended June 30,
(In millions)	2018		2017
Exploration Expenses
Unproved property impairments	$	41	$	25
Dry well costs	10		—
Geological and geophysical	8		—
Other	6		5
Total exploration expenses	$	65	$	30

Depreciation, depletion and amortizationincreased$20 million in the second quarter of 2018. United States E&P DD&A expense increased by $61 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 $39 million primarily due to the timing of our U.K. liftings, which resulted in decreased sales volumes during the second quarter 2018. 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 second 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 June 30,
($ per boe)	2018		2017
DD&A Rate
United States E&P		$20.48		$24.49
International E&P		$4.53		$7.23

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Impairmentsincreased$34 million in the second quarter of 2018. Impairments in the second quarter of 2018 were primarily a result of anticipated sales of certain non-core proved properties in our International and United States E&P segments. See Note 5 for discussion of the divestitures in further detail.

Taxes other than incomeincludes production, severance, and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. U.S. sales volumes and revenues increased during the second quarter of 2018, which resulted in an increase of $20 million versus the same period in 2017. This was partially offset by a reduction in the reserve for non-income tax examinations relating to open tax years. The following table summarizes the components of taxes other than income:

	Three Months Ended June 30,
(In millions)	2018		2017
Taxes other than income
Production and severance	$	50	$	23
Ad valorem	3		1
Other	12		21
Total taxes other than income	$	65	$	45

General and administrative increased$15 million in the second quarter of 2018 versus the same period in 2017. This was primarily the result of improved performance of stock-based performance units tied to our total shareholder return ("TSR") as compared to our peer group.

Net interest and otherdecreased$21 million in the second 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.

Provision (benefit) for income taxesreflects an effective tax rate from continuing operations of 31% in the second quarter of 2018, as compared to an effective tax rate of 37% in the second quarter of 2017. See Note 8 to the consolidated financial statements for more detail discussion concerning the rate changes.

Discontinued operationsare 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 June 30,
(In millions)	2018			2017
United States E&P	$	123		$	(107	)
International E&P	142			59
Segment income (loss)	265			(48		)
Items not allocated to segments, net of income taxes	(169		)	(105		)
Income (loss) from continuing operations	96			(153		)
Income (loss) from discontinued operations (a)	—			14
Net income (loss)	$	96		$	(139	)

^(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 segmentincome increased$230 million after-tax in the second quarter of 2018 primarily due to higher price realizations and an increase in sales volumes, which resulted in increased revenue. This increase in sales volumes resulted in a corresponding increase to production expenses, DD&A, taxes other than income, and shipping, handling and other operating expenses which partially offset the increase to revenues.

International E&P segmentincomeincreased$83 million after-tax in the second quarter of 2018 primarily due to higher price realizations partially offset by a decrease in sales volumes in the U.K. and Libya. This decrease in sales volumes resulted

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in lower production and DD&A expense. Additionally, our income tax provision decreased as a result of the sale of our Libya subsidiary in the first quarter of 2018, see Note 5 to the consolidated financial statements for further information.

Results of Operations

Six Months Ended June 30, 2018 vs. Six Months Ended June 30, 2017

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

	Six Months Ended June 30,
(In millions)	2018		2017
Revenues from contracts with customers
United States E&P	$	2,346	$	1,352
International E&P	638		423
Segment revenues from contracts with customers	$	2,984	$	1,775

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.

	Six Months Ended		Increase (Decrease) Related to						Six Months Ended
(In millions)	June 30, 2017		Price Realizations			Net Sales Volumes			June 30, 2018
United States E&P Price-Volume Analysis
Crude oil and condensate	$	1,039	$	514		$	379		$	1,932
Natural gas liquids	133		39			46			218
Natural gas	177		(51		)	58			184
Other sales	3								12
Total	$	1,352							$	2,346
International E&P Price-Volume Analysis
Crude oil and condensate	$	353	$	152		$	64		$	569
Natural gas liquids	6		—			(1		)	5
Natural gas	48		2			(2		)	48
Other sales	16								16
Total	$	423							$	638

Net gain (loss) on commodity derivatives decreased $391 million in the first six months of 2018 compared to the same period in 2017. We have multiple crude oil and natural gas derivative contracts indexed to NYMEX WTI and Henry Hub. We record commodity derivative gains/losses as the index pricing changes from period to period. See Note 12 to the consolidated financial statements for further information.

Marketing revenues for the first six months of 2018decreased by $69 million from the comparable 2017 period. This decrease is the result of adopting the new revenue standard, ASC Topic 606, Revenue from Contracts with Customers during the first quarter of 2018. As a result of this standard, we have changed our presentation of marketing revenues and marketing expenses from the historical gross presentation to a net presentation.

Income from equity method investmentsdecreased$23 million for the first six months 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 assetsincreased$300 million for the first six months of 2018 primarily related to the gain on sale of our subsidiary Marathon Oil Libya Limited, which holds a 16.33% non-operated interest in the Waha concessions in Libya, during the first quarter of 2018. See Note 5 to the consolidated financial statements for information about dispositions.

Production expenses for the first six months of 2018increased by $91 million compared to the same period in 2017 primarily due to higher sales volumes across all U.S. resource plays. United States E&Pincreased$77 million primarily due to new wells to sales across all U.S. resource plays including the Northern Delaware, where we began operating late in the second quarter of 2017. International E&P increased$15 million primarily due to the timing of our U.K. liftings.

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The first six months of 2018 production expense rate (expense per boe) was higher for International E&P due to sales volume mix within our segment and higher planned maintenance costs in E.G. due to planned maintenance activities during the first quarter 2018.

	Six Months Ended June 30,
($ per boe)	2018		2017
Production Expense Rate
United States E&P		$5.77		$5.82
International E&P		$4.91		$4.41

Marketing costsdecreased$72 million in the first six months of 2018 from the comparable 2017 period. This decrease is the result of adopting the new revenue standard, ASC Topic 606, Revenue from Contracts with Customers during the first quarter of 2018. As a result of this standard, we have changed our presentation of marketing revenues and marketing expenses from the historical gross presentation to a net presentation.

Shipping, handling and other operating expensesincreased$56 million in the first six months of 2018 from the comparable 2017 period, primarily due to an increase in our shipping and handling expenses as a result of increased sales volumes in our United States E&P segment.

Exploration expensesinclude unproved property impairments, dry well costs, geological and geophysical, and other, which increased$59 million in the first six months of 2018 versus the comparable 2017 period. The increase in unproved property impairments is primarily due to leases that we decided not to drill or extend with near term expirations and as a result of increasing the number of leases in our portfolio through acquisition.

The following table summarizes the components of exploration expenses:

	Six Months Ended June 30,
(In millions)	2018		2017
Exploration Expenses
Unproved property impairments	$	81	$	45
Dry well costs	12		—
Geological and geophysical	14		1
Other	10		12
Total exploration expenses	$	117	$	58

Depreciation, depletion and amortizationincreased$54 million in the first six months of 2018 from the comparable 2017 period primarily as a result of an increase of $117 million in the United States E&P segment primarily due to higher sales volumes across all U.S. resource plays, as well as our acquisition and development of Northern Delaware in 2017. Offsetting this higher expense was a decrease of $60 million in our International E&P segment as a result of the reduction of our asset retirement obligation by over $100 million in 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 field-level changes in sales volumes, reserves and capitalized costs, can also cause changes to our DD&A. The DD&A rate for the United States E&P segment decreased primarily due to increased proved developed reserves in our U.S. resource plays in 2017; as well as reduced capitalized costs relating to the Gulf of Mexico non-cash impairment charge in 2017. The DD&A rate for International E&P decreased with the reduction of our estimated U.K. asset retirement costs and sales volume mix changes. The following table provides DD&A rates for each segment.

	Six Months Ended June 30,
($ per boe)	2018		2017
DD&A Rate
United States E&P		$20.56		$24.81
International E&P		$4.31		$6.93

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Impairments increased$38 million in the first six months of 2018 from the comparable 2017 period. Impairments in the second quarter of 2018 were primarily a result of anticipated sales of certain non-core proved properties in our International and United States E&P segments. See Note 5 for discussion of the divestitures in further detail.

Taxes other than incomeinclude production, severance, and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. U.S. sales volumes and revenues increased in the first six months of 2018 which resulted in an increase of $45 million versus the comparable 2017 period. The following table summarizes the components of taxes other than income:

	Six Months Ended June 30,
(In millions)	2018		2017
Taxes other than income
Production and severance	$	93	$	48
Ad valorem	9		4
Other	27		32
Total taxes other than income	$	129	$	84

General and administrative expensesincreased$18 million in the first six months of 2018 compared to the same period in 2017. This was primarily the result of improved performance of stock-based performance units tied to our total shareholder return ("TSR") as compared to our peer group.

Net interest and otherdecreased$54 million in the first six months 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.

Provision (benefit) for income taxes reflects an effective tax rate from continuing operations of 32% in the first six months of 2018, as compared to an effective tax rate of 59% from the comparable 2017 period. See Note 8 to the consolidated financial statements for more detail discussion concerning the rate changes.

Discontinued operationsare 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):

	Six Months Ended June 30,
(In millions)	2018			2017
United States E&P	$	248		$	(186	)
International E&P	274			152
Segment income (loss)	522			(34		)
Items not allocated to segments, net of income taxes	(70		)	(169		)
Income (loss) from continuing operations	452			(203		)
Income (loss) from discontinued operations (a)	—			(4,893		)
Net income (loss)	$	452		$	(5,096	)

^(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$434 million after-tax in the first six months of 2018 from the comparable 2017 period primarily due to higher price realizations and an increase in sales volumes. Partially offsetting this increase was the loss related to commodity derivative positions in the first six months of 2018, as well as increased expenses such as DD&A, production expenses and shipping, handling and other operating expenses, which increase along with sales volumes.

International E&P segmentincomeincreased$122 million after-tax in the first six months of 2018 from the comparable 2017 period primarily due to higher price realizations. This increase in revenues resulted in an increase in our income tax

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provision which partially offset the increase to revenues. Additionally, DD&A expenses decreased in the first six months of 2018 as a result of lower estimated U.K. asset retirement costs as discussed above.

Critical Accounting Estimates

There have been no material changes or developments in the evaluation of the accounting estimates and the underlying assumptions or methodologies pertaining to our Critical Accounting Estimates disclosed in our Form 10-K for the year ended December 31, 2017, except as discussed below.

Fair Value Estimates - Goodwill

As of June 30, 2018, our consolidated balance sheet included goodwill of $98 million. Goodwill is tested for impairment on an annual basis, or between annual tests when events or changes in circumstances indicate the fair value may have been reduced below its carrying value. Goodwill is tested for impairment at the reporting unit level. Our reporting units are the same as our reporting segments, of which only International E&P includes goodwill. Our policy is to first assess the qualitative factors in order to determine whether the fair value of our International E&P reporting unit is more likely than not less than its carrying amount. Certain qualitative factors used in our evaluation include, among other things, the results of the most recent quantitative assessment of the goodwill impairment test, macroeconomic conditions; industry and market conditions (including commodity prices and cost factors); overall financial performance; and other relevant entity-specific events. If, after considering these events and circumstances we determine that it is more likely than not the fair value of the International E&P reporting unit is less than its carrying amount, the quantitative goodwill test is performed.

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

See Note 13 to the consolidated financial statements for further information regarding our annual goodwill impairment test.

Fair Value Estimates - Impairment Assessments of Long-Lived Assets

Due to the anticipated sales of certain non-core proved properties in our International and United States E&P segments we assessed certain non-core long-lived assets for impairment. The fair values were measured using the market approach based upon anticipated sales proceeds less costs to sell, resulting in impairments of $42 million during the first six months of 2018. See Note 11 to the consolidated financial statements for further impairment information.

Accounting Standards Not Yet Adopted

See Note 2 to the consolidated financial statements.

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Cash Flows

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

	Six Months Ended June 30,
(In millions)	2018			2017
Sources of cash and cash equivalents
Operating activities - continuing operations	$	1,416		$	923
Disposal of assets, net of cash transferred to the buyer	1,183			1,726
Other	57			51
Total sources of cash and cash equivalents	$	2,656		$	2,700
Uses of cash and cash equivalents
Cash additions to property, plant and equipment	$	(1,300	)	$	(775	)
Additions to other assets	(129		)	—
Acquisitions, net of cash acquired	(25		)	(1,828		)
Dividends paid	(85		)	(85		)
Other	(13		)	(16		)
Total uses of cash and cash equivalents	$	(1,552	)	$	(2,704	)

Cash flows generated from operating activities in the first six months of 2018 were higher as commodity prices and price realizations improved compared to the first six months of 2017. Consolidated average crude oil and condensate price realizations increased by approximately 36% during the first six months of 2018 as compared to the prior period. This increase in price realizations and net sales volumesresulted in increased cash flows generated from operating activities.

Proceeds from the disposals of assets for the first six months of 2018 are primarily from the disposal of our non-operated interest in Libya and the remaining proceeds of $750 million from the 2017 sale of our Canadian business. Proceeds from the disposal of assets for the first six months of 2017 are from the disposal 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 six months of 2018 were consistent with expectations relative to our $2.3 billion Development Capital Program. The following table shows capital expenditures related to continuing operations by segment and reconciles to additions to property, plant and equipment as presented in the consolidated statements of cash flows:

	Six Months Ended June 30,
(In millions)	2018		2017
United States E&P	$	1,252	$	924
International E&P	22		23
Corporate	10		11
Total capital expenditures	1,284		958
Change in capital expenditure accrual	16		(183		)
Total use of cash and cash equivalents for property, plant and equipment	$	1,300	$	775

Additions to other assets includes $129 million relating to our resource play leasing and exploration capital expenditures. During the first six months of 2018 our resource play leasing and exploration capital expenditures totaled $248 million, inclusive of costs included within property, plant and equipment, other assets, acquisitions and exploration expense.

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

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

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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 June 30, 2018, we had approximately $5.1 billion of liquidity consisting of $1.7 billion in cash and cash equivalents and $3.4 billion available under our revolving Credit Facility. Our working capital requirements are supported by these sources and we may draw on our revolving Credit Facility to meet short-term cash requirements, or issue debt or equity securities through the shelf registration statement discussed below as part of our longer-term liquidity and capital management program. Because of the alternatives available to us as discussed above, we believe that our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, and other amounts that may ultimately be paid in connection with contingencies.

General economic conditions, commodity prices, and financial, business and other factors could affect our operations and our ability to access the capital markets. Our corporate credit ratings as of June 30, 2018 are: Standard & Poor's Ratings Services BBB- (positive); Fitch Ratings BBB (stable); and Moody's Investor Services, Inc. Ba1 (positive). A downgrade in our credit ratings could increase our future cost of financing or limit our ability to access capital, and result in additional collateral requirements. See Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2017 for a discussion of how a further downgrade in our credit ratings could affect us.

Capital Resources

Credit Arrangements and Borrowings

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

At June 30, 2018, we had $5.5 billion in long-term debt outstanding, with our next debt maturity in the amount of $600 million due in 2020. We do not have any triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit ratings.

Shelf Registration

We have a universal shelf registration statement filed with the SEC under which we, as a "well-known seasoned issuer" for purposes of SEC rules, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities. 

Asset Disposal

In the 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.

In the second quarter of 2018, we entered into an agreement to sell a non-core property in our International E&P segment for proceeds of $56 million, before closing adjustments. We expect to close this transaction during 2018.

In the second quarter of 2018, we entered into separate agreements to sell non-core, non-operated conventional properties, primarily in the Gulf of Mexico, for combined net proceeds of $16 million, before closing adjustments. These transactions closed during July of 2018.

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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 June 30, 2018, compared to 32% at December 31, 2017.

	June 30,			December 31,
(In millions)	2018			2017
Long-term debt due within one year	$	—		$	—
Long-term debt	5,497			5,494
Total debt	$	5,497		$	5,494
Equity	$	12,132		$	11,708
Calculation:
Total debt	$	5,497		$	5,494
Total debt plus equity (total capitalization)	$	17,629		$	17,202
Debt-to-capital ratio	31		%	32		%

Capital Requirements

Other Expected Cash Outflows

On July 25, 2018, our Board of Directors approved a dividend of $0.05 per share for the second quarter of 2018 payable September 10, 2018 to stockholders of record at the close of business on August 15, 2018.

As of June 30, 2018, we plan to make contributions of up to $23 million to our funded pension plans during the remainder of 2018.

Contractual Cash Obligations

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

Environmental Matters and Other Contingencies

We have incurred and will continue to incur capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately offset by the prices we receive for our products and services, our operating results will be adversely affected.

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

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• 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.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risks in the normal course of business including commodity price risk and interest rate risk. We employ various strategies, including the use of financial derivatives to manage the risks related to commodity price fluctuations. See Note 12 and Note 13 to the consolidated financial statements for detail relating to our open commodity derivative positions, including underlying notional quantities, how they are reported in our consolidated financial statements and how their fair values are measured.

Commodity Price RiskAs of June 30, 2018, we had various open commodity derivatives related to crude oil and natural gas with a net liability position of $228 million. Based on the June 30, 2018 published NYMEX WTI and Henry Hub futures prices, a hypothetical 10% change (per bbl for crude oil and per MMBtu for natural gas) impacts the fair values of our net commodity derivative liability as follows:

(In millions)	Hypothetical Price Increase of 10%			Hypothetical Price Decrease of 10%
Crude oil derivatives	$	(173	)	$	153
Natural gas derivatives	(2		)	6
Total	$	(175	)	$	159

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

Item 4. Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer.  As of the end of the period covered by this Report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as of June 30, 2018.  

During the first six 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.

45

Part II – OTHER INFORMATION

Item 1. Legal Proceedings

There have been no significant changes to Item 3. Legal Proceedings in our 2017 Annual Report on Form 10-K. See Note 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 June 30, 2018.

Period	Total Number of Shares Purchased(a)	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(b)	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(b)
04/01/18 - 04/30/18	6,981	$16.36	—	$	1,500,285,529
05/01/18 - 05/31/18	85,036	$18.19	—	$	1,500,285,529
06/01/18 - 06/30/18	—	$0.00	—	$	1,500,285,529
Total	92,017	$18.05	—

^(a)  92,017 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

^(b)  In January 2006, we announced a $2.0 billion share repurchase program. Our Board of Directors subsequently increased the authorization for repurchases under the program by $500 million in January 2007, by $500 million in May 2007, by $2.0 billion in July 2007, and by $1.2 billion in December 2013, for a total authorized amount of $6.2 billion. The remaining share repurchase authorization as of June 30, 2018 is $1.5 billion. No repurchases were made under the program in the second 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.

46

SIGNATURES

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

August 2, 2018		MARATHON OIL CORPORATION
	By:	/s/ Gary E. Wilson
		Gary E. Wilson
		Vice President, Controller and Chief Accounting Officer
		(Duly Authorized Officer)

47

Exhibit Index

		Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
Exhibit Number	Exhibit Description	Form	Exhibit	Filing Date
3.1	Restated Certificate of Incorporation of Marathon Oil Corporation	8-K	3.1	6/1/2018
3.2	Marathon Oil Corporation By-laws (amended and restated as of February 24, 2016)	10-Q	3.2	8/4/2016
3.3	Specimen of Common Stock Certificate	10-K	3.3	2/28/2014
4.1	Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the SEC upon its request.	10-K	4.2	2/28/2014
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.

EX-31.1

Exhibit 31.1 

MARATHON OIL CORPORATION

CERTIFICATION PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002

I, Lee M. Tillman, certify that: 

1. I have reviewed this report on Form 10-Q of Marathon Oil Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	August 2, 2018	/s/ Lee M. Tillman
		Lee M. Tillman
		President and Chief Executive Officer

EX-31.2

Exhibit 31.2 

MARATHON OIL CORPORATION 

CERTIFICATION PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002 

I, Dane E. Whitehead, certify that:

1. I have reviewed this report on Form 10-Q of Marathon Oil Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	August 2, 2018	/s/ Dane E. Whitehead
		Dane E. Whitehead
		Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Marathon Oil Corporation (the “Company”) on Form 10-Q for the period ending June 30, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Lee M. Tillman, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

August 2, 2018	/s/ Lee M. Tillman
	Lee M. Tillman
	President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Marathon Oil Corporation (the “Company”) on Form 10-Q for the period ending June 30, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Dane E. Whitehead, Executive Vice President and Chief Financial Officer, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

August 2, 2018	/s/ Dane E. Whitehead
	Dane E. Whitehead
	Executive Vice President and Chief Financial Officer

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Jul. 31, 2018
Document and Entity Information [Abstract]
Document Type	10-Q
Document Period End Date	Jun. 30, 2018
Document Fiscal Period Focus	Q2
Document Fiscal Year Focus	2018
Amendment Flag	false
Entity Registrant Name	Marathon Oil Corp
Entity Central Index Key	0000101778
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Well Known Seasoned Issuer	Yes
Entity Common Stock Shares Outstanding		854,147,498

XML

Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenues and other income:
Revenues from contracts with customers	$ 1,447	$ 902	$ 2,984	$ 1,775
Net gain (loss) on commodity derivatives	(152)	56	(254)	137
Marketing revenues	0	35	0	69
Income from equity method investments	60	51	97	120
Net gain (loss) on disposal of assets	50	6	307	7
Other income	12	9	16	23
Total revenues and other income	1,417	1,059	3,150	2,131
Costs and expenses:
Production	205	178	422	331
Marketing, including purchases from related parties	0	38	0	72
Shipping, handling and other operating	126	111	256	200
Exploration	65	30	117	58
Depreciation, depletion and amortization	612	592	1,202	1,148
Impairments	34	0	42	4
Taxes other than income	65	45	129	84
General and administrative	105	90	205	187
Total costs and expenses	1,212	1,084	2,373	2,084
Income (loss) from operations	205	(25)	777	47
Net interest and other	(65)	(86)	(110)	(164)
Other net periodic benefit costs	0	(1)	(3)	(11)
Income (loss) from continuing operations before income taxes	140	(112)	664	(128)
Provision (benefit) for income taxes	44	41	212	75
Income (loss) from continuing operations	96	(153)	452	(203)
Income (loss) from discontinued operations	0	14	0	(4,893)
Net income (loss)	$ 96	$ (139)	$ 452	$ (5,096)
Per basic share:
Income (loss) from continuing operations, per basic share	$ 0.11	$ (0.18)	$ 0.53	$ (0.24)
Income (loss) from discontinued operations, per basic share	0.00	0.02	0.00	(5.76)
Net income (loss), per basic share	0.11	(0.16)	0.53	(6.00)
Per diluted share:
Income (loss) from continuing operations, per diluted share	0.11	(0.18)	0.53	(0.24)
Income (loss) from discontinued operations, per diluted share	0.00	0.02	0.00	(5.76)
Net income (loss), per diluted share	0.11	(0.16)	0.53	(6.00)
Dividends paid, per share	$ 0.05	$ 0.05	$ 0.10	$ 0.10
Weighted average common shares outstanding:
Weighted average common shares outstanding, basic	854	850	853	850
Weighted average common shares outstanding, diluted	855	850	854	850

XML

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 96	$ (139)	$ 452	$ (5,096)
Postretirement and postemployment plans
Change in actuarial loss and other	13	8	17	12
Postretirement and postemployment plans, net of tax	13	8	17	12
Derivative hedges
Net unrecognized gain (loss)	0	(14)	0	(13)
Derivative hedges, net of tax	0	(14)	0	(13)
Foreign currency hedges
Net recognized loss reclassified to discontinued operations	0	0	0	34
Income tax provision (benefit)	0	0	0	(4)
Foreign currency hedges, net of tax	0	0	0	30
Other, net of tax	4	0	4	0
Other comprehensive income (loss)	17	(6)	21	29
Comprehensive income (loss)	$ 113	$ (145)	$ 473	$ (5,067)

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 1,667	$ 563
Receivables, less reserve of $8 and $12	1,176	1,082
Notes receivable	0	748
Inventories	117	126
Other current assets	92	36
Current assets held for sale	35	11
Total current assets	3,087	2,566
Equity method investments	788	847
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $22,336 and $21,564	16,881	17,665
Goodwill	98	115
Other noncurrent assets	860	764
Noncurrent assets held for sale	157	55
Total assets	21,871	22,012
Current liabilities:
Accounts payable	1,428	1,395
Payroll and benefits payable	109	108
Accrued taxes	99	177
Other current liabilities	405	288
Current liabilities held for sale	3	0
Total current liabilities	2,044	1,968
Long-term debt	5,497	5,494
Deferred tax liabilities	237	833
Defined benefit postretirement plan obligations	311	362
Asset retirement obligations	1,364	1,428
Deferred credit and other liabilities	194	217
Noncurrent liabilities held for sale	92	2
Total liabilities	9,739	10,304
Commitments and contingencies
Stockholders' Equity
Preferred stock – no shares issued or outstanding (no par value, 26 million shares authorized)	0	0
Issued – 937 million shares and 937 million shares (par value $1 per share, 1.925 billion shares authorized at June 30, 2018 and 1.1 billion shares authorized at December 31, 2017)	937	937
Held in treasury, at cost – 83 million and 87 million shares	(3,137)	(3,325)
Additional paid-in capital	7,227	7,379
Retained earnings	7,146	6,779
Accumulated other comprehensive loss	(41)	(62)
Total stockholders' equity	12,132	11,708
Total liabilities and stockholders' equity	$ 21,871	$ 22,012

XML

Consolidated Balance Sheets Parentheticals - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Consolidated Balance Sheets Parenthetical [Abstract]
Receivables reserve	$ 8	$ 12
Less accumulated depreciation, depletion and amortization	$ (22,336)	$ (21,564)
Preferred stock, no par value	$ 0	$ 0
Preferred stock shares authorized	26,000,000	26,000,000
Preferred stock shares issued	0	0
Preferred stock shares outstanding	0	0
Common stock, par value per share	$ 1	$ 1
Common stock shares authorized	1,925,000,000	1,100,000,000
Common stock, shares issued	937,000,000	937,000,000
Common stock, held in treasury, shares	83,000,000	87,000,000

XML

Consolidated Statements of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Operating activities:
Net income (loss)	$ 452	$ (5,096)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Discontinued operations	0	4,893
Depreciation, depletion and amortization	1,202	1,148
Impairments	42	4
Exploratory dry well costs and unproved property impairments	93	45
Net (gain) loss on disposal of assets	(307)	(7)
Deferred income taxes	(6)	38
Net (gain) loss on derivative instruments	254	(140)
Net Settlement Of Derivative Instruments	(166)	3
Pension and other postretirement benefits, net	(51)	(25)
Share-based Compensation	28	26
Equity method investments, net	27	61
Changes in:
Current receivables, changes in	(256)	(15)
Inventories, changes in	(17)	(5)
Current accounts payable and accrued liabilities, changes in	133	(41)
All other operating, net	(12)	34
Net cash provided by operating activities from continuing operations	1,416	923
Investing activities:
Additions to property, plant and equipment	(1,300)	(775)
Additions to other assets	(129)	0
Acquisitions, net of cash acquired	(25)	(1,828)
Disposal of assets, net of cash transferred to buyer	1,183	1,726
Equity method investments - return of capital	32	49
All other investing, net	7	(5)
Net cash provided by (used in) investing activities from continuing operations	(232)	(833)
Financing activities:
Debt repayments	0	(1)
Purchases of common stock	(11)	(10)
Dividends paid	(85)	(85)
All other financing, net	18	0
Net cash provided by (used in) financing activities	(78)	(96)
Cash flow from discontinued operations:
Net cash provided by discontinued operations	0	130
Effect of exchange rate on cash and cash equivalents	(2)	2
Net increase (decrease) in cash and cash equivalents	1,104	126
Cash and cash equivalents at beginning of period	563	2,488
Cash and cash equivalents at end of period	$ 1,667	$ 2,614

XML

Basis of Presentation (Notes)

6 Months Ended

Jun. 30, 2018

Basis of Presentation [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

 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 second quarter and first six months of2018 are not necessarily indicative of the results to be expected for the full year.

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

Reclassifications

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

XML

Accounting Standards (Notes)

6 Months Ended

Jun. 30, 2018

Accounting Policies [Abstract]

Accounting Standards [Text Block]

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.

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

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

Hedge accounting standard

In August 2017, the FASB issued a new accounting standards update that amends the hedge accounting model to enable entities to hedge certain financial and nonfinancial risk attributes previously not allowed. The amendment also reduces the overall complexity of documenting, assessing and measuring hedge effectiveness. This standard is effective for us in the first quarter of 2019. Early adoption is permitted in any interim or annual period. The amendment mandates modified retrospective adoption when accounting for hedge relationships in effect as of the adoption date. None of our derivative instruments are currently designated as hedges; as a result we do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

Goodwill standard

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

Financial instruments - credit losses

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

Recently Adopted

Revenue recognition standard

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

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

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

	Three Months Ended June 30, 2018
(In millions)	As reported		Adjustments			Presentation without adoption of ASC Topic 606
Revenues and other income:
Revenues from contracts with customers	$	1,447	$	—		$	1,447
Marketing revenues	—		43			43
Other income	12		(1		)	11
Costs and expenses:
Marketing, including purchases from related parties	$	—	$	44		$	44
Shipping, handling and other operating	126		(2		)	124

	Six Months Ended June 30, 2018
(In millions)	As reported		Adjustments			Presentation without adoption of ASC Topic 606
Revenues and other income:
Revenues from contracts with customers	$	2,984	$	(2	)	$	2,982
Marketing revenues	—		75			75
Other income	16		(2		)	14
Costs and expenses:
Marketing, including purchases from related parties	$	—	$	76		$	76
Shipping, handling and other operating	256		(5		)	251

Pension accounting standard

In the first quarter of 2018, we adopted the new accounting standards update that changes how employers that sponsor defined pension and/or other postretirement benefit plans present the net periodic benefit cost in the income statement. As a result, employers are required to present the service cost component of net periodic benefit cost in the same income statement line item(s) as other employee compensation costs arising from services rendered during the period. We adopted this standard on a retrospective basis, and reclassified the required cost elements from general and administrative expense into production expense, exploration expense, and other net periodic benefit costs. The adoption of this standard did not have a significant impact on our consolidated balance sheet or statement of cash flows. The following tables summarize the impacts of adopting this standard on our historical consolidated income statement for the three and six months period ended June 30, 2017.

	Three Months Ended June 30, 2017
(In millions)	Previously Reported			As reclassified			Effect of Change Higher/(Lower)
Production	$	176		$	178		$	2
Exploration	30			30			—
General and administrative	93			90			(3		)
Income (loss) from operations	(26		)	(25		)	1
Other net periodic benefit costs (a)	—			1			1

	Six Months Ended June 30, 2017
(In millions)	Previously Reported		As reclassified		Effect of Change Higher/(Lower)
Production	$	327	$	331	$	4
Exploration	58		58		—
General and administrative	202		187		(15		)
Income from operations	36		47		11
Other net periodic benefit costs (a)	—		11		11

^(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.

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.

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Income per Common Share (Notes)

6 Months Ended

Jun. 30, 2018

Earnings Per Share [Abstract]

Income (Loss) per Common Share

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 6 million and 8 million of stock options for the three and six months period ended June 30, 2018 and 12 million stock options for the three and six months period ended June 30, 2017 that were antidilutive.

	Three Months Ended June 30,					Six Months Ended June 30,
(In millions, except per share data)	2018		2017			2018		2017
Income (loss) from continuing operations	$	96	$	(153	)	$	452	$	(203	)
Income (loss) from discontinued operations	—		14			—		(4,893		)
Net income (loss)	$	96	$	(139	)	$	452	$	(5,096	)
Weighted average common shares outstanding	854		850			853		850
Effect of dilutive securities	1		—			1		—
Weighted average common shares, diluted	855		850			854		850
Per basic share:
Income (loss) from continuing operations	$	0.11	$	(0.18	)	$	0.53	$	(0.24	)
Income (loss) from discontinued operations	$	—	$	0.02		$	—	$	(5.76	)
Net income	$	0.11	$	(0.16	)	$	0.53	$	(6.00	)
Per diluted share:
Income (loss) from continuing operations	$	0.11	$	(0.18	)	$	0.53	$	(0.24	)
Income (loss) from discontinued operations	$	—	$	0.02		$	—	$	(5.76	)
Net income	$	0.11	$	(0.16	)	$	0.53	$	(6.00	)

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Acquisition (Notes)

6 Months Ended

Jun. 30, 2018

Acquisitions [Abstract]

Business Combination Disclosure [Text Block]

Acquisitions

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

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Dispositions (Notes)

6 Months Ended

Jun. 30, 2018

Discontinued Operations and Disposal Groups [Abstract]

Dispositions [Text Block]

Dispositions

United States E&P Segment

In the second quarter of 2018, we entered into separate agreements to sell non-core, non-operated conventional properties, primarily in the Gulf of Mexico, for combined net proceeds of $16 million, before closing adjustments. These transactions met the criteria for assets held for sale which is reflected in the consolidated balance sheet at June 30, 2018, with total assets of $53 million and total liabilities, relating to asset retirement obligations, of $80 million. These transactions closed during July of 2018.

International E&P Segment

In the second quarter of 2018, we entered into an agreement to sell a non-core property for proceeds of $56 million, before closing adjustments. This property is classified as held for sale in the consolidated balance sheet at June 30, 2018, with total assets of $77 million, total liabilities of $11 million and expected to close during 2018.

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 for combined proceeds of $53 million, before closing adjustments. We closed on one of the asset sales in the fourth quarter of 2017 and recognized no pre-tax gain or loss on sale. The remaining asset sale is expected to close during 2018 and is classified as held for sale in the consolidated balance sheet as of June 30, 2018, with total assets of $62 million and total liabilities of $4 million.

Canadian Business - Discontinued Operations

On May 31, 2017 we closed on the sale of our Canadian business, which included our 20% non-operated interest in the AOSP to Shell and Canadian Natural Resources Limited for $2.5 billion, excluding closing adjustments. Under the terms of the agreement, $1.8 billion was paid to us upon closing. At closing we received two notes receivable for a combined $750 million for the remaining proceeds, which was received in the first quarter of 2018. In the first quarter of 2017, we recorded a non-cash impairment charge of $6.6 billion (after-tax of $4.96 billion) primarily related to the property, plant and equipment of our Canadian business. This impairment was recorded for excess net book value over anticipated sales proceeds less costs to sell. Fair values of assets held for sale were determined based upon the anticipated sales proceeds less costs to sell, which resulted in a Level 2 classification. As the effective date of the transaction was January 1, 2017, we recorded a loss on sale of $43 million during the second quarter of 2017 due to 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 and consolidated statements of cash flows as discontinued operations:

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)		2018		2017			2018		2017
Total revenue and other income		$	—	$	173		$	—	$	431
Net gain (loss) on disposal of assets		—		(43		)	—		(43		)
Total revenues and other income		—		130			—		388
Costs and expenses:
Production		—		103			—		254
Depreciation, depletion and amortization		—		1			—		40
Impairments		—		—			—		6,636
Other		—		12			—		25
Total costs and expenses		—		116			—		6,955
Pretax income (loss) from discontinued operations		—		14			—		(6,567		)
Provision (benefit) for income taxes		—		—			—		(1,674		)
Income (loss) from discontinued operations		$	—	$	14		$	—	$	(4,893	)

	Six Months Ended June 30,
(In millions)	2018		2017
Cash flow from discontinued operations:
Operating activities	$	—	$	141
Investing activities	—		(13		)
Changes in cash included in current assets held for sale	—		2
Net increase in cash and cash equivalents of discontinued operations	$	—	$	130

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Revenues

6 Months Ended

Jun. 30, 2018

Revenue from Contract with Customer [Abstract]

Revenues

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 June 30, 2018
United States E&P							Northern
(In millions)	Eagle Ford		Bakken		Oklahoma		Delaware		Other U.S.		Total
Crude oil and condensate	$	394	$	405	$	111	$	59	$	44	$	1,013
Natural gas liquids	45		17		45		6		2		115
Natural gas	33		8		38		2		5		86
Other	1		—		—		—		6		7
Revenues from contracts with customers	$	473	$	430	$	194	$	67	$	57	$	1,221

	Three Months Ended June 30, 2018
International E&P							Other
(In millions)	E.G.		U.K.		Libya		International		Total
Crude oil and condensate	$	100	$	71	$	—	$	22	$	193
Natural gas liquids	1		3		—		—		4
Natural gas	10		12		—		—		22
Other	—		7		—		—		7
Revenues from contracts with customers	$	111	$	93	$	—	$	22	$	226

	Six Months Ended June 30, 2018
United States E&P							Northern
(In millions)	Eagle Ford		Bakken		Oklahoma		Delaware		Other U.S.		Total
Crude oil and condensate	$	760	$	735	$	226	$	114	$	97	$	1,932
Natural gas liquids	87		32		82		12		5		218
Natural gas	66		18		81		7		12		184
Other	3		—		—		—		9		12
Revenues from contracts with customers	$	916	$	785	$	389	$	133	$	123	$	2,346

	Six Months Ended June 30, 2018
International E&P							Other
(In millions)	E.G.		U.K.		Libya		International		Total
Crude oil and condensate	$	171	$	166	$	187	$	45	$	569
Natural gas liquids	2		3		—		—		5
Natural gas	19		20		9		—		48
Other	—		16		—		—		16
Revenues from contracts with customers	$	192	$	205	$	196	$	45	$	638

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

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

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

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

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

Crude oil and condensate

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

Natural gas and NGLs

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

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

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

Contract receivables and assets

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

(In millions)	June 30, 2018		January 1, 2018
Receivables from contracts with customers, which are included in receivables, less reserves	$	836	$	811
Contract asset	$	33	$	—

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

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

	Six Months Ended
(In millions)	June 30, 2018
Contract asset balance as of January 1, 2018	$	—
Revenue recognized as performance obligations are satisfied	86
Amounts invoiced to customers	(53		)
Contract asset balance as of June 30, 2018	$	33

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Segment Information (Notes)

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

Segment Information [Text Block]

Segment Information

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

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

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

Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”).  Segment income (loss) represents income (loss) which excludes certain items not allocated to our operating segments, net of income taxes. A portion of our corporate and operations general and administrative support costs are not allocated to the operating segments. These unallocated costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Additionally, items which affect comparability such as: gains or losses on dispositions, certain impairments, unrealized gains or losses on commodity derivative instruments, pension settlement losses or other items (as determined by the CODM) are not allocated to operating segments.

	Three Months Ended June 30, 2018
							Not Allocated
(In millions)	U.S. E&P			Int'l E&P			to Segments				Total
Revenues from contracts with customers	$	1,221		$	226		$	—			$	1,447
Net gain (loss) on commodity derivatives	(107		)	—			(45		)	(b)	(152		)
Income from equity method investments	—			60			—				60
Net gain (loss) on disposal of assets	—			—			50				50
Other income	2			2			8				12
Less:
Production expenses	153			52			—				205
Shipping, handling and other operating	117			10			(1		)		126
Exploration	64			1			—				65
Depreciation, depletion and amortization	556			50			6				612
Impairments	—			—			34			(c)	34
Taxes other than income	68			—			(3		)		65
General and administrative	35			9			61				105
Net interest and other	—			—			65				65
Other net periodic benefit costs	—			(2		)	2			(d)	—
Income tax provision (benefit)	—			26			18				44
Segment income (loss) / Income (loss) from continuing operations	$	123		$	142		$	(169	)		$	96
Capital expenditures (a)	$	641		$	16		$	5			$	662

^(a)  Includes accruals.

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

^(c)  Primarily a result of anticipated sales of certain non-core proved properties in our International and United States E&P segments (See Note 11).

^(d)  Includes pension settlement loss of $2 million (See Note 16).

	Three Months Ended June 30, 2017
							Not Allocated
(In millions)	U.S. E&P			Int'l E&P			to Segments				Total
Revenues from contracts with customers	$	682		$	220		$	—			$	902
Net gain (loss) on commodity derivatives	13			—			43			(b)	56
Marketing revenues	7			28			—				35
Income from equity method investments	—			51			—				51
Net gain on disposal of assets	—			—			6				6
Other income	2			4			3				9
Less:
Production expenses	118			60			—				178
Marketing costs	9			29			—				38
Shipping, handling and other operating	96			13			2				111
Exploration	30			—			—				30
Depreciation, depletion and amortization	495			89			8				592
Taxes other than income	33			—			12				45
General and administrative	30			9			51				90
Net interest and other	—			—			86				86
Other net periodic benefit costs	—			(2		)	3			(c)	1
Income tax provision (benefit)	—			46			(5		)		41
Segment income (loss) / Income (loss) from continuing operations	$	(107	)	$	59		$	(105	)		$	(153	)
Capital expenditures (a)	$	575		$	14		$	10			$	599

^(a)  Includes accruals.

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

^(c)  Includes pension settlement loss of $3 million (See Note 16).

	Six Months Ended June 30, 2018
							Not Allocated
(In millions)	U.S. E&P			Int'l E&P			to Segments				Total
Revenues from contracts with customers	$	2,346		$	638		$	—			$	2,984
Net gain (loss) on commodity derivatives	(166		)	—			(88		)	(b)	(254		)
Income from equity method investments	—			97			—				97
Net gain (loss) on disposal of assets	—			—			307			(c)	307
Other income	5			3			8				16
Less:
Production expenses	304			119			(1		)		422
Shipping, handling and other operating	228			29			(1		)		256
Exploration	115			2			—				117
Depreciation, depletion and amortization	1,084			104			14				1,202
Impairments	—			—			42			(d)	42
Taxes other than income	132			—			(3		)		129
General and administrative	71			18			116				205
Net interest and other	—			—			110				110
Other net periodic benefit costs	—			(4		)	7			(e)	3
Income tax provision (benefit)	3			196			13				212
Segment income (loss) / Income (loss) from continuing operations	$	248		$	274		$	(70	)		$	452
Capital expenditures (a)	$	1,252		$	22		$	10			$	1,284

^(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)  Primarily a result of anticipated sales of certain non-core proved properties in our International and United States E&P segments (See Note 11).

^(e)  Includes pension settlement loss of $6 million (See Note 16).

	Six Months Ended June 30, 2017
							Not Allocated
(In millions)	U.S. E&P			Int'l E&P			to Segments				Total
Revenue from contracts with customers	$	1,352		$	423		$	—			$	1,775
Net gain (loss) on commodity derivatives	17			—			120			(b)	137
Marketing revenues	13			56			—				69
Income from equity method investments	—			120			—				120
Net gain (loss) on disposal of assets	1			—			6				7
Other income	6			14			3				23
Less:
Production expenses	227			104			—				331
Marketing costs	16			56			—				72
Shipping, handling and other operating	170			28			2				200
Exploration	56			2			—				58
Depreciation, depletion and amortization	967			164			17				1,148
Impairments	4			—			—				4
Taxes other than income	72			—			12				84
General and administrative	63			15			109				187
Net interest and other	—			—			164				164
Other net periodic benefit costs	—			(4		)	15			(c)	11
Income tax provision (benefit)	—			96			(21		)		75
Segment income (loss) / Income (loss) from continuing operations	$	(186	)	$	152		$	(169	)		$	(203	)
Capital expenditures (a)	$	924		$	23		$	11			$	958

^(a)  Includes accruals.

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

^(c)  Includes pension settlement loss of $17 million (See Note 16).

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Income Taxes (Notes)

6 Months Ended

Jun. 30, 2018

Income Tax Disclosure [Abstract]

Income Taxes

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 second quarter and six months ended June 30, 2018 and 2017, our effective income tax rates from continuing operations were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Effective income tax expense (benefit) rate from continuing operations	31	%	37	%	32	%	59	%

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

• Income taxes for the second quarter 2018 were impacted by foreign currency revaluation. During the six months ended June 30, 2018 income taxes were impacted by tax expense in Libya of $162 million, and we maintained our valuation allowance on our net federal deferred tax assets in the U.S.

• Income taxes for the second quarter 2017 were impacted by tax expense in Libya of $32 million. During the six months ended June 30, 2017, we incurred tax expense in Libya of $77 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 10% and a benefit of 1% for the six months ended June 30, 2018 and 2017. As a result of the sale of our Libya subsidiary in the first quarter of 2018, see Note 5 for further detail, we do not expect to incur further tax expense related to our Libya subsidiary. During 2018 and 2017, income taxes for Libya were recorded as a discrete item due to the uncertainty around the timing of future production and sales volumes.

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 ("AMT"), and a one-time deemed repatriation of accumulated foreign earnings. In the fourth quarter of 2017, we remeasured our deferred taxes at 21%, in accordance with U.S. GAAP standards. We plan to finalize certain tax positions when we file our 2017 federal tax return, and subsequently 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 second quarter of 2018, there are no material impacts on tax expense with respect to the finalization of tax positions taken due to Tax Reform Legislation.

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Inventories (Notes)

6 Months Ended

Jun. 30, 2018

Inventory Disclosure [Abstract]

Inventories [Text Block]

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.

	June 30,		December 31,
(In millions)	2018		2017
Crude oil and natural gas	$	11	$	9
Supplies and other items	106		117
Inventories	$	117	$	126

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Property, Plant and Equipment (Notes)

6 Months Ended

Jun. 30, 2018

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Text Block]

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

	June 30,		December 31,
(In millions)	2018		2017
United States E&P	$	15,953	$	15,867
International E&P	846		1,710
Corporate	82		88
Net property, plant and equipment	$	16,881	$	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 June 30, 2018 and December 31, 2017.

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Impairment Expense (Notes)

6 Months Ended

Jun. 30, 2018

Impairment Expense [Abstract]

Impairments and Exploration Expenses [Text Block]

Impairments

The following table summarizes impairment charges of proved properties from continuing operations. Additionally, it presents the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.

	Three Months Ended June 30,
	2018				2017
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets	$	69	$	34	$	—	$	—

	Six Months Ended June 30,
	2018				2017
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets	$	69	$	42	$	—	$	4

• 2018 - During the first six months of 2018 we recorded pre-tax non-cash proved property impairments of $42 million, to a fair value of $69 million, primarily as a result of anticipated sales proceeds for certain non-core proved properties in our International and United States E&P segments. The related fair value measurement utilized the market approach, based upon anticipated sales proceeds less costs to sell which resulted in a Level 2 classification. See Note 5 for discussion of the divestitures in further detail.

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Derivatives (Notes)

6 Months Ended

Jun. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives [Text Block]

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.

	June 30, 2018
(In millions)	Asset		Liability		Net Asset (Liability)			Balance Sheet Location
Not Designated as Hedges
Commodity	$	9	$	—	$	9		Other long-term assets
Commodity	—		231		$	(231	)	Other current liabilities
Commodity	—		6		$	(6	)	Deferred credits and other liabilities
Total Not Designated as Hedges	$	9	$	237	$	(228	)

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

Derivatives Not Designated as Hedges

Terminated Interest Rate Swaps

During the third quarter of 2016, we entered into forward starting interest rate swaps to hedge the variations in cash flows related to fluctuations in long term interest rates from debt that were probable to be refinanced by us in 2018, specifically interest rate risk associated with future changes in the benchmark treasury rate. During the second quarter of 2017, we de-designated the forward starting interest rate swaps previously designated as cash flow hedges. In the third quarter of 2017, the forecasted transaction consummated and we issued $1 billion in senior unsecured notes. As a result, we terminated our forward starting interest rate swaps during the third quarter of 2017.

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 June 30,					Six Months Ended June 30,
(In millions)	2018		2017			2018		2017
Interest Rate Swaps
Beginning balance	$	—	$	61		$	—	$	60
Change in fair value recognized in other comprehensive income	—		(14		)	—		(13		)
Reclassification from other comprehensive income	—		(1		)	—		(1		)
Ending balance	$	—	$	46		$	—	$	46

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 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 June 30, 2018 and the weighted average prices for those contracts:

Crude Oil	3Q 2018	4Q 2018	FY 2019	FY 2020
Three-Way Collars
Volume (Bbls/day)	95,000	95,000	50,000	—
Weighted average price per Bbl:
Ceiling	$57.65	$57.65	$71.74	—
Floor	$52.11	$52.11	$56.01	—
Sold put	$45.21	$45.21	$48.91	—
Basis Swaps (a)
Volume (Bbls/day)	10,000	10,000	10,000	15,000
Weighted average price per Bbl	$(0.67)	$(0.67)	$(0.82)	$(0.94)
Natural Gas	3Q 2018	4Q 2018
Three-Way Collars
Volume (MMBtu/day)	160,000	160,000
Weighted average price per MMBtu:
Ceiling	$3.61	$3.61
Floor	$3.00	$3.00
Sold put	$2.50	$2.50

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

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 and six month periods ended June 30, 2018 and 2017. The mark-to-market impact for the three and six month periods ended June 30, 2018 was a loss of $45 million and a loss of $88 million compared to a gain of $43 million and $120 million for the same respective periods in 2017. Net settlements of commodity derivative instruments for the three and six month periods ended June 30, 2018 was a loss of $107 million and $166 million compared to a gain of $13 million and $17 million for the respective periods in 2017.

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Fair Value Measurements (Notes)

6 Months Ended

Jun. 30, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements [Text Block]

Fair Value Measurements

 Fair Values - Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of June 30, 2018 and December 31, 2017 by fair value hierarchy level.

	June 30, 2018
(In millions)	Level 1		Level 2			Level 3		Total
Derivative instruments, assets
Commodity (a)	$	48	$	—		$	—	$	48
Derivative instruments, assets	$	48	$	—		$	—	$	48
Derivative instruments, liabilities
Commodity (a)	$	—	$	(276	)	$	—	$	(276	)
Derivative instruments, liabilities	$	—	$	(276	)	$	—	$	(276	)

^(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
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 and basis swaps. These instruments are measured at fair value using either a Black-Scholes or a modified Black-Scholes Model. For 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 - Goodwill

As of June 30, 2018, our consolidated balance sheet included goodwill of $98 million. Goodwill is tested for impairment on an annual basis, or between annual tests when events or changes in circumstances indicate the fair value may have been reduced below its carrying value. Goodwill is tested for impairment at the reporting unit level. Our reporting units are the same as our reporting segments, of which only International E&P includes goodwill. Our policy is to first assess the qualitative factors in order to determine whether the fair value of our International E&P reporting unit is more likely than not less than its carrying amount. Certain qualitative factors used in our evaluation include, among other things, the results of the most recent quantitative assessment of the goodwill impairment test, macroeconomic conditions; industry and market conditions (including commodity prices and cost factors); overall financial performance; and other relevant entity-specific events. If, after considering these events and circumstances we determined that it is more likely than not the fair value of the International E&P reporting unit is less than its carrying amount, a quantitative goodwill test is performed.

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

Fair Values – Nonrecurring

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

Fair Values – Financial Instruments

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

The following table summarizes financial instruments, excluding receivables, payables and derivative financial instruments, and their reported fair values by individual balance sheet line item at June 30, 2018 and December 31, 2017.

	June 30, 2018				December 31, 2017
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Current assets (a)	$	48	$	48	$	762	$	761
Other noncurrent assets	85		89		135		137
Total financial assets	$	133	$	137	$	897	$	898
Financial liabilities
Other current liabilities	$	32	$	44	$	32	$	43
Long-term debt, including current portion (b)	5,791		5,528		5,976		5,526
Deferred credits and other liabilities	100		97		110		103
Total financial liabilities	$	5,923	$	5,669	$	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.

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Debt (Notes)

6 Months Ended

Jun. 30, 2018

Debt Disclosure [Abstract]

Debt

Debt

Revolving Credit Facility

As of June 30, 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 June 30, 2018, we were in compliance with this covenant with a debt-to-capitalization ratio of 31%.

Long-term debt

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

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Incentive Based Compensation (Notes)

6 Months Ended

Jun. 30, 2018

Incentive Based Compensation Plans [Abstract]

Incentive Based Compensation [Text Block]

Incentive Based Compensation

Stock options, restricted stock awards and restricted stock units

The following table presents a summary of activity for the first six months of 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	4,622,514			$14.57
Options Exercised/Stock Vested	(1,349,984	)			$13.52	(2,757,023	)		$15.87
Canceled	(1,667,972	)			$30.10	(531,203	)		$14.13
Outstanding at June 30, 2018	8,169,710				$25.41	8,907,133			$13.91

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

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Defined Benefit Postretirement Plans (Notes)

6 Months Ended

Jun. 30, 2018

Defined Benefit Postretirement Plans Disclosure [Abstract]

Defined Benefit Postretirement Plans [Text Block]

Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:

	Three Months Ended June 30,
	Pension Benefits						Other Benefits
(In millions)	2018			2017			2018			2017
Service cost	$	5		$	5		$	—		$	—
Interest cost	6			7			2			2
Expected return on plan assets	(8		)	(10		)	—			—
Amortization:
– prior service cost (credit)	(3		)	(2		)	(2		)	(1		)
– actuarial loss	3			2			1			—
Net settlement loss (a)	2			3			—			—
Net periodic benefit cost	$	5		$	5		$	1		$	1

	Six Months Ended June 30,
	Pension Benefits						Other Benefits
(In millions)	2018			2017			2018			2017
Service cost	$	9		$	11		$	1		$	1
Interest cost	13			15			4			4
Expected return on plan assets	(17		)	(22		)	—			—
Amortization:
– prior service cost (credit)	(5		)	(4		)	(4		)	(3		)
– actuarial loss	6			4			1			—
Net settlement loss (a)	6			17			—			—
Net periodic benefit cost	$	12		$	21		$	2		$	2

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

During the first six 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 six months of 2018, we made contributions of $42 million to our funded pension plans and we expect to make additional contributions up to an estimated $23 million over the remainder of 2018.  During the first six months of 2018, we made payments of $12 million and $11 million related to unfunded pension plans and other postretirement benefit plans.

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Reclassifications out of Accumulated Other Comprehensive Income (Notes)

6 Months Ended

Jun. 30, 2018

Reclassifications out of AccumulatedOtherComprehensiveIncome [Abstract]

Reclassifications [Text Block]

Reclassifications Out of Accumulated Other Comprehensive Loss

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

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2018			2017			2018			2017			Income Statement Line
Postretirement and postemployment plans
Amortization of prior service credit	$	5		$	3		$	9		$	7		Other net periodic benefit costs
Amortization of actuarial loss	(4		)	(2		)	(7		)	(4		)	Other net periodic benefit costs
Net settlement loss	(2		)	(3		)	(6		)	(17		)	Other net periodic benefit costs
Derivative hedges
Ineffective portion of derivative hedge	—			(1		)	—			(1		)	Net interest and other
	(1		)	(3		)	(4		)	(15		)	Income (loss) from continuing operations before income taxes
	—			—			—			—			(Provision) benefit for income taxes
Total reclassifications to expense, net of tax	(1		)	(3		)	(4		)	(15		)	Income (loss) from continuing operations
Other insignificant, net of tax	(4		)	—			(4		)	—			Net interest and other
Foreign currency hedges
Net recognized loss in discontinued operations, net of tax	—			—			—			(30		)	Income (loss) from discontinued operations
Total reclassifications to expense	$	(5	)	$	(3	)	$	(8	)	$	(45	)	Net income (loss)

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Supplemental Cash Flow Information (Notes)

6 Months Ended

Jun. 30, 2018

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information [Text Block]

Supplemental Cash Flow Information

	Six Months Ended June 30,
(In millions)	2018			2017
Net cash (used in) operating activities:
Interest paid, net of amounts capitalized	$	(134	)	$	(193	)
Income taxes paid to taxing authorities	(282		)	(43		)
Noncash investing activities, related to continuing operations:
Notes receivable for disposal of assets	—			742

Other noncash investing activities include accrued capital expenditures as of June 30, 2018 and 2017 of $303 million and $338 million.

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Equity Method Investments and Related Party Transactions (Notes)

6 Months Ended

Jun. 30, 2018

Equity Method Investments Disclosure [Abstract]

Equity Method Investments and Related Party Transactions

Equity Method Investments

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

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

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

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

Our equity method investments are summarized in the following table:

	Ownership as of	June 30,		December 31,
(In millions)	June 30, 2018	2018		2017
EGHoldings	60%	$	414	$	456
Alba Plant LLC	52%	189		214
AMPCO	45%	185		177
Total		$	788	$	847

Summarized financial information for equity method investees is as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2018		2017		2018		2017
Income data:
Revenues and other income	$	228	$	199	$	426	$	438
Income from operations	143		113		240		265
Net income	123		101		202		235

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Commitments and Contingencies (Notes)

6 Months Ended

Jun. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

The U.K. tax authorities have challenged the timing of deductibility for certain Brae area decommissioning costs, which we claimed for U.K. corporation tax purposes.  The dispute relates to the timing of the deduction and does not dispute the general deductibility of decommissioning costs. In the fourth quarter of 2017, we received notification from the U.K.’s First-tier Tribunal that the decommissioning cost deductions, which we had claimed, were not allowable. We are progressing our appeal against 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.  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 offset by the prices we receive for our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations.  However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes.

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Basis of Presentation Accounting Policy (Policies)

6 Months Ended

Jun. 30, 2018

Accounting Policies [Abstract]

Basis of Accounting, Policy [Policy Text Block]

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 second quarter and first six months of2018 are not necessarily indicative of the results to be expected for the full year.

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

Reclassifications

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

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Accounting Standards Accounting Standards (Tables)

6 Months Ended

Jun. 30, 2018

Accounting Policies [Abstract]

Schedule of New Accounting Pronouncements and Changes in Accounting Principles

The following tables summarize the impacts of adopting this standard on our historical consolidated income statement for the three and six months period ended June 30, 2017.

	Three Months Ended June 30, 2017
(In millions)	Previously Reported			As reclassified			Effect of Change Higher/(Lower)
Production	$	176		$	178		$	2
Exploration	30			30			—
General and administrative	93			90			(3		)
Income (loss) from operations	(26		)	(25		)	1
Other net periodic benefit costs (a)	—			1			1

	Six Months Ended June 30, 2017
(In millions)	Previously Reported		As reclassified		Effect of Change Higher/(Lower)
Production	$	327	$	331	$	4
Exploration	58		58		—
General and administrative	202		187		(15		)
Income from operations	36		47		11
Other net periodic benefit costs (a)	—		11		11

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

The following tables summarize the impacts of adopting the new revenue standard on our consolidated income statement for the three and six months period ended June 30, 2018.

	Three Months Ended June 30, 2018
(In millions)	As reported		Adjustments			Presentation without adoption of ASC Topic 606
Revenues and other income:
Revenues from contracts with customers	$	1,447	$	—		$	1,447
Marketing revenues	—		43			43
Other income	12		(1		)	11
Costs and expenses:
Marketing, including purchases from related parties	$	—	$	44		$	44
Shipping, handling and other operating	126		(2		)	124

	Six Months Ended June 30, 2018
(In millions)	As reported		Adjustments			Presentation without adoption of ASC Topic 606
Revenues and other income:
Revenues from contracts with customers	$	2,984	$	(2	)	$	2,982
Marketing revenues	—		75			75
Other income	16		(2		)	14
Costs and expenses:
Marketing, including purchases from related parties	$	—	$	76		$	76
Shipping, handling and other operating	256		(5		)	251

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Income per Common Share (Tables)

6 Months Ended

Jun. 30, 2018

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

The per share calculations below exclude 6 million and 8 million of stock options for the three and six months period ended June 30, 2018 and 12 million stock options for the three and six months period ended June 30, 2017 that were antidilutive.

	Three Months Ended June 30,					Six Months Ended June 30,
(In millions, except per share data)	2018		2017			2018		2017
Income (loss) from continuing operations	$	96	$	(153	)	$	452	$	(203	)
Income (loss) from discontinued operations	—		14			—		(4,893		)
Net income (loss)	$	96	$	(139	)	$	452	$	(5,096	)
Weighted average common shares outstanding	854		850			853		850
Effect of dilutive securities	1		—			1		—
Weighted average common shares, diluted	855		850			854		850
Per basic share:
Income (loss) from continuing operations	$	0.11	$	(0.18	)	$	0.53	$	(0.24	)
Income (loss) from discontinued operations	$	—	$	0.02		$	—	$	(5.76	)
Net income	$	0.11	$	(0.16	)	$	0.53	$	(6.00	)
Per diluted share:
Income (loss) from continuing operations	$	0.11	$	(0.18	)	$	0.53	$	(0.24	)
Income (loss) from discontinued operations	$	—	$	0.02		$	—	$	(5.76	)
Net income	$	0.11	$	(0.16	)	$	0.53	$	(6.00	)

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Dispositions (Tables)

6 Months Ended

Jun. 30, 2018

Discontinued Operations and Disposal Groups [Abstract]

Disposal Group, Including Discontinued Operation

The following table contains select amounts reported in our historical consolidated statements of income and consolidated statements of cash flows as discontinued operations:

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)		2018		2017			2018		2017
Total revenue and other income		$	—	$	173		$	—	$	431
Net gain (loss) on disposal of assets		—		(43		)	—		(43		)
Total revenues and other income		—		130			—		388
Costs and expenses:
Production		—		103			—		254
Depreciation, depletion and amortization		—		1			—		40
Impairments		—		—			—		6,636
Other		—		12			—		25
Total costs and expenses		—		116			—		6,955
Pretax income (loss) from discontinued operations		—		14			—		(6,567		)
Provision (benefit) for income taxes		—		—			—		(1,674		)
Income (loss) from discontinued operations		$	—	$	14		$	—	$	(4,893	)

	Six Months Ended June 30,
(In millions)	2018		2017
Cash flow from discontinued operations:
Operating activities	$	—	$	141
Investing activities	—		(13		)
Changes in cash included in current assets held for sale	—		2
Net increase in cash and cash equivalents of discontinued operations	$	—	$	130

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Revenues (Tables)

6 Months Ended

Jun. 30, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

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

	Three Months Ended June 30, 2018
United States E&P							Northern
(In millions)	Eagle Ford		Bakken		Oklahoma		Delaware		Other U.S.		Total
Crude oil and condensate	$	394	$	405	$	111	$	59	$	44	$	1,013
Natural gas liquids	45		17		45		6		2		115
Natural gas	33		8		38		2		5		86
Other	1		—		—		—		6		7
Revenues from contracts with customers	$	473	$	430	$	194	$	67	$	57	$	1,221

	Three Months Ended June 30, 2018
International E&P							Other
(In millions)	E.G.		U.K.		Libya		International		Total
Crude oil and condensate	$	100	$	71	$	—	$	22	$	193
Natural gas liquids	1		3		—		—		4
Natural gas	10		12		—		—		22
Other	—		7		—		—		7
Revenues from contracts with customers	$	111	$	93	$	—	$	22	$	226

	Six Months Ended June 30, 2018
United States E&P							Northern
(In millions)	Eagle Ford		Bakken		Oklahoma		Delaware		Other U.S.		Total
Crude oil and condensate	$	760	$	735	$	226	$	114	$	97	$	1,932
Natural gas liquids	87		32		82		12		5		218
Natural gas	66		18		81		7		12		184
Other	3		—		—		—		9		12
Revenues from contracts with customers	$	916	$	785	$	389	$	133	$	123	$	2,346

	Six Months Ended June 30, 2018
International E&P							Other
(In millions)	E.G.		U.K.		Libya		International		Total
Crude oil and condensate	$	171	$	166	$	187	$	45	$	569
Natural gas liquids	2		3		—		—		5
Natural gas	19		20		9		—		48
Other	—		16		—		—		16
Revenues from contracts with customers	$	192	$	205	$	196	$	45	$	638

Contract with Customer, Asset

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

(In millions)	June 30, 2018		January 1, 2018
Receivables from contracts with customers, which are included in receivables, less reserves	$	836	$	811
Contract asset	$	33	$	—

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

	Six Months Ended
(In millions)	June 30, 2018
Contract asset balance as of January 1, 2018	$	—
Revenue recognized as performance obligations are satisfied	86
Amounts invoiced to customers	(53		)
Contract asset balance as of June 30, 2018	$	33

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

	Three Months Ended June 30, 2018
							Not Allocated
(In millions)	U.S. E&P			Int'l E&P			to Segments				Total
Revenues from contracts with customers	$	1,221		$	226		$	—			$	1,447
Net gain (loss) on commodity derivatives	(107		)	—			(45		)	(b)	(152		)
Income from equity method investments	—			60			—				60
Net gain (loss) on disposal of assets	—			—			50				50
Other income	2			2			8				12
Less:
Production expenses	153			52			—				205
Shipping, handling and other operating	117			10			(1		)		126
Exploration	64			1			—				65
Depreciation, depletion and amortization	556			50			6				612
Impairments	—			—			34			(c)	34
Taxes other than income	68			—			(3		)		65
General and administrative	35			9			61				105
Net interest and other	—			—			65				65
Other net periodic benefit costs	—			(2		)	2			(d)	—
Income tax provision (benefit)	—			26			18				44
Segment income (loss) / Income (loss) from continuing operations	$	123		$	142		$	(169	)		$	96
Capital expenditures (a)	$	641		$	16		$	5			$	662

^(a)  Includes accruals.

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

^(c)  Primarily a result of anticipated sales of certain non-core proved properties in our International and United States E&P segments (See Note 11).

^(d)  Includes pension settlement loss of $2 million (See Note 16).

	Three Months Ended June 30, 2017
							Not Allocated
(In millions)	U.S. E&P			Int'l E&P			to Segments				Total
Revenues from contracts with customers	$	682		$	220		$	—			$	902
Net gain (loss) on commodity derivatives	13			—			43			(b)	56
Marketing revenues	7			28			—				35
Income from equity method investments	—			51			—				51
Net gain on disposal of assets	—			—			6				6
Other income	2			4			3				9
Less:
Production expenses	118			60			—				178
Marketing costs	9			29			—				38
Shipping, handling and other operating	96			13			2				111
Exploration	30			—			—				30
Depreciation, depletion and amortization	495			89			8				592
Taxes other than income	33			—			12				45
General and administrative	30			9			51				90
Net interest and other	—			—			86				86
Other net periodic benefit costs	—			(2		)	3			(c)	1
Income tax provision (benefit)	—			46			(5		)		41
Segment income (loss) / Income (loss) from continuing operations	$	(107	)	$	59		$	(105	)		$	(153	)
Capital expenditures (a)	$	575		$	14		$	10			$	599

^(a)  Includes accruals.

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

^(c)  Includes pension settlement loss of $3 million (See Note 16).

	Six Months Ended June 30, 2018
							Not Allocated
(In millions)	U.S. E&P			Int'l E&P			to Segments				Total
Revenues from contracts with customers	$	2,346		$	638		$	—			$	2,984
Net gain (loss) on commodity derivatives	(166		)	—			(88		)	(b)	(254		)
Income from equity method investments	—			97			—				97
Net gain (loss) on disposal of assets	—			—			307			(c)	307
Other income	5			3			8				16
Less:
Production expenses	304			119			(1		)		422
Shipping, handling and other operating	228			29			(1		)		256
Exploration	115			2			—				117
Depreciation, depletion and amortization	1,084			104			14				1,202
Impairments	—			—			42			(d)	42
Taxes other than income	132			—			(3		)		129
General and administrative	71			18			116				205
Net interest and other	—			—			110				110
Other net periodic benefit costs	—			(4		)	7			(e)	3
Income tax provision (benefit)	3			196			13				212
Segment income (loss) / Income (loss) from continuing operations	$	248		$	274		$	(70	)		$	452
Capital expenditures (a)	$	1,252		$	22		$	10			$	1,284

^(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)  Primarily a result of anticipated sales of certain non-core proved properties in our International and United States E&P segments (See Note 11).

^(e)  Includes pension settlement loss of $6 million (See Note 16).

	Six Months Ended June 30, 2017
							Not Allocated
(In millions)	U.S. E&P			Int'l E&P			to Segments				Total
Revenue from contracts with customers	$	1,352		$	423		$	—			$	1,775
Net gain (loss) on commodity derivatives	17			—			120			(b)	137
Marketing revenues	13			56			—				69
Income from equity method investments	—			120			—				120
Net gain (loss) on disposal of assets	1			—			6				7
Other income	6			14			3				23
Less:
Production expenses	227			104			—				331
Marketing costs	16			56			—				72
Shipping, handling and other operating	170			28			2				200
Exploration	56			2			—				58
Depreciation, depletion and amortization	967			164			17				1,148
Impairments	4			—			—				4
Taxes other than income	72			—			12				84
General and administrative	63			15			109				187
Net interest and other	—			—			164				164
Other net periodic benefit costs	—			(4		)	15			(c)	11
Income tax provision (benefit)	—			96			(21		)		75
Segment income (loss) / Income (loss) from continuing operations	$	(186	)	$	152		$	(169	)		$	(203	)
Capital expenditures (a)	$	924		$	23		$	11			$	958

^(a)  Includes accruals.

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

^(c)  Includes pension settlement loss of $17 million (See Note 16).

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Income Taxes Effective Income Tax Rates (Tables)

6 Months Ended

Jun. 30, 2018

Income Tax Disclosure [Abstract]

Effective Income Tax Rate [Table Text Block]

For the second quarter and six months ended June 30, 2018 and 2017, our effective income tax rates from continuing operations were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Effective income tax expense (benefit) rate from continuing operations	31	%	37	%	32	%	59	%

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Inventories (Tables)

6 Months Ended

Jun. 30, 2018

Inventory Disclosure [Abstract]

Schedule of Inventory, Current [Table Text Block]

	June 30,		December 31,
(In millions)	2018		2017
Crude oil and natural gas	$	11	$	9
Supplies and other items	106		117
Inventories	$	117	$	126

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Property, Plant and Equipment (Tables)

6 Months Ended

Jun. 30, 2018

Property, Plant and Equipment [Abstract]

Schedule Of Property Plant And Equipment [Table Text Block]

	June 30,		December 31,
(In millions)	2018		2017
United States E&P	$	15,953	$	15,867
International E&P	846		1,710
Corporate	82		88
Net property, plant and equipment	$	16,881	$	17,665

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Impairment Expense (Tables)

6 Months Ended

Jun. 30, 2018

Impairment Expense [Abstract]

Fair Value Measurements, Nonrecurring [Table Text Block]

	Three Months Ended June 30,
	2018				2017
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets	$	69	$	34	$	—	$	—

	Six Months Ended June 30,
	2018				2017
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets	$	69	$	42	$	—	$	4

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Derivatives (Tables)

6 Months Ended

Jun. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives as they appear on the balance sheet [Table Text Block]

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.

	June 30, 2018
(In millions)	Asset		Liability		Net Asset (Liability)			Balance Sheet Location
Not Designated as Hedges
Commodity	$	9	$	—	$	9		Other long-term assets
Commodity	—		231		$	(231	)	Other current liabilities
Commodity	—		6		$	(6	)	Deferred credits and other liabilities
Total Not Designated as Hedges	$	9	$	237	$	(228	)

	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	)

Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block]

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 June 30,					Six Months Ended June 30,
(In millions)	2018		2017			2018		2017
Interest Rate Swaps
Beginning balance	$	—	$	61		$	—	$	60
Change in fair value recognized in other comprehensive income	—		(14		)	—		(13		)
Reclassification from other comprehensive income	—		(1		)	—		(1		)
Ending balance	$	—	$	46		$	—	$	46

Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]

Crude Oil	3Q 2018	4Q 2018	FY 2019	FY 2020
Three-Way Collars
Volume (Bbls/day)	95,000	95,000	50,000	—
Weighted average price per Bbl:
Ceiling	$57.65	$57.65	$71.74	—
Floor	$52.11	$52.11	$56.01	—
Sold put	$45.21	$45.21	$48.91	—
Basis Swaps (a)
Volume (Bbls/day)	10,000	10,000	10,000	15,000
Weighted average price per Bbl	$(0.67)	$(0.67)	$(0.82)	$(0.94)
Natural Gas	3Q 2018	4Q 2018
Three-Way Collars
Volume (MMBtu/day)	160,000	160,000
Weighted average price per MMBtu:
Ceiling	$3.61	$3.61
Floor	$3.00	$3.00
Sold put	$2.50	$2.50

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

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2018

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of June 30, 2018 and December 31, 2017 by fair value hierarchy level.

	June 30, 2018
(In millions)	Level 1		Level 2			Level 3		Total
Derivative instruments, assets
Commodity (a)	$	48	$	—		$	—	$	48
Derivative instruments, assets	$	48	$	—		$	—	$	48
Derivative instruments, liabilities
Commodity (a)	$	—	$	(276	)	$	—	$	(276	)
Derivative instruments, liabilities	$	—	$	(276	)	$	—	$	(276	)

^(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
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.

Fair Value, by Balance Sheet Grouping [Table Text Block]

The following table summarizes financial instruments, excluding receivables, payables and derivative financial instruments, and their reported fair values by individual balance sheet line item at June 30, 2018 and December 31, 2017.

	June 30, 2018				December 31, 2017
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Current assets (a)	$	48	$	48	$	762	$	761
Other noncurrent assets	85		89		135		137
Total financial assets	$	133	$	137	$	897	$	898
Financial liabilities
Other current liabilities	$	32	$	44	$	32	$	43
Long-term debt, including current portion (b)	5,791		5,528		5,976		5,526
Deferred credits and other liabilities	100		97		110		103
Total financial liabilities	$	5,923	$	5,669	$	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.

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Incentive Based Compensation (Tables)

6 Months Ended

Jun. 30, 2018

Incentive Based Compensation Plans [Abstract]

Table of Incentive based compensation activity [Table Text Block]

The following table presents a summary of activity for the first six 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	4,622,514			$14.57
Options Exercised/Stock Vested	(1,349,984	)			$13.52	(2,757,023	)		$15.87
Canceled	(1,667,972	)			$30.10	(531,203	)		$14.13
Outstanding at June 30, 2018	8,169,710				$25.41	8,907,133			$13.91

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

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Defined Benefit Postretirement Plans (Tables)

6 Months Ended

Jun. 30, 2018

Defined Benefit Postretirement Plans Disclosure [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

The following summarizes the components of net periodic benefit cost:

	Three Months Ended June 30,
	Pension Benefits						Other Benefits
(In millions)	2018			2017			2018			2017
Service cost	$	5		$	5		$	—		$	—
Interest cost	6			7			2			2
Expected return on plan assets	(8		)	(10		)	—			—
Amortization:
– prior service cost (credit)	(3		)	(2		)	(2		)	(1		)
– actuarial loss	3			2			1			—
Net settlement loss (a)	2			3			—			—
Net periodic benefit cost	$	5		$	5		$	1		$	1

	Six Months Ended June 30,
	Pension Benefits						Other Benefits
(In millions)	2018			2017			2018			2017
Service cost	$	9		$	11		$	1		$	1
Interest cost	13			15			4			4
Expected return on plan assets	(17		)	(22		)	—			—
Amortization:
– prior service cost (credit)	(5		)	(4		)	(4		)	(3		)
– actuarial loss	6			4			1			—
Net settlement loss (a)	6			17			—			—
Net periodic benefit cost	$	12		$	21		$	2		$	2

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

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Reclassifications out of Accumulated Other Comprehensive Income (Tables)

6 Months Ended

Jun. 30, 2018

Reclassifications out of AccumulatedOtherComprehensiveIncome [Abstract]

Schedule of Amounts Reclassified out of Accumulated Other Comprehensive Income [Table Text Block]

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

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2018			2017			2018			2017			Income Statement Line
Postretirement and postemployment plans
Amortization of prior service credit	$	5		$	3		$	9		$	7		Other net periodic benefit costs
Amortization of actuarial loss	(4		)	(2		)	(7		)	(4		)	Other net periodic benefit costs
Net settlement loss	(2		)	(3		)	(6		)	(17		)	Other net periodic benefit costs
Derivative hedges
Ineffective portion of derivative hedge	—			(1		)	—			(1		)	Net interest and other
	(1		)	(3		)	(4		)	(15		)	Income (loss) from continuing operations before income taxes
	—			—			—			—			(Provision) benefit for income taxes
Total reclassifications to expense, net of tax	(1		)	(3		)	(4		)	(15		)	Income (loss) from continuing operations
Other insignificant, net of tax	(4		)	—			(4		)	—			Net interest and other
Foreign currency hedges
Net recognized loss in discontinued operations, net of tax	—			—			—			(30		)	Income (loss) from discontinued operations
Total reclassifications to expense	$	(5	)	$	(3	)	$	(8	)	$	(45	)	Net income (loss)

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Supplemental Cash Flow Information (Tables)

6 Months Ended

Jun. 30, 2018

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information [Table Text Block]

Supplemental Cash Flow Information

	Six Months Ended June 30,
(In millions)	2018			2017
Net cash (used in) operating activities:
Interest paid, net of amounts capitalized	$	(134	)	$	(193	)
Income taxes paid to taxing authorities	(282		)	(43		)
Noncash investing activities, related to continuing operations:
Notes receivable for disposal of assets	—			742

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Equity Method Investments and Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2018

Equity Method Investments Disclosure [Abstract]

Schedule of Equity Method Investments

Our equity method investments are summarized in the following table:

	Ownership as of	June 30,		December 31,
(In millions)	June 30, 2018	2018		2017
EGHoldings	60%	$	414	$	456
Alba Plant LLC	52%	189		214
AMPCO	45%	185		177
Total		$	788	$	847

Income And Balance Sheet Information of Equity Investees Table

Summarized financial information for equity method investees is as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2018		2017		2018		2017
Income data:
Revenues and other income	$	228	$	199	$	426	$	438
Income from operations	143		113		240		265
Net income	123		101		202		235

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Accounting Standards - Revenue Recognition Standard (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenues and other income:
Revenues from contracts with customers	$ 1,447	$ 902	$ 2,984	$ 1,775
Marketing revenues	0	35	0	69
Other income	12	9	16	23
Costs and expenses:
Marketing, including purchases from related parties	0	38	0	72
Shipping, handling and other operating	126	$ 111	256	$ 200
Presentation without adoption of ASC Topic 606 [Member]
Revenues and other income:
Revenues from contracts with customers	1,447		2,982
Marketing revenues	43		75
Other income	11		14
Costs and expenses:
Marketing, including purchases from related parties	44		76
Shipping, handling and other operating	124		251
Accounting Standards Update 2014-09 [Member] | Adjustments [Member]
Revenues and other income:
Revenues from contracts with customers	0		(2)
Marketing revenues	43		75
Other income	(1)		(2)
Costs and expenses:
Marketing, including purchases from related parties	44		76
Shipping, handling and other operating	$ (2)		$ (5)

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Accounting Standards - Pension Accounting Standard (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Production	$ 205	$ 178	$ 422	$ 331
Exploration Expense	65	30	117	58
General and administrative	105	90	205	187
Income from operations	205	(25)	777	47
Other net periodic benefit costs	$ 0	1	$ 3	11
Previously Reported [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Production		176		327
Exploration Expense		30		58
General and administrative		93		202
Income from operations		(26)		36
Other net periodic benefit costs		0		0
Accounting Standards Update 2017-07 [Member] | Effect of Change Higher/(Lower) [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Production		2		4
Exploration Expense		0		0
General and administrative		(3)		(15)
Income from operations		1		11
Other net periodic benefit costs		$ 1		$ 11

XML

Income per Common Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Earnings Per Share [Abstract]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	6	12	8	12
Income (loss) from operations	$ 96	$ (153)	$ 452	$ (203)
Discontinued operations	0	14	0	(4,893)
Net income (loss)	$ 96	$ (139)	$ 452	$ (5,096)
Weighted average common shares outstanding, basic	854	850	853	850
Effect of dilutive securities	1	0	1	0
Weighted average common shares, diluted	855	850	854	850
Basic:
Income (loss) from continuing operations, per basic share	$ 0.11	$ (0.18)	$ 0.53	$ (0.24)
Income (loss) from discontinued operations, per basic share	0.00	0.02	0.00	(5.76)
Net income (loss), per basic share	0.11	(0.16)	0.53	(6.00)
Diluted:
Income (loss) from continuing operations, per diluted share	0.11	(0.18)	0.53	(0.24)
Income (loss) from discontinued operations, per diluted share	0.00	0.02	0.00	(5.76)
Net income (loss), per diluted share	$ 0.11	$ (0.16)	$ 0.53	$ (6.00)

XML

Acquisitions (Details) a in Thousands, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017 USD ($) a	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)
Business Acquisition [Line Items]
Number of Businesses Acquired	2
Payments to Acquire Businesses, Net of Cash Acquired			$ 25	$ 1,828
Permian Basin [Member]
Business Acquisition [Line Items]
Gas and Oil Acres, Undeveloped and Developed, Net | a		91
Permian Basin [Member] | Black Mountain Oil and Gas Transaction [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Net of Cash Acquired		$ 700
Permian Basin [Member] | BC Operating Transaction [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Net of Cash Acquired		$ 1,100

XML

Dispositions - United States E&P Segment (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas property and equipment		$ 1,183	$ 1,726
United States Exploration and Production [Member] | Gulf of Mexico - non-core properties [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas property and equipment	$ 16
Disposal group, assets	53	53
Disposal group, liabilities	$ 80	$ 80

XML

Dispositions - International E&P Segment (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
	Mar. 01, 2018	Jun. 30, 2018	Sep. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas property and equipment				$ 1,183	$ 1,726
International Exploration and Production [Member] | Non-Core Property, Second Quarter 2018 Agreement [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas property and equipment		$ 56
Disposal group, assets		77		77
Disposal group, liabilities		11		11
International Exploration and Production [Member] | Marathon Oil Libya Limited [Member] | Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas property and equipment	$ 450
Net gain (loss) on disposal of assets	$ 255
Ownership percentage by parent	16.33%
International Exploration and Production [Member] | Non-Core Property, Third Quarter 2017 Agreement [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas property and equipment			$ 53
Disposal group, assets		62		62
Disposal group, liabilities		$ 4		$ 4

XML

Dispositions - Canada Business - Discontinued Operations (Details)			3 Months Ended				6 Months Ended
	Dec. 31, 2017 USD ($)	May 31, 2017 USD ($)	Jun. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Jun. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas property and equipment							$ 1,183,000,000	$ 1,726,000,000
Impairments			$ 34,000,000		$ 0		42,000,000	4,000,000
Oil Sands Mining Segment [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Pretax income (loss) from discontinued operations						$ 6,600,000,000
Oil Sands Mining Segment [Member] | Discontinued Operations, Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas property and equipment		$ 2,500,000,000		$ 1,800,000,000
Number of notes receivable	2	2
Pretax income (loss) from discontinued operations			0		(14,000,000)		0	6,567,000,000
Impairments			0		0		0	6,636,000,000
Net gain (loss) on disposal of assets			$ 0		$ (43,000,000)		$ 0	$ (43,000,000)
Variable Interest Entity, Not Primary Beneficiary [Member] | Oil Sands Mining Segment [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Variable interest entity, ownership percentage		20.00%
Notes Receivable [Member] | Oil Sands Mining Segment [Member] | Discontinued Operations, Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Notes receivable		$ 750,000,000
Oil Sands Mining Segment [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairments						$ 4,960,000,000

XML

Dispositions - Consolidated Statements of Income and Consolidated Statements of Cash Flows (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Mar. 31, 2017	Jun. 30, 2018	Jun. 30, 2017
Consolidated Statements of Income [Abstract]
Impairments	$ 34	$ 0		$ 42	$ 4
Cash flow from discontinued operations:
Net increase in cash and cash equivalents of discontinued operations				0	130
Oil Sands Mining Segment [Member]
Consolidated Statements of Income [Abstract]
Pretax income (loss) from discontinued operations			$ (6,600)
Discontinued Operations, Disposed of by Sale [Member] | Oil Sands Mining Segment [Member]
Consolidated Statements of Income [Abstract]
Total revenue and other income	0	173		0	431
Net gain (loss) on disposal of assets	0	(43)		0	(43)
Total revenues and other income	0	130		0	388
Production	0	103		0	254
Depreciation, depletion and amortization	0	1		0	40
Impairments	0	0		0	6,636
Other	0	12		0	25
Total costs and expenses	0	116		0	6,955
Pretax income (loss) from discontinued operations	0	14		0	(6,567)
Provision (benefit) for income taxes	0	0		0	(1,674)
Income (loss) from discontinued operations	$ 0	$ 14		0	(4,893)
Cash flow from discontinued operations:
Operating activities				0	141
Investing activities				0	(13)
Changes in cash included in current assets held for sale				0	2
Net increase in cash and cash equivalents of discontinued operations				$ 0	$ 130
Oil Sands Mining Segment [Member]
Consolidated Statements of Income [Abstract]
Impairments			$ 4,960

XML

Revenues - Revenues from Contracts with Customers by Product Type and Geographic Areas (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018
United States Exploration and Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	$ 1,221	$ 2,346
United States Exploration and Production [Member] | Eagle Ford [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	473	916
United States Exploration and Production [Member] | Bakken [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	430	785
United States Exploration and Production [Member] | Oklahoma [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	194	389
United States Exploration and Production [Member] | Northern Delaware [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	67	133
United States Exploration and Production [Member] | Other U.S. [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	57	123
United States Exploration and Production [Member] | Crude oil and condensate [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	1,013	1,932
United States Exploration and Production [Member] | Crude oil and condensate [Member] | Eagle Ford [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	394	760
United States Exploration and Production [Member] | Crude oil and condensate [Member] | Bakken [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	405	735
United States Exploration and Production [Member] | Crude oil and condensate [Member] | Oklahoma [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	111	226
United States Exploration and Production [Member] | Crude oil and condensate [Member] | Northern Delaware [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	59	114
United States Exploration and Production [Member] | Crude oil and condensate [Member] | Other U.S. [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	44	97
United States Exploration and Production [Member] | Natural gas liquids [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	115	218
United States Exploration and Production [Member] | Natural gas liquids [Member] | Eagle Ford [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	45	87
United States Exploration and Production [Member] | Natural gas liquids [Member] | Bakken [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	17	32
United States Exploration and Production [Member] | Natural gas liquids [Member] | Oklahoma [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	45	82
United States Exploration and Production [Member] | Natural gas liquids [Member] | Northern Delaware [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	6	12
United States Exploration and Production [Member] | Natural gas liquids [Member] | Other U.S. [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	2	5
United States Exploration and Production [Member] | Natural gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	86	184
United States Exploration and Production [Member] | Natural gas [Member] | Eagle Ford [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	33	66
United States Exploration and Production [Member] | Natural gas [Member] | Bakken [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	8	18
United States Exploration and Production [Member] | Natural gas [Member] | Oklahoma [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	38	81
United States Exploration and Production [Member] | Natural gas [Member] | Northern Delaware [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	2	7
United States Exploration and Production [Member] | Natural gas [Member] | Other U.S. [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	5	12
United States Exploration and Production [Member] | Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	7	12
United States Exploration and Production [Member] | Other [Member] | Eagle Ford [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	1	3
United States Exploration and Production [Member] | Other [Member] | Bakken [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	0	0
United States Exploration and Production [Member] | Other [Member] | Oklahoma [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	0	0
United States Exploration and Production [Member] | Other [Member] | Northern Delaware [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	0	0
United States Exploration and Production [Member] | Other [Member] | Other U.S. [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	6	9
International Exploration and Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	226	638
International Exploration and Production [Member] | E.G. [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	111	192
International Exploration and Production [Member] | U.K. [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	93	205
International Exploration and Production [Member] | Libya [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	0	196
International Exploration and Production [Member] | Other International [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	22	45
International Exploration and Production [Member] | Crude oil and condensate [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	193	569
International Exploration and Production [Member] | Crude oil and condensate [Member] | E.G. [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	100	171
International Exploration and Production [Member] | Crude oil and condensate [Member] | U.K. [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	71	166
International Exploration and Production [Member] | Crude oil and condensate [Member] | Libya [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	0	187
International Exploration and Production [Member] | Crude oil and condensate [Member] | Other International [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	22	45
International Exploration and Production [Member] | Natural gas liquids [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	4	5
International Exploration and Production [Member] | Natural gas liquids [Member] | E.G. [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	1	2
International Exploration and Production [Member] | Natural gas liquids [Member] | U.K. [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	3	3
International Exploration and Production [Member] | Natural gas liquids [Member] | Libya [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	0	0
International Exploration and Production [Member] | Natural gas liquids [Member] | Other International [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	0	0
International Exploration and Production [Member] | Natural gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	22	48
International Exploration and Production [Member] | Natural gas [Member] | E.G. [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	10	19
International Exploration and Production [Member] | Natural gas [Member] | U.K. [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	12	20
International Exploration and Production [Member] | Natural gas [Member] | Libya [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	0	9
International Exploration and Production [Member] | Natural gas [Member] | Other International [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	0	0
International Exploration and Production [Member] | Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	7	16
International Exploration and Production [Member] | Other [Member] | E.G. [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	0	0
International Exploration and Production [Member] | Other [Member] | U.K. [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	7	16
International Exploration and Production [Member] | Other [Member] | Libya [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	0	0
International Exploration and Production [Member] | Other [Member] | Other International [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customer	$ 0	$ 0

XML

Revenues - Contract Receivables and Assets (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Receivables from contracts with customers, which are included in receivables, less reserves	$ 836	$ 811
Contract asset	$ 33	$ 0

XML

Revenues - Significant Changes in the Contract Asset Balance (Details) $ in Millions	6 Months Ended
	Jun. 30, 2018 USD ($)
Change In Contract With Customer, Asset [Roll Forward]
Contract asset balance, beginning	$ 0
Revenue recognized as performance obligations are satisfied	86
Amounts invoiced to customers	(53)
Contract asset balance, ending	$ 33

XML

Segment Information (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($) segment	Jun. 30, 2017 USD ($)
Segment Reporting Information [Line Items]
Number of Reportable Segments | segment			2
Revenues from contracts with customers	$ 1,447	$ 902	$ 2,984	$ 1,775
Net gain (loss) on commodity derivatives	(152)	56	(254)	137
Marketing revenues	0	35	0	69
Income from equity method investments	60	51	97	120
Net gain ( loss) on disposal of assets and other income	50	6	307	7
Other income	12	9	16	23
Production expenses	205	178	422	331
Marketing costs	0	38	0	72
Shipping, handling and other operating	126	111	256	200
Exploration Expense	65	30	117	58
Depreciation, depletion and amortization	612	592	1,202	1,148
Impairments	34	0	42	4
Taxes other than income	65	45	129	84
General and Administrative Expense	105	90	205	187
Net Interest And Other	65	86	110	164
Other net periodic benefit costs	0	1	3	11
Income tax provision (benefit)	44	41	212	75
Segment income (loss) / Income (loss) from continuing operations	96	(153)	452	(203)
Capital expenditures	662	599	1,284	958
Pension Plan [Member]
Segment Reporting Information [Line Items]
Net settlement loss	2	3	6	17
Operating Segments [Member] | United States Exploration and Production [Member]
Segment Reporting Information [Line Items]
Revenues from contracts with customers	1,221	682	2,346	1,352
Net gain (loss) on commodity derivatives	(107)	13	(166)	17
Marketing revenues		7		13
Income from equity method investments	0	0	0	0
Net gain ( loss) on disposal of assets and other income	0	0	0	1
Other income	2	2	5	6
Production expenses	153	118	304	227
Marketing costs		9		16
Shipping, handling and other operating	117	96	228	170
Exploration Expense	64	30	115	56
Depreciation, depletion and amortization	556	495	1,084	967
Impairments	0		0	4
Taxes other than income	68	33	132	72
General and Administrative Expense	35	30	71	63
Net Interest And Other	0	0	0	0
Other net periodic benefit costs	0	0	0	0
Income tax provision (benefit)	0	0	3	0
Segment income (loss) / Income (loss) from continuing operations	123	(107)	248	(186)
Capital expenditures	641	575	1,252	924
Operating Segments [Member] | International Exploration and Production [Member]
Segment Reporting Information [Line Items]
Revenues from contracts with customers	226	220	638	423
Net gain (loss) on commodity derivatives	0	0	0	0
Marketing revenues		28		56
Income from equity method investments	60	51	97	120
Net gain ( loss) on disposal of assets and other income	0	0	0	0
Other income	2	4	3	14
Production expenses	52	60	119	104
Marketing costs		29		56
Shipping, handling and other operating	10	13	29	28
Exploration Expense	1	0	2	2
Depreciation, depletion and amortization	50	89	104	164
Impairments	0		0	0
Taxes other than income	0	0	0	0
General and Administrative Expense	9	9	18	15
Net Interest And Other	0	0	0	0
Other net periodic benefit costs	(2)	(2)	(4)	(4)
Income tax provision (benefit)	26	46	196	96
Segment income (loss) / Income (loss) from continuing operations	142	59	274	152
Capital expenditures	16	14	22	23
Corporate, Non-Segment [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Revenues from contracts with customers	0	0	0	0
Net gain (loss) on commodity derivatives	(45)	43	(88)	120
Marketing revenues		0		0
Income from equity method investments	0	0	0	0
Net gain ( loss) on disposal of assets and other income	50	6	307	6
Other income	8	3	8	3
Production expenses	0	0	(1)	0
Marketing costs		0		0
Shipping, handling and other operating	(1)	2	(1)	2
Exploration Expense	0	0	0	0
Depreciation, depletion and amortization	6	8	14	17
Impairments	34		42	0
Taxes other than income	(3)	12	(3)	12
General and Administrative Expense	61	51	116	109
Net Interest And Other	65	86	110	164
Other net periodic benefit costs	2	3	7	15
Income tax provision (benefit)	18	(5)	13	(21)
Segment income (loss) / Income (loss) from continuing operations	(169)	(105)	(70)	(169)
Capital expenditures	$ 5	$ 10	$ 10	$ 11

XML

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Income Tax Contingency [Line Items]
Income tax provision (benefit)	$ 44	$ 41	$ 212	$ 75
Effective Income Tax Rate Reconciliation, Percent	31.00%	37.00%	32.00%	59.00%
Effective income tax rate excluding Libya			10.00%	1.00%
Libya, Dinars
Income Tax Contingency [Line Items]
Income tax provision (benefit)		$ 32	$ 162	$ 77
ALASKA
Income Tax Contingency [Line Items]
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority		$ 13		$ 13

XML

Inventories (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Inventory Disclosure [Abstract]
Crude oil and natural gas	$ 11	$ 9
Supplies and other items	106	117
Total inventories, at cost	$ 117	$ 126

XML

Property, Plant and Equipment (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Property, plant and equipment, net	$ 16,881	$ 17,665
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year After Completion of Drilling	32	32
United States Exploration and Production [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, net	15,953	15,867
International Exploration and Production [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, net	846	1,710
Corporate [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, net	$ 82	$ 88

XML

Impairment Expense - Impairment Expense (Details) - Fair Value, Measurements, Nonrecurring [Member] - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Impairment Expense [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure	$ 69	$ 0	$ 69	$ 0
Assets, Fair Value Adjustment	$ 34	$ 0	$ 42	$ 4

XML

Derivatives (Details-BS) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017	Sep. 30, 2017
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset		$ 0
Derivative Liability, Fair Value, Gross Liability		140
Derivative Liability, Fair Value, Net		(140)
Derivative Asset (Liability), Fair Value, Gross Asset	$ 9
Derivative Liability (Asset), Fair Value, Gross Liability	237
Derivative, Fair Value, Net	(228)
Commodity Contract [Member] | Other Long-Term Assets [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	9
Derivative Asset, Fair Value, Gross Liability	0
Derivative Asset, Fair Value, Net	9
Commodity Contract [Member] | Other Current Liabilities [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	231	138
Derivative Liability, Fair Value, Net	(231)	(138)
Commodity Contract [Member] | Deferred Credits and Other Liabilities [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	6	2
Derivative Liability, Fair Value, Net	$ (6)	$ (2)
Unsecured Debt [Member]
Derivatives, Fair Value [Line Items]
Debt Instrument, Face Amount			$ 1,000

XML

Derivatives (Details 3-Schedule of Cash Flow Hedges Rollforward) (Details) - Interest Rate Swap [Member] - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Cash Flow Hedges Derivative Instruments at Fair Value, Net [Roll Forward]
Beginning balance	$ 0	$ 61	$ 0	$ 60
Change in fair value recognized in other comprehensive income	0	(14)	0	(13)
Reclassification from other comprehensive income	0	(1)	0	(1)
Ending balance	$ 0	$ 46	$ 0	$ 46

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Derivatives (Details 4-Non Hedges Commodity) (Details)	Jun. 30, 2018 MMBTU BBL / Days Bbls_per_day $ / bbl $ / MMBTU
Crude Oil Three-Way Collars For Third Quarter of Year 1 [Member]
Derivative [Line Items]
Volume | BBL / Days	95,000
Ceiling Price	57.65
Floor Price	52.11
Sold Put Price	45.21
Crude Oil Three-Way Collars For Fourth Quarter of Year 1 [Member]
Derivative [Line Items]
Volume | BBL / Days	95,000
Ceiling Price	57.65
Floor Price	52.11
Sold Put Price	45.21
Crude Oil Three-Way Collars For Year 2 [Member]
Derivative [Line Items]
Volume | BBL / Days	50,000
Ceiling Price	71.74
Floor Price	56.01
Sold Put Price	48.91
Crude Oil Three-Way Collars For Year 3 [Member]
Derivative [Line Items]
Volume | BBL / Days	0
Ceiling Price	0.00
Floor Price	0.00
Sold Put Price	0.00
Crude Oil Basis Swaps For the Third Quarter of Year 1 [Member]
Derivative [Line Items]
Volume | Bbls_per_day	10,000
Weighted Average Differential To WTI Midland and WTI Cushing	(0.67)
Crude Oil Basis Swaps For the Fourth Quarter of Year 1 [Member]
Derivative [Line Items]
Volume | Bbls_per_day	10,000
Weighted Average Differential To WTI Midland and WTI Cushing	(0.67)
Crude Oil Basis Swaps For Year 2 [Member]
Derivative [Line Items]
Volume | Bbls_per_day	10,000
Weighted Average Differential To WTI Midland and WTI Cushing	(0.82)
Crude Oil Basis Swaps For Year 3 [Member]
Derivative [Line Items]
Volume | Bbls_per_day	15,000
Weighted Average Differential To WTI Midland and WTI Cushing	(0.94)
Natural Gas Three-Way Collars For the Third Quarter of Year 1 [Member]
Derivative [Line Items]
Volume | MMBTU	160,000
Ceiling Price | $ / MMBTU	3.61
Floor Price | $ / MMBTU	3.00
Sold Put Price | $ / MMBTU	2.50
Natural Gas Three-Way Collars For the Fourth Quarter of Year 1 [Member]
Derivative [Line Items]
Volume | MMBTU	160,000
Ceiling Price | $ / MMBTU	3.61
Floor Price | $ / MMBTU	3.00
Sold Put Price | $ / MMBTU	2.50

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Derivatives (Details 5-Non Hedges - Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ (152)	$ 56	$ (254)	$ 137
Corporate and Other [Member] | Corporate, Non-Segment [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(45)	43	(88)	120
United States Exploration and Production [Member] | Operating Segments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ (107)	$ 13	$ (166)	$ 17

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Fair Value Measurements (Details-Recurring) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Goodwill	$ 98	$ 115
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	48	0
Derivative Liability	(276)	(140)
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	48
Derivative Liability	(276)	(140)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	48	0
Derivative Liability	0	(20)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	48
Derivative Liability	0	(20)
Fair Value, Measurements, Recurring [Member] | Fair Value Inputs Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Derivative Liability	(276)	(120)
Fair Value, Measurements, Recurring [Member] | Fair Value Inputs Level 2 [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0
Derivative Liability	(276)	(120)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Derivative Liability	0	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Commodity Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0
Derivative Liability	$ 0	$ 0

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Fair Value Measurements (Details 3-Reported)	Dec. 31, 2017 USD ($)	May 31, 2017	Jun. 30, 2018 USD ($)
Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	$ 762,000,000		$ 48,000,000
Financial Instruments, Financial Assets, Balance Sheet Groupings [Abstract]
Other noncurrent financial assets	135,000,000		85,000,000
Total financial assets	897,000,000		133,000,000
Financial liabilities
Other current financial liabilities	32,000,000		32,000,000
Long-term debt, including current portion	5,976,000,000		5,791,000,000
Deferred credits and other financial liabilities	110,000,000		100,000,000
Financial Liabilities Fair Value Disclosure	6,118,000,000		5,923,000,000
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	761,000,000		48,000,000
Financial Instruments, Financial Assets, Balance Sheet Groupings [Abstract]
Other noncurrent financial assets	137,000,000		89,000,000
Total financial assets	898,000,000		137,000,000
Financial liabilities
Other current financial liabilities	43,000,000		44,000,000
Long-term debt, including current portion	5,526,000,000		5,528,000,000
Deferred credits and other financial liabilities	103,000,000		97,000,000
Financial Liabilities Fair Value Disclosure	$ 5,672,000,000		$ 5,669,000,000
Oil Sands Mining Segment [Member] | Discontinued Operations, Disposed of by Sale [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Number of notes receivable	2	2

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Debt - Revolving Credit Facility (Details) $ in Millions	Jun. 30, 2018 USD ($)
Line of Credit Facility [Line Items]
Line of Credit Facility, maximum borrowing capacity	$ 3,400
Ratio of indebtedness to net capital	0.31
Maximum [Member]
Line of Credit Facility [Line Items]
Ratio of indebtedness to net capital	0.65
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit, Current	$ 0

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Debt Long-Term Debt (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Long-term Debt, Unclassified [Abstract]
Long-term Debt and Capital Lease Obligations	$ 5,497	$ 5,494
Debentures Due 2020 [Member]
Subsequent Event [Line Items]
Other Long-term Debt, Noncurrent	$ 600

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Incentive Based Compensation (Details 1-Restricted) - $ / shares	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Incentive Based Compensation Plans [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 5.82
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures	856,890
Share-based Compensation Arrangements by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price	$ 14.52
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	8,169,710	10,330,776
Restricted Stock
Beginning year unvested restricted stock	7,572,845
Granted restricted stock	4,622,514
Vested restricted stock	(2,757,023)
Forfeited restricted stock	(531,203)
End of period unvested restricted stock	8,907,133
Beginning year weighted average grant date fair value unvested restricted stock	$ 14.24
Granted restricted stock weighted average grant date fair value restricted stock	14.57
Vested restricted stock weighted average grant date fair value restricted stock	15.87
Forfeited restricted stock weighted average grant date fair value restricted stock	14.13
End of period weighted average grant date fair value unvested restricted stock	$ 13.91
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period	(1,349,984)
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price	$ 13.52
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period	(1,667,972)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price	$ 30.10
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 25.41	$ 25.52

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Incentive Based Compensation (Details 2-Performance) - $ / shares	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 13.91	$ 14.24
Performance Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award Instruments Other Than Options Performance Unit Granted	754,140
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 17.02

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Defined Benefit Postretirement Plans (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2018
Payment for Pension and Other Postretirement Benefits [Abstract]
Payment for Pension Benefits			$ 42
Scenario, Forecast [Member]
Payment for Pension and Other Postretirement Benefits [Abstract]
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year					$ 23
Pension Plan [Member]
Defined Benefit Plan Net Periodic Benefit Cost [Line Items]
Service cost	$ 5	$ 5	9	$ 11
Interest cost	6	7	13	15
Expected return on plan assets	(8)	(10)	(17)	(22)
Amortization:
- prior service cost (credit)	(3)	(2)	(5)	(4)
-actuarial loss (gain)	3	2	6	4
Net settlement loss	2	3	6	17
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	5	5	12	21
Unfunded Plan [Member]
Payment for Pension and Other Postretirement Benefits [Abstract]
Payment for Other Postretirement Benefits			12
Other Postretirement Benefit Plans Defined Benefit [Member]
Defined Benefit Plan Net Periodic Benefit Cost [Line Items]
Service cost	0	0	1	1
Interest cost	2	2	4	4
Expected return on plan assets	0	0	0	0
Amortization:
- prior service cost (credit)	(2)	(1)	(4)	(3)
-actuarial loss (gain)	1	0	1	0
Net settlement loss	0	0	0	0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 1	$ 1	2	$ 2
Payment for Pension and Other Postretirement Benefits [Abstract]
Payment for Other Postretirement Benefits			$ 11

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Reclassifications out of Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Provision for income taxes	$ (44)	$ (41)	$ (212)	$ (75)
Other Expenses	126	111	256	200
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amortization of prior service credit	5	3	9	7
Amortization of actuarial loss	(4)	(2)	(7)	(4)
Net settlement loss	(2)	(3)	(6)	(17)
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	(1)	0	(1)
Income from operations before income taxes	(1)	(3)	(4)	(15)
Provision for income taxes	0	0	0	0
Total reclassifications to expense, net of tax	(1)	(3)	(4)	(15)
Other Expenses	(4)	0	(4)	0
Net recognized loss in discontinued operations, net of tax	0	0	0	(30)
Total reclassifications to expense	$ (5)	$ (3)	$ (8)	$ (45)

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Net cash provided by (used in) operating activities included:
Interest paid (net of amounts capitalized)	$ (134)	$ (193)
Income taxes paid to taxing authorities	(282)	(43)
Noncash investing activities:
Receivable Related To Disposal Of Assets	0	742
Capital Expenditures Incurred but Not yet Paid	$ 303	$ 338

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Equity Method Investments and Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	$ 788		$ 788		$ 847
Equity Method Investment, Summarized Financial Information [Abstract]
Revenues and other income	228	$ 199	426	$ 438
Income from operations	143	113	240	265
Net income	$ 123	$ 101	$ 202	$ 235
EG Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	60.00%		60.00%
Equity Method Investments	$ 414		$ 414		456
Alba Plant LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	52.00%		52.00%
Equity Method Investments	$ 189		$ 189		214
AMPCO [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	45.00%		45.00%
Equity Method Investments	$ 185		$ 185		$ 177

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Commitments and Contingencies (Details) $ in Millions	Dec. 31, 2017 USD ($)
Foreign Tax Authority [Member] | UK Government [Member]
Loss Contingencies [Line Items]
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority	$ 108