10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)
☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended	September 30, 2020

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 1-1513

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, Texas  

77056-2723

(Address of principal executive offices)

(713) 629-6600

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol	Name of each exchange on which registered
Common Stock, par value $1.00	MRO	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.       Yes þ No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).   Yes þ No o

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

Large accelerated filer	þ	Accelerated filer		o	Non-accelerated filer		o
Smaller reporting company		☐	Emerging growth company			☐

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 ☐ No þ  

    There were 789,391,520 shares of Marathon Oil Corporation common stock outstanding as of October 31, 2020.

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 2019 Annual Report on Form 10-K.

	Table of Contents
		Page
Part I - FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Consolidated Statements of Income (Unaudited)	2
	Consolidated Statements of Comprehensive Income (Unaudited)	3
	Consolidated Balance Sheets (Unaudited)	4
	Consolidated Statements of Cash Flows (Unaudited)	5
	Consolidated Statements of Stockholders' Equity (Unaudited)	6
	Notes to Consolidated Financial Statements (Unaudited)	8
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48
Item 4.	Controls and Procedures	48
Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50
Item 6.	Exhibits	50
	Signatures	51

1

Part I – FINANCIAL INFORMATION

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions, except per share data)	2020		2019		2020		2019
Revenues and other income:
Revenues from contracts with customers	$	761	$	1,249	$	2,275	$	3,830
Net gain (loss) on commodity derivatives	(1)		47		131		(28)
Income (loss) from equity method investments	(10)		21		(174)		63
Net gain on disposal of assets	1		22		8		56
Other income	3		6		16		54
Total revenues and other income	754		1,345		2,256		3,975
Costs and expenses:
Production	129		163		418		543
Shipping, handling and other operating	183		138		432		462
Exploration	27		22		81		107
Depreciation, depletion and amortization	554		622		1,795		1,781
Impairments	1		—		98		24
Taxes other than income	49		81		145		232
General and administrative	53		82		217		263
Total costs and expenses	996		1,108		3,186		3,412
Income (loss) from operations	(242)		237		(930)		563
Net interest and other	(62)		(64)		(195)		(177)
Other net periodic benefit (costs) credits	(6)		2		1		9
Income (loss) before income taxes	(310)		175		(1,124)		395
Provision (benefit) for income taxes	7		10		(11)		(105)
Net income (loss)	$	(317)	$	165	$	(1,113)	$	500
Net income (loss) per share:
Basic	$	(0.40)	$	0.21	$	(1.41)	$	0.62
Diluted	$	(0.40)	$	0.21	$	(1.41)	$	0.62
Weighted average common shares outstanding:
Basic	790		802		792		813
Diluted	790		803		792		813

 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				Nine Months Ended
	September 30,				September 30,
(In millions)	2020		2019		2020		2019
Net income (loss)	$	(317)	$	165	$	(1,113)	$	500
Other comprehensive income (loss), net of tax
Change in actuarial gain (loss) and other for postretirement and postemployment plans	9		38		(33)		25
Change in derivative hedges unrecognized gain (loss)	11		—		(15)		—
Foreign currency translation adjustment related to sale of U.K. business	—		23		—		23
Other	—		1		—		1
Other comprehensive income (loss)	20		62		(48)		49
Comprehensive income (loss)	$	(297)	$	227	$	(1,161)	$	549

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

3

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)

	September 30,		December 31,
(In millions, except par value and share amounts)	2020		2019
Assets
Current assets:
Cash and cash equivalents	$	1,119	$	858
Receivables, less reserve of $25 and $11	643		1,122
Inventories	77		72
Other current assets	83		83
Total current assets	1,922		2,135
Equity method investments	467		663
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $19,782 and $18,003	16,029		17,000
Goodwill	—		95
Other noncurrent assets	245		352
Total assets	$	18,663	$	20,245
Liabilities
Current liabilities:
Accounts payable	$	730	$	1,307
Payroll and benefits payable	72		112
Accrued taxes	45		118
Other current liabilities	219		208
Long-term debt due within one year	500		—
Total current liabilities	1,566		1,745
Long-term debt	5,405		5,501
Deferred tax liabilities	184		186
Defined benefit postretirement plan obligations	182		183
Asset retirement obligations	236		243
Deferred credits and other liabilities	198		234
Total liabilities	7,771		8,092
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 (par value $1 per share, 1.925 billion shares authorized at September 30, 2020 and December 31, 2019)	937		937
Held in treasury, at cost – 147 million shares and 141 million shares	(4,089)		(4,089)
Additional paid-in capital	7,159		7,207
Retained earnings	6,828		7,993
Accumulated other comprehensive income	57		105
Total stockholders’ equity	10,892		12,153
Total liabilities and stockholders’ equity	$	18,663	$	20,245

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

4

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)

	Nine Months Ended
	September 30,
(In millions)	2020		2019
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income (loss)	$	(1,113)	$	500
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	1,795		1,781
Impairments	98		24
Exploratory dry well costs and unproved property impairments	63		85
Net gain on disposal of assets	(8)		(56)
Deferred income taxes	(2)		(34)
Net (gain) loss on derivative instruments	(131)		28
Net settlements of derivative instruments	92		41
Pension and other post retirement benefits, net	(35)		(51)
Stock-based compensation	43		45
Equity method investments, net	189		26
Changes in:
Current receivables	467		(99)
Inventories	(5)		4
Current accounts payable and accrued liabilities	(478)		(164)
Other current assets and liabilities	83		108
All other operating, net	(3)		(189)
Net cash provided by operating activities	1,055		2,049
Investing activities:
Additions to property, plant and equipment	(1,090)		(1,934)
Additions to other assets	15		41
Acquisitions, net of cash acquired	(1)		—
Disposal of assets, net of cash transferred to the buyer	9		(84)
Equity method investments - return of capital	7		51
All other investing, net	—		2
Net cash used in investing activities	(1,060)		(1,924)
Financing activities:
Borrowings	400		—
Purchases of common stock	(92)		(296)
Dividends paid	(40)		(122)
All other financing, net	(2)		(4)
Net cash provided by (used in) financing activities	266		(422)
Net increase (decrease) in cash and cash equivalents	261		(297)
Cash and cash equivalents at beginning of period	858		1,462
Cash and cash equivalents at end of period	$	1,119	$	1,165

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

5

MARATHON OIL CORPORATION

Consolidated Statements of Stockholders’ Equity (Unaudited)

	Total Equity of Marathon Oil Stockholders
(In millions)	Preferred Stock		Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total Equity
Nine Months Ended September 30, 2019
December 31, 2018 Balance	$	—	$	937	$	(3,816)	$	7,238	$	7,706	$	63	12,128
Cumulative-effect adjustment	—		—		—		—		(31)		—		(31)
Shares issued - stock-based compensation	—		—		101		(39)		—		—		62
Shares repurchased	—		—		(30)		—		—		—		(30)
Stock-based compensation	—		—		—		(50)		—		—		(50)
Net income	—		—		—		—		174		—		174
Other comprehensive loss	—		—		—		—		—		(4)		(4)
Dividends paid (per share amount of $0.05)	—		—		—		—		(41)		—		(41)
March 31, 2019 Balance	$	—	$	937	$	(3,745)	$	7,149	$	7,808	$	59	$	12,208
Shares issued - stock-based compensation	—		—		(3)		5		—		—		2
Shares repurchased	—		—		(236)		—		—		—		(236)
Stock-based compensation	—		—		—		16		—		—		16
Net income	—		—		—		—		161		—		161
Other comprehensive loss	—		—		—		—		—		(9)		(9)
Dividends paid (per share amount of $0.05)	—		—		—		—		(41)		—		(41)
June 30, 2019 Balance	$	—	$	937	$	(3,984)	$	7,170	$	7,928	$	50	$	12,101
Shares issued - stock-based compensation	—		—		(14)		9		—		—		(5)
Shares repurchased	—		—		(30)		—		—		—		(30)
Stock-based compensation	—		—		—		18		—		—		18
Net income	—		—		—		—		165		—		165
Other comprehensive income	—		—		—		—		—		62		62
Dividends paid (per share amount of $0.05)	—		—		—		—		(40)		—		(40)
September 30, 2019 Balance	$	—	$	937	$	(4,028)	$	7,197	$	8,053	$	112	$	12,271

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

6

MARATHON OIL CORPORATION

Consolidated Statements of Stockholders’ Equity (Unaudited)

	Total Equity of Marathon Oil Stockholders
(In millions)	Preferred Stock		Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total Equity
Nine Months Ended September 30, 2020
December 31, 2019 Balance	$	—	$	937	$	(4,089)	$	7,207	$	7,993	$	105	12,153
Cumulative-effect adjustment (Note 2)	—		—		—		—		(12)		—		(12)
Shares issued - stock based compensation	—		—		121		(83)		—		—		38
Shares repurchased	—		—		(91)		—		—		—		(91)
Stock-based compensation	—		—		—		(22)		—		—		(22)
Net loss	—		—		—		—		(46)		—		(46)
Other comprehensive loss	—		—		—		—		—		(22)		(22)
Dividends paid (per share amount of $0.05)	—		—		—		—		(40)		—		(40)
March 31, 2020 Balance	$	—	$	937	$	(4,059)	$	7,102	$	7,895	$	83	$	11,958
Shares issued - stock-based compensation	—		—		(28)		20		—		—		(8)
Stock-based compensation	—		—		—		21		—		—		21
Net loss	—		—		—		—		(750)		—		(750)
Other comprehensive loss	—		—		—		—		—		(46)		(46)
June 30, 2020 Balance	$	—	$	937	$	(4,087)	$	7,143	$	7,145	$	37	$	11,175
Shares issued - stock-based compensation	—		—		(2)		2		—		—		—
Stock-based compensation	—		—		—		14		—		—		14
Net loss	—		—		—		—		(317)		—		(317)
Other comprehensive income	—		—		—		—		—		20		20
September 30, 2020 Balance	$	—	$	937	$	(4,089)	$	7,159	$	6,828	$	57	$	10,892

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

7

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 2019 Annual Report on Form 10-K. The results of operations for the third quarter and first nine months of 2020 are not necessarily indicative of the results to be expected for the full year.

2.    Accounting Standards

Recently Adopted

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. On January 1, 2020 we adopted this standard using the modified retrospective transition method through a cumulative-effect adjustment of $12 million to retained earnings as of the beginning of the adoption period. The standard requires the use of a forward-looking “expected loss” model as opposed to the “incurred loss” model used previously. See Note 8 for more information on credit losses.

3.    Income (loss) and Dividends per Common Share

Basic income (loss) per share is based on the weighted average number of common shares outstanding. Diluted income (loss) per share assumes exercise of stock options in all periods, provided the effect is not antidilutive. The per share calculations below exclude 6 million of stock options for each of the three and nine months ended September 30, 2020 and 6 million and 5 million of stock options for the three and nine months ended September 30, 2019 that were antidilutive.

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions, except per share data)	2020		2019		2020		2019
Net income (loss)	$	(317)	$	165	$	(1,113)	$	500
Weighted average common shares outstanding	790		802		792		813
Effect of dilutive securities	—		1		—		—
Weighted average common shares, diluted	790		803		792		813
Net income (loss) per share:
Basic	$	(0.40)	$	0.21	$	(1.41)	$	0.62
Diluted	$	(0.40)	$	0.21	$	(1.41)	$	0.62
Dividends per share	$	—	$	0.05	$	0.05	$	0.15

4.    Dispositions

International Segment

In July 2019, we closed on the sale of our U.K. business (Marathon Oil U.K. LLC and Marathon Oil West of Shetlands Limited) for proceeds of $95 million which included the assumption by RockRose Energy PLC (the buyer) of the U.K. business’ cash equivalent balance and working capital balance as of year-end 2018. During the third quarter of 2019, we recognized a pre-tax gain of $14 million. Our income before income taxes relating to our U.K. business for the three and nine months ended September 30, 2019, was nil and $28 million.

In the second quarter of 2019, we closed on the sale of our 15% non-operated interest in the Atrush block in Kurdistan for proceeds of $63 million, before closing adjustments.

8

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

5.    Revenues

The majority of our revenues are derived from the sale of crude oil and condensate, NGLs and natural gas under spot and term agreements with our customers in the United States and various international locations.

As of September 30, 2020 and December 31, 2019, receivables from contracts with customers, included in receivables, less reserves were $502 million and $837 million, respectively.

The following tables present our revenues from contracts with customers disaggregated by product type and geographic areas for the three and nine months ended September 30 as follows:

United States

	Three Months Ended September 30, 2020
(In millions)	Eagle Ford		Bakken		Oklahoma		Northern Delaware		Other U.S.		Total
Crude oil and condensate	$	190	$	230	$	65	$	53	$	14	$	552
Natural gas liquids	22		15		28		7		1		73
Natural gas	18		9		33		6		3		69
Other	1		—		—		—		27		28
Revenues from contracts with customers	$	231	$	254	$	126	$	66	$	45	$	722

	Three Months Ended September 30, 2019
(In millions)	Eagle Ford		Bakken		Oklahoma		Northern Delaware		Other U.S.		Total
Crude oil and condensate	$	336	$	452	$	116	$	88	$	25	$	1,017
Natural gas liquids	23		6		28		5		2		64
Natural gas	28		8		37		3		5		81
Other	1		—		—		—		9		10
Revenues from contracts with customers	$	388	$	466	$	181	$	96	$	41	$	1,172

	Nine Months Ended September 30, 2020
(In millions)	Eagle Ford		Bakken		Oklahoma		Northern Delaware		Other U.S.		Total
Crude oil and condensate	$	639	$	707	$	181	$	160	$	54	$	1,741
Natural gas liquids	53		28		62		14		4		161
Natural gas	62		22		86		13		7		190
Other	4		—		—		—		58		62
Revenues from contracts with customers	$	758	$	757	$	329	$	187	$	123	$	2,154

	Nine Months Ended September 30, 2019
(In millions)	Eagle Ford		Bakken		Oklahoma		Northern Delaware		Other U.S.		Total
Crude oil and condensate	$	1,004	$	1,277	$	304	$	229	$	83	$	2,897
Natural gas liquids	88		31		81		20		5		225
Natural gas	94		26		118		10		15		263
Other	4		—		—		—		45		49
Revenues from contracts with customers	$	1,190	$	1,334	$	503	$	259	$	148	$	3,434

9

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

International

	Three Months Ended September 30, 2020
(In millions)	E.G.
Crude oil and condensate	$	31
Natural gas liquids	1
Natural gas	7
Other	—
Revenues from contracts with customers	$	39

	Three Months Ended September 30, 2019
(In millions)	E.G.
Crude oil and condensate	$	67
Natural gas liquids	1
Natural gas	8
Other	1
Revenues from contracts with customers	$	77

	Nine Months Ended September 30, 2020
(In millions)	E.G.
Crude oil and condensate	$	96
Natural gas liquids	3
Natural gas	22
Revenues from contracts with customers	$	121

	Nine Months Ended September 30, 2019
(In millions)	E.G.		U.K.		Other Int’l		Total
Crude oil and condensate	$	215	$	107	$	19	$	341
Natural gas liquids	3		1		—		4
Natural gas	24		12		—		36
Other	1		14		—		15
Revenues from contracts with customers	$	243	$	134	$	19	$	396

10

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

6.    Segment Information

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

•United States (“U.S.”) – explores for, produces and markets crude oil and condensate, NGLs and natural gas in the United States

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

    Segment income represents income 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, impairments of proved property, goodwill, and equity method investments, unrealized gains or losses on commodity and interest rate derivative instruments, effects of pension settlements and curtailments, or other items (as determined by the chief operating decision maker (“CODM”)) are not allocated to operating segments.

	Three Months Ended September 30, 2020
(In millions)	U.S.		Int’l		Not Allocated to Segments			Total
Revenues from contracts with customers	$	722	$	39	$	—		$	761
Net gain (loss) on commodity derivatives	35		—		(36)		(b)	(1)
Income (loss) from equity method investments	—		8		(18)			(10)
Net gain on disposal of assets	—		—		1			1
Other income	1		1		1			3
Less costs and expenses:
Production	118		11		—			129
Shipping, handling and other operating	154		1		28			183
Exploration	21		—		6			27
Depreciation, depletion and amortization	530		19		5			554
Impairments	—		—		1			1
Taxes other than income	48		—		1			49
General and administrative	25		3		25			53
Net interest and other	—		—		62			62
Other net periodic benefit costs	—		—		6		(c)	6
Income tax provision (benefit)	(3)		6		4			7
Segment income (loss)	$	(135)	$	8	$	(190)		$	(317)
Total assets	$	16,396	$	1,104	$	1,163		$	18,663
Capital expenditures(a)	$	176	$	—	$	1		$	177

(a)Includes accruals.

(b)Unrealized loss on commodity derivative instruments (See Note 15).

(c)Includes pension settlement loss of $9 million (See Note 20).

11

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	Three Months Ended September 30, 2019
(In millions)	U.S.		Int’l		Not Allocated to Segments			Total
Revenues from contracts with customers	$	1,172	$	77	$	—		$	1,249
Net gain on commodity derivatives	14		—		33		(b)	47
Income from equity method investments	—		21		—			21
Net gain on disposal of assets	—		—		22		(c)	22
Other income	3		2		1			6
Less costs and expenses:
Production	147		16		—			163
Shipping, handling and other operating	137		1		—			138
Exploration	22		—		—			22
Depreciation, depletion and amortization	589		25		8			622
Taxes other than income	80		—		1			81
General and administrative	34		5		43			82
Net interest and other	—		—		64			64
Other net periodic benefit credit	—		—		(2)			(2)
Income tax provision	—		10		—			10
Segment income (loss)	$	180	$	43	$	(58)		$	165
Total assets	$	17,722	$	2,003	$	648		$	20,373
Capital expenditures(a)	$	667	$	1	$	7		$	675

(a)Includes accruals.

(b)Unrealized gain on commodity derivative instruments (See Note 15).

(c)Primarily related to the sale of our U.K. business (see Note 4).

12

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	Nine Months Ended September 30, 2020
(In millions)	U.S.		Int’l		Not Allocated to Segments			Total
Revenues from contracts with customers	$	2,154	$	121	$	—		$	2,275
Net gain on commodity derivatives	92		—		39		(b)	131
Loss from equity method investments	—		(4)		(170)		(c)	(174)
Net gain on disposal of assets	—		—		8			8
Other income	8		5		3			16
Less costs and expenses:
Production	375		43		—			418
Shipping, handling and other operating	385		5		42			432
Exploration	75		—		6			81
Depreciation, depletion and amortization	1,716		62		17			1,795
Impairments	—		—		98		(d)	98
Taxes other than income	144		—		1			145
General and administrative	89		10		118		(e)	217
Net interest and other	—		—		195			195
Other net periodic benefit credit	—		—		(1)		(f)	(1)
Income tax provision (benefit)	(10)		1		(2)			(11)
Segment income (loss)	$	(520)	$	1	$	(594)		$	(1,113)
Total assets	$	16,396	$	1,104	$	1,163		$	18,663
Capital expenditures(a)	$	874	$	—	$	10		$	884

(a)Includes accruals.

(b)Unrealized gain on commodity derivative instruments (See Note 15).

(c)Partial impairment of investment in equity method investee (See Note 23).

(d)Includes the full impairment of the International reporting unit goodwill of $95 million (See Note 14).

(e)Includes severance expenses associated with workforce reductions of $15 million.

(f)Includes pension settlement loss of $25 million and pension curtailment gain of $17 million (See Note 20).

13

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	Nine Months Ended September 30, 2019
(In millions)	U.S.		Int’l		Not Allocated to Segments			Total
Revenue from contracts with customers	$	3,434	$	396	$	—		$	3,830
Net gain (loss) on commodity derivatives	41		—		(69)		(b)	(28)
Income from equity method investments	—		63		—			63
Net gain on disposal of assets	—		—		56		(c)	56
Other income	8		7		39		(d)	54
Less costs and expenses:
Production	433		112		(2)			543
Shipping, handling and other operating	424		24		14			462
Exploration	107		—		—			107
Depreciation, depletion and amortization	1,664		97		20			1,781
Impairments	—		—		24		(e)	24
Taxes other than income	233		—		(1)			232
General and administrative	94		20		149			263
Net interest and other	—		—		177			177
Other net periodic benefit credit	—		(3)		(6)			(9)
Income tax provision (benefit)	1		16		(122)		(f)	(105)
Segment income (loss)	$	527	$	200	$	(227)		$	500
Total assets	$	17,722	$	2,003	$	648		$	20,373
Capital expenditures(a)	$	1,959	$	16	$	15		$	1,990

(a)Includes accruals.

(b)Unrealized loss on commodity derivative instruments (See Note 15).

(c)Primarily related to the sale of our working interest in the Droshky field (Gulf of Mexico) and the sale of our U.K. business (See Note 4).

(d)Primarily related to the indemnification of certain tax liabilities in connection with the 2010-2011 Federal Tax Audit.

(e)Primarily as a result of anticipated sales of certain non-core proved properties in our International and United States segments.

(f)Primarily relates to the settlement of the 2010-2011 Federal Tax Audit (See Note 7).

14

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

7.    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 6.

For the three and nine months ended September 30, 2020 and 2019, our effective income tax rates were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Effective income tax rate(a)	(2)	%	6	%	1	%	(27)	%

(a)In all periods presented, we maintained our valuation allowance on our net federal deferred tax assets in the U.S.

The following items caused the effective income tax rates to be different from our U.S. statutory tax rate of 21% for 2020 and 2019:

•For the three and nine months ended September 30, 2020, the income tax rate was reduced below the statutory rate due to the valuation allowance on our net federal deferred tax assets in the U.S., which resulted in no federal tax benefit on the U.S. loss.

•For the three and nine months ended September 30, 2019, the mix of pre-tax income in our international operations and the valuation allowance on our net federal deferred tax assets in the U.S., reduced the annual effective tax rate below the statutory tax rate. Income tax rates for the nine months ended September 30, 2019 were also impacted by the settlement of the 2010-2011 U.S. Federal Tax Audit in the first quarter of 2019, resulting in a tax benefit of $126 million. Additionally, in the first quarter of 2019, we recorded a non-cash deferred tax benefit of $18 million in the U.K. related to an internal restructuring. These two items are discrete to the first nine months of 2019. Excluding these discrete adjustments, the effective income tax rate for the first nine months of 2019 was an expense of 10%.

In the third quarter of 2020, we received an $89 million cash refund related to alternative minimum tax credits and interest. This refund was accelerated as a result of the enactment of the Coronavirus Aid, Relief, and Economic Security Act, commonly referred to as the CARES Act, in the first quarter of 2020. 

8.    Credit Losses

    The majority of our receivables are from purchasers of commodities or joint interest owners in properties we operate, both of which are recorded at estimated or invoiced amounts and do not bear interest. The majority of these receivables have payment terms of 30 days or less. At the end of each reporting period, we assess the collectability of our receivables and estimate the expected credit losses using historical data, current market conditions and reasonable and supportable forecasts of future economic conditions.

    We are exposed to credit losses through the receivables generated from sales of crude oil, NGLs and natural gas to our customers. When dealing with the commodity purchasers, we conduct a credit review to assess each counterparty’s ability to pay. The credit review considers our expected billing exposure, timing for payment and the counterparty’s established credit rating with the rating agencies or our internal assessment of the counterparty’s creditworthiness based on our analysis of their financial statements. Our evaluation also considers contract terms and other factors, such as country and/or political risk. A credit limit is established for each counterparty based on the outcome of this review. We may require a bank letter of credit or a prepayment to mitigate credit risk. We monitor our ongoing credit exposure through active review of counterparty balances against contract terms and due dates. The expected credit losses related to receivables with the commodity purchasers were determined using the weighted average probability of default method. We also collect revenues from our non-operated joint properties where other oil and gas exploration and production companies operate the properties and market our share of production and remit payments to us. The current expected credit losses related to these receivables were determined using the loss rate method applied to aging pools.

15

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

We are exposed to credit losses from joint interest billings to other joint interest owners for properties we operate. For this group of receivables, the expected credit losses are determined using the loss rate method applied to aging pools. Our counterparties in this group include numerous large, mid-size and small oil and gas exploration and production companies. Although we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings or require a prepayment of future costs through cash calls, our credit loss exposure with this group is more significant due to inherent ownership or billing adjustments. Also, some of our counterparties may experience liquidity problems and may not be able to meet their financial obligations to us. We expect that liquidity problems will increase in the future as a result of the recent demand and pricing decline for hydrocarbons. Our current-period provision reflects the anticipated effects caused by the recent market deterioration.

Changes in the allowance for doubtful accounts balance for the nine months ended were as follows:    

(In millions)	September 30, 2020
Beginning balance as of January 1	$	11
Cumulative-effect adjustment	12
Current period provision(a)	22
Current period write offs	(12)
Recoveries of amounts previously reserved	(8)
Ending balance as of September 30	$	25

(a)For the nine months ended September 30, 2020, the current period provision increased by $10 million in joint interest receivables and $12 million in trade receivables.

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. The continued volatility and future decline in crude oil and natural gas prices could affect the value of our inventories and result in future impairments.

(In millions)	September 30, 2020		December 31, 2019
Crude oil and natural gas	$	11	$	10
Supplies and other items	66		62
Inventories	$	77	$	72

10.    Property, Plant and Equipment

(In millions)	September 30, 2020		December 31, 2019
United States	$	15,533	$	16,427
International	424		493
Corporate	72		80
Net property, plant and equipment	$	16,029	$	17,000

We had no exploratory well costs capitalized greater than one year as of September 30, 2020 and December 31, 2019.

11.    Impairments

    During the first quarter of 2020, a global pandemic caused a substantial deterioration in the worldwide demand of hydrocarbons. The decreased demand, when coupled with an oversupplied market, caused a corresponding deterioration in hydrocarbon prices. We reviewed our long-lived assets for indicators of impairment during the first quarter by conducting a sensitivity analysis of the most impactful inputs to their undiscounted cash flows, including commodity prices, capital spend and reductions in production volumes to correspond with lower capital spending. Our review concluded that the carrying amounts of our long-lived assets are recoverable; however, further deterioration or a more sustained decline of commodity prices may result in impairment charges in future periods. 

16

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

    We also reviewed our equity method investments for indicators of impairment. Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred. When a loss in value occurs that is deemed other than temporary, the carrying value of the equity method investment is written down to fair value. Our first quarter review concluded that any potential losses in values of our equity method investments were temporary because the underlying declines in both commodity prices and demand did not materially manifest until early March. However, during the second and third quarters of 2020, we recognized impairments related to one of our equity method investees, as noted in the tables below.

The following table summarizes impairment charges of proved properties, goodwill and equity method investments and their corresponding fair values.

	Three Months Ended September 30,
	2020				2019
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	—	$	1	$	—	$	—
Equity method investment	$	23	$	18	N/A		$	—

	Nine Months Ended September 30,
	2020				2019
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	—	$	3	$	56	$	24
Goodwill	$	—	$	95	N/A		$	—
Equity method investment	$	119	$	170	N/A		$	—

•2020 – Impairments for the nine months ended September 30, 2020 include charges recognized for our equity method investments of $170 million. During the second quarter of 2020, the continuation of the depressed commodity prices caused us to perform a review of our equity method investments. Our review concluded that a loss of our investment value in one of our equity method investees was other than temporary and we recorded an impairment of $152 million based on the difference between our carrying value and the fair value of our investment. During the third quarter of 2020, we further reduced our long term price forecast of a gas index in which one of our equity method investees transacts, which resulted in an incremental reduction of our investment value. We recorded an impairment of $18 million during the third quarter, which we deemed other than temporary. Our remaining investments in equity method investees did not experience losses in value that caused the fair values to be below their carrying values.

We estimated the fair value of our equity method investment using an income approach, specifically utilizing a discounted cash flow analysis. The estimated fair value was based on significant inputs not observable in the market, such as the amount of gas processed by the plant, future commodity prices, forecasted operating expenses, discount rate, and estimated cash returned to shareholders. Collectively, these inputs represent Level 3 measurements.

The impairments of our equity method investments were recognized in income (loss) from equity method investments in our consolidated statements of income. The impairments caused us to incur a basis differential between the net book value of our investment and the amount of our underlying share of equity in the investee’s net assets. The amount of this basis differential is $140 million and will be accreted into income over the next 6.25 years, which is consistent with the remaining useful life of the investee’s primary assets.

Impairments for the nine months ended September 30, 2020 also included $95 million of goodwill impairment in the International reporting unit. See Note 14 for further information.

•2019 – During the nine months ended September 30, 2019, we recorded proved property impairments of $24 million, as a result of the anticipated sales proceeds for certain non-core proved properties in our United States segment and the sale of our non-operated interest in the Atrush block (Kurdistan) in our International segment. The related fair value was measured using the market approach, based upon anticipated sales proceeds less costs to sell which resulted in a Level 2 classification. See Note 4 for further information.

17

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

12.    Asset Retirement Obligations

Asset retirement obligations primarily consist of estimated costs to remove, dismantle and restore land or seabed at the end of oil and gas production operations. Changes in asset retirement obligations for the nine months ended September 30 were as follows:

	September 30,
(In millions)	2020		2019
Beginning balance as of January 1	$	255	$	1,145
Incurred liabilities, including acquisitions	3		25
Settled liabilities, including dispositions	(11)		(1,106)
Accretion expense (included in depreciation, depletion and amortization)	9		29
Revisions of estimates	(8)		15
Held for sale	—		108
Ending balance as of September 30	$	248	$	216

September 30, 2020

•Ending balance includes $12 million classified as short-term at September 30, 2020.

September 30, 2019

•Settled liabilities primarily relate to the sale of our U.K. business, which closed during the third quarter of 2019.

•Held for sale reflects a transfer to settled liabilities during 2019. This transfer was primarily related to the Droshky field (Gulf of Mexico), which was considered held for sale at year-end 2018 and closed in the first quarter of 2019.

13. Leases

We enter into various lease agreements to support our operations including drilling rigs, well fracturing equipment, compressors, buildings, aircraft, vessels, vehicles and miscellaneous field equipment. We primarily act as a lessee in these transactions and all of our existing leases are classified as either short-term or long-term operating leases.

Supplemental balance sheet information related to leases was as follows:

(In millions)		September 30, 2020
Operating Leases:	Balance Sheet Location:
Right-of-use asset	Other noncurrent assets	$	137
Current portion of long-term lease liability	Other current liabilities	$	79
Long-term lease liability	Deferred credits and other liabilities	$	61

18

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

    Our wholly-owned subsidiary, Marathon E.G. Production Limited, is a lessor for residential housing in Equatorial Guinea, which is occupied by EGHoldings, a related party equity method investee – see Note 24. The lease was classified as an operating lease and expires in 2024, with a lessee option to extend through 2034. Lease payments are fixed for the entire duration of the agreement at approximately $6 million per year. Our lease income is reported in other income in our consolidated statements of income for all periods presented. The undiscounted cash flows to be received under this lease agreement are summarized below.

(In millions)	Operating Lease Future Cash Receipts
2020	$	2
2021	6
2022	6
2023	6
2024	6
Thereafter	60
Total undiscounted cash flows	$	86

In 2018, we signed an agreement with an owner/lessor to construct and lease a new build-to-suit office building in Houston, Texas. The lessor and other participants are providing financing for up to $340 million to fund the estimated project costs, which was reduced effective August 2020, from $380 million to align with our revised estimate of the project costs. As of September 30, 2020, project costs incurred totaled approximately $117 million, including land acquisition and construction costs. The initial lease term is five years and will commence once construction is substantially complete and the new Houston office is ready for occupancy. At the end of the initial lease term, we can negotiate to extend the lease term for an additional five years, subject to the approval of the participants; purchase the property subject to certain terms and conditions; or remarket the property to an unrelated third party. The lease contains a residual value guarantee of approximately 89% of the total acquisition and construction costs.

14.  Goodwill

As of December 31, 2019, our consolidated balance sheet included goodwill of $95 million in the International reporting unit. Goodwill is tested for impairment on an annual basis, or between annual tests when events or changes in circumstances indicate the fair value of a reporting unit with goodwill may have been reduced below its carrying value. During the first quarter of 2020, a global pandemic caused a substantial deterioration in the worldwide demand of hydrocarbons. This demand loss resulted in a significant decline in hydrocarbon prices. The commensurate decline in our market capitalization during the first quarter indicated that it was more likely than not that the fair value of the International reporting unit was less than its carrying value.

We estimated the fair value of our International reporting unit using a combination of market and income approaches. The market approach referenced observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value, and valuation multiples of us and peers from the investor analyst community. The income approach utilized discounted cash flows, which were based on forecasted assumptions. Key assumptions to the income approach include future liquid hydrocarbon and natural gas pricing, estimated quantities of liquid hydrocarbons and natural gas proved and probable reserves, estimated timing of production, discount rates, future capital requirements, operating expenses and tax rates. The assumptions used in the income approach are consistent with those that management uses to make business decisions. These valuation methodologies represent Level 3 fair value measurements. Based on the results, we concluded our goodwill was fully impaired, and recorded an impairment of $95 million in the consolidated statements of income for the first quarter of 2020.

19

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	September 30,
(In millions)	2020		2019
Beginning balance as of January 1, gross	$	95	$	97
Less: accumulated impairments	—		—
Beginning balance, net	95		97
Dispositions	—		(2)
Impairment	(95)		—
Ending balance as of September 30, net	$	—	$	95

15.  Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note 16. All of our commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we report net amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts along with where they appear on the consolidated balance sheets.

	September 30, 2020
(In millions)	Asset		Liability		Net Asset (Liability)		Balance Sheet Location
Not Designated as Hedges
Commodity	$	59	$	14	$	45	Other current assets
Commodity	—		2		(2)		Deferred credits and other liabilities
Interest Rate	1		—		1		Other noncurrent assets
Interest Rate	—		3		(3)		Deferred credits and other liabilities
Total Not Designated as Hedges	$	60	$	19	$	41
Cash Flow Hedges
Interest Rate	$	9	$	—	$	9	Other noncurrent assets
Interest Rate	—		19		(19)		Deferred credits and other liabilities
Total Designated Hedges	$	9	$	19	$	(10)
Total	$	69	$	38	$	31

	December 31, 2019
(In millions)	Asset		Liability		Net Asset (Liability)		Balance Sheet Location
Not Designated as Hedges
Commodity	$	9	$	1	$	8	Other current assets
Commodity	1		—		1		Other noncurrent assets
Commodity	—		5		(5)		Other current liabilities
Total Not Designated as Hedges	$	10	$	6	$	4
Cash Flow Hedges
Interest Rate	$	2	$	—	$	2	Other noncurrent assets
Total Designated Hedges	$	2	$	—	$	2
Total	$	12	$	6	$	6

20

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Derivatives Not Designated as Hedges

Commodity Derivatives

We have entered into multiple crude oil, natural gas and NGL derivatives indexed to the respective indices as noted in the table below, related to a portion of our forecasted United States sales through 2021. These derivatives consist of three-way collars, two-way collars, fixed price swaps, basis swaps, and NYMEX roll basis swaps. Three-way collars consist of a sold call (ceiling), a purchased put (floor) and a sold put. The ceiling price is the maximum we will receive for the contract volumes; the floor is the minimum price we will receive, unless the market price falls below the sold put strike price. In this case, we receive the NYMEX WTI price plus the difference between the floor and the sold put price. Two-way collars only consist of a sold call (ceiling) and a purchased put (floor). These crude oil, natural gas and NGL derivatives were not designated as hedges.

The following table sets forth outstanding derivative contracts as of September 30, 2020, and the weighted average prices for those contracts:

	2020		2021		2021
	Fourth Quarter		First Half		Second Half
Crude Oil
NYMEX WTI Three-Way Collars
Volume (Bbls/day)	80,000		—		—
Weighted average price per Bbl:
Ceiling	$	64.40	$	—	$	—
Floor	$	55.00	$	—	$	—
Sold put	$	48.00	$	—	$	—
NYMEX WTI Two-Way Collars
Volume (Bbls/day)	20,000		10,000		10,000
Weighted average price per Bbl:
Ceiling	$	46.83	$	52.37	$	52.37
Floor	$	37.00	$	35.00	$	35.00
Basis Swaps - NYMEX WTI / Argus WTI Midland (a)
Volume (Bbls/day)	15,000		—		—
Weighted average price per Bbl	$	(0.94)	$	—	$	—
Basis Swaps - NYMEX WTI / ICE Brent (b)
Volume (Bbls/day)	5,000		1,630		—
Weighted average price per Bbl	$	(7.24)	$	(7.24)	$	—
NYMEX Roll Basis Swaps
Volume (Bbls/day)	30,000		—		—
Weighted average price per Bbl	$	(0.81)	$	—	$	—
Natural Gas
Henry Hub (“HH”) Two-Way Collars
Volume (MMBtu/day)	250,000		175,000		150,000
Weighted average price per MMBtu:
Ceiling	$	2.82	$	3.10	$	3.03
Floor	$	2.25	$	2.46	$	2.43
Basis Swaps - WAHA / HH (c)
Volume (MMBtu/day)	10,000		—		—
Weighted average price per MMBtu	$	(0.37)	$	—	$	—
NGL
Fixed Price Ethane Swaps (d)
Volume (Bbls/day)	10,000		—		—
Weighted average price per Bbl	$	8.78	$	—	$	—

(a)The basis differential price is indexed against Argus WTI Midland and NYMEX WTI.

(b)The basis differential price is indexed against Intercontinental Exchange (“ICE”) Brent and NYMEX WTI.

(c)The basis differential price is indexed against Waha and NYMEX Henry Hub.

(d)The fixed price ethane swap is priced at OPIS Mont Belvieu Purity Ethane.

21

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The following table sets forth outstanding derivative contracts entered into between October 1 and November 3, 2020, and the weighted average prices for those contracts:

	2021		2021
	First Half		Second Half
Crude Oil
Basis Swaps - NYMEX WTI / UHC (a)
Volume (Bbls/day)	14,000		—
Weighted average price per Bbl	$	(1.80)	$	—
Natural Gas
HH Two-Way Collars
Volume (MMBtu/day)	50,000		50,000
Weighted average price per MMBtu:
Ceiling	$	3.13	$	3.13
Floor	$	2.70	$	2.70
HH Fixed Price Swaps
Volume (MMBtu/day)	50,000		50,000
Weighted average price per MMBtu	$	2.88	$	2.88

(a)The basis differential price is indexed against U.S. Sweet Clearbrook (“UHC”) and NYMEX WTI.

The mark-to-market impact and settlement of our commodity derivative instruments appears in the table below and is reflected in net gain (loss) on commodity derivatives in the consolidated statements of income.

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2020		2019		2020		2019
Mark-to-market gain (loss)	$	(36)	$	33	$	39	$	(69)
Net settlements of commodity derivative instruments	$	35	$	14	$	92	$	41

22

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Interest Rate Swaps

During 2020, we entered into forward starting interest rate swaps to hedge the variations in cash flows related to fluctuations in the London Interbank Offered Rate (“LIBOR”) benchmark interest rate related to forecasted interest payments of a future debt issuance in 2022. Each respective derivative contract can be tied to an anticipated underlying dollar notional amount. During the third quarter of 2020, we de-designated these forward starting interest rate swaps previously designated as cash flow hedges. At September 30, 2020, accumulated other comprehensive income included a net deferred loss of $2 million related to the de-designated forward starting interest rate swaps previously designated as cash flow hedges. No portion of this amount has been reclassified from accumulated other comprehensive income as of September 30, 2020. We expect to reclassify this amount into earnings as an adjustment to net interest and other upon the occurrence of the forecasted transactions.

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

	September 30, 2020				December 31, 2019
Maturity Date	Aggregate Notional Amount (in millions)		Weighted Average, LIBOR		Aggregate Notional Amount (in millions)		Weighted Average, LIBOR
November 1, 2022	$	500	0.99	%	$	—	—	%

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

	Three Months Ended September 30,		Nine Months Ended September 30,
(In millions)	2020		2020
Interest Rate Swaps
Beginning balance	$	(7)	$	—
Change in fair value recognized in other comprehensive income (loss)	5		(2)
Ending balance	$	(2)	$	(2)

Derivatives Designated as Cash Flow Hedges

During 2020, we entered into forward starting interest rate swaps with a notional amount of $350 million to hedge variations in cash flows arising from fluctuations in the LIBOR benchmark interest rate related to forecasted interest payments of a future debt issuance in 2025. We expect to refinance these debt maturities in 2025. The swaps will terminate on or prior to the refinancing of the debt and the final value will be reclassified from accumulated other comprehensive income into earnings with each future interest payment.

During 2019, we entered into forward starting interest rate swaps with a total notional amount of $320 million to hedge variations in cash flows related to the 1-month LIBOR component of future lease payments of our future Houston office. These swaps will settle monthly on the same day the lease payment is made with the first swap settlement occurring in January 2022. We expect the first lease payment to commence sometime in the period from December 2021 to May 2022. The last swap will mature on September 9, 2026. See Note 13 for further details regarding the lease of the new Houston office.

23

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The following table presents, by maturity date, information about our interest rate swap agreements, including the weighted average LIBOR-based, fixed rate.

	September 30, 2020				December 31, 2019
Maturity Date	Aggregate Notional Amount (in millions)		Weighted Average, LIBOR		Aggregate Notional Amount (in millions)		Weighted Average, LIBOR
June 1, 2025	$	350	0.95	%	$	—	—	%
September 9, 2026	$	320	1.51	%	$	320	1.51	%

At September 30, 2020, accumulated other comprehensive income included deferred losses of $10 million related to forward starting interest rate swaps designated as cash flow hedges. No amounts related to these swaps are expected to impact the consolidated statements of income in the next 12 months.

16.    Fair Value Measurements

Fair Values – Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of September 30, 2020 and December 31, 2019 by hierarchy level.

	September 30, 2020
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity(a)	$	3	$	40	$	—	$	43
Interest rate - not designated as cash flow hedges	—		1		—		1
Interest rate - designated as cash flow hedges	—		9		—		9
Derivative instruments, assets	$	3	$	50	$	—	$	53
Derivative instruments, liabilities
Interest rate - not designated as cash flow hedges	$	—	$	(3)	$	—	$	(3)
Interest rate - designated as cash flow hedges	—		(19)		—		(19)
Derivative instruments, liabilities	$	—	$	(22)	$	—	$	(22)
Total	$	3	$	28	$	—	$	31

	December 31, 2019
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity(a)	$	—	$	7	$	—	$	7
Interest rate - designated as cash flow hedges	—		2		—		2
Derivative instruments, assets	$	—	$	9	$	—	$	9
Derivative instruments, liabilities
Commodity(a)	$	(3)	$	—	$	—	$	(3)
Derivative instruments, liabilities	$	(3)	$	—	$	—	$	(3)
Total	$	(3)	$	9	$	—	$	6

(a)Commodity derivative instruments are recorded on a net basis in our consolidated balance sheet. See Note 15.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Commodity derivatives include three-way collars, two-way collars, fixed price swaps, basis swaps and NYMEX roll basis swaps. These instruments are measured at fair value using either a Black-Scholes or a modified Black-Scholes Model. For 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 and two-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.

The forward starting interest rate swaps are measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs. See Note 15 for detail on the forward starting interest rate swaps.

Fair Value Estimates – Goodwill

See Note 14 for detail information relating to goodwill.

Fair Values – Nonrecurring

See Note 11 for detail on our fair values related to impairments.

Fair Values – Financial Instruments

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

The following table summarizes financial instruments, excluding receivables, payables and derivative financial instruments, and their reported fair values by individual balance sheet line item at September 30, 2020 and December 31, 2019.

	September 30, 2020				December 31, 2019
(In millions)	Fair Value		Carrying Amount		Fair Value		Carrying Amount
Financial assets
Current assets	$	4	$	4	$	4	$	4
Other noncurrent assets	35		49		26		38
Total financial assets	$	39	$	53	$	30	$	42
Financial liabilities
Other current liabilities	$	62	$	99	$	62	$	90
Long-term debt, including current portion(a)	6,044		5,931		6,174		5,529
Deferred credits and other liabilities	105		84		99		86
Total financial liabilities	$	6,211	$	6,114	$	6,335	$	5,705

(a)Excludes debt issuance costs.

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

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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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

17.    Debt

Revolving Credit Facility

As of September 30, 2020, we had no borrowings against our $3.0 billion unsecured revolving credit facility (“Credit Facility”), as described below.

The Credit Facility includes a covenant requiring our total debt to total capitalization ratio not to exceed 65% as of the last day of each fiscal quarter. In the event of a default, the lenders holding more than half of the commitments may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility. As of September 30, 2020, we were in compliance with this covenant with a ratio of 35%.

Debt Remarketing

On August 18, 2020, we closed a $400 million remarketing to investors of sub-series B bonds which are part of the $1 billion St. John the Baptist, State of Louisiana revenue refunding bonds originally issued and purchased in December 2017. The sub-series B bonds are subject to mandatory tender for purchase on the dates set forth in the table below.

The following table further summarizes this transaction.

Sub-Series B Bonds	Par Amount	Interest Rate	Mandatory Purchase Date	Maturity Date
Sub-series B-1 Bonds	$200 million	2.125%	July 1, 2024	June 1, 2037
Sub-series B-2 Bonds	$200 million	2.375%	July 1, 2026	June 1, 2037

Debt Redemption

On September 16, 2020, we commenced a cash tender offer for up to an aggregate principal amount of $500 million (the “Aggregate Maximum Tender Amount”) of our outstanding $1 billion 2.8% Senior Notes due 2022 (“2022 Notes”). The Aggregate Maximum Tender Amount was fully subscribed and we completed the early settlement on October 1, 2020, repaying the $500 million. As such, the $500 million was moved to long-term due within one year on our consolidated balance sheet as of September 30, 2020. The remaining $500 million of the 2.8% 2022 Notes remains part of long-term debt on our consolidated balance sheet as of September 30, 2020.

18.    Stockholders’ Equity

During the nine months ended September 30, 2020, we acquired approximately 9 million common shares at a cost of $85 million, which were held as treasury stock. Including these repurchases, the total remaining share repurchase authorization was $1.3 billion at September 30, 2020. Purchases under the program are made at our discretion and may be in either open market transactions, including block purchases, or in privately negotiated transactions using cash on hand, cash generated from operations or proceeds from potential asset sales. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

19.    Incentive Based Compensation

Stock options, restricted stock awards and restricted stock units

The following table presents a summary of activity for the first nine months of 2020: 

	Stock Options				Restricted Stock Awards & Units
	Number of Shares		Weighted Average Exercise Price		Awards	Weighted Average Grant Date Fair Value
Outstanding at December 31, 2019	5,659,731		$	23.55	7,174,386	$	15.88
Granted	1,132,808	(a)	$	10.47	5,337,796	$	8.55
Exercised/Vested	(52,333)		$	7.22	(3,024,561)	$	15.83
Canceled(b)	(662,482)		$	24.66	(1,529,949)	$	11.66
Outstanding at September 30, 2020	6,077,724		$	21.13	7,957,672	$	11.80

(a)The weighted average grant date fair value of stock option awards granted was $3.82 per share.

(b)Included in canceled are forfeitures related to workforce reductions.

Stock-based performance unit awards

    During the first nine months of 2020, we granted 1,038,676 stock-based performance units to certain officers to be settled in shares. The grant date fair value per unit was $10.55, as calculated using a Monte Carlo valuation model. As of September 30, 2020 there were 1,658,088 units outstanding.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

20.    Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit costs (credits):

	Three Months Ended September 30,
	Pension Benefits				Other Benefits
(In millions)	2020		2019(c)		2020		2019
Service cost	$	4	$	5	$	—	$	—
Interest cost	2		3		1		1
Expected return on plan assets	(2)		(3)		—		—
Amortization:
– prior service credit	(1)		(1)		(4)		(5)
– actuarial loss	2		2		—		1
Net settlement loss(a)	9		—		—		—
Net periodic benefit costs (credits)(b)	$	14	$	6	$	(3)	$	(3)

	Nine Months Ended September 30,
	Pension Benefits				Other Benefits
(In millions)	2020		2019(c)		2020		2019
Service cost	$	14	$	14	$	—	$	—
Interest cost	7		17		2		3
Expected return on plan assets	(7)		(19)		—		—
Amortization:
– prior service credit	(5)		(5)		(13)		(14)
– actuarial loss	7		6		1		1
Net settlement loss(a)	25		2		—		—
Net curtailment gain(d)	(3)		—		(14)		—
Net periodic benefit costs (credits)(b)	$	38	$	15	$	(24)	$	(10)

(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.

(b)Net periodic benefit costs (credits) reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.

(c)Includes amounts related to the noncontributory defined benefit pension plan covering U.K. employees, prior to the plan being transferred to the buyer upon sale of the U.K. asset on July 1, 2019.

(d)Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans.

    During the first nine months of 2020, we made contributions of $21 million to our funded pension plan and expect to contribute an additional $7 million this year. During the first nine months of 2020, we made payments of $17 million and $11 million related to unfunded pension plans and other postretirement benefit plans.

In connection with the sale of our U.K. business, the noncontributory defined benefit pension plan covering U.K. employees was transferred to the buyer. See Note 4 for further information on this disposition. During the three and nine months ended September 30, 2019, we reclassified $20 million from accumulated other comprehensive income to pension assets upon remeasurement of the plan.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2020		2019		2020		2019		Income Statement Line
Postretirement and postemployment plans
Amortization of prior service credit	$	5	$	6	$	18	$	19
Amortization of actuarial loss	(2)		(3)		(8)		(7)
Net settlement loss	(9)		—		(25)		(2)
Net curtailment gain	—		—		17		—
	(6)		3		2		10		Other net periodic benefit (costs) credits
Other
U.K. pension plan transferred to buyer (a)(b)	—		83		—		83
Foreign currency translation adjustment related to sale of U.K. business (b)	—		30		—		30
Income taxes related to the sale of U.K. business (b)	—		(46)		—		(46)
	—		67		—		67		Net gain on disposal of assets
Total reclassifications to expense, net of tax (c)	$	(6)	$	70	$	2	$	77	Net income (loss)

(a)See Note 20 for detail on the U.K. pension plan.

(b)See Note 4 for detail on the U.K. disposition.

(c)During 2020 and 2019 we had a full valuation allowance on net federal deferred tax assets in the U.S. and as such, there is no tax impact to our postretirement and postemployment plans other than on the sale of the U.K. business.

22.    Supplemental Cash Flow Information

	Nine Months Ended September 30,
(In millions)	2020		2019
Included in operating activities:
Interest paid, net of amounts capitalized	$	175	$	177
Income taxes paid to (received from) taxing authorities, net of refunds (a)	(50)		67
Noncash investing activities:
Increase (decrease) in asset retirement costs	$	(5)	$	40
Asset retirement obligations assumed by buyer (b)	—		1,082

(a)The nine months ended September 30, 2020 and 2019 includes $94 million and $89 million, respectively, related to tax refunds.

(b)In 2019, we closed on the sale of our working interest in the Droshky field (Gulf of Mexico), the sale of our non-operated interest in the Atrush block in Kurdistan and the sale of our U.K. business.

    Other noncash investing activities include accrued capital expenditures for the nine months ended September 30, 2020 and 2019 of $81 million and $302 million, respectively.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

23.    Equity Method Investments

During the periods ended September 30, 2020 and December 31, 2019 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% noncontrolling interest. AMPCO is engaged in methanol production activity.

Our equity method investments are summarized in the following table:

(In millions)	Ownership as of September 30, 2020	September 30, 2020		December 31, 2019
EGHoldings	60%	$	119	$	310
Alba Plant LLC	52%	179		163
AMPCO	45%	169		190
Total		$	467	$	663

During the nine months ended September 30, 2020, we recorded impairments of $170 million to an investment in an equity method investee, which was reflected in income (loss) from equity method investments in our consolidated statements of income. See Note 11 to the consolidated financial statements for further information on the equity method investee impairment.

Summarized financial information for equity method investees is as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2020		2019		2020		2019
Income data:
Revenues and other income	$	140	$	184	$	423	$	637
Income (loss) from operations	19		61		(21)		192
Net income (loss)	12		45		(27)		140

Revenues from related parties were $9 million and $29 million, respectively, for the three and nine months ended September 30, 2020 and $11 million and $32 million, respectively, for the three and nine months ended September 30, 2019 with the majority related to EGHoldings in all periods.

Current receivables from related parties at September 30, 2020 were $28 million with the majority related to EGHoldings and $28 million at December 31, 2019 with the majority related EGHoldings and Alba Plant LLC. Payables to related parties at September 30, 2020 and December 31, 2019 were $13 million and $11 million, respectively, with the majority related to Alba Plant LLC in both periods.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

24.    Commitments and Contingencies

In the second quarter of 2019, Marathon E.G. Production Limited (“MEGPL”), a consolidated and wholly-owned subsidiary, signed a series of agreements to process third-party Alen Unit gas through existing infrastructure located in Punta Europa, E.G. Our equity method investee, Alba Plant LLC, is also a party to some of the agreements. These agreements contain clauses that require MEGPL to indemnify the owners of the Alen Unit against injury to Alba Plant LLC’s personnel and damage to or loss of Alba Plant LLC’s automobiles, as well as third party claims caused by Alba Plant and certain environmental liabilities arising from certain hydrocarbons in the custody of Alba Plant LLC. Pursuant to these agreements, MEGPL agreed to indemnify third party property or events, including environmental liabilities, injury to Alba Plant LLC’s personnel, and damage to or loss of Alba Plant LLC’s automobiles. At this time, we cannot reasonably estimate this obligation as we do not have any history of prior indemnification claims, and thus, we do not have any history of environmental discharge or contamination. Therefore, we have not recorded a liability with respect to these indemnities since the amount of potential future payments under these indemnification clauses is not determinable.

The agreements to process the third-party Alen Unit gas required the execution of third-party guarantees by Marathon Oil Corporation in favor of the Alen Unit’s owners. Two separate guarantees were executed during the second quarter of 2020; one for a maximum of $91 million pertaining to the payment obligations of Equatorial Guinea LNG Operations, S.A. and another for a maximum of $25 million pertaining to the payment obligations of Alba Plant LLC.  Payment by us would be required if either of those entities fails to honor its payment obligations pursuant to the relevant agreements with the owners of the Alen Unit. Certain owners of the Alen Unit, or their affiliates, are also direct or indirect shareholders in Equatorial Guinea LNG Operations, S.A. and Alba Plant LLC. Each guarantee expires no later than December 31, 2027. We measured these guarantees at fair value using the net present value of premium payments we expect to receive from our investees. Our liability for these guarantees was $4 million as of September 30, 2020, with a corresponding receivable from our investees. Each of Equatorial Guinea LNG Operations, S.A. and Equatorial Guinea LNG Train 1, S.A. provided us with a pledge of its receivables as recourse against any payments we may make under the guaranty of Equatorial Guinea LNG Operations, S.A.’s performance.

Various groups, including the State of North Dakota and three Indian tribes represented by the Bureau of Indian Affairs, have been involved in a dispute regarding the ownership of certain lands underlying the Missouri River and Little Missouri River.  As a result, as of September 30, 2020, we have a $103 million current liability in suspended royalty and working interest revenue, including interest, and have a long-term receivable of $23 million for capital and expenses.

In December 2019, we received a Notice of Violation from the North Dakota Department of Environmental Quality and a verbal notice of enforcement in January 2020 from the North Dakota Industrial Commission, related to a release of produced water in North Dakota. In January 2020, we received a Notice of Violation from the EPA related to the Clean Air Act. Each enforcement action will likely result in monetary sanctions in excess of $100,000; however, we do not believe these enforcement actions would have a material adverse effect on our consolidated financial position, results of operations or cash flow.

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. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance.

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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. Our strategy is to deliver competitive and improving corporate level returns by focusing our capital investment in the lower cost, higher margin U.S. resource plays (the Eagle Ford in Texas, the Bakken in North Dakota, STACK and SCOOP in Oklahoma and Northern Delaware in New Mexico).

    Commodity prices experienced significant volatility and declined substantially in the first half of 2020. While commodity prices improved during the third quarter as compared to the second quarter of 2020, they are likely to remain lower and volatile for the foreseeable future. We believe we can manage through this lower commodity price macro environment as our portfolio affords us the flexibility to respond to changing market conditions. Our primary focus remains on protecting our balance sheet and maintaining a strong liquidity position. We believe our financial strength, quality portfolio, and ongoing focus on reducing our cost structure better position us to navigate during this unprecedented time.

The risks associated with COVID-19 impacted our workforce and the way we meet our business objectives. Due to concerns over health and safety, the vast majority of our corporate workforce works remotely as we plan a process for a phased return of employees to the office. Working remotely has not significantly impacted our ability to maintain operations, has allowed our field offices to operate without any disruption, and has not caused us to incur significant additional expenses; however, we are unable to predict the duration or ultimate impact of these measures.

Key highlights include the following:

Maintained focus on balance sheet and liquidity

•At the end of the third quarter 2020, we had approximately $4.1 billion of liquidity, comprised of an undrawn $3.0 billion revolving credit facility and $1.1 billion in cash. We remain investment grade at all three primary rating agencies.

•In August, we closed on the remarketing of $400 million sub-series B bonds. On October 1, 2020, we completed a cash tender for an aggregate principal amount of $500 million of our outstanding $1 billion 2.8% 2022 Notes. The tender was funded from cash on hand, resulting in a gross debt reduction of $100 million from the second quarter of 2020.

•The September 30, 2020 cash balance reflects an increase of approximately $261 million from year-end, primarily due to the remarketing of $400 million of sub-series B bonds, partially offset by repurchases of common stock and dividend payments made during the first quarter. Our cash provided from operations was commensurate with our capital expenditures for the nine months ended September 30, 2020.

•In early July 2020, we collected an $89 million cash refund related to alternative minimum tax credits and associated interest.

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•On October 1, the Board of Directors approved and declared the reinstatement of the base quarterly dividend of $0.03 per share, effective in the fourth quarter of 2020. Our share repurchase program remains suspended as we continue to maximize liquidity.

•Continued our capital discipline to be within our Capital Budget of $1.2 billion.

•Continued to opportunistically execute additional commodity derivatives to minimize the risk of price fluctuations.

Financial and operational results

•U.S. net sales volumes decreased by 12% to 297 mboed, including a 21% reduction in U.S. crude oil net sales volumes compared to the same quarter last year as a result of overall lower wells to sales activity driven by the lower drilling and completions activity.

•Our net loss per share was $0.40 in the third quarter of 2020 as compared to net income per share of $0.21 in the same period last year. Included in our financial results for the current quarter:

◦Revenues from contracts with customers decreased $488 million compared to the same quarter last year, largely due to lower price realizations and decreased production volumes. Average crude oil price realizations decreased by 37% during the third quarter of 2020 as compared to the third quarter of 2019.

◦Net loss on commodity derivatives of $1 million for the third quarter of 2020, a $48 million decrease from the same period in 2019, which was a net gain of $47 million.

◦A non-cash impairment of an investment in one of our equity method investees of $18 million.

•Net cash provided by operating activities in the first nine months of 2020 decreased to $1.1 billion or 49% primarily as a result of lower commodity price realizations and decreased production volumes, compared to the first nine months of 2019. As described in the preceding section, we reduced our Capital Budget such that Capital Budget expenditures are closely aligned with cash generated by operations over the duration of the year.

Outlook

Capital Budget

    Earlier this year, we announced an approved 2020 Capital Budget of $2.4 billion, including $200 million to fund resource play leasing and exploration (“REx”). In light of the substantial decline in commodity prices and oversupply in the market, our Board of Directors approved a reduction to our Capital Budget earlier in the year to a level of $1.3 billion. Due to strong execution and capital efficiency improvement, in August we further reduced our full year 2020 capital spending budget to $1.2 billion. This revised Capital Budget represents a 50% reduction of our original budget. The revised budget contemplates a full suspension of our Oklahoma activity in 2020, a decrease in Northern Delaware drilling activity, and a continued optimization of our development plans in the Bakken and Eagle Ford. This also completes our REx drilling program for 2020. Additional adjustments to capital spending plans may be necessary in the future to respond to the shifts in the macro environment.

Commensurate with our budget of $1.2 billion for 2020, we believe our full year production volumes will be between 375 mboed to 390 mboed.

Operations

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

	Three Months Ended September 30,				Nine Months Ended September 30,
Net Sales Volumes	2020	2019	Increase (Decrease)		2020	2019	Increase (Decrease)
United States (mboed)	297	339	(12)	%	314	322	(2)	%
International (mboed)(a)	71	88	(19)	%	79	94	(16)	%
Total (mboed)	368	427	(14)	%	393	416	(6)	%

(a)We closed on the sale of our U.K. business in the third quarter of 2019. The nine months ended September 30, 2019 includes net sales volumes related to the U.K. of 7 mboed. See Note 4 to the consolidated financial statements for further information.

United States

    Net sales volumes in the segment were lower in the third quarter of 2020 and the first nine months of 2020 as compared to their respective 2019 periods. In the second quarter of 2020, we began the process of transitioning to a significantly lower level

33

of drilling and completion activity across our domestic portfolio. As a result of the decreased drilling and completion activity, fewer wells were brought to sales resulting in a significant decline in production in the third quarter of 2020.

We continue to expect that our planned pace of drilling and completions activity during the remainder of the year will enable us to meet our 2020 production guidance as noted in the preceding Outlook section. The following tables provide additional details regarding net sales volumes, sales mix and operational drilling activity for our significant operations within this segment:

	Three Months Ended September 30,				Nine Months Ended September 30,
Net Sales Volumes	2020	2019	Increase (Decrease)		2020	2019	Increase (Decrease)
Equivalent Barrels (mboed)
Eagle Ford	91	107	(15)	%	104	107	(3)	%
Bakken	98	109	(10)	%	103	101	2	%
Oklahoma	73	84	(13)	%	69	77	(10)	%
Northern Delaware	27	30	(10)	%	29	28	4	%
Other United States	8	9	(11)	%	9	9	—	%
Total United States	297	339	(12)	%	314	322	(2)	%

	Three Months Ended September 30, 2020
Sales Mix - U.S. Resource Plays	Eagle Ford		Bakken		Oklahoma		Northern Delaware		Total
Crude oil and condensate	58	%	71	%	25	%	55	%	54	%
Natural gas liquids	21	%	16	%	34	%	20	%	23	%
Natural gas	21	%	13	%	41	%	25	%	23	%

	Three Months Ended September 30,		Nine Months Ended September 30,
Drilling Activity - U.S. Resource Plays	2020	2019	2020	2019
Gross Operated
Eagle Ford:
Wells drilled to total depth	17	31	58	97
Wells brought to sales	9	35	67	117
Bakken:
Wells drilled to total depth	6	20	41	52
Wells brought to sales	8	30	41	89
Oklahoma:
Wells drilled to total depth	—	15	9	53
Wells brought to sales	—	19	13	55
Northern Delaware:
Wells drilled to total depth	—	10	15	37
Wells brought to sales	1	10	13	41

•Eagle Ford – Our net sales volumes were 91 mboed in the third quarter of 2020, including oil sales of 53 mbbld and we brought 9 gross company-operated wells to sales. Given the market conditions in the second quarter, we suspended frac activities. In the third quarter of 2020, we restarted our drilling program with 2 rigs and 1 frac crew which we expect to continue for the remainder of the year.

•Bakken – Our net sales volumes were 98 mboed, including 69 mbbld of oil sales and we brought 8 gross company-operated wells to sales. We suspended frac activity in the second quarter. In the third quarter of 2020, we resumed completions activities. We plan to average 2 rigs and 1 frac crew for the remainder of the year.

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•Oklahoma – Our net sales volumes were 73 mboed, including 18 mbbld of oil sales. During the second quarter, we suspended all drilling and completions operations in Oklahoma; we do not plan to drill any additional wells in Oklahoma during 2020.

•Northern Delaware – Our net sales volumes were 27 mboed, including 15 mbbld of oil sales and we brought 1 gross company-operated well to sales. We suspended all drilling and completions operations during the second quarter and expect to bring only a limited number of wells to sales during the remainder of the year.

International

    Net sales volumes were lower in the third quarter of 2020 compared to the third quarter of 2019 primarily due to timing of E.G. liftings. The following table provides details regarding net sales volumes for our operations within this segment:

	Three Months Ended September 30,				Nine Months Ended September 30,
Net Sales Volumes	2020	2019	Increase (Decrease)		2020	2019	Increase (Decrease)
Equivalent Barrels (mboed)
Equatorial Guinea	71	88	(19)	%	79	86	(8)	%
United Kingdom(a)	—	—	—	%	—	7	(100)	%
Other International	—	—	—	%	—	1	(100)	%
Total International	71	88	(19)	%	79	94	(16)	%
Equity Method Investees
LNG (mtd)	3,960	4,590	(14)	%	4,551	4,849	(6)	%
Methanol (mtd)	1,065	1,036	3	%	996	1,058	(6)	%
Condensate and LPG (boed)	9,340	11,586	(19)	%	10,288	10,858	(5)	%

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

•Equatorial Guinea – Net sales volumes in the third quarter of 2020 were lower compared to the same period in 2019 primarily due to timing of liftings.

•United Kingdom – In July 2019, we closed on the sale of our U.K. business. See Note 4 to the consolidated financial statements for further information.

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Market Conditions

Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows, the amount of capital we invest in our business, payment of dividends and funding of share repurchases. Commodity prices declined substantially in the first half of 2020 resulting from demand contraction related to the global pandemic and increased supply following the OPEC decision to increase production. A revised OPEC deal to reduce production was agreed early in the second quarter of 2020 and oil prices partially recovered in the latter part of the second quarter. Prices continued to increase in the third quarter; however, pricing remains lower relative to 2019 and given the scale of worldwide demand contraction, we expect commodity prices to remain volatile. Refer to Item 1A. Risk Factors in our 2019 Annual Report on Form 10-K for further discussion on how further declines in commodity prices could impact us.    

United States

    The following table presents our average price realizations and the related benchmarks for crude oil and condensate, NGLs and natural gas for the third quarter and first nine months of 2020 and 2019.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
Average Price Realizations(a)
Crude oil and condensate (per bbl)(b)	$	37.78	$	55.09	(31)	%	$	34.82	$	56.14	(38)	%
Natural gas liquids (per bbl)	11.80		11.37		4	%	9.77		13.81		(29)	%
Natural gas (per mcf)(c)	1.78		1.92		(7)	%	1.61		2.20		(27)	%
Benchmarks
WTI crude oil average of daily prices (per bbl)	$	40.92	$	56.44	(27)	%	$	38.21	$	57.10	(33)	%
Magellan East Houston (“MEH”) crude oil average of daily prices (per bbl)	41.59		61.06		(32)	%	38.93		62.60		(38)	%
Mont Belvieu NGLs (per bbl)(d)	15.87		15.16		5	%	13.77		18.14		(24)	%
Henry Hub natural gas settlement date average (per mmbtu)	1.98		2.23		(11)	%	1.88		2.67		(30)	%

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

(b)Inclusion of realized gains (losses) on crude oil derivative instruments would have increased average price realizations by $2.24 per bbl and $0.72 per bbl for the third quarter 2020 and 2019, respectively, and $1.74 per bbl and $0.70 per bbl for the first nine months of 2020 and 2019, respectively.

(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 55% ethane, 25% propane, 5% butane, 8% isobutane and 7% natural gasoline.

Crude oil and condensate – Price realizations may differ from benchmarks due to the quality and location of the product.

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

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

International    

The following table presents our average price realizations and the related benchmark for crude oil for the third quarter and first nine months of 2020 and 2019.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
Average Price Realizations
Crude oil and condensate (per bbl)	$	30.28	$	46.04	(34)	%	$	26.05	$	53.98	(52)	%
Natural gas liquids (per bbl)	1.00		1.00		—	%	1.00		1.53		(35)	%
Natural gas (per mcf)	0.24		0.24		—	%	0.24		0.35		(31)	%
Benchmark
Brent (Europe) crude oil (per bbl)(a)	$	42.96	$	61.93	(31)	%	$	40.92	$	64.67	(37)	%

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

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United Kingdom

Crude oil and condensate – Generally sold in relation to the Brent crude benchmark. We closed on the sale of our U.K. business on July 1, 2019.

Equatorial Guinea

Crude oil and condensate – Alba field liquids production is primarily condensate and generally sold in relation to the Brent crude benchmark. Alba Plant LLC processes the rich hydrocarbon gas which is supplied by the Alba field under a fixed price long term contract. Alba Plant LLC extracts NGLs and secondary condensate which is then sold by Alba Plant LLC at market prices, with our share of the revenue reflected in income from equity method investments on the consolidated statements of income. Alba Plant LLC delivers the processed dry natural gas to the Alba field for distribution and sale to AMPCO and EG LNG.

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

Natural gas – Dry natural gas, processed by Alba Plant LLC on behalf of the Alba field is sold by the Alba field to EG LNG and AMPCO at fixed-price long term contracts resulting in realized prices not tracking market price. We derive additional value from the equity investment in our downstream gas processing units EG LNG and AMPCO. EG LNG sells LNG on a market-based long-term contract and AMPCO markets methanol at market prices.

Results of Operations

Three Months Ended September 30, 2020 vs. Three Months Ended September 30, 2019

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

	Three Months Ended September 30,
(In millions)	2020		2019
Revenues from contracts with customers
United States	$	722	$	1,172
International	39		77
Segment revenues from contracts with customers	$	761	$	1,249

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

			Increase (Decrease) Related to
(In millions)	Three Months Ended September 30, 2019		Price Realizations		Net Sales Volumes		Three Months Ended September 30, 2020
United States Price/Volume Analysis
Crude oil and condensate	$	1,017	$	(253)	$	(212)	$	552
Natural gas liquids	64		2		7		73
Natural gas	81		(5)		(7)		69
Other sales	10						28
Total	$	1,172					$	722
International Price/Volume Analysis
Crude oil and condensate	$	67	$	(16)	$	(20)	$	31
Natural gas liquids	1		—		—		1
Natural gas	8		—		(1)		7
Other sales	1						—
Total	$	77					$	39

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Net gain (loss) on commodity derivatives in the third quarter of 2020, was a loss of $1 million, compared to a net gain of $47 million for the same period in 2019. We have multiple crude oil, natural gas and NGL derivative contracts that settle against various indices. We record commodity derivative gains/losses as the index pricing and forward curves change each period. See Note 15 to the consolidated financial statements for further information.

Income from equity method investments decreased $31 million for the third quarter of 2020 from the comparable 2019 period primarily due to an impairment of $18 million to an investment in an equity method investee. Lower Alba plant condensate sales volumes and lower methanol prices at AMPCO methanol facility also contributed to the decline. See Note 11 to the consolidated financial statements for further information on the equity method investee impairment.

Net gain on disposal of assets decreased $21 million in the third quarter of 2020 versus the same period in 2019, primarily as a result of the sale of our U.K. business during third quarter of 2019. See Note 4 to the consolidated financial statements for more detail.

Production expenses decreased $34 million in the third quarter of 2020 versus the same period in 2019, primarily as a result of the U.S. segment’s lower operational costs and continued cost management, specifically staffing and contract labor. International segment production expense slightly decreased due to timing of E.G. liftings.

The following table provides production expense and production expense rates (expense per boe) for each segment:

	Three Months Ended September 30,
($ in millions; rate in $ per boe)	2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
Production Expense and Rate	Expense						Rate
United States	$	118	$	147	(20)	%	$	4.32	$	4.75	(9)	%
International	$	11	$	16	(31)	%	$	1.76	$	1.98	(11)	%

Shipping, handling and other operating expenses increased $45 million in the third quarter of 2020 primarily due to increased purchased volumes from third parties of commodities for resale in order to satisfy transportation commitments and other expenses.

Exploration expenses include unproved property impairments, dry well costs, geological and geophysical, and other costs, which remained relatively flat in comparison to the third quarter of 2019.

The following table summarizes the components of exploration expenses:

	Three Months Ended September 30,
(In millions)	2020		2019		Increase (Decrease)
Exploration Expenses
Unproved property impairments	$	23	$	15	53	%
Dry well costs	—		1		(100)	%
Geological and geophysical	2		1		100	%
Other	2		5		(60)	%
Total exploration expenses	$	27	$	22	23	%

Depreciation, depletion and amortization decreased $68 million in the third quarter of 2020 as a result of lower sales volumes in our U.S. and International segments. 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) is impacted by field-level changes in reserves, capitalized costs and sales volume mix between fields. The following table provides DD&A expense and DD&A expense rates for each segment:

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	Three Months Ended September 30,
($ in millions; rate in $ per boe)	2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
DD&A Expense and Rate	Expense						Rate
United States	$	530	$	589	(10)	%	$	19.39	$	18.90	3	%
International	$	19	$	25	(24)	%	$	2.89	$	3.15	(8)	%

Taxes other than income include production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. Taxes other than income decreased $32 million primarily due to lower price realizations and lower sales volumes in the U.S. segment in the third quarter of 2020.

General and administrative expenses decreased $29 million in the third quarter of 2020 primarily as a result of cost savings realized from workforce reductions.

Segment Income

Segment income represents income 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, impairments of proved property, goodwill and equity method investments, unrealized gains or losses on commodity and interest rate derivative instruments, effects of pension settlements and curtailments, or other items (as determined by the CODM) are not allocated to operating segments.

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

	Three Months Ended September 30,
(In millions)	2020		2019		Increase (Decrease)
United States	$	(135)	$	180	(175)	%
International	8		43		(81)	%
Segment income (loss)	(127)		223		(157)	%
Items not allocated to segments, net of income taxes	(190)		(58)		(228)	%
Net income (loss)	$	(317)	$	165	(292)	%

United States segment income (loss) in the third quarter of 2020, was $135 million loss after-tax versus $180 million income after-tax for the same period in 2019, primarily due to lower price realizations and sales volumes in the current quarter, which was partially offset by lower DD&A and production taxes (due to the lower sales volumes), coupled with cost management efforts to lower production and G&A expenses.

International segment income in the third quarter of 2020, was $8 million after-tax versus $43 million after-tax for the same period in 2019, primarily due to timing of E.G. liftings and lower price realizations resulting in lower income from equity method investments.

Results of Operations

Nine Months Ended September 30, 2020 vs. Nine Months Ended September 30, 2019

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

	Nine Months Ended September 30,
(In millions)	2020		2019
Revenues from contracts with customers
United States	$	2,154	$	3,434
International	121		396
Segment revenues from contracts with customers	$	2,275	$	3,830

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

			Increase (Decrease) Related to
(In millions)	Nine Months Ended September 30, 2019		Price Realizations		Net Sales Volumes		Nine Months Ended September 30, 2020
United States Price/Volume Analysis
Crude oil and condensate	$	2,897	$	(1,066)	$	(90)	$	1,741
Natural gas liquids	225		(67)		3		161
Natural gas	263		(70)		(3)		190
Other sales	49						62
Total	$	3,434					$	2,154
International Price/Volume Analysis
Crude oil and condensate	$	341	$	(102)	$	(143)	$	96
Natural gas liquids	4		(1)		—		3
Natural gas	36		(10)		(4)		22
Other sales	15						—
Total	$	396					$	121

Net gain (loss) on commodity derivatives in the first nine months of 2020, was a gain of $131 million, compared to a net loss of $28 million for the same period in 2019. We have multiple crude oil, natural gas and NGL derivative contracts that settle against various indices. We record commodity derivative gains/losses as the index pricing and forward curves change each period. See Note 15 to the consolidated financial statements for further information.

Income (loss) from equity method investments decreased $237 million for the first nine months of 2020 primarily due to impairments of $170 million to an investment in an equity method investee in the first nine months of 2020 as well as lower price realizations and lower net sales volumes from equity method investments in E.G. primarily due to the planned triennial turnaround in the first quarter of 2020.

Net gain on disposal of assets decreased $48 million for the first nine months of 2020 primarily as a result of the sale of our working interest in the Droshky field (Gulf of Mexico) and U.K. business during the first nine months of 2019.

Other income decreased $38 million in the first nine months of 2020 primarily due to income recognized in 2019 arising from indemnification payments received from Marathon Petroleum Corporation (“MPC”). Pursuant to the Tax Sharing Agreement we entered into with MPC, in connection with the 2011 spin-off transaction, MPC agreed to indemnify us for certain liabilities. The indemnity relates to tax and interest allocable to MPC as a result of the closure of the 2010-2011 U.S. Federal Tax Audit in the first quarter of 2019.

Production expenses for the first nine months of 2020 decreased by $125 million compared to the same period in 2019. Production expense in our International segment decreased $69 million primarily as a result of the sale of our U.K. business, which closed during the third quarter of 2019. Production expense in our U.S. segment decreased $58 million primarily due to lower operational activity and continued cost management, specifically staffing and contract labor.

The first nine months of 2020 production expense rate (expense per boe) was lower for our United States segment due to the aforementioned reasons. Expense per boe for our International segment decreased due to the sale of the U.K. business, which closed during the third quarter of 2019. We expect our full year production expense rates for the United States and International segments to be $4.25 - $4.75 per boe and $2.05 - $2.35 per boe, respectively.

The following table provides production expense and production expense rates for each segment:

	Nine Months Ended September 30,
($ in millions; rate in $ per boe)	2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
Production Expense and Rate	Expense						Rate
United States	$	375	$	433	(13)	%	$	4.36	$	4.94	(12)	%
International	$	43	$	112	(62)	%	$	2.00	$	4.33	(54)	%

Shipping, handling and other operating expenses decreased $30 million in the first nine months of 2020 from the comparable 2019 period, primarily as a result of lower net sales volumes in the U.S during the first nine months of 2020 and

40

lower NGL shipping and handling rates realized in Bakken in the second quarter of 2020. This was partially offset by higher marketing costs due to higher volumes purchased for resale during the third quarter of 2020.

Exploration expenses include unproved property impairments, dry well costs, geological and geophysical, and other, which decreased $26 million in the first nine months of 2020. Decreases in unproved property impairments were primarily driven by our decision not to drill certain leases related to resource exploration in the first quarter of 2019.

The following table summarizes the components of exploration expenses:

	Nine Months Ended September 30,
(In millions)	2020		2019		Increase (Decrease)
Exploration Expenses
Unproved property impairments	$	62	$	79	(22)	%
Dry well costs	1		6		(83)	%
Geological and geophysical	6		10		(40)	%
Other	12		12		—	%
Total exploration expenses	$	81	$	107	(24)	%

Depreciation, depletion and amortization increased $14 million in the first nine months of 2020 from the comparable 2019 period, primarily due to additional wells coming online in 2020 related to our resource exploration development coupled with field-level reserve adjustments increasing the United States DD&A expense. This was partially offset by the sale of our U.K. business, which closed during the third quarter of 2019. 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) is impacted by field-level changes in reserves, capitalized costs and sales volume mix between fields. The DD&A rate for International decreased primarily as a result of dispositions. The following table provides DD&A expense and DD&A expense rates for each segment:

	Nine Months Ended September 30,
($ in millions; rate in $ per boe)	2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
DD&A Expense and Rate	Expense						Rate
United States	$	1,716	$	1,664	3	%	$	19.91	$	18.95	5	%
International	$	62	$	97	(36)	%	$	2.87	$	3.77	(24)	%

Impairments increased $74 million in the first nine months of 2020, primarily as a result of the impairment to goodwill for $95 million related to our International reporting unit in the first quarter of 2020. See Note 11 for discussion of the impairments in further detail.

Taxes other than income include production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. Taxes other than income decreased $87 million in the first nine months of 2020 from the comparable 2019 period primarily due to lower price realizations and lower sales volumes in the U.S. segment.

General and administrative expenses decreased $46 million in the first nine months of 2020 from the comparable 2019 period, which reflects costs savings realized from workforce reductions.

Provision (benefit) for income taxes reflects an effective income tax rate of 1% in the first nine months of 2020, as compared to an effective income tax rate of (27)% for the comparable 2019 period. See Note 7 to the consolidated financial statements for a more detailed discussion concerning the components impacting the rate change.

41

Segment Income

Segment income represents income 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, impairments of proved property, goodwill and equity method investments, unrealized gains or losses on commodity and interest rate derivative instruments, effects of pension settlements and curtailments, 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):

	Nine Months Ended September 30,
(In millions)	2020		2019		Increase (Decrease)
United States	$	(520)	$	527	(199)	%
International	1		200		(100)	%
Segment income (loss)	(519)		727		(171)	%
Items not allocated to segments, net of income taxes	(594)		(227)		(162)	%
Net income (loss)	$	(1,113)	$	500	(323)	%

United States segment income (loss) for the first nine months of 2020, was a $520 million loss after-tax versus $527 million income after-tax for the same period in 2019, primarily as a result of lower crude price realizations and lower net sales volumes, which was partially offset by lower production taxes and production expenses.

International segment income for the first nine months of 2020, was $1 million after-tax versus $200 million after-tax for the same period in 2019, primarily due to lower price realizations and sales volumes partially offset by lower costs due to the sale of our U.K. business in third quarter of 2019.

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, 2019, except as discussed below.

Impairment of Equity Method Investments

During the nine months ended September 30, 2020, we recorded an impairment of $170 million to an investment in an equity method investee, which was reflected in income (loss) from equity method investments in our consolidated statements of income. Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred. When a loss is deemed to have occurred that is other than temporary, the carrying value of the equity method investment is written down to fair value.

Fair value calculated for the purpose of testing our equity method investees for impairment is estimated using the present value of expected future cash flows method. Significant judgment is involved in performing these fair value estimates since the results are based on forecasted assumptions and the performance of entities that we do not control. Significant assumptions include:

•Future condensate, NGL, LNG, natural gas & methanol prices. Our estimates of future prices are based on our analysis of market supply and demand and consideration of market price indicators. Although these commodity prices may experience extreme volatility in any given year, we believe long-term industry prices are driven by global market supply and demand. To estimate supply, we consider numerous factors, including the worldwide resource base, depletion rates and OPEC production policies. We believe demand is largely driven by global economic factors, such as population and income growth, and governmental policies. The prices we use in our fair value estimates are consistent with those used in our planning and capital investment reviews. There has been significant volatility in commodity prices and estimates of such future prices are inherently imprecise. See Item 1A. Risk Factors in our Form 10-K for the year ended December 31, 2019 for further discussion on commodity prices.

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•Estimated quantities of feedstock condensate, NGLs and natural gas processed by our investees. There are two primary sets of inputs used to estimate feedstock volumes processed by our investees. The first input involves hydrocarbons produced from our Alba Field. Our equity method investees currently process hydrocarbons from our Alba Field, which consists of condensate, NGLs and natural gas reserves. Estimated quantities of hydrocarbons processed from our Alba Field are based on a combination of proved reserves and risk-weighted probable reserves and resources such that the combined volumes represent the most likely expectation of recovery. See Item 1A. Risk Factors in our Form 10-K for the year ended December 31, 2019 for further discussion on reserves.

The second input involves our estimate of future third-party gas to be processed by our investees. Our investees have capacity to process hydrocarbons from sources other than our Alba field. During 2019, we executed agreements for processing natural gas produced from the third party-owned Alen Unit through the existing Alba Plant LLC LPG processing plant and the EGHoldings LNG production facility beginning in 2021. Estimated natural gas volumes processed from the Alen Unit were based on forecasts received from the operator of the Alen Unit.

•Expected timing of production. Production forecasts are the outcome of engineering studies which estimate reserves, as well as expected capital programs. The actual timing of the production could be different than the projection. Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money. The expected timing of production from the Alba Field that we use in our fair value estimates is consistent with that used in our planning and capital investment reviews. The expected timing of production from the Alen Unit is consistent with forecasts received from the operator of that field.

•Discount rate commensurate with the risks involved. We apply a discount rate to our expected cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. A higher discount rate decreases the net present value of cash flows

We base our fair value estimates on projected financial information which we believe to be reasonably likely to occur. This includes the estimated dividends and/or return of capital we expect to be paid by our equity method investees, which are directly affected by the significant assumptions described in the preceding paragraphs. An estimate of the sensitivity to changes in assumptions in our cash flow calculations is not practicable, given the numerous other assumptions (e.g. reserves, commodity prices, operating costs, inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions.

See Note 11 to the consolidated financial statements for further information regarding the impairment recognized during the second and third quarter of 2020.

Fair Value Estimates – Goodwill

    In the first quarter of 2020, a triggering event (significant decline in market capitalization caused by worldwide declines in hydrocarbon demand and corresponding prices) required us to assess our goodwill in the International reporting unit for impairment as of March 31, 2020. We estimated the fair value of our International reporting unit using a combination of market and income approaches and concluded that a full impairment of $95 million was required. See Note 14 to the consolidated financial statements for further information.

Estimated Quantity of Net Reserves    

Continued lower commodity prices could have a material effect on the quantity and present value of our proved reserves. When we apply actual SEC pricing as of year-end, a portion of our proved reserves could be deemed uneconomic and no longer classified as proved. This could impact both proved developed producing reserves as well as proved undeveloped reserves. Future reserve revisions could also result from changes to our Capital Budget and drilling plans among other things. However, any impact of lower SEC pricing will likely be partially offset by continued cost reduction efforts. Also, any volumes reclassified to unproved reserves could return to proved reserves as commodity prices improve. Any reduction in proved reserves, especially as a result of continued lower commodity prices, could result in an acceleration of future DD&A expense and impairments to long-lived assets.

Accounting Standards Not Yet Adopted

See Note 2 to the consolidated financial statements.

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Cash Flows

    Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows, the amount of capital we invest in our business, payment of dividends, and funding of share repurchases. While we generated cash flows from operations during the first nine months of 2020, the lower price environment reduced our cash flow generation compared to the prior year. Should lower prices continue, our ability to generate cash from operations could be negatively affected. The following table presents sources and uses of cash and cash equivalents:

	Nine Months Ended September 30,
(In millions)	2020		2019
Sources of cash and cash equivalents
Operating activities	$	1,055	$	2,049
Borrowings	400		—
Disposal of assets, net of cash transferred to the buyer	9		(84)
Other	7		53
Total sources of cash and cash equivalents	$	1,471	$	2,018
Uses of cash and cash equivalents
Additions to property, plant and equipment	$	(1,090)	$	(1,934)
Additions to other assets	15		41
Purchases of common stock	(92)		(296)
Dividends paid	(40)		(122)
Other	(3)		(4)
Total uses of cash and cash equivalents	$	(1,210)	$	(2,315)

Cash flows generated from operating activities in the first nine months of 2020 were 49% lower compared to the same period in 2019, primarily as a result of lower commodity price realizations.

The following table shows capital expenditures by segment and reconciles to additions to property, plant and equipment as presented in the consolidated statements of cash flows:

	Nine Months Ended September 30,
(In millions)	2020		2019
United States	$	874	$	1,959
International	—		16
Corporate	10		15
Total capital expenditures	884		1,990
Change in capital expenditure accrual	206		(56)
Total use of cash and cash equivalents for property, plant and equipment	$	1,090	$	1,934

The decline in our capital expenditures for the U.S. segment in the first nine months of 2020 compared to the same period in 2019, was caused by lower drilling and completions activities across all four of our shale basins.

In the first quarter of 2020, we acquired approximately 9 million common shares at a cost of $85 million, which were held as treasury stock. See Note 18 to the consolidated financial statements for further information.

Liquidity and Capital Resources

Available Liquidity

Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, sales of non-core assets, capital market transactions, and our revolving Credit Facility. At September 30, 2020, we had approximately $4.1 billion of liquidity consisting of $1.1 billion in cash and cash equivalents and $3.0 billion available under our revolving Credit Facility. On October 1, 2020, we completed a cash tender offer for an aggregate principal amount of $500 million of our $1 billion 2.8% 2022 Notes funded by cash on hand. See Item 1A. Risk Factors for a more detailed discussion of recent developments affecting the energy industry.

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Our working capital requirements are supported by our cash and cash equivalents and our Credit Facility. 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, 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, including the global pandemic, could affect our operations and our ability to access the capital markets.

During the first half of 2020, commodity prices significantly declined due to the combined impacts of global crude oil oversupply and lower demand for hydrocarbons due to the global pandemic. As a result, credit rating agencies reviewed many companies in the industry, including us. We continue to be rated investment grade at all three primary credit rating agencies. A downgrade in our credit ratings could increase our future cost of financing or limit our ability to access capital, and could result in additional credit support requirements. See Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2019 for a discussion of how a downgrade in our credit ratings could affect us.

During the second quarter of this year, our Board of Directors temporarily suspended our quarterly dividend payment as we prioritize our liquidity and balance sheet. On October 1, 2020, our Board of Directors approved the reinstatement of and declared a base quarterly dividend of $0.03 per share payable December 10, 2020 to stockholders of record at the close of business on November 18, 2020.

Capital Resources

Credit Arrangements and Borrowings

At September 30, 2020, we had no borrowings against our Credit Facility. At September 30, 2020, we had $5.9 billion of total debt outstanding. On October 1, 2020, we completed a cash tender offer for an aggregate principal amount of $500 million of our $1 billion 2.8% 2022 Notes funded by cash on hand. After giving consideration to the cash tender, our next significant debt maturity is $500 million due in November 2022. 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.

On August 18, 2020, we closed a $400 million remarketing to investors of sub-series B bonds which are part of the $1.0 billion St. John the Baptist, State of Louisiana revenue refunding bonds originally issued and purchased in December 2017. Information about these bonds are available on the website of the Municipal Securities Rulemaking Board via its Electronic Municipal Market Access system at www.msrb.org. Information on that website is not incorporated by reference into this filing.

In 2018, we signed an agreement with an owner/lessor to construct and lease a new build-to-suit office building in Houston, Texas. The lessor and other participants are providing financing for up to $340 million to fund the estimated project costs, which was reduced effective August 2020 from $380 million to align with our revised estimate of the project costs. As of September 30, 2020, project costs incurred totaled approximately $117 million, including land acquisition and construction costs.

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. 

Debt-To-Capital Ratio

The Credit Facility includes a covenant requiring that our total debt to total capitalization ratio not exceed 65% as of the last day of the fiscal quarter. Our ratio was 35% and 31% at September 30, 2020 and at December 31, 2019, respectively.

Capital Requirements

Share Repurchase Program

In the first quarter of 2020, we acquired approximately 9 million common shares at a cost of $85 million under our share repurchase program. While the share repurchase program has $1.3 billion of remaining authorization, we elected to suspend additional share repurchases to preserve liquidity.

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Contractual Cash Obligations

As of September 30, 2020, our contractual obligations as it relates to our short and long-term debt increased by $400 million ($200 million in 2024 and $200 million thereafter) due to the remarketing of the St. John the Baptist, State of Louisiana revenue refunding bonds. On October 1, 2020, we completed a cash tender for an aggregate principal amount of $500 million of our outstanding $1 billion 2.8% 2022 Notes. The tender was funded from cash on hand, resulting in a gross debt reduction of $100 million from the second quarter of 2020.

As of September 30, 2020, our contractual cash obligations as it relates to our transportation and processing commitments decreased approximately $79 million ($8 million in 2021, $11 million in 2022, $11 million in 2023, $11 million in 2024 and $38 million thereafter) related to the cancellation of a transportation service agreement in the Bakken resource play.

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. 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. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance.

Other than the items set forth in Item 1. Legal Proceedings, there have been no significant changes to the environmental, health and safety matters under Item 1. Business or Item 3. Legal Proceedings in our 2019 Annual Report on Form 10-K. See Note 24 to the consolidated financial statements for a description of other contingencies.

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Forward-Looking Statements

This Quarterly Report on Form 10-Q 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 operational and financial strategies, including drilling plans and projects, planned wells, rig count, inventory, seismic, exploration plans, maintenance activities, drilling and completion improvements, cost reductions, and financial flexibility; our ability to successfully effect those strategies and the expected timing and results thereof; our 2020 Capital Budget and the planned allocation thereof; planned capital expenditures and the impact thereof; expectations regarding future economic and market conditions and their effects on us; our financial and operational outlook, and ability to fulfill that outlook; our financial position, balance sheet, liquidity and capital resources, and the benefits thereof; resource and asset potential; reserve estimates; growth expectations; and future production and sales expectations, and the drivers thereof, are forward-looking statements. Words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “future,” “guidance,” “intend,” “may,” “outlook,” “plan,” “positioned,” “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 U.S. and E.G., including changes in foreign currency exchange rates, interest rates, and inflation rates;

•actions taken by the members of OPEC and Russia affecting the production and pricing of crude oil; and other global and domestic political, economic or diplomatic developments;

•risks related to our hedging activities;

•voluntary and involuntary volume curtailments;

•delays or cancellations of certain drilling activities;

•liability resulting from litigation;

•capital available for exploration and development;

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

•drilling and operating risks;

•lack of, or disruption in, access to storage capacity, pipelines or other transportation methods;

•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 their contractual obligations, including due to bankruptcy;

•hazards such as weather conditions, a health pandemic (including COVID-19), acts of war or terrorist acts and the governmental or military response thereto;

•shortages of key personnel, including employees, contractors and subcontractors;

•cyber-attacks;

•changes in safety, health, environmental, tax and other regulations or requirements or initiatives including those addressing the impact of global climate change, air emissions or water management;

•other geological, operating and economic considerations; and

•the risk factors, forward-looking statements and challenges and uncertainties described in our 2019 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 15 and Note 16 to the consolidated financial statements for detail relating to our open commodity derivative positions, including underlying notional quantities, how they are reported in our consolidated financial statements and how their fair values are measured.

Commodity Price Risk

As of September 30, 2020, we had various open commodity derivatives. Based on the September 30, 2020 published NYMEX WTI and natural gas futures prices, a hypothetical 10% change (per bbl for crude oil and per MMbtu for gas) would change the fair values of our $43 million net asset position to the following:

(In millions)	Hypothetical Price Increase of 10%		Hypothetical Price Decrease of 10%
Derivative asset - Crude Oil	$	42	$	68
Derivative asset (liability) - Natural Gas	(30)		2
Total	$	12	$	70

Interest Rate Risk

At September 30, 2020 our portfolio of current and long-term debt is comprised of fixed-rate instruments with an outstanding balance of $5.9 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.

At September 30, 2020, we had forward starting interest rate swap agreements with a total notional amount of $670 million designated as cash flow hedges and $500 million not designated as hedges. We utilize cash flow hedges to manage our exposure to interest rate movements by utilizing interest rate swap agreements to hedge variations in cash flows related to (1) the 1-month LIBOR component of future lease payments on our future Houston office and (2) the benchmark LIBOR index for our debt due in 2025. We de-designated the cash flow hedges related to our debt due in 2022 during the third quarter of 2020. A hypothetical 10% change in interest rates would change the fair values of our $10 million net liability position of our cash flow hedge and our $2 million net liability position of our de-designated cash flow hedge to the following as of September 30, 2020:

(In millions)	Hypothetical Interest Rate Increase of 10%		Hypothetical Interest Rate Decrease of 10%
Interest rate liability - designated as cash flow hedges	$	(5)	$	(14)
Interest rate asset (liability)- not designated as cash flow hedges	3		(7)
Total	$	(2)	$	(21)

Item 4. Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer.  As of the end of the period covered by this Report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as of September 30, 2020.  

During the first nine months of 2020, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Part II – OTHER INFORMATION

Item 1. Legal Proceedings

There have been no significant changes to Item 3. Legal Proceedings in our 2019 Annual Report on Form 10-K. See Note 24 to the consolidated financial statements included in Part I, Item I for a description of such legal and administrative proceedings and Item 3. Legal Proceedings in our 2019 Annual Report on Form 10-K.

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. In addition to the other information set forth in this Quarterly Report on Form 10-Q, the reader should carefully consider the factors discussed in Item 1A. Risk Factors in our 2019 Annual Report on Form 10-K. There have been no material changes to the risk factors from those listed in Item 1A. Risk Factors in our 2019 Annual Report on Form 10-K, except as noted below.

Our business, financial conditions and results of operations have been adversely affected and may continue to be adversely affected by the recent COVID-19 global pandemic and the recent energy industry developments.

Any widespread outbreaks of contagious diseases have the potential to impact our business and operations. The recent novel coronavirus global pandemic, known as COVID-19, has had an adverse impact on our business, financial condition and results of operations and such impacts could be material. The current effects of COVID-19 include a substantial decline in demand for crude oil, condensate, NGLs, natural gas and other petroleum hydrocarbons, along with a corresponding deterioration in prices. In addition, COVID-19, combined with the resulting economic downturn could have a negative impact on our operations; impact the ability of our counterparties to perform their obligations; result in voluntary and involuntary curtailments, delays or cancellations of certain drilling activities; impair the quantity or value of our reserves; result in transportation and storage capacity restraints; cause shortages of key personnel, including employees, contractors and subcontractors; interrupt global supply chains; increase impairments and associated charges to our earnings; impact our cash on hand, uses of cash and cause a decrease to our financial flexibility and liquidity. In addition, the risks associated with COVID-19 impacted our workforce and the way we meet our business objectives. Due to concerns over health and safety, the vast majority of our corporate workforce works remotely as we plan a process to phase employees to return to the office. Working remotely has not significantly impacted our ability to maintain operations, or caused us to incur significant additional expenses; however, we are unable to predict the duration or ultimate impact of these measures.

The impacts of COVID-19 could be further exacerbated by the Organization of the Petroleum Exporting Countries (OPEC) and Russia regarding crude oil production cuts. Negotiations in April 2020 with OPEC and Russia resulted in an agreement to reduce production volumes; however, a failure to abide by these agreed upon crude oil production cuts may further destabilize the global oil market. The extent to which COVID-19 or the recent energy industry developments will impact our business and our financial results will depend on future developments, which are highly uncertain and cannot be predicted. As a result, at the time of this filing, it is not possible to predict the overall impact of COVID-19 or the recent energy industry developments on our business, liquidity, capital resources and financial results.

We may incur substantial capital expenditures and operating costs as a result of compliance with and changes in law, regulations or requirements or initiatives, including those addressing environmental, health, safety, or security or the impact of global climate change, air emissions or water management, and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected.

Our businesses are currently subject to numerous laws, regulations and other requirements relating to the protection of the environment, including those relating to the discharge of materials into the environment such as the flaring of natural gas, waste management, pollution prevention, greenhouse gas emissions, including carbon dioxide and methane, and the protection of endangered species as well as laws, regulations, and other requirements relating to public and employee safety and health and to facility security. Additionally, states in which we operate may: impose additional regulations legislation, or requirements, such as the proposed methane emission rules in New Mexico; begin initiatives addressing the impact of global climate change, air emissions or water management; or we may become subject to additional regulations based on questions of sovereignty between the states and Native American tribes. We have incurred and may continue to incur capital, operating and maintenance, and remediation expenditures as a result of these laws, regulations, and other requirements or initiatives that are being considered or otherwise implemented. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products, our operating results could be adversely affected. The specific impact of these laws, regulations, and other requirements may vary depending on a number of factors, including the age and location of operating facilities and production processes. We may also be required to make material expenditures to modify operations, install pollution control equipment, perform site clean-ups or curtail operations that could materially and adversely affect our business, financial condition, results of operations and cash flows. We may become subject to liabilities that we currently do not anticipate in

49

connection with new, amended or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination. In addition, any failure by us to comply with existing or future laws, regulations, and other requirements could result in civil penalties or criminal fines and other enforcement actions against us.

We believe it is likely that the scientific and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations that could affect our operations. Our operations result in greenhouse gas emissions. Currently, various legislative or regulatory measures to address greenhouse gas emissions (including carbon dioxide, methane and nitrous oxides) are in various phases of review, discussion or implementation in the U.S. Internationally, the United Nations Framework Convention on Climate Change finalized an agreement among 195 nations at the 21st Conference of the Parties in Paris with an overarching goal of preventing global temperatures from rising more than 2 degrees Celsius. The agreement includes provisions that every country take some action to lower emissions, but there is no legal requirement for how or by what amount emissions should be lowered. Finalization of new legislation, regulations or international agreements in the future could result in increased costs to operate and maintain our facilities, capital expenditures to install new emission controls at our facilities, and costs to administer and manage any potential greenhouse gas emissions or carbon trading or tax programs. These costs and capital expenditures could be material. Although uncertain, these developments could increase our costs, reduce the demand for crude oil and condensate, NGLs and natural gas, and create delays in our obtaining air pollution permits for new or modified facilities.

Our operations may be adversely affected by pipeline, rail and other transportation capacity constraints.

The marketability of our production depends in part on the availability, proximity, and capacity of gathering and transportation pipeline facilities, rail cars, trucks and vessels. If any pipelines, rail cars, trucks or vessels become unavailable, we would, to the extent possible, be required to find a suitable alternative to transport our crude oil and condensate, NGLs and natural gas, which could increase the costs and/or reduce the revenues we might obtain from the sale of our production. For example, in early July, a U.S. district court ordered the Dakota Access Pipeline to halt oil flow and empty the pipeline within 30 days because the United States Army Corps of Engineers did not conduct a full Environmental Impact Statement.  Though a federal appellate court has administratively stayed the shutdown, if a shutdown occurs, we will need to use alternative means to transport approximately 10,000 bpd (on a net basis) of our Bakken oil. A shutdown could also have an impact on safety (because it would require the use of additional trucks, rail cars and personnel) and our Bakken price differentials, all of which could adversely affect the results of our operations. In addition, both the cost and availability of pipelines, rail cars, trucks, or vessels to transport our production could be adversely impacted by new and expected state or federal regulations relating to transportation of crude oil.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table provides information about purchases by Marathon Oil and its affiliated purchaser, during the quarter ended September 30, 2020 of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities Exchange Act of 1934:

Period	Total Number of Shares Purchased(a)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(b)	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(b)
07/01/2020 - 07/31/2020	27,584	$	5.89	—	$	1,320,335,751
08/01/2020 - 08/31/2020	—	$	—	—	$	1,320,335,751
09/01/2020 - 09/30/2020	—	$	—	—	$	1,320,335,751
Total	27,584	$	5.89	—

(a) 27,584 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, by $1.2 billion in December 2013, and by $950 million in July 2019.

As of September 30, 2020, we have repurchased 191 million common shares at a cost of approximately $5.9 billion, excluding transaction fees and commissions. Purchases under the program are made at our discretion and may be in either open market transactions, including block purchases, or in privately negotiated transactions using cash on hand, cash generated from operations, proceeds from potential asset sales or cash from available borrowings to acquire shares. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. In connection with the economic downturn, during the second quarter of 2020, the Company temporarily suspended the share repurchase program. Shares repurchased as of September 30, 2020 were held as treasury stock.

Item 6.  Exhibits

The information required by this Item 6 is set forth in the Exhibit Index accompanying this Form 10-Q.

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SIGNATURES

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

November 5, 2020		MARATHON OIL CORPORATION
	By:	/s/ Gary E. Wilson
		Gary E. Wilson
		Vice President, Controller and Chief Accounting Officer
		(Duly Authorized Officer)

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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 - the XBRL Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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
104*	Cover Page Interactive Data File, formatted in iXBRL and contained in Exhibit 101
*	Filed herewith.
†	Management contract or compensatory plan or arrangement.

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:	November 5, 2020	/s/ Lee M. Tillman
		Lee M. Tillman
		Chairman, 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;

1.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;

2.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;

3.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

4.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:	November 5, 2020	/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 September 30, 2020 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Lee M. Tillman, Chairman, 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.

November 5, 2020	/s/ Lee M. Tillman
	Lee M. Tillman
	Chairman, 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 September 30, 2020 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 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.

November 5, 2020	/s/ Dane E. Whitehead
	Dane E. Whitehead
	Executive Vice President and Chief Financial Officer

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Cover - shares	9 Months Ended
	Sep. 30, 2020	Oct. 31, 2020
Document and Entity Information [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2020
Document Transition Report	false
Entity File Number	1-1513
Entity Registrant Name (tagged on cover)	Marathon Oil Corporation
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	25-0996816
Entity Address, Address Line One	5555 San Felipe Street,
Entity Address, City or Town	Houston,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77056-2723
City Area Code	(713)
Local Phone Number	629-6600
Title of 12(b) Security	Common Stock, par value $1.00
Trading Symbol	MRO
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		789,391,520
Document Fiscal Period Focus	Q3
Document Fiscal Year Focus	2020
Amendment Flag	false
Entity Central Index Key	0000101778
Current Fiscal Year End Date	--12-31

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Consolidated Statements of Income (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Revenues and other income:
Revenues from contracts with customers	$ 761	$ 1,249	$ 2,275	$ 3,830
Net gain (loss) on commodity derivatives	(1)	47	131	(28)
Income (loss) from equity method investments	(10)	21	(174)	63
Net gain on disposal of assets	1	22	8	56
Other income	3	6	16	54
Total revenues and other income	754	1,345	2,256	3,975
Costs and expenses:
Production	129	163	418	543
Shipping, handling and other operating	183	138	432	462
Exploration	27	22	81	107
Depreciation, depletion and amortization	554	622	1,795	1,781
Impairments	1	0	98	24
Taxes other than income	49	81	145	232
General and administrative	53	82	217	263
Total costs and expenses	996	1,108	3,186	3,412
Income (loss) from operations	(242)	237	(930)	563
Net interest and other	(62)	(64)	(195)	(177)
Other net periodic benefit (costs) credits	(6)	2	1	9
Income (loss) before income taxes	(310)	175	(1,124)	395
Provision (benefit) for income taxes	7	10	(11)	(105)
Net income (loss)	$ (317)	$ 165	$ (1,113)	$ 500
Net income (loss) per share:
Basic (in dollars per share)	$ (0.40)	$ 0.21	$ (1.41)	$ 0.62
Diluted (in dollars per share)	$ (0.40)	$ 0.21	$ (1.41)	$ 0.62
Weighted average common shares outstanding:
Basic (in shares)	790	802	792	813
Diluted (in shares)	790	803	792	813

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Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (317)	$ 165	$ (1,113)	$ 500
Other comprehensive income (loss), net of tax
Change in actuarial gain (loss) and other for postretirement and postemployment plans	9	38	(33)	25
Change in derivative hedges unrecognized gain (loss)	11	0	(15)	0
Foreign currency translation adjustment related to sale of U.K. business	0	23	0	23
Other	0	1	0	1
Other comprehensive income (loss)	20	62	(48)	49
Comprehensive income (loss)	$ (297)	$ 227	$ (1,161)	$ 549

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Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 1,119	$ 858
Receivables, less reserve of $25 and $11	643	1,122
Inventories	77	72
Other current assets	83	83
Total current assets	1,922	2,135
Equity method investments	467	663
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $19,782 and $18,003	16,029	17,000
Goodwill	0	95
Other noncurrent assets	245	352
Total assets	18,663	20,245
Current liabilities:
Accounts payable	730	1,307
Payroll and benefits payable	72	112
Accrued taxes	45	118
Other current liabilities	219	208
Long-term debt due within one year	500	0
Total current liabilities	1,566	1,745
Long-term debt	5,405	5,501
Deferred tax liabilities	184	186
Defined benefit postretirement plan obligations	182	183
Asset retirement obligations	236	243
Deferred credits and other liabilities	198	234
Total liabilities	7,771	8,092
Commitments and contingencies
Stockholders’ Equity
Preferred stock – no shares issued or outstanding (no par value, 26 million shares authorized)	0	0
Common stock:
Issued – 937 million shares (par value $1 per share, 1.925 billion shares authorized at September 30, 2020 and December 31, 2019)	937	937
Held in treasury, at cost – 147 million shares and 141 million shares	(4,089)	(4,089)
Additional paid-in capital	7,159	7,207
Retained earnings	6,828	7,993
Accumulated other comprehensive income	57	105
Total stockholders’ equity	10,892	12,153
Total liabilities and stockholders’ equity	$ 18,663	$ 20,245

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Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Receivables reserve	$ 25	$ 11
Property, plant and equipment, accumulated depreciation	$ 19,782	$ 18,003
Preferred stock, shares issued (in shares)	0	0
Preferred stock, shares outstanding (in shares)	0	0
Preferred stock, par value (in dollars per share)	$ 0	$ 0
Preferred stock, shares authorized (in shares)	26,000,000	26,000,000
Common stock, shares issued (in shares)	937,000,000	937,000,000
Common stock, par value (in dollars per share)	$ 1	$ 1
Common stock, shares authorized (in shares)	1,925,000,000	1,925,000,000
Held in treasury, shares (in shares)	147,000,000	141,000,000

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Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
Operating activities:
Net income (loss)	$ (1,113)	$ 500
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	1,795	1,781
Impairments	98	24
Exploratory dry well costs and unproved property impairments	63	85
Net gain on disposal of assets	(8)	(56)
Deferred income taxes	(2)	(34)
Net (gain) loss on derivative instruments	(131)	28
Net settlements of derivative instruments	92	41
Pension and other post retirement benefits, net	(35)	(51)
Stock-based compensation	43	45
Equity method investments, net	189	26
Changes in:
Current receivables	467	(99)
Inventories	(5)	4
Current accounts payable and accrued liabilities	(478)	(164)
Other current assets and liabilities	83	108
All other operating, net	(3)	(189)
Net cash provided by operating activities	1,055	2,049
Investing activities:
Additions to property, plant and equipment	(1,090)	(1,934)
Additions to other assets	15	41
Acquisitions, net of cash acquired	(1)	0
Disposal of assets, net of cash transferred to the buyer	9	(84)
Equity method investments - return of capital	7	51
All other investing, net	0	2
Net cash used in investing activities	(1,060)	(1,924)
Financing activities:
Borrowings	400	0
Purchases of common stock	(92)	(296)
Dividends paid	(40)	(122)
All other financing, net	(2)	(4)
Net cash provided by (used in) financing activities	266	(422)
Net increase (decrease) in cash and cash equivalents	261	(297)
Cash and cash equivalents at beginning of period	858	1,462
Cash and cash equivalents at end of period	$ 1,119	$ 1,165

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Consolidated Statements of Stockholders' Equity (Unaudited) - USD ($) $ in Millions	Total	Preferred Stock	Common Stock	Treasury Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Beginning balance at Dec. 31, 2018	$ 12,128	$ 0	$ 937	$ (3,816)	$ 7,238	$ 7,706	$ 63
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cumulative-effect adjustment	(31)					(31)
Shares issued - stock-based compensation	62			101	(39)
Shares repurchased	(30)			(30)
Stock-based compensation	(50)				(50)
Net income (loss)	174					174
Other comprehensive income (loss)	(4)						(4)
Dividends paid	(41)					(41)
Ending balance at Mar. 31, 2019	12,208	0	937	(3,745)	7,149	7,808	59
Beginning balance at Dec. 31, 2018	12,128	0	937	(3,816)	7,238	7,706	63
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	500
Other comprehensive income (loss)	49
Ending balance at Sep. 30, 2019	12,271	0	937	(4,028)	7,197	8,053	112
Beginning balance at Mar. 31, 2019	12,208	0	937	(3,745)	7,149	7,808	59
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued - stock-based compensation	2			(3)	5
Shares repurchased	(236)			(236)
Stock-based compensation	16				16
Net income (loss)	161					161
Other comprehensive income (loss)	(9)						(9)
Dividends paid	(41)					(41)
Ending balance at Jun. 30, 2019	12,101	0	937	(3,984)	7,170	7,928	50
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued - stock-based compensation	(5)			(14)	9
Shares repurchased	(30)			(30)
Stock-based compensation	18				18
Net income (loss)	165					165
Other comprehensive income (loss)	62						62
Dividends paid	(40)					(40)
Ending balance at Sep. 30, 2019	12,271	0	937	(4,028)	7,197	8,053	112
Beginning balance at Dec. 31, 2019	12,153	0	937	(4,089)	7,207	7,993	105
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued - stock-based compensation	38			121	(83)
Shares repurchased	(91)			(91)
Stock-based compensation	(22)				(22)
Net income (loss)	(46)					(46)
Other comprehensive income (loss)	(22)						(22)
Dividends paid	(40)					(40)
Ending balance at Mar. 31, 2020	11,958	0	937	(4,059)	7,102	7,895	83
Beginning balance at Dec. 31, 2019	12,153	0	937	(4,089)	7,207	7,993	105
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(1,113)
Other comprehensive income (loss)	(48)
Ending balance at Sep. 30, 2020	10,892	0	937	(4,089)	7,159	6,828	57
Beginning balance at Mar. 31, 2020	11,958	0	937	(4,059)	7,102	7,895	83
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued - stock-based compensation	(8)			(28)	20
Stock-based compensation	21				21
Net income (loss)	(750)					(750)
Other comprehensive income (loss)	(46)						(46)
Ending balance at Jun. 30, 2020	11,175	0	937	(4,087)	7,143	7,145	37
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued - stock-based compensation	0			(2)	2
Stock-based compensation	14				14
Net income (loss)	(317)					(317)
Other comprehensive income (loss)	20						20
Ending balance at Sep. 30, 2020	$ 10,892	$ 0	$ 937	$ (4,089)	$ 7,159	$ 6,828	$ 57

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Consolidated Statements of Stockholders' Equity (Unaudited) (Parenthetical) - $ / shares	3 Months Ended					9 Months Ended
	Sep. 30, 2020	Mar. 31, 2020	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2020	Sep. 30, 2019
Statement of Stockholders' Equity [Abstract]
Dividends paid (in dollars per share)	$ 0	$ 0.05	$ 0.05	$ 0.05	$ 0.05	$ 0.05	$ 0.15

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Basis of Presentation

9 Months Ended

Sep. 30, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

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 2019 Annual Report on Form 10-K. The results of operations for the third quarter and first nine months of 2020 are not necessarily indicative of the results to be expected for the full year.

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Accounting Standards

9 Months Ended

Sep. 30, 2020

Accounting Policies [Abstract]

Accounting Standards

Accounting Standards

Recently Adopted

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. On January 1, 2020 we adopted this standard using the modified retrospective transition method through a cumulative-effect adjustment of $12 million to retained earnings as of the beginning of the adoption period. The standard requires the use of a forward-looking “expected loss” model as opposed to the “incurred loss” model used previously. See Note 8 for more information on credit losses.

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Income (loss) and Dividends per Common Share

9 Months Ended

Sep. 30, 2020

Earnings Per Share [Abstract]

Income (loss) and Dividends per Common Share

Income (loss) and Dividends per Common Share

Basic income (loss) per share is based on the weighted average number of common shares outstanding. Diluted income (loss) per share assumes exercise of stock options in all periods, provided the effect is not antidilutive. The per share calculations below exclude 6 million of stock options for each of the three and nine months ended September 30, 2020 and 6 million and 5 million of stock options for the three and nine months ended September 30, 2019 that were antidilutive.

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions, except per share data)	2020		2019		2020		2019
Net income (loss)	$	(317)	$	165	$	(1,113)	$	500
Weighted average common shares outstanding	790		802		792		813
Effect of dilutive securities	—		1		—		—
Weighted average common shares, diluted	790		803		792		813
Net income (loss) per share:
Basic	$	(0.40)	$	0.21	$	(1.41)	$	0.62
Diluted	$	(0.40)	$	0.21	$	(1.41)	$	0.62
Dividends per share	$	—	$	0.05	$	0.05	$	0.15

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Dispositions

9 Months Ended

Sep. 30, 2020

Discontinued Operations and Disposal Groups [Abstract]

Dispositions

Dispositions

International Segment

In July 2019, we closed on the sale of our U.K. business (Marathon Oil U.K. LLC and Marathon Oil West of Shetlands Limited) for proceeds of $95 million which included the assumption by RockRose Energy PLC (the buyer) of the U.K. business’ cash equivalent balance and working capital balance as of year-end 2018. During the third quarter of 2019, we recognized a pre-tax gain of $14 million. Our income before income taxes relating to our U.K. business for the three and nine months ended September 30, 2019, was nil and $28 million.

In the second quarter of 2019, we closed on the sale of our 15% non-operated interest in the Atrush block in Kurdistan for proceeds of $63 million, before closing adjustments.

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Revenues

9 Months Ended

Sep. 30, 2020

Revenue from Contract with Customer [Abstract]

Revenues

Revenues

The majority of our revenues are derived from the sale of crude oil and condensate, NGLs and natural gas under spot and term agreements with our customers in the United States and various international locations.

As of September 30, 2020 and December 31, 2019, receivables from contracts with customers, included in receivables, less reserves were $502 million and $837 million, respectively.

The following tables present our revenues from contracts with customers disaggregated by product type and geographic areas for the three and nine months ended September 30 as follows:

United States

	Three Months Ended September 30, 2020
(In millions)	Eagle Ford		Bakken		Oklahoma		Northern Delaware		Other U.S.		Total
Crude oil and condensate	$	190	$	230	$	65	$	53	$	14	$	552
Natural gas liquids	22		15		28		7		1		73
Natural gas	18		9		33		6		3		69
Other	1		—		—		—		27		28
Revenues from contracts with customers	$	231	$	254	$	126	$	66	$	45	$	722

	Three Months Ended September 30, 2019
(In millions)	Eagle Ford		Bakken		Oklahoma		Northern Delaware		Other U.S.		Total
Crude oil and condensate	$	336	$	452	$	116	$	88	$	25	$	1,017
Natural gas liquids	23		6		28		5		2		64
Natural gas	28		8		37		3		5		81
Other	1		—		—		—		9		10
Revenues from contracts with customers	$	388	$	466	$	181	$	96	$	41	$	1,172

	Nine Months Ended September 30, 2020
(In millions)	Eagle Ford		Bakken		Oklahoma		Northern Delaware		Other U.S.		Total
Crude oil and condensate	$	639	$	707	$	181	$	160	$	54	$	1,741
Natural gas liquids	53		28		62		14		4		161
Natural gas	62		22		86		13		7		190
Other	4		—		—		—		58		62
Revenues from contracts with customers	$	758	$	757	$	329	$	187	$	123	$	2,154

	Nine Months Ended September 30, 2019
(In millions)	Eagle Ford		Bakken		Oklahoma		Northern Delaware		Other U.S.		Total
Crude oil and condensate	$	1,004	$	1,277	$	304	$	229	$	83	$	2,897
Natural gas liquids	88		31		81		20		5		225
Natural gas	94		26		118		10		15		263
Other	4		—		—		—		45		49
Revenues from contracts with customers	$	1,190	$	1,334	$	503	$	259	$	148	$	3,434

International

	Three Months Ended September 30, 2020
(In millions)	E.G.
Crude oil and condensate	$	31
Natural gas liquids	1
Natural gas	7
Other	—
Revenues from contracts with customers	$	39

	Three Months Ended September 30, 2019
(In millions)	E.G.
Crude oil and condensate	$	67
Natural gas liquids	1
Natural gas	8
Other	1
Revenues from contracts with customers	$	77

	Nine Months Ended September 30, 2020
(In millions)	E.G.
Crude oil and condensate	$	96
Natural gas liquids	3
Natural gas	22
Revenues from contracts with customers	$	121

	Nine Months Ended September 30, 2019
(In millions)	E.G.		U.K.		Other Int’l		Total
Crude oil and condensate	$	215	$	107	$	19	$	341
Natural gas liquids	3		1		—		4
Natural gas	24		12		—		36
Other	1		14		—		15
Revenues from contracts with customers	$	243	$	134	$	19	$	396

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Segment Information

9 Months Ended

Sep. 30, 2020

Segment Reporting [Abstract]

Segment Information

Segment Information

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

•United States (“U.S.”) – explores for, produces and markets crude oil and condensate, NGLs and natural gas in the United States

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

    Segment income represents income 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, impairments of proved property, goodwill, and equity method investments, unrealized gains or losses on commodity and interest rate derivative instruments, effects of pension settlements and curtailments, or other items (as determined by the chief operating decision maker (“CODM”)) are not allocated to operating segments.

	Three Months Ended September 30, 2020
(In millions)	U.S.		Int’l		Not Allocated to Segments			Total
Revenues from contracts with customers	$	722	$	39	$	—		$	761
Net gain (loss) on commodity derivatives	35		—		(36)		(b)	(1)
Income (loss) from equity method investments	—		8		(18)			(10)
Net gain on disposal of assets	—		—		1			1
Other income	1		1		1			3
Less costs and expenses:
Production	118		11		—			129
Shipping, handling and other operating	154		1		28			183
Exploration	21		—		6			27
Depreciation, depletion and amortization	530		19		5			554
Impairments	—		—		1			1
Taxes other than income	48		—		1			49
General and administrative	25		3		25			53
Net interest and other	—		—		62			62
Other net periodic benefit costs	—		—		6		(c)	6
Income tax provision (benefit)	(3)		6		4			7
Segment income (loss)	$	(135)	$	8	$	(190)		$	(317)
Total assets	$	16,396	$	1,104	$	1,163		$	18,663
Capital expenditures(a)	$	176	$	—	$	1		$	177

(a)Includes accruals.

(b)Unrealized loss on commodity derivative instruments (See Note 15).

(c)Includes pension settlement loss of $9 million (See Note 20).

	Three Months Ended September 30, 2019
(In millions)	U.S.		Int’l		Not Allocated to Segments			Total
Revenues from contracts with customers	$	1,172	$	77	$	—		$	1,249
Net gain on commodity derivatives	14		—		33		(b)	47
Income from equity method investments	—		21		—			21
Net gain on disposal of assets	—		—		22		(c)	22
Other income	3		2		1			6
Less costs and expenses:
Production	147		16		—			163
Shipping, handling and other operating	137		1		—			138
Exploration	22		—		—			22
Depreciation, depletion and amortization	589		25		8			622
Taxes other than income	80		—		1			81
General and administrative	34		5		43			82
Net interest and other	—		—		64			64
Other net periodic benefit credit	—		—		(2)			(2)
Income tax provision	—		10		—			10
Segment income (loss)	$	180	$	43	$	(58)		$	165
Total assets	$	17,722	$	2,003	$	648		$	20,373
Capital expenditures(a)	$	667	$	1	$	7		$	675

(a)Includes accruals.

(b)Unrealized gain on commodity derivative instruments (See Note 15).

(c)Primarily related to the sale of our U.K. business (see Note 4).

	Nine Months Ended September 30, 2020
(In millions)	U.S.		Int’l		Not Allocated to Segments			Total
Revenues from contracts with customers	$	2,154	$	121	$	—		$	2,275
Net gain on commodity derivatives	92		—		39		(b)	131
Loss from equity method investments	—		(4)		(170)		(c)	(174)
Net gain on disposal of assets	—		—		8			8
Other income	8		5		3			16
Less costs and expenses:
Production	375		43		—			418
Shipping, handling and other operating	385		5		42			432
Exploration	75		—		6			81
Depreciation, depletion and amortization	1,716		62		17			1,795
Impairments	—		—		98		(d)	98
Taxes other than income	144		—		1			145
General and administrative	89		10		118		(e)	217
Net interest and other	—		—		195			195
Other net periodic benefit credit	—		—		(1)		(f)	(1)
Income tax provision (benefit)	(10)		1		(2)			(11)
Segment income (loss)	$	(520)	$	1	$	(594)		$	(1,113)
Total assets	$	16,396	$	1,104	$	1,163		$	18,663
Capital expenditures(a)	$	874	$	—	$	10		$	884

(a)Includes accruals.

(b)Unrealized gain on commodity derivative instruments (See Note 15).

(c)Partial impairment of investment in equity method investee (See Note 23).

(d)Includes the full impairment of the International reporting unit goodwill of $95 million (See Note 14).

(e)Includes severance expenses associated with workforce reductions of $15 million.

(f)Includes pension settlement loss of $25 million and pension curtailment gain of $17 million (See Note 20).

	Nine Months Ended September 30, 2019
(In millions)	U.S.		Int’l		Not Allocated to Segments			Total
Revenue from contracts with customers	$	3,434	$	396	$	—		$	3,830
Net gain (loss) on commodity derivatives	41		—		(69)		(b)	(28)
Income from equity method investments	—		63		—			63
Net gain on disposal of assets	—		—		56		(c)	56
Other income	8		7		39		(d)	54
Less costs and expenses:
Production	433		112		(2)			543
Shipping, handling and other operating	424		24		14			462
Exploration	107		—		—			107
Depreciation, depletion and amortization	1,664		97		20			1,781
Impairments	—		—		24		(e)	24
Taxes other than income	233		—		(1)			232
General and administrative	94		20		149			263
Net interest and other	—		—		177			177
Other net periodic benefit credit	—		(3)		(6)			(9)
Income tax provision (benefit)	1		16		(122)		(f)	(105)
Segment income (loss)	$	527	$	200	$	(227)		$	500
Total assets	$	17,722	$	2,003	$	648		$	20,373
Capital expenditures(a)	$	1,959	$	16	$	15		$	1,990

(a)Includes accruals.

(b)Unrealized loss on commodity derivative instruments (See Note 15).

(c)Primarily related to the sale of our working interest in the Droshky field (Gulf of Mexico) and the sale of our U.K. business (See Note 4).

(d)Primarily related to the indemnification of certain tax liabilities in connection with the 2010-2011 Federal Tax Audit.

(e)Primarily as a result of anticipated sales of certain non-core proved properties in our International and United States segments.

(f)Primarily relates to the settlement of the 2010-2011 Federal Tax Audit (See Note 7).

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Income Taxes

9 Months Ended

Sep. 30, 2020

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 6.

For the three and nine months ended September 30, 2020 and 2019, our effective income tax rates were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Effective income tax rate(a)	(2)	%	6	%	1	%	(27)	%

(a)In all periods presented, we maintained our valuation allowance on our net federal deferred tax assets in the U.S.

The following items caused the effective income tax rates to be different from our U.S. statutory tax rate of 21% for 2020 and 2019:

•For the three and nine months ended September 30, 2020, the income tax rate was reduced below the statutory rate due to the valuation allowance on our net federal deferred tax assets in the U.S., which resulted in no federal tax benefit on the U.S. loss.

•For the three and nine months ended September 30, 2019, the mix of pre-tax income in our international operations and the valuation allowance on our net federal deferred tax assets in the U.S., reduced the annual effective tax rate below the statutory tax rate. Income tax rates for the nine months ended September 30, 2019 were also impacted by the settlement of the 2010-2011 U.S. Federal Tax Audit in the first quarter of 2019, resulting in a tax benefit of $126 million. Additionally, in the first quarter of 2019, we recorded a non-cash deferred tax benefit of $18 million in the U.K. related to an internal restructuring. These two items are discrete to the first nine months of 2019. Excluding these discrete adjustments, the effective income tax rate for the first nine months of 2019 was an expense of 10%.

In the third quarter of 2020, we received an $89 million cash refund related to alternative minimum tax credits and interest. This refund was accelerated as a result of the enactment of the Coronavirus Aid, Relief, and Economic Security Act, commonly referred to as the CARES Act, in the first quarter of 2020.

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Credit Losses

9 Months Ended

Sep. 30, 2020

Credit Loss [Abstract]

Credit Losses

Credit Losses

    The majority of our receivables are from purchasers of commodities or joint interest owners in properties we operate, both of which are recorded at estimated or invoiced amounts and do not bear interest. The majority of these receivables have payment terms of 30 days or less. At the end of each reporting period, we assess the collectability of our receivables and estimate the expected credit losses using historical data, current market conditions and reasonable and supportable forecasts of future economic conditions.

    We are exposed to credit losses through the receivables generated from sales of crude oil, NGLs and natural gas to our customers. When dealing with the commodity purchasers, we conduct a credit review to assess each counterparty’s ability to pay. The credit review considers our expected billing exposure, timing for payment and the counterparty’s established credit rating with the rating agencies or our internal assessment of the counterparty’s creditworthiness based on our analysis of their financial statements. Our evaluation also considers contract terms and other factors, such as country and/or political risk. A credit limit is established for each counterparty based on the outcome of this review. We may require a bank letter of credit or a prepayment to mitigate credit risk. We monitor our ongoing credit exposure through active review of counterparty balances against contract terms and due dates. The expected credit losses related to receivables with the commodity purchasers were determined using the weighted average probability of default method. We also collect revenues from our non-operated joint properties where other oil and gas exploration and production companies operate the properties and market our share of production and remit payments to us. The current expected credit losses related to these receivables were determined using the loss rate method applied to aging pools.

We are exposed to credit losses from joint interest billings to other joint interest owners for properties we operate. For this group of receivables, the expected credit losses are determined using the loss rate method applied to aging pools. Our counterparties in this group include numerous large, mid-size and small oil and gas exploration and production companies. Although we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings or require a prepayment of future costs through cash calls, our credit loss exposure with this group is more significant due to inherent ownership or billing adjustments. Also, some of our counterparties may experience liquidity problems and may not be able to meet their financial obligations to us. We expect that liquidity problems will increase in the future as a result of the recent demand and pricing decline for hydrocarbons. Our current-period provision reflects the anticipated effects caused by the recent market deterioration.

Changes in the allowance for doubtful accounts balance for the nine months ended were as follows:    

(In millions)	September 30, 2020
Beginning balance as of January 1	$	11
Cumulative-effect adjustment	12
Current period provision(a)	22
Current period write offs	(12)
Recoveries of amounts previously reserved	(8)
Ending balance as of September 30	$	25

(a)For the nine months ended September 30, 2020, the current period provision increased by $10 million in joint interest receivables and $12 million in trade receivables.

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Inventories

9 Months Ended

Sep. 30, 2020

Inventory Disclosure [Abstract]

Inventories

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. The continued volatility and future decline in crude oil and natural gas prices could affect the value of our inventories and result in future impairments.

(In millions)	September 30, 2020		December 31, 2019
Crude oil and natural gas	$	11	$	10
Supplies and other items	66		62
Inventories	$	77	$	72

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Property, Plant and Equipment

9 Months Ended

Sep. 30, 2020

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

(In millions)	September 30, 2020		December 31, 2019
United States	$	15,533	$	16,427
International	424		493
Corporate	72		80
Net property, plant and equipment	$	16,029	$	17,000

We had no exploratory well costs capitalized greater than one year as of September 30, 2020 and December 31, 2019.

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Impairments

9 Months Ended

Sep. 30, 2020

Impairment Expense [Abstract]

Impairments

Impairments     During the first quarter of 2020, a global pandemic caused a substantial deterioration in the worldwide demand of hydrocarbons. The decreased demand, when coupled with an oversupplied market, caused a corresponding deterioration in hydrocarbon prices. We reviewed our long-lived assets for indicators of impairment during the first quarter by conducting a sensitivity analysis of the most impactful inputs to their undiscounted cash flows, including commodity prices, capital spend and reductions in production volumes to correspond with lower capital spending. Our review concluded that the carrying amounts of our long-lived assets are recoverable; however, further deterioration or a more sustained decline of commodity prices may result in impairment charges in future periods. 

    We also reviewed our equity method investments for indicators of impairment. Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value may have occurred. When a loss in value occurs that is deemed other than temporary, the carrying value of the equity method investment is written down to fair value. Our first quarter review concluded that any potential losses in values of our equity method investments were temporary because the underlying declines in both commodity prices and demand did not materially manifest until early March. However, during the second and third quarters of 2020, we recognized impairments related to one of our equity method investees, as noted in the tables below.

The following table summarizes impairment charges of proved properties, goodwill and equity method investments and their corresponding fair values.

	Three Months Ended September 30,
	2020				2019
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	—	$	1	$	—	$	—
Equity method investment	$	23	$	18	N/A		$	—

	Nine Months Ended September 30,
	2020				2019
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	—	$	3	$	56	$	24
Goodwill	$	—	$	95	N/A		$	—
Equity method investment	$	119	$	170	N/A		$	—

•2020 – Impairments for the nine months ended September 30, 2020 include charges recognized for our equity method investments of $170 million. During the second quarter of 2020, the continuation of the depressed commodity prices caused us to perform a review of our equity method investments. Our review concluded that a loss of our investment value in one of our equity method investees was other than temporary and we recorded an impairment of $152 million based on the difference between our carrying value and the fair value of our investment. During the third quarter of 2020, we further reduced our long term price forecast of a gas index in which one of our equity method investees transacts, which resulted in an incremental reduction of our investment value. We recorded an impairment of $18 million during the third quarter, which we deemed other than temporary. Our remaining investments in equity method investees did not experience losses in value that caused the fair values to be below their carrying values.

We estimated the fair value of our equity method investment using an income approach, specifically utilizing a discounted cash flow analysis. The estimated fair value was based on significant inputs not observable in the market, such as the amount of gas processed by the plant, future commodity prices, forecasted operating expenses, discount rate, and estimated cash returned to shareholders. Collectively, these inputs represent Level 3 measurements.

The impairments of our equity method investments were recognized in income (loss) from equity method investments in our consolidated statements of income. The impairments caused us to incur a basis differential between the net book value of our investment and the amount of our underlying share of equity in the investee’s net assets. The amount of this basis differential is $140 million and will be accreted into income over the next 6.25 years, which is consistent with the remaining useful life of the investee’s primary assets.

Impairments for the nine months ended September 30, 2020 also included $95 million of goodwill impairment in the International reporting unit. See Note 14 for further information.

•2019 – During the nine months ended September 30, 2019, we recorded proved property impairments of $24 million, as a result of the anticipated sales proceeds for certain non-core proved properties in our United States segment and the sale of our non-operated interest in the Atrush block (Kurdistan) in our International segment. The related fair value was measured using the market approach, based upon anticipated sales proceeds less costs to sell which resulted in a Level 2 classification. See Note 4 for further information.

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2020

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

Asset retirement obligations primarily consist of estimated costs to remove, dismantle and restore land or seabed at the end of oil and gas production operations. Changes in asset retirement obligations for the nine months ended September 30 were as follows:

	September 30,
(In millions)	2020		2019
Beginning balance as of January 1	$	255	$	1,145
Incurred liabilities, including acquisitions	3		25
Settled liabilities, including dispositions	(11)		(1,106)
Accretion expense (included in depreciation, depletion and amortization)	9		29
Revisions of estimates	(8)		15
Held for sale	—		108
Ending balance as of September 30	$	248	$	216

September 30, 2020

•Ending balance includes $12 million classified as short-term at September 30, 2020.

September 30, 2019

•Settled liabilities primarily relate to the sale of our U.K. business, which closed during the third quarter of 2019.

•Held for sale reflects a transfer to settled liabilities during 2019. This transfer was primarily related to the Droshky field (Gulf of Mexico), which was considered held for sale at year-end 2018 and closed in the first quarter of 2019.

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Leases

9 Months Ended

Sep. 30, 2020

Leases [Abstract]

Leases

Leases

We enter into various lease agreements to support our operations including drilling rigs, well fracturing equipment, compressors, buildings, aircraft, vessels, vehicles and miscellaneous field equipment. We primarily act as a lessee in these transactions and all of our existing leases are classified as either short-term or long-term operating leases.

Supplemental balance sheet information related to leases was as follows:

(In millions)		September 30, 2020
Operating Leases:	Balance Sheet Location:
Right-of-use asset	Other noncurrent assets	$	137
Current portion of long-term lease liability	Other current liabilities	$	79
Long-term lease liability	Deferred credits and other liabilities	$	61

    Our wholly-owned subsidiary, Marathon E.G. Production Limited, is a lessor for residential housing in Equatorial Guinea, which is occupied by EGHoldings, a related party equity method investee – see Note 24. The lease was classified as an operating lease and expires in 2024, with a lessee option to extend through 2034. Lease payments are fixed for the entire duration of the agreement at approximately $6 million per year. Our lease income is reported in other income in our consolidated statements of income for all periods presented. The undiscounted cash flows to be received under this lease agreement are summarized below.

(In millions)	Operating Lease Future Cash Receipts
2020	$	2
2021	6
2022	6
2023	6
2024	6
Thereafter	60
Total undiscounted cash flows	$	86

In 2018, we signed an agreement with an owner/lessor to construct and lease a new build-to-suit office building in Houston, Texas. The lessor and other participants are providing financing for up to $340 million to fund the estimated project costs, which was reduced effective August 2020, from $380 million to align with our revised estimate of the project costs. As of September 30, 2020, project costs incurred totaled approximately $117 million, including land acquisition and construction costs. The initial lease term is five years and will commence once construction is substantially complete and the new Houston office is ready for occupancy. At the end of the initial lease term, we can negotiate to extend the lease term for an additional five years, subject to the approval of the participants; purchase the property subject to certain terms and conditions; or remarket the property to an unrelated third party. The lease contains a residual value guarantee of approximately 89% of the total acquisition and construction costs.

Leases

Leases

We enter into various lease agreements to support our operations including drilling rigs, well fracturing equipment, compressors, buildings, aircraft, vessels, vehicles and miscellaneous field equipment. We primarily act as a lessee in these transactions and all of our existing leases are classified as either short-term or long-term operating leases.

Supplemental balance sheet information related to leases was as follows:

(In millions)		September 30, 2020
Operating Leases:	Balance Sheet Location:
Right-of-use asset	Other noncurrent assets	$	137
Current portion of long-term lease liability	Other current liabilities	$	79
Long-term lease liability	Deferred credits and other liabilities	$	61

    Our wholly-owned subsidiary, Marathon E.G. Production Limited, is a lessor for residential housing in Equatorial Guinea, which is occupied by EGHoldings, a related party equity method investee – see Note 24. The lease was classified as an operating lease and expires in 2024, with a lessee option to extend through 2034. Lease payments are fixed for the entire duration of the agreement at approximately $6 million per year. Our lease income is reported in other income in our consolidated statements of income for all periods presented. The undiscounted cash flows to be received under this lease agreement are summarized below.

(In millions)	Operating Lease Future Cash Receipts
2020	$	2
2021	6
2022	6
2023	6
2024	6
Thereafter	60
Total undiscounted cash flows	$	86

In 2018, we signed an agreement with an owner/lessor to construct and lease a new build-to-suit office building in Houston, Texas. The lessor and other participants are providing financing for up to $340 million to fund the estimated project costs, which was reduced effective August 2020, from $380 million to align with our revised estimate of the project costs. As of September 30, 2020, project costs incurred totaled approximately $117 million, including land acquisition and construction costs. The initial lease term is five years and will commence once construction is substantially complete and the new Houston office is ready for occupancy. At the end of the initial lease term, we can negotiate to extend the lease term for an additional five years, subject to the approval of the participants; purchase the property subject to certain terms and conditions; or remarket the property to an unrelated third party. The lease contains a residual value guarantee of approximately 89% of the total acquisition and construction costs.

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Goodwill

9 Months Ended

Sep. 30, 2020

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill

Goodwill

As of December 31, 2019, our consolidated balance sheet included goodwill of $95 million in the International reporting unit. Goodwill is tested for impairment on an annual basis, or between annual tests when events or changes in circumstances indicate the fair value of a reporting unit with goodwill may have been reduced below its carrying value. During the first quarter of 2020, a global pandemic caused a substantial deterioration in the worldwide demand of hydrocarbons. This demand loss resulted in a significant decline in hydrocarbon prices. The commensurate decline in our market capitalization during the first quarter indicated that it was more likely than not that the fair value of the International reporting unit was less than its carrying value.

We estimated the fair value of our International reporting unit using a combination of market and income approaches. The market approach referenced observable inputs specific to us and our industry, such as the price of our common equity, our enterprise value, and valuation multiples of us and peers from the investor analyst community. The income approach utilized discounted cash flows, which were based on forecasted assumptions. Key assumptions to the income approach include future liquid hydrocarbon and natural gas pricing, estimated quantities of liquid hydrocarbons and natural gas proved and probable reserves, estimated timing of production, discount rates, future capital requirements, operating expenses and tax rates. The assumptions used in the income approach are consistent with those that management uses to make business decisions. These valuation methodologies represent Level 3 fair value measurements. Based on the results, we concluded our goodwill was fully impaired, and recorded an impairment of $95 million in the consolidated statements of income for the first quarter of 2020.

	September 30,
(In millions)	2020		2019
Beginning balance as of January 1, gross	$	95	$	97
Less: accumulated impairments	—		—
Beginning balance, net	95		97
Dispositions	—		(2)
Impairment	(95)		—
Ending balance as of September 30, net	$	—	$	95

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Derivatives

9 Months Ended

Sep. 30, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note 16. All of our commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we report net amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts along with where they appear on the consolidated balance sheets.

	September 30, 2020
(In millions)	Asset		Liability		Net Asset (Liability)		Balance Sheet Location
Not Designated as Hedges
Commodity	$	59	$	14	$	45	Other current assets
Commodity	—		2		(2)		Deferred credits and other liabilities
Interest Rate	1		—		1		Other noncurrent assets
Interest Rate	—		3		(3)		Deferred credits and other liabilities
Total Not Designated as Hedges	$	60	$	19	$	41
Cash Flow Hedges
Interest Rate	$	9	$	—	$	9	Other noncurrent assets
Interest Rate	—		19		(19)		Deferred credits and other liabilities
Total Designated Hedges	$	9	$	19	$	(10)
Total	$	69	$	38	$	31

	December 31, 2019
(In millions)	Asset		Liability		Net Asset (Liability)		Balance Sheet Location
Not Designated as Hedges
Commodity	$	9	$	1	$	8	Other current assets
Commodity	1		—		1		Other noncurrent assets
Commodity	—		5		(5)		Other current liabilities
Total Not Designated as Hedges	$	10	$	6	$	4
Cash Flow Hedges
Interest Rate	$	2	$	—	$	2	Other noncurrent assets
Total Designated Hedges	$	2	$	—	$	2
Total	$	12	$	6	$	6

Derivatives Not Designated as Hedges

Commodity Derivatives

We have entered into multiple crude oil, natural gas and NGL derivatives indexed to the respective indices as noted in the table below, related to a portion of our forecasted United States sales through 2021. These derivatives consist of three-way collars, two-way collars, fixed price swaps, basis swaps, and NYMEX roll basis swaps. Three-way collars consist of a sold call (ceiling), a purchased put (floor) and a sold put. The ceiling price is the maximum we will receive for the contract volumes; the floor is the minimum price we will receive, unless the market price falls below the sold put strike price. In this case, we receive the NYMEX WTI price plus the difference between the floor and the sold put price. Two-way collars only consist of a sold call (ceiling) and a purchased put (floor). These crude oil, natural gas and NGL derivatives were not designated as hedges.

The following table sets forth outstanding derivative contracts as of September 30, 2020, and the weighted average prices for those contracts:

	2020		2021		2021
	Fourth Quarter		First Half		Second Half
Crude Oil
NYMEX WTI Three-Way Collars
Volume (Bbls/day)	80,000		—		—
Weighted average price per Bbl:
Ceiling	$	64.40	$	—	$	—
Floor	$	55.00	$	—	$	—
Sold put	$	48.00	$	—	$	—
NYMEX WTI Two-Way Collars
Volume (Bbls/day)	20,000		10,000		10,000
Weighted average price per Bbl:
Ceiling	$	46.83	$	52.37	$	52.37
Floor	$	37.00	$	35.00	$	35.00
Basis Swaps - NYMEX WTI / Argus WTI Midland (a)
Volume (Bbls/day)	15,000		—		—
Weighted average price per Bbl	$	(0.94)	$	—	$	—
Basis Swaps - NYMEX WTI / ICE Brent (b)
Volume (Bbls/day)	5,000		1,630		—
Weighted average price per Bbl	$	(7.24)	$	(7.24)	$	—
NYMEX Roll Basis Swaps
Volume (Bbls/day)	30,000		—		—
Weighted average price per Bbl	$	(0.81)	$	—	$	—
Natural Gas
Henry Hub (“HH”) Two-Way Collars
Volume (MMBtu/day)	250,000		175,000		150,000
Weighted average price per MMBtu:
Ceiling	$	2.82	$	3.10	$	3.03
Floor	$	2.25	$	2.46	$	2.43
Basis Swaps - WAHA / HH (c)
Volume (MMBtu/day)	10,000		—		—
Weighted average price per MMBtu	$	(0.37)	$	—	$	—
NGL
Fixed Price Ethane Swaps (d)
Volume (Bbls/day)	10,000		—		—
Weighted average price per Bbl	$	8.78	$	—	$	—

(a)The basis differential price is indexed against Argus WTI Midland and NYMEX WTI.

(b)The basis differential price is indexed against Intercontinental Exchange (“ICE”) Brent and NYMEX WTI.

(c)The basis differential price is indexed against Waha and NYMEX Henry Hub.

(d)The fixed price ethane swap is priced at OPIS Mont Belvieu Purity Ethane.

The following table sets forth outstanding derivative contracts entered into between October 1 and November 3, 2020, and the weighted average prices for those contracts:

	2021		2021
	First Half		Second Half
Crude Oil
Basis Swaps - NYMEX WTI / UHC (a)
Volume (Bbls/day)	14,000		—
Weighted average price per Bbl	$	(1.80)	$	—
Natural Gas
HH Two-Way Collars
Volume (MMBtu/day)	50,000		50,000
Weighted average price per MMBtu:
Ceiling	$	3.13	$	3.13
Floor	$	2.70	$	2.70
HH Fixed Price Swaps
Volume (MMBtu/day)	50,000		50,000
Weighted average price per MMBtu	$	2.88	$	2.88

(a)The basis differential price is indexed against U.S. Sweet Clearbrook (“UHC”) and NYMEX WTI.

The mark-to-market impact and settlement of our commodity derivative instruments appears in the table below and is reflected in net gain (loss) on commodity derivatives in the consolidated statements of income.

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2020		2019		2020		2019
Mark-to-market gain (loss)	$	(36)	$	33	$	39	$	(69)
Net settlements of commodity derivative instruments	$	35	$	14	$	92	$	41

Interest Rate Swaps

During 2020, we entered into forward starting interest rate swaps to hedge the variations in cash flows related to fluctuations in the London Interbank Offered Rate (“LIBOR”) benchmark interest rate related to forecasted interest payments of a future debt issuance in 2022. Each respective derivative contract can be tied to an anticipated underlying dollar notional amount. During the third quarter of 2020, we de-designated these forward starting interest rate swaps previously designated as cash flow hedges. At September 30, 2020, accumulated other comprehensive income included a net deferred loss of $2 million related to the de-designated forward starting interest rate swaps previously designated as cash flow hedges. No portion of this amount has been reclassified from accumulated other comprehensive income as of September 30, 2020. We expect to reclassify this amount into earnings as an adjustment to net interest and other upon the occurrence of the forecasted transactions.

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

	September 30, 2020				December 31, 2019
Maturity Date	Aggregate Notional Amount (in millions)		Weighted Average, LIBOR		Aggregate Notional Amount (in millions)		Weighted Average, LIBOR
November 1, 2022	$	500	0.99	%	$	—	—	%

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

	Three Months Ended September 30,		Nine Months Ended September 30,
(In millions)	2020		2020
Interest Rate Swaps
Beginning balance	$	(7)	$	—
Change in fair value recognized in other comprehensive income (loss)	5		(2)
Ending balance	$	(2)	$	(2)

Derivatives Designated as Cash Flow Hedges

During 2020, we entered into forward starting interest rate swaps with a notional amount of $350 million to hedge variations in cash flows arising from fluctuations in the LIBOR benchmark interest rate related to forecasted interest payments of a future debt issuance in 2025. We expect to refinance these debt maturities in 2025. The swaps will terminate on or prior to the refinancing of the debt and the final value will be reclassified from accumulated other comprehensive income into earnings with each future interest payment.

During 2019, we entered into forward starting interest rate swaps with a total notional amount of $320 million to hedge variations in cash flows related to the 1-month LIBOR component of future lease payments of our future Houston office. These swaps will settle monthly on the same day the lease payment is made with the first swap settlement occurring in January 2022. We expect the first lease payment to commence sometime in the period from December 2021 to May 2022. The last swap will mature on September 9, 2026. See Note 13 for further details regarding the lease of the new Houston office.

The following table presents, by maturity date, information about our interest rate swap agreements, including the weighted average LIBOR-based, fixed rate.

	September 30, 2020				December 31, 2019
Maturity Date	Aggregate Notional Amount (in millions)		Weighted Average, LIBOR		Aggregate Notional Amount (in millions)		Weighted Average, LIBOR
June 1, 2025	$	350	0.95	%	$	—	—	%
September 9, 2026	$	320	1.51	%	$	320	1.51	%

At September 30, 2020, accumulated other comprehensive income included deferred losses of $10 million related to forward starting interest rate swaps designated as cash flow hedges. No amounts related to these swaps are expected to impact the consolidated statements of income in the next 12 months.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2020

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

Fair Values – Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of September 30, 2020 and December 31, 2019 by hierarchy level.

	September 30, 2020
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity(a)	$	3	$	40	$	—	$	43
Interest rate - not designated as cash flow hedges	—		1		—		1
Interest rate - designated as cash flow hedges	—		9		—		9
Derivative instruments, assets	$	3	$	50	$	—	$	53
Derivative instruments, liabilities
Interest rate - not designated as cash flow hedges	$	—	$	(3)	$	—	$	(3)
Interest rate - designated as cash flow hedges	—		(19)		—		(19)
Derivative instruments, liabilities	$	—	$	(22)	$	—	$	(22)
Total	$	3	$	28	$	—	$	31

	December 31, 2019
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity(a)	$	—	$	7	$	—	$	7
Interest rate - designated as cash flow hedges	—		2		—		2
Derivative instruments, assets	$	—	$	9	$	—	$	9
Derivative instruments, liabilities
Commodity(a)	$	(3)	$	—	$	—	$	(3)
Derivative instruments, liabilities	$	(3)	$	—	$	—	$	(3)
Total	$	(3)	$	9	$	—	$	6

(a)Commodity derivative instruments are recorded on a net basis in our consolidated balance sheet. See Note 15.

Commodity derivatives include three-way collars, two-way collars, fixed price swaps, basis swaps and NYMEX roll basis swaps. These instruments are measured at fair value using either a Black-Scholes or a modified Black-Scholes Model. For 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 and two-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.

The forward starting interest rate swaps are measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs. See Note 15 for detail on the forward starting interest rate swaps.

Fair Value Estimates – Goodwill

See Note 14 for detail information relating to goodwill.

Fair Values – Nonrecurring

See Note 11 for detail on our fair values related to impairments.

Fair Values – Financial Instruments

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

The following table summarizes financial instruments, excluding receivables, payables and derivative financial instruments, and their reported fair values by individual balance sheet line item at September 30, 2020 and December 31, 2019.

	September 30, 2020				December 31, 2019
(In millions)	Fair Value		Carrying Amount		Fair Value		Carrying Amount
Financial assets
Current assets	$	4	$	4	$	4	$	4
Other noncurrent assets	35		49		26		38
Total financial assets	$	39	$	53	$	30	$	42
Financial liabilities
Other current liabilities	$	62	$	99	$	62	$	90
Long-term debt, including current portion(a)	6,044		5,931		6,174		5,529
Deferred credits and other liabilities	105		84		99		86
Total financial liabilities	$	6,211	$	6,114	$	6,335	$	5,705

(a)Excludes debt issuance costs.

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

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

9 Months Ended

Sep. 30, 2020

Debt Disclosure [Abstract]

Debt

Debt

Revolving Credit Facility

As of September 30, 2020, we had no borrowings against our $3.0 billion unsecured revolving credit facility (“Credit Facility”), as described below.

The Credit Facility includes a covenant requiring our total debt to total capitalization ratio not to exceed 65% as of the last day of each fiscal quarter. In the event of a default, the lenders holding more than half of the commitments may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility. As of September 30, 2020, we were in compliance with this covenant with a ratio of 35%.

Debt Remarketing

On August 18, 2020, we closed a $400 million remarketing to investors of sub-series B bonds which are part of the $1 billion St. John the Baptist, State of Louisiana revenue refunding bonds originally issued and purchased in December 2017. The sub-series B bonds are subject to mandatory tender for purchase on the dates set forth in the table below.

The following table further summarizes this transaction.

Sub-Series B Bonds	Par Amount	Interest Rate	Mandatory Purchase Date	Maturity Date
Sub-series B-1 Bonds	$200 million	2.125%	July 1, 2024	June 1, 2037
Sub-series B-2 Bonds	$200 million	2.375%	July 1, 2026	June 1, 2037

Debt Redemption

On September 16, 2020, we commenced a cash tender offer for up to an aggregate principal amount of $500 million (the “Aggregate Maximum Tender Amount”) of our outstanding $1 billion 2.8% Senior Notes due 2022 (“2022 Notes”). The Aggregate Maximum Tender Amount was fully subscribed and we completed the early settlement on October 1, 2020, repaying the $500 million. As such, the $500 million was moved to long-term due within one year on our consolidated balance sheet as of September 30, 2020. The remaining $500 million of the 2.8% 2022 Notes remains part of long-term debt on our consolidated balance sheet as of September 30, 2020.

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Stockholders' Equity	9 Months Ended
	Sep. 30, 2020
Equity [Abstract]
Stockholders' Equity	Stockholders’ EquityDuring the nine months ended September 30, 2020, we acquired approximately 9 million common shares at a cost of $85 million, which were held as treasury stock. Including these repurchases, the total remaining share repurchase authorization was $1.3 billion at September 30, 2020. Purchases under the program are made at our discretion and may be in either open market transactions, including block purchases, or in privately negotiated transactions using cash on hand, cash generated from operations or proceeds from potential asset sales. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion.

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Incentive Based Compensation

9 Months Ended

Sep. 30, 2020

Share-based Payment Arrangement [Abstract]

Incentive Based Compensation

Incentive Based Compensation

Stock options, restricted stock awards and restricted stock units

The following table presents a summary of activity for the first nine months of 2020: 

	Stock Options				Restricted Stock Awards & Units
	Number of Shares		Weighted Average Exercise Price		Awards	Weighted Average Grant Date Fair Value
Outstanding at December 31, 2019	5,659,731		$	23.55	7,174,386	$	15.88
Granted	1,132,808	(a)	$	10.47	5,337,796	$	8.55
Exercised/Vested	(52,333)		$	7.22	(3,024,561)	$	15.83
Canceled(b)	(662,482)		$	24.66	(1,529,949)	$	11.66
Outstanding at September 30, 2020	6,077,724		$	21.13	7,957,672	$	11.80

(a)The weighted average grant date fair value of stock option awards granted was $3.82 per share.

(b)Included in canceled are forfeitures related to workforce reductions.

Stock-based performance unit awards

    During the first nine months of 2020, we granted 1,038,676 stock-based performance units to certain officers to be settled in shares. The grant date fair value per unit was $10.55, as calculated using a Monte Carlo valuation model. As of September 30, 2020 there were 1,658,088 units outstanding.

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Defined Benefit Postretirement Plans

9 Months Ended

Sep. 30, 2020

Retirement Benefits [Abstract]

Defined Benefit Postretirement Plans

Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit costs (credits):

	Three Months Ended September 30,
	Pension Benefits				Other Benefits
(In millions)	2020		2019(c)		2020		2019
Service cost	$	4	$	5	$	—	$	—
Interest cost	2		3		1		1
Expected return on plan assets	(2)		(3)		—		—
Amortization:
– prior service credit	(1)		(1)		(4)		(5)
– actuarial loss	2		2		—		1
Net settlement loss(a)	9		—		—		—
Net periodic benefit costs (credits)(b)	$	14	$	6	$	(3)	$	(3)

	Nine Months Ended September 30,
	Pension Benefits				Other Benefits
(In millions)	2020		2019(c)		2020		2019
Service cost	$	14	$	14	$	—	$	—
Interest cost	7		17		2		3
Expected return on plan assets	(7)		(19)		—		—
Amortization:
– prior service credit	(5)		(5)		(13)		(14)
– actuarial loss	7		6		1		1
Net settlement loss(a)	25		2		—		—
Net curtailment gain(d)	(3)		—		(14)		—
Net periodic benefit costs (credits)(b)	$	38	$	15	$	(24)	$	(10)

(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.

(b)Net periodic benefit costs (credits) reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.

(c)Includes amounts related to the noncontributory defined benefit pension plan covering U.K. employees, prior to the plan being transferred to the buyer upon sale of the U.K. asset on July 1, 2019.

(d)Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans.

    During the first nine months of 2020, we made contributions of $21 million to our funded pension plan and expect to contribute an additional $7 million this year. During the first nine months of 2020, we made payments of $17 million and $11 million related to unfunded pension plans and other postretirement benefit plans.

In connection with the sale of our U.K. business, the noncontributory defined benefit pension plan covering U.K. employees was transferred to the buyer. See Note 4 for further information on this disposition. During the three and nine months ended September 30, 2019, we reclassified $20 million from accumulated other comprehensive income to pension assets upon remeasurement of the plan.

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Reclassifications Out of Accumulated Other Comprehensive Income (Loss)

9 Months Ended

Sep. 30, 2020

Equity [Abstract]

Reclassifications Out of Accumulated Other Comprehensive Income (Loss)

Reclassifications Out of Accumulated Other Comprehensive Income (Loss)

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2020		2019		2020		2019		Income Statement Line
Postretirement and postemployment plans
Amortization of prior service credit	$	5	$	6	$	18	$	19
Amortization of actuarial loss	(2)		(3)		(8)		(7)
Net settlement loss	(9)		—		(25)		(2)
Net curtailment gain	—		—		17		—
	(6)		3		2		10		Other net periodic benefit (costs) credits
Other
U.K. pension plan transferred to buyer (a)(b)	—		83		—		83
Foreign currency translation adjustment related to sale of U.K. business (b)	—		30		—		30
Income taxes related to the sale of U.K. business (b)	—		(46)		—		(46)
	—		67		—		67		Net gain on disposal of assets
Total reclassifications to expense, net of tax (c)	$	(6)	$	70	$	2	$	77	Net income (loss)

(a)See Note 20 for detail on the U.K. pension plan.

(b)See Note 4 for detail on the U.K. disposition.

(c)During 2020 and 2019 we had a full valuation allowance on net federal deferred tax assets in the U.S. and as such, there is no tax impact to our postretirement and postemployment plans other than on the sale of the U.K. business.

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Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2020

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

Supplemental Cash Flow Information

	Nine Months Ended September 30,
(In millions)	2020		2019
Included in operating activities:
Interest paid, net of amounts capitalized	$	175	$	177
Income taxes paid to (received from) taxing authorities, net of refunds (a)	(50)		67
Noncash investing activities:
Increase (decrease) in asset retirement costs	$	(5)	$	40
Asset retirement obligations assumed by buyer (b)	—		1,082

(a)The nine months ended September 30, 2020 and 2019 includes $94 million and $89 million, respectively, related to tax refunds.

(b)In 2019, we closed on the sale of our working interest in the Droshky field (Gulf of Mexico), the sale of our non-operated interest in the Atrush block in Kurdistan and the sale of our U.K. business.

    Other noncash investing activities include accrued capital expenditures for the nine months ended September 30, 2020 and 2019 of $81 million and $302 million, respectively.

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Equity Method Investments

9 Months Ended

Sep. 30, 2020

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments

Equity Method Investments

During the periods ended September 30, 2020 and December 31, 2019 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% noncontrolling interest. AMPCO is engaged in methanol production activity.

Our equity method investments are summarized in the following table:

(In millions)	Ownership as of September 30, 2020	September 30, 2020		December 31, 2019
EGHoldings	60%	$	119	$	310
Alba Plant LLC	52%	179		163
AMPCO	45%	169		190
Total		$	467	$	663

During the nine months ended September 30, 2020, we recorded impairments of $170 million to an investment in an equity method investee, which was reflected in income (loss) from equity method investments in our consolidated statements of income. See Note 11 to the consolidated financial statements for further information on the equity method investee impairment.

Summarized financial information for equity method investees is as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2020		2019		2020		2019
Income data:
Revenues and other income	$	140	$	184	$	423	$	637
Income (loss) from operations	19		61		(21)		192
Net income (loss)	12		45		(27)		140

Revenues from related parties were $9 million and $29 million, respectively, for the three and nine months ended September 30, 2020 and $11 million and $32 million, respectively, for the three and nine months ended September 30, 2019 with the majority related to EGHoldings in all periods.

Current receivables from related parties at September 30, 2020 were $28 million with the majority related to EGHoldings and $28 million at December 31, 2019 with the majority related EGHoldings and Alba Plant LLC. Payables to related parties at September 30, 2020 and December 31, 2019 were $13 million and $11 million, respectively, with the majority related to Alba Plant LLC in both periods.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2020

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

In the second quarter of 2019, Marathon E.G. Production Limited (“MEGPL”), a consolidated and wholly-owned subsidiary, signed a series of agreements to process third-party Alen Unit gas through existing infrastructure located in Punta Europa, E.G. Our equity method investee, Alba Plant LLC, is also a party to some of the agreements. These agreements contain clauses that require MEGPL to indemnify the owners of the Alen Unit against injury to Alba Plant LLC’s personnel and damage to or loss of Alba Plant LLC’s automobiles, as well as third party claims caused by Alba Plant and certain environmental liabilities arising from certain hydrocarbons in the custody of Alba Plant LLC. Pursuant to these agreements, MEGPL agreed to indemnify third party property or events, including environmental liabilities, injury to Alba Plant LLC’s personnel, and damage to or loss of Alba Plant LLC’s automobiles. At this time, we cannot reasonably estimate this obligation as we do not have any history of prior indemnification claims, and thus, we do not have any history of environmental discharge or contamination. Therefore, we have not recorded a liability with respect to these indemnities since the amount of potential future payments under these indemnification clauses is not determinable.

The agreements to process the third-party Alen Unit gas required the execution of third-party guarantees by Marathon Oil Corporation in favor of the Alen Unit’s owners. Two separate guarantees were executed during the second quarter of 2020; one for a maximum of $91 million pertaining to the payment obligations of Equatorial Guinea LNG Operations, S.A. and another for a maximum of $25 million pertaining to the payment obligations of Alba Plant LLC.  Payment by us would be required if either of those entities fails to honor its payment obligations pursuant to the relevant agreements with the owners of the Alen Unit. Certain owners of the Alen Unit, or their affiliates, are also direct or indirect shareholders in Equatorial Guinea LNG Operations, S.A. and Alba Plant LLC. Each guarantee expires no later than December 31, 2027. We measured these guarantees at fair value using the net present value of premium payments we expect to receive from our investees. Our liability for these guarantees was $4 million as of September 30, 2020, with a corresponding receivable from our investees. Each of Equatorial Guinea LNG Operations, S.A. and Equatorial Guinea LNG Train 1, S.A. provided us with a pledge of its receivables as recourse against any payments we may make under the guaranty of Equatorial Guinea LNG Operations, S.A.’s performance.

Various groups, including the State of North Dakota and three Indian tribes represented by the Bureau of Indian Affairs, have been involved in a dispute regarding the ownership of certain lands underlying the Missouri River and Little Missouri River.  As a result, as of September 30, 2020, we have a $103 million current liability in suspended royalty and working interest revenue, including interest, and have a long-term receivable of $23 million for capital and expenses.

In December 2019, we received a Notice of Violation from the North Dakota Department of Environmental Quality and a verbal notice of enforcement in January 2020 from the North Dakota Industrial Commission, related to a release of produced water in North Dakota. In January 2020, we received a Notice of Violation from the EPA related to the Clean Air Act. Each enforcement action will likely result in monetary sanctions in excess of $100,000; however, we do not believe these enforcement actions would have a material adverse effect on our consolidated financial position, results of operations or cash flow.

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. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance.

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Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2020

Organization, Consolidation and Presentation of Financial Statements [Abstract]

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 2019 Annual Report on Form 10-K. The results of operations for the third quarter and first nine months of 2020 are not necessarily indicative of the results to be expected for the full year.

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Income (loss) and Dividends per Common Share (Tables)

9 Months Ended

Sep. 30, 2020

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

The per share calculations below exclude 6 million of stock options for each of the three and nine months ended September 30, 2020 and 6 million and 5 million of stock options for the three and nine months ended September 30, 2019 that were antidilutive.

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions, except per share data)	2020		2019		2020		2019
Net income (loss)	$	(317)	$	165	$	(1,113)	$	500
Weighted average common shares outstanding	790		802		792		813
Effect of dilutive securities	—		1		—		—
Weighted average common shares, diluted	790		803		792		813
Net income (loss) per share:
Basic	$	(0.40)	$	0.21	$	(1.41)	$	0.62
Diluted	$	(0.40)	$	0.21	$	(1.41)	$	0.62
Dividends per share	$	—	$	0.05	$	0.05	$	0.15

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Revenues (Tables)

9 Months Ended

Sep. 30, 2020

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 for the three and nine months ended September 30 as follows:

United States

	Three Months Ended September 30, 2020
(In millions)	Eagle Ford		Bakken		Oklahoma		Northern Delaware		Other U.S.		Total
Crude oil and condensate	$	190	$	230	$	65	$	53	$	14	$	552
Natural gas liquids	22		15		28		7		1		73
Natural gas	18		9		33		6		3		69
Other	1		—		—		—		27		28
Revenues from contracts with customers	$	231	$	254	$	126	$	66	$	45	$	722

	Three Months Ended September 30, 2019
(In millions)	Eagle Ford		Bakken		Oklahoma		Northern Delaware		Other U.S.		Total
Crude oil and condensate	$	336	$	452	$	116	$	88	$	25	$	1,017
Natural gas liquids	23		6		28		5		2		64
Natural gas	28		8		37		3		5		81
Other	1		—		—		—		9		10
Revenues from contracts with customers	$	388	$	466	$	181	$	96	$	41	$	1,172

	Nine Months Ended September 30, 2020
(In millions)	Eagle Ford		Bakken		Oklahoma		Northern Delaware		Other U.S.		Total
Crude oil and condensate	$	639	$	707	$	181	$	160	$	54	$	1,741
Natural gas liquids	53		28		62		14		4		161
Natural gas	62		22		86		13		7		190
Other	4		—		—		—		58		62
Revenues from contracts with customers	$	758	$	757	$	329	$	187	$	123	$	2,154

	Nine Months Ended September 30, 2019
(In millions)	Eagle Ford		Bakken		Oklahoma		Northern Delaware		Other U.S.		Total
Crude oil and condensate	$	1,004	$	1,277	$	304	$	229	$	83	$	2,897
Natural gas liquids	88		31		81		20		5		225
Natural gas	94		26		118		10		15		263
Other	4		—		—		—		45		49
Revenues from contracts with customers	$	1,190	$	1,334	$	503	$	259	$	148	$	3,434

International

	Three Months Ended September 30, 2020
(In millions)	E.G.
Crude oil and condensate	$	31
Natural gas liquids	1
Natural gas	7
Other	—
Revenues from contracts with customers	$	39

	Three Months Ended September 30, 2019
(In millions)	E.G.
Crude oil and condensate	$	67
Natural gas liquids	1
Natural gas	8
Other	1
Revenues from contracts with customers	$	77

	Nine Months Ended September 30, 2020
(In millions)	E.G.
Crude oil and condensate	$	96
Natural gas liquids	3
Natural gas	22
Revenues from contracts with customers	$	121

	Nine Months Ended September 30, 2019
(In millions)	E.G.		U.K.		Other Int’l		Total
Crude oil and condensate	$	215	$	107	$	19	$	341
Natural gas liquids	3		1		—		4
Natural gas	24		12		—		36
Other	1		14		—		15
Revenues from contracts with customers	$	243	$	134	$	19	$	396

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2020

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

	Three Months Ended September 30, 2020
(In millions)	U.S.		Int’l		Not Allocated to Segments			Total
Revenues from contracts with customers	$	722	$	39	$	—		$	761
Net gain (loss) on commodity derivatives	35		—		(36)		(b)	(1)
Income (loss) from equity method investments	—		8		(18)			(10)
Net gain on disposal of assets	—		—		1			1
Other income	1		1		1			3
Less costs and expenses:
Production	118		11		—			129
Shipping, handling and other operating	154		1		28			183
Exploration	21		—		6			27
Depreciation, depletion and amortization	530		19		5			554
Impairments	—		—		1			1
Taxes other than income	48		—		1			49
General and administrative	25		3		25			53
Net interest and other	—		—		62			62
Other net periodic benefit costs	—		—		6		(c)	6
Income tax provision (benefit)	(3)		6		4			7
Segment income (loss)	$	(135)	$	8	$	(190)		$	(317)
Total assets	$	16,396	$	1,104	$	1,163		$	18,663
Capital expenditures(a)	$	176	$	—	$	1		$	177

(a)Includes accruals.

(b)Unrealized loss on commodity derivative instruments (See Note 15).

(c)Includes pension settlement loss of $9 million (See Note 20).

	Three Months Ended September 30, 2019
(In millions)	U.S.		Int’l		Not Allocated to Segments			Total
Revenues from contracts with customers	$	1,172	$	77	$	—		$	1,249
Net gain on commodity derivatives	14		—		33		(b)	47
Income from equity method investments	—		21		—			21
Net gain on disposal of assets	—		—		22		(c)	22
Other income	3		2		1			6
Less costs and expenses:
Production	147		16		—			163
Shipping, handling and other operating	137		1		—			138
Exploration	22		—		—			22
Depreciation, depletion and amortization	589		25		8			622
Taxes other than income	80		—		1			81
General and administrative	34		5		43			82
Net interest and other	—		—		64			64
Other net periodic benefit credit	—		—		(2)			(2)
Income tax provision	—		10		—			10
Segment income (loss)	$	180	$	43	$	(58)		$	165
Total assets	$	17,722	$	2,003	$	648		$	20,373
Capital expenditures(a)	$	667	$	1	$	7		$	675

(a)Includes accruals.

(b)Unrealized gain on commodity derivative instruments (See Note 15).

(c)Primarily related to the sale of our U.K. business (see Note 4).

	Nine Months Ended September 30, 2020
(In millions)	U.S.		Int’l		Not Allocated to Segments			Total
Revenues from contracts with customers	$	2,154	$	121	$	—		$	2,275
Net gain on commodity derivatives	92		—		39		(b)	131
Loss from equity method investments	—		(4)		(170)		(c)	(174)
Net gain on disposal of assets	—		—		8			8
Other income	8		5		3			16
Less costs and expenses:
Production	375		43		—			418
Shipping, handling and other operating	385		5		42			432
Exploration	75		—		6			81
Depreciation, depletion and amortization	1,716		62		17			1,795
Impairments	—		—		98		(d)	98
Taxes other than income	144		—		1			145
General and administrative	89		10		118		(e)	217
Net interest and other	—		—		195			195
Other net periodic benefit credit	—		—		(1)		(f)	(1)
Income tax provision (benefit)	(10)		1		(2)			(11)
Segment income (loss)	$	(520)	$	1	$	(594)		$	(1,113)
Total assets	$	16,396	$	1,104	$	1,163		$	18,663
Capital expenditures(a)	$	874	$	—	$	10		$	884

(a)Includes accruals.

(b)Unrealized gain on commodity derivative instruments (See Note 15).

(c)Partial impairment of investment in equity method investee (See Note 23).

(d)Includes the full impairment of the International reporting unit goodwill of $95 million (See Note 14).

(e)Includes severance expenses associated with workforce reductions of $15 million.

(f)Includes pension settlement loss of $25 million and pension curtailment gain of $17 million (See Note 20).

	Nine Months Ended September 30, 2019
(In millions)	U.S.		Int’l		Not Allocated to Segments			Total
Revenue from contracts with customers	$	3,434	$	396	$	—		$	3,830
Net gain (loss) on commodity derivatives	41		—		(69)		(b)	(28)
Income from equity method investments	—		63		—			63
Net gain on disposal of assets	—		—		56		(c)	56
Other income	8		7		39		(d)	54
Less costs and expenses:
Production	433		112		(2)			543
Shipping, handling and other operating	424		24		14			462
Exploration	107		—		—			107
Depreciation, depletion and amortization	1,664		97		20			1,781
Impairments	—		—		24		(e)	24
Taxes other than income	233		—		(1)			232
General and administrative	94		20		149			263
Net interest and other	—		—		177			177
Other net periodic benefit credit	—		(3)		(6)			(9)
Income tax provision (benefit)	1		16		(122)		(f)	(105)
Segment income (loss)	$	527	$	200	$	(227)		$	500
Total assets	$	17,722	$	2,003	$	648		$	20,373
Capital expenditures(a)	$	1,959	$	16	$	15		$	1,990

(a)Includes accruals.

(b)Unrealized loss on commodity derivative instruments (See Note 15).

(c)Primarily related to the sale of our working interest in the Droshky field (Gulf of Mexico) and the sale of our U.K. business (See Note 4).

(d)Primarily related to the indemnification of certain tax liabilities in connection with the 2010-2011 Federal Tax Audit.

(e)Primarily as a result of anticipated sales of certain non-core proved properties in our International and United States segments.

(f)Primarily relates to the settlement of the 2010-2011 Federal Tax Audit (See Note 7).

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2020

Income Tax Disclosure [Abstract]

Effective Income Tax Rate

For the three and nine months ended September 30, 2020 and 2019, our effective income tax rates were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Effective income tax rate(a)	(2)	%	6	%	1	%	(27)	%

(a)In all periods presented, we maintained our valuation allowance on our net federal deferred tax assets in the U.S.

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Credit Losses (Tables)

9 Months Ended

Sep. 30, 2020

Credit Loss [Abstract]

Changes in Allowance For Doubtful Account Balance

Changes in the allowance for doubtful accounts balance for the nine months ended were as follows:    

(In millions)	September 30, 2020
Beginning balance as of January 1	$	11
Cumulative-effect adjustment	12
Current period provision(a)	22
Current period write offs	(12)
Recoveries of amounts previously reserved	(8)
Ending balance as of September 30	$	25

(a)For the nine months ended September 30, 2020, the current period provision increased by $10 million in joint interest receivables and $12 million in trade receivables.

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Inventories (Tables)

9 Months Ended

Sep. 30, 2020

Inventory Disclosure [Abstract]

Schedule of Inventory, Current

(In millions)	September 30, 2020		December 31, 2019
Crude oil and natural gas	$	11	$	10
Supplies and other items	66		62
Inventories	$	77	$	72

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Property, Plant and Equipment (Tables)

9 Months Ended

Sep. 30, 2020

Property, Plant and Equipment [Abstract]

Schedule of Property, Plant and Equipment

(In millions)	September 30, 2020		December 31, 2019
United States	$	15,533	$	16,427
International	424		493
Corporate	72		80
Net property, plant and equipment	$	16,029	$	17,000

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Impairments (Tables)

9 Months Ended

Sep. 30, 2020

Impairment Expense [Abstract]

Fair Value Measurements, Nonrecurring

The following table summarizes impairment charges of proved properties, goodwill and equity method investments and their corresponding fair values.

	Three Months Ended September 30,
	2020				2019
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	—	$	1	$	—	$	—
Equity method investment	$	23	$	18	N/A		$	—

	Nine Months Ended September 30,
	2020				2019
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	—	$	3	$	56	$	24
Goodwill	$	—	$	95	N/A		$	—
Equity method investment	$	119	$	170	N/A		$	—

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2020

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Changes in Asset Retirement Obligations

Asset retirement obligations primarily consist of estimated costs to remove, dismantle and restore land or seabed at the end of oil and gas production operations. Changes in asset retirement obligations for the nine months ended September 30 were as follows:

	September 30,
(In millions)	2020		2019
Beginning balance as of January 1	$	255	$	1,145
Incurred liabilities, including acquisitions	3		25
Settled liabilities, including dispositions	(11)		(1,106)
Accretion expense (included in depreciation, depletion and amortization)	9		29
Revisions of estimates	(8)		15
Held for sale	—		108
Ending balance as of September 30	$	248	$	216

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Leases (Tables)

9 Months Ended

Sep. 30, 2020

Leases [Abstract]

Supplemental Balance Sheet Information

Supplemental balance sheet information related to leases was as follows:

(In millions)		September 30, 2020
Operating Leases:	Balance Sheet Location:
Right-of-use asset	Other noncurrent assets	$	137
Current portion of long-term lease liability	Other current liabilities	$	79
Long-term lease liability	Deferred credits and other liabilities	$	61

Operating Lease, Undiscounted Cash Flows to be Received

The undiscounted cash flows to be received under this lease agreement are summarized below.

(In millions)	Operating Lease Future Cash Receipts
2020	$	2
2021	6
2022	6
2023	6
2024	6
Thereafter	60
Total undiscounted cash flows	$	86

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Goodwill (Tables)

9 Months Ended

Sep. 30, 2020

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill Rollforward

	September 30,
(In millions)	2020		2019
Beginning balance as of January 1, gross	$	95	$	97
Less: accumulated impairments	—		—
Beginning balance, net	95		97
Dispositions	—		(2)
Impairment	(95)		—
Ending balance as of September 30, net	$	—	$	95

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Derivatives (Tables)

9 Months Ended

Sep. 30, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments in the Consolidated Balance Sheets

The following tables present the gross fair values of derivative instruments and the reported net amounts along with where they appear on the consolidated balance sheets.

	September 30, 2020
(In millions)	Asset		Liability		Net Asset (Liability)		Balance Sheet Location
Not Designated as Hedges
Commodity	$	59	$	14	$	45	Other current assets
Commodity	—		2		(2)		Deferred credits and other liabilities
Interest Rate	1		—		1		Other noncurrent assets
Interest Rate	—		3		(3)		Deferred credits and other liabilities
Total Not Designated as Hedges	$	60	$	19	$	41
Cash Flow Hedges
Interest Rate	$	9	$	—	$	9	Other noncurrent assets
Interest Rate	—		19		(19)		Deferred credits and other liabilities
Total Designated Hedges	$	9	$	19	$	(10)
Total	$	69	$	38	$	31

	December 31, 2019
(In millions)	Asset		Liability		Net Asset (Liability)		Balance Sheet Location
Not Designated as Hedges
Commodity	$	9	$	1	$	8	Other current assets
Commodity	1		—		1		Other noncurrent assets
Commodity	—		5		(5)		Other current liabilities
Total Not Designated as Hedges	$	10	$	6	$	4
Cash Flow Hedges
Interest Rate	$	2	$	—	$	2	Other noncurrent assets
Total Designated Hedges	$	2	$	—	$	2
Total	$	12	$	6	$	6

The mark-to-market impact and settlement of our commodity derivative instruments appears in the table below and is reflected in net gain (loss) on commodity derivatives in the consolidated statements of income.

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2020		2019		2020		2019
Mark-to-market gain (loss)	$	(36)	$	33	$	39	$	(69)
Net settlements of commodity derivative instruments	$	35	$	14	$	92	$	41

Schedule of Notional Amounts of Outstanding Derivative Positions

The following table sets forth outstanding derivative contracts as of September 30, 2020, and the weighted average prices for those contracts:

	2020		2021		2021
	Fourth Quarter		First Half		Second Half
Crude Oil
NYMEX WTI Three-Way Collars
Volume (Bbls/day)	80,000		—		—
Weighted average price per Bbl:
Ceiling	$	64.40	$	—	$	—
Floor	$	55.00	$	—	$	—
Sold put	$	48.00	$	—	$	—
NYMEX WTI Two-Way Collars
Volume (Bbls/day)	20,000		10,000		10,000
Weighted average price per Bbl:
Ceiling	$	46.83	$	52.37	$	52.37
Floor	$	37.00	$	35.00	$	35.00
Basis Swaps - NYMEX WTI / Argus WTI Midland (a)
Volume (Bbls/day)	15,000		—		—
Weighted average price per Bbl	$	(0.94)	$	—	$	—
Basis Swaps - NYMEX WTI / ICE Brent (b)
Volume (Bbls/day)	5,000		1,630		—
Weighted average price per Bbl	$	(7.24)	$	(7.24)	$	—
NYMEX Roll Basis Swaps
Volume (Bbls/day)	30,000		—		—
Weighted average price per Bbl	$	(0.81)	$	—	$	—
Natural Gas
Henry Hub (“HH”) Two-Way Collars
Volume (MMBtu/day)	250,000		175,000		150,000
Weighted average price per MMBtu:
Ceiling	$	2.82	$	3.10	$	3.03
Floor	$	2.25	$	2.46	$	2.43
Basis Swaps - WAHA / HH (c)
Volume (MMBtu/day)	10,000		—		—
Weighted average price per MMBtu	$	(0.37)	$	—	$	—
NGL
Fixed Price Ethane Swaps (d)
Volume (Bbls/day)	10,000		—		—
Weighted average price per Bbl	$	8.78	$	—	$	—

(a)The basis differential price is indexed against Argus WTI Midland and NYMEX WTI.

(b)The basis differential price is indexed against Intercontinental Exchange (“ICE”) Brent and NYMEX WTI.

(c)The basis differential price is indexed against Waha and NYMEX Henry Hub.

(d)The fixed price ethane swap is priced at OPIS Mont Belvieu Purity Ethane.

The following table sets forth outstanding derivative contracts entered into between October 1 and November 3, 2020, and the weighted average prices for those contracts:

	2021		2021
	First Half		Second Half
Crude Oil
Basis Swaps - NYMEX WTI / UHC (a)
Volume (Bbls/day)	14,000		—
Weighted average price per Bbl	$	(1.80)	$	—
Natural Gas
HH Two-Way Collars
Volume (MMBtu/day)	50,000		50,000
Weighted average price per MMBtu:
Ceiling	$	3.13	$	3.13
Floor	$	2.70	$	2.70
HH Fixed Price Swaps
Volume (MMBtu/day)	50,000		50,000
Weighted average price per MMBtu	$	2.88	$	2.88

(a)The basis differential price is indexed against U.S. Sweet Clearbrook (“UHC”) and NYMEX WTI.

Schedule of Interest Rate Swap Agreement

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

	September 30, 2020				December 31, 2019
Maturity Date	Aggregate Notional Amount (in millions)		Weighted Average, LIBOR		Aggregate Notional Amount (in millions)		Weighted Average, LIBOR
November 1, 2022	$	500	0.99	%	$	—	—	%

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

	Three Months Ended September 30,		Nine Months Ended September 30,
(In millions)	2020		2020
Interest Rate Swaps
Beginning balance	$	(7)	$	—
Change in fair value recognized in other comprehensive income (loss)	5		(2)
Ending balance	$	(2)	$	(2)

The following table presents, by maturity date, information about our interest rate swap agreements, including the weighted average LIBOR-based, fixed rate.

	September 30, 2020				December 31, 2019
Maturity Date	Aggregate Notional Amount (in millions)		Weighted Average, LIBOR		Aggregate Notional Amount (in millions)		Weighted Average, LIBOR
June 1, 2025	$	350	0.95	%	$	—	—	%
September 9, 2026	$	320	1.51	%	$	320	1.51	%

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2020

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of September 30, 2020 and December 31, 2019 by hierarchy level.

	September 30, 2020
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity(a)	$	3	$	40	$	—	$	43
Interest rate - not designated as cash flow hedges	—		1		—		1
Interest rate - designated as cash flow hedges	—		9		—		9
Derivative instruments, assets	$	3	$	50	$	—	$	53
Derivative instruments, liabilities
Interest rate - not designated as cash flow hedges	$	—	$	(3)	$	—	$	(3)
Interest rate - designated as cash flow hedges	—		(19)		—		(19)
Derivative instruments, liabilities	$	—	$	(22)	$	—	$	(22)
Total	$	3	$	28	$	—	$	31

	December 31, 2019
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity(a)	$	—	$	7	$	—	$	7
Interest rate - designated as cash flow hedges	—		2		—		2
Derivative instruments, assets	$	—	$	9	$	—	$	9
Derivative instruments, liabilities
Commodity(a)	$	(3)	$	—	$	—	$	(3)
Derivative instruments, liabilities	$	(3)	$	—	$	—	$	(3)
Total	$	(3)	$	9	$	—	$	6

(a)Commodity derivative instruments are recorded on a net basis in our consolidated balance sheet. See Note 15.

Fair Value, by Balance Sheet Grouping

The following table summarizes financial instruments, excluding receivables, payables and derivative financial instruments, and their reported fair values by individual balance sheet line item at September 30, 2020 and December 31, 2019.

	September 30, 2020				December 31, 2019
(In millions)	Fair Value		Carrying Amount		Fair Value		Carrying Amount
Financial assets
Current assets	$	4	$	4	$	4	$	4
Other noncurrent assets	35		49		26		38
Total financial assets	$	39	$	53	$	30	$	42
Financial liabilities
Other current liabilities	$	62	$	99	$	62	$	90
Long-term debt, including current portion(a)	6,044		5,931		6,174		5,529
Deferred credits and other liabilities	105		84		99		86
Total financial liabilities	$	6,211	$	6,114	$	6,335	$	5,705

(a)Excludes debt issuance costs.

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Debt (Tables)

9 Months Ended

Sep. 30, 2020

Debt Disclosure [Abstract]

Schedule of Debt

The following table further summarizes this transaction.

Sub-Series B Bonds	Par Amount	Interest Rate	Mandatory Purchase Date	Maturity Date
Sub-series B-1 Bonds	$200 million	2.125%	July 1, 2024	June 1, 2037
Sub-series B-2 Bonds	$200 million	2.375%	July 1, 2026	June 1, 2037

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Incentive Based Compensation (Tables)

9 Months Ended

Sep. 30, 2020

Share-based Payment Arrangement [Abstract]

Schedule of Stock Options, Restricted Stock Awards and Restricted Stock Units Activity

The following table presents a summary of activity for the first nine months of 2020: 

	Stock Options				Restricted Stock Awards & Units
	Number of Shares		Weighted Average Exercise Price		Awards	Weighted Average Grant Date Fair Value
Outstanding at December 31, 2019	5,659,731		$	23.55	7,174,386	$	15.88
Granted	1,132,808	(a)	$	10.47	5,337,796	$	8.55
Exercised/Vested	(52,333)		$	7.22	(3,024,561)	$	15.83
Canceled(b)	(662,482)		$	24.66	(1,529,949)	$	11.66
Outstanding at September 30, 2020	6,077,724		$	21.13	7,957,672	$	11.80

(a)The weighted average grant date fair value of stock option awards granted was $3.82 per share.

(b)Included in canceled are forfeitures related to workforce reductions.

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Defined Benefit Postretirement Plans (Tables)

9 Months Ended

Sep. 30, 2020

Retirement Benefits [Abstract]

Schedule of Net Periodic Benefit Cost

The following summarizes the components of net periodic benefit costs (credits):

	Three Months Ended September 30,
	Pension Benefits				Other Benefits
(In millions)	2020		2019(c)		2020		2019
Service cost	$	4	$	5	$	—	$	—
Interest cost	2		3		1		1
Expected return on plan assets	(2)		(3)		—		—
Amortization:
– prior service credit	(1)		(1)		(4)		(5)
– actuarial loss	2		2		—		1
Net settlement loss(a)	9		—		—		—
Net periodic benefit costs (credits)(b)	$	14	$	6	$	(3)	$	(3)

	Nine Months Ended September 30,
	Pension Benefits				Other Benefits
(In millions)	2020		2019(c)		2020		2019
Service cost	$	14	$	14	$	—	$	—
Interest cost	7		17		2		3
Expected return on plan assets	(7)		(19)		—		—
Amortization:
– prior service credit	(5)		(5)		(13)		(14)
– actuarial loss	7		6		1		1
Net settlement loss(a)	25		2		—		—
Net curtailment gain(d)	(3)		—		(14)		—
Net periodic benefit costs (credits)(b)	$	38	$	15	$	(24)	$	(10)

(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.

(b)Net periodic benefit costs (credits) reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.

(c)Includes amounts related to the noncontributory defined benefit pension plan covering U.K. employees, prior to the plan being transferred to the buyer upon sale of the U.K. asset on July 1, 2019.

(d)Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans.

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Reclassifications Out of Accumulated Other Comprehensive Income (Loss) (Tables)

9 Months Ended

Sep. 30, 2020

Equity [Abstract]

Schedule of Amounts Reclassified out of Accumulated Other Comprehensive Income (Loss)

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2020		2019		2020		2019		Income Statement Line
Postretirement and postemployment plans
Amortization of prior service credit	$	5	$	6	$	18	$	19
Amortization of actuarial loss	(2)		(3)		(8)		(7)
Net settlement loss	(9)		—		(25)		(2)
Net curtailment gain	—		—		17		—
	(6)		3		2		10		Other net periodic benefit (costs) credits
Other
U.K. pension plan transferred to buyer (a)(b)	—		83		—		83
Foreign currency translation adjustment related to sale of U.K. business (b)	—		30		—		30
Income taxes related to the sale of U.K. business (b)	—		(46)		—		(46)
	—		67		—		67		Net gain on disposal of assets
Total reclassifications to expense, net of tax (c)	$	(6)	$	70	$	2	$	77	Net income (loss)

(a)See Note 20 for detail on the U.K. pension plan.

(b)See Note 4 for detail on the U.K. disposition.

(c)During 2020 and 2019 we had a full valuation allowance on net federal deferred tax assets in the U.S. and as such, there is no tax impact to our postretirement and postemployment plans other than on the sale of the U.K. business.

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Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2020

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

	Nine Months Ended September 30,
(In millions)	2020		2019
Included in operating activities:
Interest paid, net of amounts capitalized	$	175	$	177
Income taxes paid to (received from) taxing authorities, net of refunds (a)	(50)		67
Noncash investing activities:
Increase (decrease) in asset retirement costs	$	(5)	$	40
Asset retirement obligations assumed by buyer (b)	—		1,082

(a)The nine months ended September 30, 2020 and 2019 includes $94 million and $89 million, respectively, related to tax refunds.

(b)In 2019, we closed on the sale of our working interest in the Droshky field (Gulf of Mexico), the sale of our non-operated interest in the Atrush block in Kurdistan and the sale of our U.K. business.

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Equity Method Investments (Tables)

9 Months Ended

Sep. 30, 2020

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Equity Method Investments

Our equity method investments are summarized in the following table:

(In millions)	Ownership as of September 30, 2020	September 30, 2020		December 31, 2019
EGHoldings	60%	$	119	$	310
Alba Plant LLC	52%	179		163
AMPCO	45%	169		190
Total		$	467	$	663

Summarized financial information for equity method investees is as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2020		2019		2020		2019
Income data:
Revenues and other income	$	140	$	184	$	423	$	637
Income (loss) from operations	19		61		(21)		192
Net income (loss)	12		45		(27)		140

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Accounting Standards (Details) - USD ($) $ in Millions		3 Months Ended
	Jan. 01, 2020	Mar. 31, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative-effect adjustment	$ (12)	$ (31)
Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative-effect adjustment	$ (12)	$ (31)

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Income (loss) and Dividends per Common Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended						9 Months Ended
	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2020	Sep. 30, 2019
Earnings Per Share [Abstract]
Antidilutive securities excluded from computation of earnings per share (in shares)	6			6			6	5
Net income (loss)	$ (317)	$ (750)	$ (46)	$ 165	$ 161	$ 174	$ (1,113)	$ 500
Weighted average common shares outstanding (in shares)	790			802			792	813
Effect of dilutive securities (in shares)	0			1			0	0
Weighted average common shares, diluted (in shares)	790			803			792	813
Net income (loss) per share:
Basic (in dollars per share)	$ (0.40)			$ 0.21			$ (1.41)	$ 0.62
Per diluted share:
Diluted (in dollars per share)	(0.40)			0.21			(1.41)	0.62
Dividends per share (in dollars per share)	$ 0		$ 0.05	$ 0.05	$ 0.05	$ 0.05	$ 0.05	$ 0.15

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Dispositions - International Segment (Details) - USD ($)	1 Months Ended	3 Months Ended		9 Months Ended
	Jul. 31, 2019	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income before income taxes		$ (310,000,000)	$ 175,000,000	$ (1,124,000,000)	$ 395,000,000
International E&P | U.K. Business | Disposal Group, Disposed of by Sale, Not Discontinued Operations
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	$ 95,000,000
Gain on disposition of business			14,000,000
Income before income taxes			0		$ 28,000,000
International E&P | Atrush Block in Kurdistan | Disposal Group, Disposed of by Sale, Not Discontinued Operations
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			$ 63,000,000
Percentage of oil and gas property disposed			15.00%

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Revenues - Narrative (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Receivables from contract with customer	$ 502	$ 837

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Revenues - Revenues from Contracts with Customers by Product Type and Geographic Areas (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 761	$ 1,249	$ 2,275	$ 3,830
United States E&P
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	722	1,172	2,154	3,434
United States E&P | Eagle Ford
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	231	388	758	1,190
United States E&P | Bakken
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	254	466	757	1,334
United States E&P | Oklahoma
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	126	181	329	503
United States E&P | Northern Delaware
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	66	96	187	259
United States E&P | Other U.S.
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	45	41	123	148
United States E&P | Crude oil and condensate
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	552	1,017	1,741	2,897
United States E&P | Crude oil and condensate | Eagle Ford
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	190	336	639	1,004
United States E&P | Crude oil and condensate | Bakken
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	230	452	707	1,277
United States E&P | Crude oil and condensate | Oklahoma
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	65	116	181	304
United States E&P | Crude oil and condensate | Northern Delaware
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	53	88	160	229
United States E&P | Crude oil and condensate | Other U.S.
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	14	25	54	83
United States E&P | Natural gas liquids
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	73	64	161	225
United States E&P | Natural gas liquids | Eagle Ford
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	22	23	53	88
United States E&P | Natural gas liquids | Bakken
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	15	6	28	31
United States E&P | Natural gas liquids | Oklahoma
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	28	28	62	81
United States E&P | Natural gas liquids | Northern Delaware
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	7	5	14	20
United States E&P | Natural gas liquids | Other U.S.
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1	2	4	5
United States E&P | Natural gas
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	69	81	190	263
United States E&P | Natural gas | Eagle Ford
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	18	28	62	94
United States E&P | Natural gas | Bakken
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	9	8	22	26
United States E&P | Natural gas | Oklahoma
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	33	37	86	118
United States E&P | Natural gas | Northern Delaware
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	6	3	13	10
United States E&P | Natural gas | Other U.S.
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	3	5	7	15
United States E&P | Other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	28	10	62	49
United States E&P | Other | Eagle Ford
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1	1	4	4
United States E&P | Other | Bakken
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0	0
United States E&P | Other | Oklahoma
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0	0
United States E&P | Other | Northern Delaware
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	0	0	0	0
United States E&P | Other | Other U.S.
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	27	9	58	45
International E&P
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers				396
International E&P | E.G.
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	39	77	121	243
International E&P | U.K.
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers				134
International E&P | Other Int’l
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers				19
International E&P | Crude oil and condensate
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers				341
International E&P | Crude oil and condensate | E.G.
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	31	67	96	215
International E&P | Crude oil and condensate | U.K.
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers				107
International E&P | Crude oil and condensate | Other Int’l
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers				19
International E&P | Natural gas liquids
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers				4
International E&P | Natural gas liquids | E.G.
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	1	1	3	3
International E&P | Natural gas liquids | U.K.
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers				1
International E&P | Natural gas liquids | Other Int’l
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers				0
International E&P | Natural gas
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers				36
International E&P | Natural gas | E.G.
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	7	8	$ 22	24
International E&P | Natural gas | U.K.
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers				12
International E&P | Natural gas | Other Int’l
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers				0
International E&P | Other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers				15
International E&P | Other | E.G.
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 0	$ 1		1
International E&P | Other | U.K.
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers				14
International E&P | Other | Other Int’l
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers				$ 0

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Segment Information (Details) $ in Millions	3 Months Ended						9 Months Ended
	Sep. 30, 2020 USD ($)	Jun. 30, 2020 USD ($)	Mar. 31, 2020 USD ($)	Sep. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)	Mar. 31, 2019 USD ($)	Sep. 30, 2020 USD ($) segment	Sep. 30, 2019 USD ($)	Dec. 31, 2019 USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | segment							2
Revenues from contracts with customers	$ 761			$ 1,249			$ 2,275	$ 3,830
Net gain (loss) on commodity derivatives	(1)			47			131	(28)
Income (loss) from equity method investments	(10)			21			(174)	63
Net gain on disposal of assets	1			22			8	56
Other income	3			6			16	54
Less costs and expenses:
Production	129			163			418	543
Shipping, handling and other operating	183			138			432	462
Exploration	27			22			81	107
Depreciation, depletion and amortization	554			622			1,795	1,781
Impairments	1			0			98	24
Taxes other than income	49			81			145	232
General and administrative	53			82			217	263
Net interest and other	62			64			195	177
Other net periodic benefit costs	6			(2)			(1)	(9)
Income tax provision (benefit)	7			10			(11)	(105)
Net income (loss)	(317)	$ (750)	$ (46)	165	$ 161	$ 174	(1,113)	500
Assets	18,663			20,373			18,663	20,373	$ 20,245
Capital expenditures	177			675			884	1,990
Goodwill impairment loss							95	0
Severance costs							15
Pension Plan
Less costs and expenses:
Other net periodic benefit costs	9			0			25	2
Net curtailment gain							3	0
Not Allocated to Segments
Segment Reporting Information [Line Items]
Revenues from contracts with customers	0			0			0	0
Net gain (loss) on commodity derivatives	(36)			33			39	(69)
Income (loss) from equity method investments	(18)			0			(170)	0
Net gain on disposal of assets	1			22			8	56
Other income	1			1			3	39
Less costs and expenses:
Production	0			0			0	(2)
Shipping, handling and other operating	28			0			42	14
Exploration	6			0			6	0
Depreciation, depletion and amortization	5			8			17	20
Impairments	1						98	24
Taxes other than income	1			1			1	(1)
General and administrative	25			43			118	149
Net interest and other	62			64			195	177
Other net periodic benefit costs	6			(2)			(1)	(6)
Income tax provision (benefit)	4			0			(2)	(122)
Net income (loss)	(190)			(58)			(594)	(227)
Assets	1,163			648			1,163	648
Capital expenditures	1			7			10	15
Not Allocated to Segments | Pension Plan
Less costs and expenses:
Net curtailment gain							17
United States E&P
Segment Reporting Information [Line Items]
Revenues from contracts with customers	722			1,172			2,154	3,434
United States E&P | Operating Segments
Segment Reporting Information [Line Items]
Revenues from contracts with customers	722			1,172			2,154	3,434
Net gain (loss) on commodity derivatives	35			14			92	41
Income (loss) from equity method investments	0			0			0	0
Net gain on disposal of assets	0			0			0	0
Other income	1			3			8	8
Less costs and expenses:
Production	118			147			375	433
Shipping, handling and other operating	154			137			385	424
Exploration	21			22			75	107
Depreciation, depletion and amortization	530			589			1,716	1,664
Impairments	0						0	0
Taxes other than income	48			80			144	233
General and administrative	25			34			89	94
Net interest and other	0			0			0	0
Other net periodic benefit costs	0			0			0	0
Income tax provision (benefit)	(3)			0			(10)	1
Net income (loss)	(135)			180			(520)	527
Assets	16,396			17,722			16,396	17,722
Capital expenditures	176			667			874	1,959
Int'l E&P
Segment Reporting Information [Line Items]
Revenues from contracts with customers								396
Int'l E&P | Operating Segments
Segment Reporting Information [Line Items]
Revenues from contracts with customers	39			77			121	396
Net gain (loss) on commodity derivatives	0			0			0	0
Income (loss) from equity method investments	8			21			(4)	63
Net gain on disposal of assets	0			0			0	0
Other income	1			2			5	7
Less costs and expenses:
Production	11			16			43	112
Shipping, handling and other operating	1			1			5	24
Exploration	0			0			0	0
Depreciation, depletion and amortization	19			25			62	97
Impairments	0						0	0
Taxes other than income	0			0			0	0
General and administrative	3			5			10	20
Net interest and other	0			0			0	0
Other net periodic benefit costs	0			0			0	(3)
Income tax provision (benefit)	6			10			1	16
Net income (loss)	8			43			1	200
Assets	1,104			2,003			1,104	2,003
Capital expenditures	$ 0			$ 1			$ 0	$ 16

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Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Jun. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Income Tax Disclosure [Abstract]
Effective income tax expense (benefit) rate	(2.00%)	6.00%		1.00%	(27.00%)
Tax benefit from settlement			$ 126
Tax benefit from internal restructuring			$ 18
Effective income tax expense (benefit) rate, excluding discrete items					10.00%
Proceeds from income tax refunds	$ 89			$ 94	$ 89

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Credit Losses (Details) $ in Millions	9 Months Ended
	Sep. 30, 2020 USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Beginning balance as of January 1	$ 11
Current period provision	22
Current period write offs	(12)
Recoveries of amounts previously reserved	(8)
Ending balance as of September 30	25
Cumulative-effect adjustment
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Beginning balance as of January 1	12
JIB Receivables
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Current period provision	10
Trade Receivables
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Current period provision	$ 12

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Inventories (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Inventory Disclosure [Abstract]
Crude oil and natural gas	$ 11	$ 10
Supplies and other items	66	62
Inventories	$ 77	$ 72

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Property, Plant and Equipment (Details) - USD ($)	Sep. 30, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	$ 16,029,000,000	$ 17,000,000,000
Exploratory well costs capitalized greater than one year after completion of drilling	0	0
Operating Segments | United States E&P
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	15,533,000,000	16,427,000,000
Operating Segments | International E&P
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	424,000,000	493,000,000
Not Allocated to Segments
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net	$ 72,000,000	$ 80,000,000

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Impairments - Fair Value Measurements, Nonrecurring (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2020	Jun. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairments				$ 98	$ 24
Goodwill	$ 0		$ 95	0	95	$ 95	$ 97
Goodwill impairment loss				95	0
Oil and Gas Properties
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long lived assets held for use, fair value	0		0	0	56
Impairments	1		0	3	24
Goodwill
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Goodwill	0			0
Goodwill impairment loss				95	0
Equity Method Investments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity method investments	23			119
Equity method investment, impairment	$ 18	$ 152	$ 0	$ 170	$ 0

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Impairments - Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
Impairment Expense [Abstract]
Equity method investment, difference between carrying amount and underlying equity	$ 140
Equity method investment, difference between carrying amount and underlying equity, amortization period	6 years 3 months
Goodwill impairment loss	$ 95	$ 0
Impairments	$ 98	$ 24

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Asset Retirement Obligations (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation, beginning balance	$ 255	$ 1,145
Incurred liabilities, including acquisitions	3	25
Settled liabilities, including dispositions	(11)	(1,106)
Accretion expense (included in depreciation, depletion and amortization)	9	29
Revisions of estimates	(8)	15
Held for sale	0	108
Asset retirement obligation, ending balance	248	$ 216
Asset retirement obligation, current	$ 12

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Leases - Supplemental Balance Sheet Information (Details) $ in Millions	Sep. 30, 2020 USD ($)
Leases [Abstract]
Right-of-use asset	$ 137
Current portion of long-term lease liability	79
Long-term lease liability	$ 61
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	us-gaap:OtherAssetsNoncurrent
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:OtherLiabilitiesCurrent
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	mro:Deferredcreditandotherliabilities

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Leases - Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2020	Jul. 31, 2020
Leases [Abstract]
Annual payments to be received	$ 6
Maximum financing available	340	$ 380
Total costs incurred under lease	$ 117
Term of contract	5 years
Finance lease extension term	5 years
Residual value guarantee	89.00%

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Leases - Lease Payments to be Received (Details) $ in Millions	Sep. 30, 2020 USD ($)
Leases [Abstract]
2020	$ 2
2021	6
2022	6
2023	6
2024	6
Thereafter	60
Total undiscounted cash flows	$ 86

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Goodwill (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	$ 0	$ 95	$ 95	$ 97
Goodwill impairment loss	$ 95	$ 0

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Goodwill - Rollforward (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Beginning balance as of January 1, gross			$ 95	$ 97
Less: accumulated impairments			$ 0	$ 0
Beginning balance, net	$ 95	$ 97
Dispositions	0	(2)
Impairment	(95)	0
Ending balance as of September 30, net	$ 0	$ 95

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Derivatives - Schedule of Derivative Instruments in the Consolidated Balance Sheets (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Derivatives, Fair Value [Line Items]
Asset	$ 69	$ 12
Liability	38	6
Net Asset (Liability)	31	6
Not Designated as Hedges
Derivatives, Fair Value [Line Items]
Asset	60	10
Liability	19	6
Net Asset (Liability)	41	4
Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Asset	9	2
Liability	19	0
Net Asset (Liability)	(10)	2
Commodity | Other current assets | Not Designated as Hedges
Derivatives, Fair Value [Line Items]
Asset	59	9
Liability	14	1
Net Asset (Liability)	45	8
Commodity | Deferred credits and other liabilities | Not Designated as Hedges
Derivatives, Fair Value [Line Items]
Asset	0
Liability	2
Net Asset (Liability)	(2)
Commodity | Other noncurrent assets | Not Designated as Hedges
Derivatives, Fair Value [Line Items]
Asset		1
Liability		0
Net Asset (Liability)		1
Commodity | Other current liabilities | Not Designated as Hedges
Derivatives, Fair Value [Line Items]
Asset		0
Liability		5
Net Asset (Liability)		(5)
Interest Rate | Deferred credits and other liabilities | Not Designated as Hedges
Derivatives, Fair Value [Line Items]
Asset	0
Liability	3
Net Asset (Liability)	(3)
Interest Rate | Deferred credits and other liabilities | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Asset	0
Liability	19
Net Asset (Liability)	(19)
Interest Rate | Other noncurrent assets | Not Designated as Hedges
Derivatives, Fair Value [Line Items]
Asset	1
Liability	0
Net Asset (Liability)	1
Interest Rate | Other noncurrent assets | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Asset	9	2
Liability	0	0
Net Asset (Liability)	$ 9	$ 2

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Derivatives - Outstanding Derivative Contracts (Details) - Not Designated as Hedges	Sep. 30, 2020 MMBTU_per_day Bbls_per_day $ / bbl $ / MMBTU
Three-Way Collars - Crude Oil 2020 Q4
Derivative [Line Items]
Derivative, volume | Bbls_per_day	80,000
Derivative, ceiling	64.40
Derivative, floor	55.00
Derivative, sold put	48.00
Three-Way Collars - Crude Oil 2021, First Half
Derivative [Line Items]
Derivative, volume | Bbls_per_day	0
Derivative, ceiling	0
Derivative, floor	0
Derivative, sold put	0
Three-Way Collars - Crude Oil 2021, Second Half
Derivative [Line Items]
Derivative, volume | Bbls_per_day	0
Derivative, ceiling	0
Derivative, floor	0
Derivative, sold put	0
Two-Way Collars - Crude Oil 2020 Q4
Derivative [Line Items]
Derivative, volume | Bbls_per_day	20,000
Derivative, ceiling	46.83
Derivative, floor	37.00
Basis Swaps - Crude Oil 2021, First Half
Derivative [Line Items]
Derivative, volume | Bbls_per_day	10,000
Derivative, ceiling	52.37
Derivative, floor	35.00
Basis Swaps - Crude Oil 2021, Second Half
Derivative [Line Items]
Derivative, volume | Bbls_per_day	10,000
Derivative, ceiling	52.37
Derivative, floor	35.00
Midland Basis Swaps - Crude Oil 2020 Q4
Derivative [Line Items]
Derivative, volume | Bbls_per_day	15,000
Midland Basis Swaps - Crude Oil 2020 Q4 | Long
Derivative [Line Items]
Derivative, weighted average price	0.94
Midland Basis Swaps - Crude Oil 2021, First Half
Derivative [Line Items]
Derivative, volume | Bbls_per_day	0
Midland Basis Swaps - Crude Oil 2021, First Half | Long
Derivative [Line Items]
Derivative, weighted average price	0
Midland Basis Swaps - Crude Oil 2021, Second Half
Derivative [Line Items]
Derivative, volume | Bbls_per_day	0
Midland Basis Swaps - Crude Oil 2021, Second Half | Long
Derivative [Line Items]
Derivative, weighted average price	0
Brent Basis Swaps - Crude Oil 2020 Q4
Derivative [Line Items]
Derivative, volume | Bbls_per_day	5,000
Brent Basis Swaps - Crude Oil 2020 Q4 | Long
Derivative [Line Items]
Derivative, weighted average price	7.24
Brent Basis Swaps - Crude Oil 2021, First Half
Derivative [Line Items]
Derivative, volume | Bbls_per_day	1,630
Brent Basis Swaps - Crude Oil 2021, First Half | Long
Derivative [Line Items]
Derivative, weighted average price	7.24
Brent Basis Swaps - Crude Oil 2021, Second Half
Derivative [Line Items]
Derivative, volume | Bbls_per_day	0
Brent Basis Swaps - Crude Oil 2021, Second Half | Long
Derivative [Line Items]
Derivative, weighted average price	0
NYMEX Roll Basis Swaps - Crude Oil 2020 Q4
Derivative [Line Items]
Derivative, volume | Bbls_per_day	30,000
NYMEX Roll Basis Swaps - Crude Oil 2020 Q4 | Long
Derivative [Line Items]
Derivative, weighted average price	0.81
NYMEX Roll Basis Swaps - Crude Oil 2021, First Half
Derivative [Line Items]
Derivative, volume | Bbls_per_day	0
NYMEX Roll Basis Swaps - Crude Oil 2021, First Half | Long
Derivative [Line Items]
Derivative, weighted average price	0
NYMEX Roll Basis Swaps - Crude Oil 2021, Second Half
Derivative [Line Items]
Derivative, volume | Bbls_per_day	0
NYMEX Roll Basis Swaps - Crude Oil 2021, Second Half | Long
Derivative [Line Items]
Derivative, weighted average price	0
Henry Hub ("HH") Two-Way Collars - Natural Gas 2020 Q4
Derivative [Line Items]
Derivative, volume | MMBTU_per_day	250,000
Derivative, ceiling | $ / MMBTU	2.82
Derivative, floor | $ / MMBTU	2.25
Henry Hub ("HH") Two-Way Collars - Natural Gas 2021, First Half
Derivative [Line Items]
Derivative, volume | MMBTU_per_day	175,000
Derivative, ceiling | $ / MMBTU	3.10
Derivative, floor | $ / MMBTU	2.46
Henry Hub ("HH") Two-Way Collars - Natural Gas 2021, Second Half
Derivative [Line Items]
Derivative, volume | MMBTU_per_day	150,000
Derivative, ceiling | $ / MMBTU	3.03
Derivative, floor | $ / MMBTU	2.43
WAHA/HH Basis Swaps - Natural Gas 2020 Q4
Derivative [Line Items]
Derivative, volume | MMBTU_per_day	10,000
WAHA/HH Basis Swaps - Natural Gas 2020 Q4 | Long
Derivative [Line Items]
Derivative, weighted average price | $ / MMBTU	0.37
WAHA/HH Basis Swaps - Natural Gas 2021, First Half
Derivative [Line Items]
Derivative, volume | MMBTU_per_day	0
WAHA/HH Basis Swaps - Natural Gas 2021, First Half | Long
Derivative [Line Items]
Derivative, weighted average price | $ / MMBTU	0
WAHA/HH Basis Swaps - Natural Gas 2021, Second Half
Derivative [Line Items]
Derivative, volume | MMBTU_per_day	0
WAHA/HH Basis Swaps - Natural Gas 2021, Second Half | Long
Derivative [Line Items]
Derivative, weighted average price | $ / MMBTU	0
Fixed Price Ethane Swaps - NGL 2020 Q4
Derivative [Line Items]
Derivative, volume | Bbls_per_day	10,000
Fixed Price Ethane Swaps - NGL 2020 Q4 | Short
Derivative [Line Items]
Derivative, weighted average price	8.78
Fixed Price Ethane Swaps - NGL 2021, First Half
Derivative [Line Items]
Derivative, volume | Bbls_per_day	0
Fixed Price Ethane Swaps - NGL 2021, First Half | Short
Derivative [Line Items]
Derivative, weighted average price	0
Fixed Price Ethane Swaps - NGL 2021, Second Half
Derivative [Line Items]
Derivative, volume | Bbls_per_day	0
Fixed Price Ethane Swaps - NGL 2021, Second Half | Short
Derivative [Line Items]
Derivative, weighted average price	0

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Derivatives - Subsequent Event Derivative Contracts (Details) - Not Designated as Hedges	Nov. 03, 2020 MMBTU_per_day Bbls_per_day $ / MMBTU	Sep. 30, 2020 MMBTU_per_day Bbls_per_day $ / bbl $ / MMBTU
Basis Swaps - Crude Oil 2021, First Half
Derivative [Line Items]
Derivative, volume | Bbls_per_day		10,000
Derivative, ceiling | $ / bbl		52.37
Derivative, floor | $ / bbl		35.00
Basis Swaps - Crude Oil 2021, First Half | Subsequent Event
Derivative [Line Items]
Derivative, volume | Bbls_per_day	14,000
Basis Swaps - Crude Oil 2021, First Half | Subsequent Event | Long
Derivative [Line Items]
Derivative, weighted average price	1.80
Basis Swaps - Crude Oil 2021, Second Half
Derivative [Line Items]
Derivative, volume | Bbls_per_day		10,000
Derivative, ceiling | $ / bbl		52.37
Derivative, floor | $ / bbl		35.00
Basis Swaps - Crude Oil 2021, Second Half | Subsequent Event
Derivative [Line Items]
Derivative, volume | Bbls_per_day	0
Basis Swaps - Crude Oil 2021, Second Half | Subsequent Event | Long
Derivative [Line Items]
Derivative, weighted average price	0
Henry Hub ("HH") Two-Way Collars - Natural Gas 2021, First Half
Derivative [Line Items]
Derivative, volume | MMBTU_per_day		175,000
Derivative, ceiling		3.10
Derivative, floor		2.46
Henry Hub ("HH") Two-Way Collars - Natural Gas 2021, First Half | Subsequent Event
Derivative [Line Items]
Derivative, volume | MMBTU_per_day	50,000
Derivative, ceiling	3.13
Derivative, floor	2.70
Henry Hub ("HH") Two-Way Collars - Natural Gas 2021, Second Half
Derivative [Line Items]
Derivative, volume | MMBTU_per_day		150,000
Derivative, ceiling		3.03
Derivative, floor		2.43
Henry Hub ("HH") Two-Way Collars - Natural Gas 2021, Second Half | Subsequent Event
Derivative [Line Items]
Derivative, volume | MMBTU_per_day	50,000
Derivative, ceiling	3.13
Derivative, floor	2.70
Fixed Price Swaps - Natural Gas 2021, First Half | Subsequent Event
Derivative [Line Items]
Derivative, volume | MMBTU_per_day	50,000
Fixed Price Swaps - Natural Gas 2021, First Half | Subsequent Event | Short
Derivative [Line Items]
Derivative, weighted average price	2.88
Fixed Price Swaps - Natural Gas 2021, Second Half | Subsequent Event
Derivative [Line Items]
Derivative, volume | MMBTU_per_day	50,000
Fixed Price Swaps - Natural Gas 2021, Second Half | Subsequent Event | Short
Derivative [Line Items]
Derivative, weighted average price	2.88

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Derivatives - Schedule of mark-to-market impact and commodity derivative settlements (Details) - Commodity - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Mark-to-market gain (loss)	$ (36)	$ 33	$ 39	$ (69)
Net settlements of commodity derivative instruments	$ 35	$ 14	$ 92	$ 41

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Derivatives - Narrative (Details) - USD ($)	Sep. 30, 2020	Jun. 30, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Net Asset (Liability)	$ 31,000,000		$ 6,000,000
Interest rate swap gain (loss) to be reclassified during next twelve months	0
Interest Rate
Derivative Instruments, Gain (Loss) [Line Items]
Deferred loss related to interest rate swaps	10,000,000
Interest Rate | Not Designated as Hedges
Derivative Instruments, Gain (Loss) [Line Items]
Net Asset (Liability)	(2,000,000)	$ (7,000,000)	0
Cash Flow Hedges
Derivative Instruments, Gain (Loss) [Line Items]
Net Asset (Liability)	(10,000,000)		2,000,000
Cash Flow Hedges | Interest Rate
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, notional amount			$ 320,000,000
Notes Due 2025 | Cash Flow Hedges | Interest Rate
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, notional amount	$ 350,000,000

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Derivatives - Schedule of Terminated Interest Rate Swap Agreements (Details) - Interest Rate Contract, Maturing November 1, 2022 - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Derivative [Line Items]
Derivative, notional amount	$ 500	$ 0
Weighted average interest rate, LIBOR	0.99%	0.00%

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Derivatives - Rollforward of Interest Rate Swap Balance (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2020
Net Impact Of Derivatives De-Designated As Cash Flow Hedges [Roll Forward]
Beginning balance		$ 6
Ending balance	$ 31	31
Interest Rate | Not Designated as Hedges
Net Impact Of Derivatives De-Designated As Cash Flow Hedges [Roll Forward]
Beginning balance	(7)	0
Change in fair value recognized in other comprehensive income (loss)	5	(2)
Ending balance	$ (2)	$ (2)

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Derivatives - Schedule of Interest Rate Swap Agreements (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Interest Rate Contract, Maturing June 1, 2025
Derivative [Line Items]
Derivative, notional amount	$ 350	$ 0
Weighted average interest rate, LIBOR	0.95%	0.00%
Interest Rate Contract, Maturing September 9, 2026
Derivative [Line Items]
Derivative, notional amount	$ 320	$ 320
Weighted average interest rate, LIBOR	1.51%	1.51%

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Fair Value Measurements - Fair Values - Recurring (Details) - Recurring - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, assets	$ 53	$ 9
Derivative instruments, liabilities	(22)	(3)
Total	31	6
Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, assets	43	7
Derivative instruments, liabilities		(3)
Interest Rate | Not Designated as Hedges
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, assets	1
Derivative instruments, liabilities	(3)
Interest Rate | Designated as Hedging Instrument
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, assets	9	2
Derivative instruments, liabilities	(19)
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, assets	3	0
Derivative instruments, liabilities	0	(3)
Total	3	(3)
Level 1 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, assets	3	0
Derivative instruments, liabilities		(3)
Level 1 | Interest Rate | Not Designated as Hedges
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, assets	0
Derivative instruments, liabilities	0
Level 1 | Interest Rate | Designated as Hedging Instrument
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, assets	0	0
Derivative instruments, liabilities	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, assets	50	9
Derivative instruments, liabilities	(22)	0
Total	28	9
Level 2 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, assets	40	7
Derivative instruments, liabilities		0
Level 2 | Interest Rate | Not Designated as Hedges
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, assets	1
Derivative instruments, liabilities	(3)
Level 2 | Interest Rate | Designated as Hedging Instrument
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, assets	9	2
Derivative instruments, liabilities	(19)
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, assets	0	0
Derivative instruments, liabilities	0	0
Total	0	0
Level 3 | Commodity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, assets	0	0
Derivative instruments, liabilities		0
Level 3 | Interest Rate | Not Designated as Hedges
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, assets	0
Derivative instruments, liabilities	0
Level 3 | Interest Rate | Designated as Hedging Instrument
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments, assets	0	$ 0
Derivative instruments, liabilities	$ 0

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Fair Value Measurements - Fair Values - Financial Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Fair Value
Financial assets
Current assets	$ 4	$ 4
Other noncurrent assets	35	26
Total financial assets	39	30
Financial liabilities
Other current liabilities	62	62
Long-term debt, including current portion	6,044	6,174
Deferred credits and other liabilities	105	99
Total financial liabilities	6,211	6,335
Carrying Amount
Financial assets
Current assets	4	4
Other noncurrent assets	49	38
Total financial assets	53	42
Financial liabilities
Other current liabilities	99	90
Long-term debt, including current portion	5,931	5,529
Deferred credits and other liabilities	84	86
Total financial liabilities	$ 6,114	$ 5,705

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Debt - Revolving Credit Facility (Details) - Revolving Credit Facility	Sep. 30, 2020 USD ($)
Line of Credit Facility [Line Items]
Line of credit, outstanding amount	$ 0
Maximum borrowing capacity	$ 3,000,000,000.0
Covenant, ratio of indebtedness to net capital, maximum	0.65
Ratio of indebtedness to net capital	0.35

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Debt - Debt Remarketing (Details) - USD ($)		9 Months Ended
	Aug. 18, 2020	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2017
Debt Instrument [Line Items]
Borrowings		$ 400,000,000	$ 0
St. John the Baptist Parish, State of Louisiana Revenue Bonds Due 2037
Debt Instrument [Line Items]
Borrowings	$ 400,000,000
Revenue refunding bond				$ 1,000,000,000

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Debt - Schedule of Debt Remarketing (Details)	Aug. 18, 2020 USD ($)
Sub-series B-1 Bonds
Debt Instrument [Line Items]
Par Amount	$ 200,000,000
Interest Rate	0.02125%
Sub-series B-2 Bonds
Debt Instrument [Line Items]
Par Amount	$ 200,000,000
Interest Rate	0.02375%

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Debt - Debt Redemption (Details) - USD ($)	Oct. 01, 2020	Sep. 30, 2020	Sep. 16, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Long-term debt due within one year		$ 500,000,000		$ 0
Aggregate Maximum Tender
Debt Instrument [Line Items]
Long-term debt due within one year		500,000,000
Aggregate Maximum Tender | Subsequent Event
Debt Instrument [Line Items]
Repayments of debt	$ 500,000,000
Senior Unsecured Note Due 2022
Debt Instrument [Line Items]
Outstanding debt		1,000,000,000
Interest rate			2.80%
Long-term debt		$ 500,000,000

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Stockholders' Equity (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended				9 Months Ended
	Mar. 31, 2020	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2020
Equity, Class of Treasury Stock [Line Items]
Shares repurchased	$ 91	$ 30	$ 236	$ 30
Share Repurchase Program
Equity, Class of Treasury Stock [Line Items]
Shares repurchased (in shares)					9
Shares repurchased					$ 85
Stock repurchase program, remaining authorized repurchase amount					$ 1,300

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Incentive Based Compensation - Stock Options, Restricted Stock Awards and Restricted Stock Units (Details)	9 Months Ended
	Sep. 30, 2020 $ / shares shares
Number of Shares
Outstanding, beginning (in shares) | shares	5,659,731
Granted (in shares) | shares	1,132,808
Options Exercised/Vested (in shares) | shares	(52,333)
Canceled (in shares) | shares	(662,482)
Outstanding, ending (in shares) | shares	6,077,724
Weighted Average Exercise Price
Outstanding, beginning (in dollars per share)	$ 23.55
Granted (in dollars per share)	10.47
Options Exercised (in dollars per share)	7.22
Canceled (in dollars per share)	24.66
Outstanding, ending (in dollars per share)	21.13
Weighted Average Grant Date Fair Value
Weighted average grant date fair value (in dollars per share)	$ 3.82
Restricted Stock Awards & Units
Awards
Outstanding, beginning (in shares) | shares	7,174,386
Granted (in shares) | shares	5,337,796
Stock Exercised/Vested (in shares) | shares	(3,024,561)
Canceled (in shares) | shares	(1,529,949)
Outstanding, ending (in shares) | shares	7,957,672
Weighted Average Grant Date Fair Value
Outstanding, beginning (in dollars per share)	$ 15.88
Granted (in dollars per share)	8.55
Stock Vested (in dollars per share)	15.83
Canceled (in dollars per share)	11.66
Outstanding, ending (in dollars per share)	$ 11.80

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Incentive Based Compensation - Stock-based Performance Unit Awards (Details) - Granted Officer - Performance Unit Awards	9 Months Ended
	Sep. 30, 2020 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	1,038,676
Grant date fair value (in dollars per share) | $ / shares	$ 10.55
Outstanding units (in shares)	1,658,088

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Defined Benefit Postretirement Plans (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Amortization:
Net settlement loss	$ 6	$ (2)	$ (1)	$ (9)
Estimated future contributions over the remainder of the current year	7		7
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	4	5	14	14
Interest cost	2	3	7	17
Expected return on plan assets	(2)	(3)	(7)	(19)
Amortization:
– prior service credit	(1)	(1)	(5)	(5)
– actuarial loss	2	2	7	6
Net settlement loss	9	0	25	2
Net curtailment gain			(3)	0
Net periodic benefit costs (credits)	14	6	38	15
Pension Benefits | U.K.
Amortization:
Reclassifications from AOCI upon remeasurement		20		20
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	0	0	0
Interest cost	1	1	2	3
Expected return on plan assets	0	0	0	0
Amortization:
– prior service credit	(4)	(5)	(13)	(14)
– actuarial loss	0	1	1	1
Net settlement loss	0	0	0	0
Net curtailment gain			(14)	0
Net periodic benefit costs (credits)	$ (3)	$ (3)	(24)	$ (10)
Payment for other postretirement benefits			11
Funded Plan
Amortization:
Payment for pension benefits			21
Unfunded Plan
Amortization:
Payment for pension benefits			$ 17

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Reclassifications Out of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	3 Months Ended						9 Months Ended
	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2020	Sep. 30, 2019
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other net periodic benefit (costs) credits	$ (6)			$ 2			$ 1	$ 9
Net gain on disposal of assets	1			22			8	56
Net income (loss)	(317)	$ (750)	$ (46)	165	$ 161	$ 174	(1,113)	500
Amortization of prior service credit | Reclassification out of Accumulated Other Comprehensive Income (Loss)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other net periodic benefit (costs) credits	5			6			18	19
Amortization of actuarial loss | Reclassification out of Accumulated Other Comprehensive Income (Loss)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other net periodic benefit (costs) credits	(2)			(3)			(8)	(7)
Net settlement loss | Reclassification out of Accumulated Other Comprehensive Income (Loss)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other net periodic benefit (costs) credits	(9)			0			(25)	(2)
Net curtailment gain | Reclassification out of Accumulated Other Comprehensive Income (Loss)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other net periodic benefit (costs) credits	0			0			17	0
Postretirement and postemployment plans | Reclassification out of Accumulated Other Comprehensive Income (Loss)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Other net periodic benefit (costs) credits	(6)			3			2	10
Net income (loss)	(6)			70			2	77
U.K. pension plan transferred to buyer (a)(b) | Reclassification out of Accumulated Other Comprehensive Income (Loss)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net gain on disposal of assets	0			83			0	83
Foreign currency translation adjustment related to sale of U.K. business (b) | Reclassification out of Accumulated Other Comprehensive Income (Loss)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net gain on disposal of assets	0			30			0	30
Income taxes related to the sale of U.K. business (b) | Reclassification out of Accumulated Other Comprehensive Income (Loss)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net gain on disposal of assets	0			(46)			0	(46)
Other | Reclassification out of Accumulated Other Comprehensive Income (Loss)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net gain on disposal of assets	$ 0			$ 67			$ 0	$ 67

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2020	Sep. 30, 2019
Included in operating activities:
Interest paid, net of amounts capitalized		$ 175	$ 177
Income taxes paid to (received from) taxing authorities, net of refunds		(50)	67
Noncash investing activities:
Increase (decrease) in asset retirement costs		(5)	40
Asset retirement obligations assumed by buyer		0	1,082
Proceeds from income tax refunds	$ 89	94	89
Capital expenditures incurred but not yet paid		$ 81	$ 302

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Equity Method Investments - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019
Schedule of Equity Method Investments [Line Items]
Revenue from related parties	$ 9	$ 11	$ 29	$ 32
Due from related parties	28		28		$ 28
Due to related parties	$ 13		$ 13		$ 11
EGHoldings
Schedule of Equity Method Investments [Line Items]
Ownership percentage	60.00%		60.00%
Alba Plant LLC
Schedule of Equity Method Investments [Line Items]
Ownership percentage	52.00%		52.00%
AMPCO
Schedule of Equity Method Investments [Line Items]
Ownership percentage	45.00%		45.00%

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Equity Method Investments - Schedule of Equity Method Investments (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 467	$ 663
EGHoldings
Schedule of Equity Method Investments [Line Items]
Ownership percentage	60.00%
Equity method investments	$ 119	310
Alba Plant LLC
Schedule of Equity Method Investments [Line Items]
Ownership percentage	52.00%
Equity method investments	$ 179	163
AMPCO
Schedule of Equity Method Investments [Line Items]
Ownership percentage	45.00%
Equity method investments	$ 169	$ 190

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Equity Method Investments - Summarized Financial Information (Details) - USD ($) $ in Millions	3 Months Ended						9 Months Ended
	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2020	Sep. 30, 2019
Schedule of Equity Method Investments [Line Items]
Revenues and other income	$ 754			$ 1,345			$ 2,256	$ 3,975
Income (loss) from operations	(242)			237			(930)	563
Net income (loss)	(317)	$ (750)	$ (46)	165	$ 161	$ 174	(1,113)	500
Consolidated Equity Method Investments
Schedule of Equity Method Investments [Line Items]
Revenues and other income	140			184			423	637
Income (loss) from operations	19			61			(21)	192
Net income (loss)	$ 12			$ 45			$ (27)	$ 140

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Commitments and Contingencies (Details) - USD ($) $ in Thousands	Sep. 30, 2020	Jan. 31, 2020
Loss Contingencies [Line Items]
Guarantees recorded	$ 4,000
Contingent royalty liability	103,000
Contingent capital and expense receivable, noncurrent	23,000
Estimated minimum monetary sanctions for Clean Air Act enforcement action		$ 100
Performance of Equatorial Guinea LNG Operations, S.A.
Loss Contingencies [Line Items]
Guarantor obligations, maximum exposure	91,000
Performance of Alba Plant LLC.
Loss Contingencies [Line Items]
Guarantor obligations, maximum exposure	$ 25,000