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

June 30, ~~2020~~2021


☐			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

Accelerated filer

Non-accelerated filer

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 ~~789,439,221~~788,398,843 shares of Marathon Oil Corporation common stock outstanding as of July 31, ~~2020.~~2021.

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~~2020 Annual Report on Form 10-K.

Part I – FINANCIAL INFORMATION

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)


		Three Months Ended						Six Months Ended							Three Months Ended				Six Months Ended
		June 30,						June 30,							June 30,				June 30,
(In millions, except per share data)	(In millions, except per share data)	2020		2019		2020		2019		(In millions, except per share data)	2021		2020		2021		2020
Revenues and other income:	Revenues and other income:									Revenues and other income:
Revenues from contracts with customers	Revenues from contracts with customers	$	490	$	1,381	$	1,514	$	2,581	Revenues from contracts with customers	$	1,254	$	490	$	2,431	$	1,514
Net gain (loss) on commodity derivatives	Net gain (loss) on commodity derivatives	(70)		16		132		(75)		Net gain (loss) on commodity derivatives	(166)		(70)		(319)		132
Income (loss) from equity method investments	Income (loss) from equity method investments	(152)		31		(164)		42		Income (loss) from equity method investments	49		(152)		93		(164)
Net gain (loss) on disposal of assets	Net gain (loss) on disposal of assets	(2)		(8)		7		34		Net gain (loss) on disposal of assets	1		(2)		1		7
Other income	Other income	6		13		13		48		Other income	5		6		8		13
Total revenues and other income	Total revenues and other income	272		1,433		1,502		2,630		Total revenues and other income	1,143		272		2,214		1,502
Costs and expenses:	Costs and expenses:									Costs and expenses:
Production	Production	129		193		289		380		Production	126		129		247		289
Shipping, handling and other operating	Shipping, handling and other operating	105		170		249		324		Shipping, handling and other operating	167		105		319		249
Exploration	Exploration	26		26		54		85		Exploration	25		26		46		54
Depreciation, depletion and amortization	Depreciation, depletion and amortization	597		605		1,241		1,159		Depreciation, depletion and amortization	532		597		1,028		1,241
Impairments	Impairments	—		18		97		24		Impairments	46		0		47		97
Taxes other than income	Taxes other than income	30		79		96		151		Taxes other than income	74		30		148		96
General and administrative	General and administrative	88		87		164		181		General and administrative	68		88		157		164
Total costs and expenses	Total costs and expenses	975		1,178		2,190		2,304		Total costs and expenses	1,038		975		1,992		2,190
Income (loss) from operations	Income (loss) from operations	(703)		255		(688)		326		Income (loss) from operations	105		(703)		222		(688)
Net interest and other	Net interest and other	(69)		(64)		(133)		(113)		Net interest and other	(59)		(69)		(72)		(133)
Other net periodic benefit credit		7		2		7		7
Other net periodic benefit (costs) credits										Other net periodic benefit (costs) credits	(1)		7		2		7
Loss on early extinguishment of debt										Loss on early extinguishment of debt	(19)		0		(19)		0
Income (loss) before income taxes	Income (loss) before income taxes	(765)		193		(814)		220		Income (loss) before income taxes	26		(765)		133		(814)
Provision (benefit) for income taxes	Provision (benefit) for income taxes	(15)		32		(18)		(115)		Provision (benefit) for income taxes	10		(15)		20		(18)
Net income (loss)	Net income (loss)	$	(750)	$	161	$	(796)	$	335	Net income (loss)	$	16	$	(750)	$	113	$	(796)
Net income (loss) per share:	Net income (loss) per share:									Net income (loss) per share:
Basic	Basic	$	(0.95)	$	0.20	$	(1.00)	$	0.41	Basic	$	0.02	$	(0.95)	$	0.14	$	(1.00)
Diluted	Diluted	$	(0.95)	$	0.20	$	(1.00)	$	0.41	Diluted	$	0.02	$	(0.95)	$	0.14	$	(1.00)
Weighted average common shares outstanding:	Weighted average common shares outstanding:									Weighted average common shares outstanding:
Basic	Basic	790		813		793		817		Basic	789		790		790		793
Diluted	Diluted	790		814		793		817		Diluted	789		790		791		793

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

MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income (Unaudited)


		Three Months Ended						Six Months Ended							Three Months Ended				Six Months Ended
		June 30,						June 30,							June 30,				June 30,
(In millions)	(In millions)	2020		2019		2020		2019		(In millions)	2021		2020		2021		2020
Net income (loss)	Net income (loss)	$	(750)	$	161	$	(796)	$	335	Net income (loss)	$	16	$	(750)	$	113	$	(796)
Other comprehensive income (loss), net of tax	Other comprehensive income (loss), net of tax									Other comprehensive income (loss), net of tax

Change in actuarial loss and other for postretirement and postemployment plans		(42)		(9)		(42)		(13)

Change in derivative hedges unrecognized loss		(4)		—		(26)		—

Change in actuarial gain (loss) and other for postretirement and postemployment plans										Change in actuarial gain (loss) and other for postretirement and postemployment plans	16		(42)		13		(42)

Change in derivative hedges unrecognized gain (loss)										Change in derivative hedges unrecognized gain (loss)	(21)		(4)		19		(26)
Reclassification of de-designated forward interest rate swaps										Reclassification of de-designated forward interest rate swaps	(30)		0		(28)		0

Other comprehensive loss		(46)		(9)		(68)		(13)
Other comprehensive income (loss)										Other comprehensive income (loss)	(35)		(46)		4		(68)
Comprehensive income (loss)	Comprehensive income (loss)	$	(796)	$	152	$	(864)	$	322	Comprehensive income (loss)	$	(19)	$	(796)	$	117	$	(864)

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)


		June 30,		December 31,			June 30,		December 31,
(In millions, except par value and share amounts)	(In millions, except par value and share amounts)	2020		2019		(In millions, except par value and share amounts)	2021		2020
Assets	Assets					Assets
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	522	$	858	Cash and cash equivalents	$	970	$	742
Receivables, less reserve of $23 and $11		620		1,122
Receivables, less reserve of $19 and $22						Receivables, less reserve of $19 and $22	1,008		747
Inventories	Inventories	77		72		Inventories	78		76
Derivative assets		79		9
Other current assets	Other current assets	107		74		Other current assets	19		47
Total current assets	Total current assets	1,405		2,135		Total current assets	2,075		1,612
Equity method investments	Equity method investments	476		663		Equity method investments	458		447
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $19,216 and $18,003		16,424		17,000
Goodwill		—		95
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $21,364 and $20,358						Property, plant and equipment, less accumulated depreciation, depletion and amortization of $21,364 and $20,358	15,019		15,638

Other noncurrent assets	Other noncurrent assets	262		352		Other noncurrent assets	248		259
Total assets	Total assets	$	18,567	$	20,245	Total assets	$	17,800	$	17,956
Liabilities	Liabilities					Liabilities
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable	Accounts payable	$	696	$	1,307	Accounts payable	$	937	$	837
Payroll and benefits payable	Payroll and benefits payable	76		112		Payroll and benefits payable	49		57
Accrued taxes	Accrued taxes	77		118		Accrued taxes	95		72
Other current liabilities	Other current liabilities	216		208		Other current liabilities	461		247
Long-term debt due within one year						Long-term debt due within one year	33		0
Total current liabilities	Total current liabilities	1,065		1,745		Total current liabilities	1,575		1,213
Long-term debt	Long-term debt	5,503		5,501		Long-term debt	4,875		5,404
Deferred tax liabilities	Deferred tax liabilities	171		186		Deferred tax liabilities	156		163
Defined benefit postretirement plan obligations	Defined benefit postretirement plan obligations	194		183		Defined benefit postretirement plan obligations	151		180
Asset retirement obligations	Asset retirement obligations	242		243		Asset retirement obligations	272		241
Deferred credits and other liabilities	Deferred credits and other liabilities	217		234		Deferred credits and other liabilities	137		194
Total liabilities	Total liabilities	7,392		8,092		Total liabilities	7,166		7,395
Commitments and contingencies	Commitments and contingencies					Commitments and contingencies	0		0
Stockholders’ Equity	Stockholders’ Equity					Stockholders’ Equity
Preferred stock – no shares issued or outstanding (no par value, 26 million shares authorized)		$	—	$	—
Preferred stock – 0 shares issued or outstanding (0 par value, 26 million shares authorized)						Preferred stock – 0 shares issued or outstanding (0 par value, 26 million shares authorized)	$	0	$	0
Common stock:	Common stock:					Common stock:
Issued – 937 million shares (par value $1 per share, 1.925 billion shares authorized at June 30, 2020 and December 31, 2019)		937		937
Held in treasury, at cost – 147 million shares and 141 million shares		(4,087)		(4,089)
Issued – 937 million shares (par value $1 per share, 1.925 billion shares authorized at June 30, 2021 and December 31, 2020)						Issued – 937 million shares (par value $1 per share, 1.925 billion shares authorized at June 30, 2021 and December 31, 2020)	937		937
Held in treasury, at cost – 148 million shares						Held in treasury, at cost – 148 million shares	(4,105)		(4,089)
Additional paid-in capital	Additional paid-in capital	7,143		7,207		Additional paid-in capital	7,201		7,174
Retained earnings	Retained earnings	7,145		7,993		Retained earnings	6,524		6,466
Accumulated other comprehensive income	Accumulated other comprehensive income	37		105		Accumulated other comprehensive income	77		73
Total stockholders’ equity	Total stockholders’ equity	11,175		12,153		Total stockholders’ equity	10,634		10,561
Total liabilities and stockholders’ equity	Total liabilities and stockholders’ equity	$	18,567	$	20,245	Total liabilities and stockholders’ equity	$	17,800	$	17,956

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)


		Six Months Ended							Six Months Ended
		June 30,							June 30,
(In millions)	(In millions)	2020		2019		(In millions)	2021		2020
Increase (decrease) in cash and cash equivalents	Increase (decrease) in cash and cash equivalents					Increase (decrease) in cash and cash equivalents
Operating activities:	Operating activities:					Operating activities:
Net income (loss)	Net income (loss)	$	(796)	$	335	Net income (loss)	$	113	$	(796)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	Adjustments to reconcile net income (loss) to net cash provided by operating activities:					Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	Depreciation, depletion and amortization	1,241		1,159		Depreciation, depletion and amortization	1,028		1,241
Impairments	Impairments	97		24		Impairments	47		97
Exploratory dry well costs and unproved property impairments	Exploratory dry well costs and unproved property impairments	40		69		Exploratory dry well costs and unproved property impairments	39		40
Net gain on disposal of assets	Net gain on disposal of assets	(7)		(34)		Net gain on disposal of assets	(1)		(7)
Loss on early extinguishment of debt						Loss on early extinguishment of debt	19		0
Deferred income taxes	Deferred income taxes	(14)		(33)		Deferred income taxes	(7)		(14)
Net (gain) loss on derivative instruments		(132)		75
Net settlements of derivative instruments		57		27
Unrealized (gain) loss on derivative instruments, net						Unrealized (gain) loss on derivative instruments, net	157		(75)

Pension and other post retirement benefits, net	Pension and other post retirement benefits, net	(31)		(41)		Pension and other post retirement benefits, net	(14)		(31)
Stock-based compensation	Stock-based compensation	28		32		Stock-based compensation	17		28
Equity method investments, net	Equity method investments, net	180		12		Equity method investments, net	(17)		180
Changes in:	Changes in:					Changes in:
Current receivables	Current receivables	489		(95)		Current receivables	(253)		489
Inventories	Inventories	(5)		3		Inventories	(2)		(5)
Current accounts payable and accrued liabilities	Current accounts payable and accrued liabilities	(456)		(158)		Current accounts payable and accrued liabilities	121		(456)
Other current assets and liabilities	Other current assets and liabilities	46		119		Other current assets and liabilities	73		46
All other operating, net	All other operating, net	(27)		(182)		All other operating, net	(43)		(27)
Net cash provided by operating activities	Net cash provided by operating activities	710		1,312		Net cash provided by operating activities	1,277		710
Investing activities:	Investing activities:					Investing activities:
Additions to property, plant and equipment	Additions to property, plant and equipment	(946)		(1,262)		Additions to property, plant and equipment	(483)		(946)
Additions to other assets	Additions to other assets	12		42		Additions to other assets	0		12
Acquisitions, net of cash acquired	Acquisitions, net of cash acquired	3		—		Acquisitions, net of cash acquired	0		3
Disposal of assets, net of cash transferred to the buyer	Disposal of assets, net of cash transferred to the buyer	9		69		Disposal of assets, net of cash transferred to the buyer	15		9
Equity method investments - return of capital	Equity method investments - return of capital	7		49		Equity method investments - return of capital	6		7
All other investing, net	All other investing, net	—		(27)		All other investing, net	(1)		0
Net cash used in investing activities	Net cash used in investing activities	(915)		(1,129)		Net cash used in investing activities	(463)		(915)
Financing activities:	Financing activities:					Financing activities:

Debt repayment						Debt repayment	(500)		0
Debt extinguishment costs						Debt extinguishment costs	(19)		0
Purchases of common stock	Purchases of common stock	(92)		(266)		Purchases of common stock	(9)		(92)
Dividends paid	Dividends paid	(40)		(82)		Dividends paid	(55)		(40)
All other financing, net	All other financing, net	1		(2)		All other financing, net	(3)		1
Net cash used in financing activities	Net cash used in financing activities	(131)		(350)		Net cash used in financing activities	(586)		(131)
Effect of exchange rate on cash and cash equivalents		—		1
Net decrease in cash and cash equivalents		(336)		(166)

Net increase (decrease) in cash and cash equivalents						Net increase (decrease) in cash and cash equivalents	228		(336)
Cash and cash equivalents at beginning of period	Cash and cash equivalents at beginning of period	858		1,462		Cash and cash equivalents at beginning of period	742		858
Cash and cash equivalents at end of period	Cash and cash equivalents at end of period	$	522	$	1,296	Cash and cash equivalents at end of period	$	970	$	522

Reconciliation of cash and cash equivalents
Cash and cash equivalents		$	522	$	961
Cash and cash equivalents included in current assets held for sale		—		335
Total cash and cash equivalents		$	522	$	1,296

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

MARATHON OIL CORPORATION

Consolidated Statements of Stockholders’ Equity (Unaudited)

Total Equity of Marathon Oil Stockholders
(In millions) Preferred
Stock Common
Stock Treasury
Stock Additional
Paid-in
Capital Retained
Earnings Accumulated
Other
Comprehensive
Income (Loss) Total
Equity
Six Months Ended June 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


																	Total Equity of Marathon Oil Stockholders

(In millions)																(In millions)	Preferred Stock		Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total Equity
Six Months Ended June 30, 2020	Six Months Ended June 30, 2020															Six Months Ended June 30, 2020
December 31, 2019 Balance	December 31, 2019 Balance	$	—	$	937	$	(4,089)	$	7,207	$	7,993	$	105	12,153		December 31, 2019 Balance	$	0	$	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
Cumulative-effect adjustment																Cumulative-effect adjustment	—		—		—		—		(12)		—		(12)
Shares issued - stock-based compensation																Shares issued - stock-based compensation	—		—		121		(83)		—		—		38
Shares repurchased	Shares repurchased	—		—		(91)		—		—		—		(91)		Shares repurchased	—		—		(91)		—		—		—		(91)
Stock-based compensation	Stock-based compensation	—		—		—		(22)		—		—		(22)		Stock-based compensation	—		—		—		(22)		—		—		(22)
Net loss		—		—		—		—		(46)		—		(46)
Other comprehensive loss		—		—		—		—		—		(22)		(22)
Net income (loss)																Net income (loss)	—		—		—		—		(46)		—		(46)
Other comprehensive income (loss)																Other comprehensive income (loss)	—		—		—		—		—		(22)		(22)
Dividends paid (per share amount of $0.05)	Dividends paid (per share amount of $0.05)	—		—		—		—		(40)		—		(40)		Dividends paid (per share amount of $0.05)	—		—		—		—		(40)		—		(40)
March 31, 2020 Balance	March 31, 2020 Balance	$	—	$	937	$	(4,059)	$	7,102	$	7,895	$	83	$	11,958	March 31, 2020 Balance	$	0	$	937	$	(4,059)	$	7,102	$	7,895	$	83	$	11,958
Shares issued - stock-based compensation	Shares issued - stock-based compensation	—		—		(28)		20		—		—		(8)		Shares issued - stock-based compensation	—		—		(28)		20		—		—		(8)

Stock-based compensation	Stock-based compensation	—		—		—		21		—		—		21		Stock-based compensation	—		—		—		21		—		—		21
Net loss		—		—		—		—		(750)		—		(750)
Net income (loss)																Net income (loss)	—		—		—		—		(750)		—		(750)
Other comprehensive loss	Other comprehensive loss	—		—		—		—		—		(46)		(46)		Other comprehensive loss	—		—		—		—		—		(46)		(46)

June 30, 2020 Balance	June 30, 2020 Balance	$	—	$	937	$	(4,087)	$	7,143	$	7,145	$	37	$	11,175	June 30, 2020 Balance	$	0	$	937	$	(4,087)	$	7,143	$	7,145	$	37	$	11,175

Six Months Ended June 30, 2021																Six Months Ended June 30, 2021
December 31, 2020 Balance																December 31, 2020 Balance	$	0	$	937	$	(4,089)	$	7,174	$	6,466	$	73	$	10,561

Shares issued - stock based compensation																Shares issued - stock based compensation	—		—		(15)		10		—		—		(5)
Shares repurchased																Shares repurchased	—		—		(9)		—		—		—		(9)
Stock-based compensation																Stock-based compensation	—		—		—		11		—		—		11
Net income (loss)																Net income (loss)	—		—		—		—		97		—		97
Other comprehensive income (loss)																Other comprehensive income (loss)	—		—		—		—		—		39		39
Dividends paid (per share amount of $0.03)																Dividends paid (per share amount of $0.03)	—		—		—		—		(23)		—		(23)
March 31, 2021 Balance																March 31, 2021 Balance	$	0	$	937	$	(4,113)	$	7,195	$	6,540	$	112	$	10,671
Shares issued - stock based compensation																Shares issued - stock based compensation	—		—		8		1		—		—		9
Shares repurchased																Shares repurchased	—		—		0		—		—		—		0
Stock-based compensation																Stock-based compensation	—		—		—		5		—		—		5
Net income (loss)																Net income (loss)	—		—		—		—		16		—		16
Other comprehensive income (loss)																Other comprehensive income (loss)	—		—		—		—		—		(35)		(35)
Dividends paid (per share amount of $0.04)																Dividends paid (per share amount of $0.04)	—		—		—		—		(32)		—		(32)
June 30, 2021 Balance																June 30, 2021 Balance	$	0	$	937	$	(4,105)	$	7,201	$	6,524	$	77	$	10,634

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

1. Basis of Presentation

These consolidated financial statements are unaudited; however, in the opinion of management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported. All such adjustments are of a normal recurring nature unless disclosed otherwise. These consolidated financial statements, including notes, have been prepared in accordance with the applicable rules of the SEC and do not include all of the information and disclosures required by U.S. GAAP for complete financial statements.

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our ~~2019~~2020 Annual Report on Form 10-K. The results of operations for the second quarter and first six months of ~~2020~~2021 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~~No accounting standards ~~update~~were adopted in the second quarter or first six months of 2021 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 throughhad 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~~material impact on ~~credit losses.~~our consolidated financial statements.

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 4 million and 5 million of stock options for each of the three and six months ended June 30, 2021, respectively, and 7 million of stock options for each of the three and six months ended June 30, 2020 ~~and 6 million of stock options for each of the three and six months ended June 30, 2019~~ that were antidilutive.


		Three Months Ended June 30,						Six Months Ended June 30,							Three Months Ended June 30,				Six Months Ended June 30,
(In millions, except per share data)	(In millions, except per share data)	2020		2019		2020		2019		(In millions, except per share data)	2021		2020		2021		2020
Net income (loss)	Net income (loss)	$	(750)	$	161	$	(796)	$	335	Net income (loss)	$	16	$	(750)	$	113	$	(796)

Weighted average common shares outstanding	Weighted average common shares outstanding	790		813		793		817		Weighted average common shares outstanding	789		790		790		793
Effect of dilutive securities	Effect of dilutive securities	—		1		—		—		Effect of dilutive securities	0		0		1		0
Weighted average common shares, diluted	Weighted average common shares, diluted	790		814		793		817		Weighted average common shares, diluted	789		790		791		793
Net income (loss) per share:	Net income (loss) per share:									Net income (loss) per share:
Basic	Basic	$	(0.95)	$	0.20	$	(1.00)	$	0.41	Basic	$	0.02	$	(0.95)	$	0.14	$	(1.00)
Diluted	Diluted	$	(0.95)	$	0.20	$	(1.00)	$	0.41	Diluted	$	0.02	$	(0.95)	$	0.14	$	(1.00)

Dividends per share	Dividends per share	$	—	$	0.05	$	0.05	$	0.10	Dividends per share	$	0.04	$	0	$	0.07	$	0.05

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 approximately $95 million which reflects 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. Our income before income taxes relating to our U.K. business for the three and six months ended June 30, 2019, was $18 million 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.~~

~~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.~~Equatorial Guinea.

As of June 30, ~~2020~~2021 and December 31, ~~2019,~~2020, receivables from contracts with customers, included in receivables, less reserves were ~~$487~~$841 million and ~~$837~~$572 million, respectively.

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

~~United States~~

Three Months Ended June 30, 2020
(In millions) Eagle Ford Bakken Oklahoma Northern Delaware Other U.S. Total
Crude oil and condensate $ 142 $ 147 $ 32 $ 33 $ 7 $ 361
Natural gas liquids 16 3 13 4 1 37
Natural gas 20 5 24 4 1 54
Other 1�� — — — 9 10
Revenues from contracts with customers $ 179 $ 155 $ 69 $ 41 $ 18 $ 462

Three Months Ended June 30, 2019
(In millions) Eagle Ford Bakken Oklahoma Northern Delaware Other U.S. Total
Crude oil and condensate $ 350 $ 453 $ 111 $ 77 $ 30 $ 1,021
Natural gas liquids 30 15 31 7 1 84
Natural gas 32 6 36 1 4 79
Other 1 — — — 15 16
Revenues from contracts with customers $ 413 $ 474 $ 178 $ 85 $ 50 $ 1,200

Six Months Ended June 30, 2020
(In millions) Eagle Ford Bakken Oklahoma Northern Delaware Other U.S. Total
Crude oil and condensate $ 449 $ 477 $ 116 $ 107 $ 40 $ 1,189
Natural gas liquids 31 13 34 7 3 88
Natural gas 44 13 53 7 4 121
Other 3 — — — 31 34
Revenues from contracts with customers $ 527 $ 503 $ 203 $ 121 $ 78 $ 1,432

Six Months Ended June 30, 2019
(In millions) Eagle Ford Bakken Oklahoma Northern Delaware Other U.S. Total
Crude oil and condensate $ 668 $ 825 $ 188 $ 141 $ 58 $ 1,880
Natural gas liquids 65 25 53 15 3 161
Natural gas 66 18 81 7 10 182
Other 3 — — — 36 39
Revenues from contracts with customers $ 802 $ 868 $ 322 $ 163 $ 107 $ 2,262

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~International~~United States


	~~Three Months Ended June 30, 2020~~
~~(In millions)~~	~~E.G.~~
~~Crude oil and condensate~~	$	20
~~Natural gas liquids~~	1
~~Natural gas~~	7

~~Revenues from contracts with customers~~	$	28


	Three Months Ended June 30, 2021
(In millions)	Eagle Ford		Bakken		Oklahoma		Northern Delaware		Other U.S.		Total
Crude oil and condensate	$	353	$	411	$	71	$	77	$	24	$	936
Natural gas liquids	33		48		37		11		2		131
Natural gas	29		17		41		5		(1)		91
Other	2		0		0		0		29		31
Revenues from contracts with customers	$	417	$	476	$	149	$	93	$	54	$	1,189


		Three Months Ended June 30, 2019															Three Months Ended June 30, 2020
(In millions)	(In millions)	E.G.		U.K.		Other Int’l		Total		(In millions)	Eagle Ford		Bakken		Oklahoma		Northern Delaware		Other U.S.		Total
Crude oil and condensate	Crude oil and condensate	$	101	$	51	$	9	$	161	Crude oil and condensate	$	142	$	147	$	32	$	33	$	7	$	361
Natural gas liquids	Natural gas liquids	1		—		—		1		Natural gas liquids	16		3		13		4		1		37
Natural gas	Natural gas	9		4		—		13		Natural gas	20		5		24		4		1		54
Other	Other	—		6		—		6		Other	1		0		0		0		9		10
Revenues from contracts with customers	Revenues from contracts with customers	$	111	$	61	$	9	$	181	Revenues from contracts with customers	$	179	$	155	$	69	$	41	$	18	$	462


	~~Six Months Ended June 30, 2020~~
~~(In millions)~~	~~E.G.~~
~~Crude oil and condensate~~	$	65
~~Natural gas liquids~~	2
~~Natural gas~~	15

~~Revenues from contracts with customers~~	$	82


	Six Months Ended June 30, 2021
(In millions)	Eagle Ford		Bakken		Oklahoma		Northern Delaware		Other U.S.		Total
Crude oil and condensate	$	612	$	783	$	132	$	154	$	46	$	1,727
Natural gas liquids	59		89		74		20		5		247
Natural gas	76		42		150		30		8		306
Other	4		0		0		0		37		41
Revenues from contracts with customers	$	751	$	914	$	356	$	204	$	96	$	2,321


		Six Months Ended June 30, 2019															Six Months Ended June 30, 2020
(In millions)	(In millions)	E.G.		U.K.		Other Int’l		Total		(In millions)	Eagle Ford		Bakken		Oklahoma		Northern Delaware		Other U.S.		Total
Crude oil and condensate	Crude oil and condensate	$	148	$	107	$	19	$	274	Crude oil and condensate	$	449	$	477	$	116	$	107	$	40	$	1,189
Natural gas liquids	Natural gas liquids	2		1		—		3		Natural gas liquids	31		13		34		7		3		88
Natural gas	Natural gas	16		12		—		28		Natural gas	44		13		53		7		4		121
Other	Other	—		14		—		14		Other	3		0		0		0		31		34
Revenues from contracts with customers	Revenues from contracts with customers	$	166	$	134	$	19	$	319	Revenues from contracts with customers	$	527	$	503	$	203	$	121	$	78	$	1,432

International (E.G.)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2021		2020		2021		2020
Crude oil and condensate	$	58	$	20	$	95	$	65
Natural gas liquids	1		1		2		2
Natural gas	5		7		12		15
Other	1		0		1		0
Revenues from contracts with customers	$	65	$	28	$	110	$	82

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

6.5. Segment Information

We have 2 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~~that 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,~~and certain unproved properties, 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 June 30, 2020																	Three Months Ended June 30, 2021
(In millions)	(In millions)	U.S.		Int’l		Not Allocated to Segments			Total		(In millions)	U.S.		Int’l		Not Allocated to Segments			Total
Revenues from contracts with customers	Revenues from contracts with customers	$	462	$	28	$	—		$	490	Revenues from contracts with customers	$	1,189	$	65	$	0		$	1,254
Net gain (loss) on commodity derivatives	Net gain (loss) on commodity derivatives	26		—		(96)		^(b)	(70)		Net gain (loss) on commodity derivatives	(91)		0		(75)		(b)	(166)
Loss from equity method investments		—		—		(152)		^(c)	(152)
Net loss on disposal of assets		—		—		(2)			(2)
Income (loss) from equity method investments											Income (loss) from equity method investments	0		49		0			49
Net gain on disposal of assets											Net gain on disposal of assets	0		0		1			1
Other income	Other income	3		2		1			6		Other income	3		2		0			5
Less costs and expenses:	Less costs and expenses:										Less costs and expenses:
Production	Production	114		15		—			129		Production	113		13		0			126
Shipping, handling and other operating	Shipping, handling and other operating	91		1		13			105		Shipping, handling and other operating	153		2		12			167
Exploration	Exploration	26		—		—			26		Exploration	18		0		7			25
Depreciation, depletion and amortization	Depreciation, depletion and amortization	569		22		6			597		Depreciation, depletion and amortization	506		18		8			532

Impairments											Impairments	0		0		46		(c)	46
Taxes other than income	Taxes other than income	30		—		—			30		Taxes other than income	76		0		(2)			74
General and administrative	General and administrative	32		3		53		^(d)	88		General and administrative	27		4		37			68
Net interest and other	Net interest and other	—		—		69			69		Net interest and other	0		0		59		(d)	59
Other net periodic benefit credit		—		—		(7)		^(e)	(7)
Income tax benefit		(6)		(5)		(4)			(15)
Segment loss		$	(365)	$	(6)	$	(379)		$	(750)
Other net periodic benefit costs											Other net periodic benefit costs	0		0		1			1
Loss on early extinguishment of debt											Loss on early extinguishment of debt	0		0		19		(e)	19
Income tax provision (benefit)											Income tax provision (benefit)	1		11		(2)			10
Segment income (loss)											Segment income (loss)	$	207	$	68	$	(259)		$	16
Total assets	Total assets	$	16,791	$	1,144	$	632		$	18,567	Total assets	$	15,747	$	1,047	$	1,006		$	17,800
Capital expenditures^(a)	Capital expenditures^(a)	$	137	$	—	$	2		$	139	Capital expenditures(a)	$	284	$	2	$	3		$	289

^(a)Includes accruals.

^(b)Unrealized loss on commodity derivative instruments (See Note 1514).

^(c)Includes impairments of $24 million associated with central facilities in Eagle Ford (SeeNote 10) and $22 million associated with decommissioning costs for non-producing long-lived assets in the Gulf of Mexico (‘GOM’) (SeeN ot e 1 0,Note 11, and Note 23).

(d)Includes a $22 million loss on 2022 interest rate swaps and a $31 million gain on 2025 interest rate swaps, neither of which were designated as cash flow hedges as of June 30 (See Note 14).

(e)Represents costs related to a make-whole provision premium and the write off of unamortized discount and issuance costs related to the redemption of the 2022 Notes in April 2021 (See Note 16) .

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


	Three Months Ended June 30, 2020
(In millions)	U.S.		Int’l		Not Allocated to Segments			Total
Revenues from contracts with customers	$	462	$	28	$	0		$	490
Net gain (loss) on commodity derivatives	26		0		(96)		(b)	(70)
Income (loss) from equity method investments	0		0		(152)		(c)	(152)
Net loss on disposal of assets	0		0		(2)			(2)
Other income	3		2		1			6
Less costs and expenses:
Production	114		15		0			129
Shipping, handling and other operating	91		1		13			105
Exploration	26		0		0			26
Depreciation, depletion and amortization	569		22		6			597

Taxes other than income	30		0		0			30
General and administrative	32		3		53		(d)	88
Net interest and other	0		0		69			69
Other net periodic benefit costs	0		0		(7)		(e)	(7)
Income tax benefit	(6)		(5)		(4)			(15)
Segment loss	$	(365)	$	(6)	$	(379)		$	(750)
Total assets	$	16,791	$	1,144	$	632		$	18,567
Capital expenditures(a)	$	137	$	0	$	2		$	139

(a)Includes accruals.

(b)Unrealized loss on commodity derivative instruments (See Note 14).

(c)Partial impairment of investment in equity method investee (See N ot ~~e 2~~3Note 22).

^(d)Includes severance ~~expenses~~expense associated with workforce reductions of $13 million.

^(e)Includes pension settlement loss of $14 million and pension curtailment gain of $17 million (SeeN ~~ote~~ 2 0).

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

Three Months Ended June 30, 2019
(In millions) U.S. Int’l Not Allocated to Segments Total
Revenues from contracts with customers $ 1,200 $ 181 $ — $ 1,381
Net gain on commodity derivatives 5 — 11
^(b)
16
Income from equity method investments — 31 — 31
Net loss on disposal of assets — — (8)
^(c)
(8)
Other income 4 2 7 13
Less costs and expenses:
Production 147 46 — 193
Shipping, handling and other operating 147 10 13 170
Exploration 26 — — 26
Depreciation, depletion and amortization 561 38 6 605
Impairments — — 18
^(d)
18
Taxes other than income 79 — — 79
General and administrative 31 8 48 87
Net interest and other — — 64 64
Other net periodic benefit credit — (1) (1) (2)
Income tax provision 3 17 12 32
Segment income (loss) $ 215 $ 96 $ (150) $ 161
Total assets $ 17,539 $ 2,913 $ 830 $ 21,282
Capital expenditures^(a)
$ 686 $ 10 $ 5 $ 701

^(a)~~Includes accruals.~~

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

^(c)~~Primarily related to the sale of certain non-core proved properties in our International segment (see~~ No te 4).

^(d)~~Primarily as a result of the anticipated sale of non-core proved properties in our United States segment (See~~ ~~Note 11~~19).

1110

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


		Six Months Ended June 30, 2020																	Six Months Ended June 30, 2021
(In millions)	(In millions)	U.S.		Int’l		Not Allocated to Segments			Total		(In millions)	U.S.		Int’l		Not Allocated to Segments			Total
Revenues from contracts with customers	Revenues from contracts with customers	$	1,432	$	82	$	—		$	1,514	Revenues from contracts with customers	$	2,321	$	110	$	0		$	2,431
Net gain on commodity derivatives		57		—		75		^(b)	132
Loss from equity method investments		—		(12)		(152)		^(c)	(164)
Net loss on commodity derivatives											Net loss on commodity derivatives	(162)		0		(157)		(b)	(319)
Income (loss) from equity method investments											Income (loss) from equity method investments	0		93		0			93
Net gain on disposal of assets	Net gain on disposal of assets	—		—		7			7		Net gain on disposal of assets	0		0		1			1
Other income	Other income	7		4		2			13		Other income	4		3		1			8
Less costs and expenses:	Less costs and expenses:										Less costs and expenses:
Production	Production	257		32		—			289		Production	224		23		0			247
Shipping, handling and other operating	Shipping, handling and other operating	231		4		14			249		Shipping, handling and other operating	297		6		16			319
Exploration	Exploration	54		—		—			54		Exploration	39		0		7			46
Depreciation, depletion and amortization	Depreciation, depletion and amortization	1,186		43		12			1,241		Depreciation, depletion and amortization	978		37		13			1,028
Impairments	Impairments	—		—		97		^(d)	97		Impairments	0		0		47		(c)	47
Taxes other than income	Taxes other than income	96		—		—			96		Taxes other than income	150		0		(2)			148
General and administrative	General and administrative	64		7		93		^(e)	164		General and administrative	50		6		101		(d)	157
Net interest and other	Net interest and other	—		—		133			133		Net interest and other	0		0		72		(e)	72
Other net periodic benefit credit	Other net periodic benefit credit	—		—		(7)		^(f)	(7)		Other net periodic benefit credit	0		0		(2)			(2)
Income tax benefit		(7)		(5)		(6)			(18)
Segment loss		$	(385)	$	(7)	$	(404)		$	(796)
Loss on early extinguishment of debt											Loss on early extinguishment of debt	0		0		19		(f)	19
Income tax provision (benefit)											Income tax provision (benefit)	6		16		(2)			20
Segment income (loss)											Segment income (loss)	$	419	$	118	$	(424)		$	113
Total assets	Total assets	$	16,791	$	1,144	$	632		$	18,567	Total assets	$	15,747	$	1,047	$	1,006		$	17,800
Capital expenditures^(a)	Capital expenditures^(a)	$	698	$	—	$	9		$	707	Capital expenditures(a)	$	467	$	2	$	4		$	473

^(a)Includes accruals.

^(b)Unrealized loss on commodity derivative instruments (SeeNote 14).

(c)Includes second quarter 2021 impairments of $24 million for central facilities in Eagle Ford (SeeNote 10) and $22 million associated with decommissioning costs for non-producing long-lived assets in GOM (SeeNote 10, Note 11, and Note 23).

(d)Includes $13 million associated with the termination of an aircraft lease agreement and $12 million arising from severance expenses associated with a workforce reduction.

(e)Includes a $19 million gain on 2022 interest rate swaps and a $31 million gain on 2025 interest rate swaps, neither of which were designated as cash flow hedges as of June 30 (See Note 14).

(f)Represents costs related to a make-whole provision premium and the write off of unamortized discount and issuance costs in regards to the redemption of the 2022 Notes in April 2021 (See Note 16).

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


	Six Months Ended June 30, 2020
(In millions)	U.S.		Int’l		Not Allocated to Segments			Total
Revenue from contracts with customers	$	1,432	$	82	$	0		$	1,514
Net gain on commodity derivatives	57		0		75		(b)	132
Loss from equity method investments	0		(12)		(152)		(c)	(164)
Net gain on disposal of assets	0		0		7			7
Other income	7		4		2			13
Less costs and expenses:
Production	257		32		0			289
Shipping, handling and other operating	231		4		14			249
Exploration	54		0		0			54
Depreciation, depletion and amortization	1,186		43		12			1,241
Impairments	0		0		97		(d)	97
Taxes other than income	96		0		0			96
General and administrative	64		7		93		(e)	164
Net interest and other	0		0		133			133
Other net periodic benefit credit	0		0		(7)		(f)	(7)
Income tax benefit	(7)		(5)		(6)			(18)
Segment loss	$	(385)	$	(7)	$	(404)		$	(796)
Total assets	$	16,791	$	1,144	$	632		$	18,567
Capital expenditures(a)	$	698	$	0	$	9		$	707

(a)Includes accruals.

(b)Unrealized gain on commodity derivative instruments (See Note 1514).

^(c)Partial impairment of investment in equity method investee (See N~~ote 23~~Note 22).

^(d)Includes the full impairment of the International reporting unit goodwill of $95 million (See N ~~ote~~ 14Note 13).

^(e)Includes severance expenses associated with workforce reductions of $13 million.

^(f)Includes pension settlement loss of $16 million and pension curtailment gain of $17 million (See Note 20).

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

Six Months Ended June 30, 2019
(In millions) U.S. Int’l Not Allocated to Segments Total
Revenue from contracts with customers $ 2,262 $ 319 $ — $ 2,581
Net gain (loss) on commodity derivatives 27 — (102)
^(b)
(75)
Income from equity method investments — 42 — 42
Net gain on disposal of assets — — 34
^(c)
34
Other income 5 5 38
^(d)
48
Less costs and expenses:
Production 286 96 (2) 380
Shipping, handling and other operating 287 23 14 324
Exploration 85 — — 85
Depreciation, depletion and amortization 1,075 72 12 1,159
Impairments — — 24
^(e)
24
Taxes other than income 153 — (2) 151
General and administrative 60 15 106 181
Net interest and other — — 113 113
Other net periodic benefit credit — (3) (4) (7)
Income tax provision (benefit) 1 6 (122)
^(f)
(115)
Segment income (loss) $ 347 $ 157 $ (169) $ 335
Total assets $ 17,539 $ 2,913 $ 830 $ 21,282
Capital expenditures^(a)
$ 1,292 $ 15 $ 8 $ 1,315

^(a)~~Includes accruals.~~

^(b)~~Unrealized loss on commodity derivative instruments (SeeNote 15~~).

^(c)~~Primarily related to the sale of our working interest in the Droshky field (Gulf of Mexico).~~

^(d)~~Primarily related to the indemnification of certain tax liabilities in connection with the 2010-2011 Federal Tax Audit(SeeNote 7~~).

^(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 (SeeNote 7~~19).

1312

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

7.6. 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 65.

For the three and six months ended June 30, ~~2020~~2021 and ~~2019,~~2020, our effective income tax rates were as follows:

Three Months Ended June 30, Six Months Ended June 30,
2020 2019 2020 2019
Effective income tax rate^(a)
2 % 17 % 2 % (52) %


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Effective income tax rate	38	%	2	%	15	%	2	%

^(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~~Our effective income tax ~~rates to be~~rate was different from our U.S. statutory tax rate of 21% for ~~2020 and 2019:~~

•~~For~~ the three and six months ended June 30, 2021 and 2020 as a result of the income ~~tax rate was reduced below~~mix of our U.S. and E.G. operations, including the ~~statutory rate due to the~~income mix within E.G. between equity method investees and subsidiaries. We currently have a full valuation allowance on ~~our~~ net federal deferred tax assets in the U.S., which ~~resulted~~results in no federal deferred tax expense or benefit on ~~the~~current year U.S. ~~loss.~~

•~~For the three and six months ended June 30, 2019, the mix of pre-tax income in our international operations reduced the annual effective tax rate below the statutory tax rate~~. Income tax rates for the six months ended June 30, 2019 were also impacted by the settlement of the 2010-2011 U.S. Federal Tax Audit (“IRS 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 six months of 2019. Excluding these discrete adjustments, the effective income tax rate for the first six months of 2019 was an expense of 13%.

~~In the first quarter of 2020, the U.S. enacted the~~ ~~Coronavirus Aid, Relief, and Economic Security Act~~, commonly referred to as the CARES Act. This legislation included certain provisions which accelerate income tax refunds, and as a result, in the first quarter of 2020, long term receivable balances related to alternative minimum tax credits were classified as short term. Subsequent to June 30, 2020, we received an $89 million cash refund related to these alternative minimum tax credits and interest.activity.

8.7. 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 termsconditions and other ~~factors, such~~data 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.

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

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.deemed appropriate.

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


~~(In millions)~~	~~June 30, 2020~~
~~Beginning balance as of January 1~~	$	11
~~Cumulative-effect adjustment~~	12
~~Current period provision~~^(a)	6
~~Recoveries of amounts previously written off~~	~~(6)~~
~~Ending balance as of June 30~~	$	23


(In millions)	June 30, 2021		December 31, 2020
Beginning balance as of January 1	$	22	$	11
Cumulative-effect adjustment	0		12
Current period provision(a)	(2)		22
Current period write offs	(1)		(13)
Recoveries of amounts previously reserved	0		(10)
Ending balance	$	19	$	22

^(a)~~For the six months ended June 30,~~As of December 31, 2020, the current period provision ~~increased by $7~~consisted of $10 million in joint interest receivables and ~~decreased by $1~~$12 million in trade receivables.

9.8. 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) June 30, 2020 December 31, 2019
Crude oil and natural gas $ 9 $ 10
Supplies and other items 68 62
Inventories $ 77 $ 72

~~10. Property, Plant and Equipment~~

(In millions) June 30, 2020 December 31, 2019
United States $ 15,899 $ 16,427
International 449 493
Corporate 76 80
Net property, plant and equipment $ 16,424 $ 17,000

~~We had 0 exploratory well costs capitalized greater than one year as of June 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.

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


(In millions)	June 30, 2021		December 31, 2020
Crude oil and natural gas	$	12	$	10
Supplies and other items	66		66
Inventories	$	78	$	76

1513

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~value. Our first quarter review concluded that any potential losses in values~~9. Property, Plant and Equipment


(In millions)	June 30, 2021		December 31, 2020
United States	$	14,583	$	15,156
International	380		414
Corporate	56		68
Net property, plant and equipment	$	15,019	$	15,638

As of ~~our equity method investments were temporary because the underlying declines in both commodity prices~~June 30, 2021 and ~~demand did not materially manifest until early March. However, during the second quarter of~~December 31, 2020, we ~~did recognize an impairment~~had $158 million and $98 million, respectively, of exploratory well costs capitalized greater than one year related to ~~one~~suspended wells. Management believes these wells exhibit sufficient quantities of ~~our equity method investees~~hydrocarbons to justify potential development. The vast majority of the suspended wells require completion activities and installation of infrastructure in order to classify the reserves as ~~noted in the table below.~~

proved.

10. Impairments

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


		Three Months Ended June 30,															Three Months Ended June 30,
		2020						2019							2021				2020
(In millions)	(In millions)	Fair Value		Impairment		Fair Value		Impairment		(In millions)	Fair Value		Impairment		Fair Value		Impairment

Long-lived assets held for use	Long-lived assets held for use	$	—	$	—	$	19	$	18	Long-lived assets held for use	$	0	$	24	$	0	$	0
Asset retirement costs of long-lived assets										Asset retirement costs of long-lived assets	0		22		0		0
Equity method investment	Equity method investment	$	142	$	152	N/A		$	—	Equity method investment	$	0	$	0	$	142	$	152

Six Months Ended June 30,
2020 2019
(In millions) Fair Value Impairment Fair Value Impairment
Long-lived assets held for use $ — $ 2 $ 56 $ 24
Goodwill $ — $ 95 N/A $ —
Equity method investment $ 142 $ 152 N/A $ —


	Six Months Ended June 30,
	2021				2020
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	0	$	25	$	0	$	2
Asset retirement costs of long-lived assets	0		22		0		0
Goodwill	0		0		0		95
Equity method investment	$	0	$	0	$	142	$	152

•2021– During the second quarter of 2021, we recorded an impairment expense of $24 million associated with two central facilities located in Eagle Ford. Decommissioning activities commenced during the quarter, which included the re-routing of existing wells.

We also recognized an incremental $22 million of impairment expense associated with an increase in the estimated future decommissioning costs of certain non-producing wells, pipelines and production facilities for previously divested offshore assets located in the Gulf of Mexico. In a prior reporting period, we recorded a $7 million liability in our consolidated balance sheet associated with these assets, thereby increasing the total recognized asset retirement obligation to $29 million as of June 30, 2021. See Note 11 and Note 23 for further information.

The combined effects of these items were recorded within the Impairments line item within our consolidated statements of income.

•2020 – 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. WeAs a result, we recorded an impairment of $152 million, based on the difference between our carrying value and the fair value of our investment. 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 impairment~~which was recognized in income (loss) from equity method investments in our consolidated statements of income. The impairment 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~~This differential is ~~$126 million and will be~~being accreted into income over ~~the next 6.5 years, which is consistent with~~ the remaining useful life of the investee’s primary assets.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~Impairments~~Additionally, impairments for the first six months ~~ended June 30,~~of 2020 ~~also~~ included $95 million of goodwill impairment in the International reporting unit. See No ~~te 1~~4Note 13 for further information.

•~~2019~~– During the six months ended June 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.~~

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

~~12.~~11. 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 six months ended June 30~~ were as follows:


		June 30,							June 30,
(In millions)	(In millions)	2020		2019		(In millions)	2021		2020
Beginning balance as of January 1	Beginning balance as of January 1	$	255	$	1,145	Beginning balance as of January 1	$	254	$	255
Incurred liabilities, including acquisitions	Incurred liabilities, including acquisitions	2		18		Incurred liabilities, including acquisitions	6		2
Settled liabilities, including dispositions	Settled liabilities, including dispositions	(3)		(129)		Settled liabilities, including dispositions	(2)		(3)
Accretion expense (included in depreciation, depletion and amortization)	Accretion expense (included in depreciation, depletion and amortization)	6		26		Accretion expense (included in depreciation, depletion and amortization)	6		6
Revisions of estimates	Revisions of estimates	(8)		11		Revisions of estimates	32		(8)
Held for sale		—		(864)
Ending balance as of June 30		$	252	$	207

Ending balance as of June 30, total						Ending balance as of June 30, total	$	296	$	252

Ending balance as of June 30, short-term						Ending balance as of June 30, short-term	$	24	$	10

In the second quarter of 2021, we had a revision of estimate of $29 million related to anticipated costs for decommissioning certain wells, pipelines and production facilities for previously divested offshore non-producing long-lived assets located in the Gulf of Mexico. As of June 30, ~~2020~~

•~~Ending balance~~ ~~includes $10~~2021, $14 million of this revision of estimate was classified as ~~short-term at June 30, 2020.~~

~~June 30, 2019~~

•~~Settled liabilities~~ ~~primarily relate to the sale of our working interest in the Droshky field (Gulf of Mexico), which closed during the first quarter of 2019.~~

•~~Held for sale~~ includes the asset retirement obligations of $966 million associated with the sale of our U.K. business, which was partially offset by settled liabilities for dispositions primarily related to the Droshky field in the first quarter of 2019.short-term. See Note 423 for ~~discussion~~further information. During the quarter, we recognized $22 million of ~~the divestitures in~~impairment expense associated with these non-producing long-lived assets within our consolidated statement of operations. SeeNote 10 for further ~~detail.~~information.

•~~Ending balance~~ ~~includes $18 million classified as short-term at June 30, 2019.~~

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

~~13.~~12. 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~~the majority 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)~~		~~June 30, 2020~~
~~Operating Leases:~~	~~Balance Sheet Location:~~
~~Right-of-use asset~~	~~Other noncurrent assets~~	$	~~153~~
~~Current portion of long-term lease liability~~	~~Other current liabilities~~	$	83
~~Long-term lease liability~~	~~Deferred credits and other liabilities~~	$	74


(In millions)		June 30, 2021		December 31, 2020
Operating Leases:	Balance Sheet Location:
Right-of-use asset	Other noncurrent assets	$	92	$	133
Current portion of long-term lease liability	Other current liabilities	$	52	$	70
Long-term lease liability	Deferred credits and other liabilities	$	44	$	67

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Our ~~wholly-owned~~wholly owned subsidiary, Marathon E.G. Production Limited, is a lessor for residential housing in ~~Equatorial Guinea,~~E.G., which is occupied by EGHoldings, a related party equity method investee – see Note 2422. 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)	(In millions)	Operating Lease Future Cash Receipts		(In millions)	Operating Lease Future Cash Receipts
2020		$	3
2021	2021	6		2021	$	4
2022	2022	6		2022	6
2023	2023	6		2023	6
2024	2024	6		2024	6
2025				2025	6
Thereafter	Thereafter	60		Thereafter	54
Total undiscounted cash flows	Total undiscounted cash flows	$	87	Total undiscounted cash flows	$	82

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 new Houston office location is expected to be completed in 2021.~~Texas. The lessor and other participants are providing financing for up to ~~$380~~$340 million to fund the estimated project costs. As of June 30, ~~2020,~~2021, project costs incurred totaled approximately ~~$87~~$214 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.~~occupancy, which is expected to occur in the second half of 2021. 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.

In June 2020, we submitted a notice to the lessor, as the construction agent, to reduce the financing capacity to $340 million to align with our revised estimate of the project costs. We expect the reduction to become effective in August 2020.

~~14.~~13. 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

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

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.

June 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 June 30, net $ — $ 95
This represented the entirety of our goodwill on our consolidated balance sheet.

~~15.~~14. Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note 1615. All of our commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we report net amounts.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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


		June 30, 2020												June 30, 2021
(In millions)	(In millions)	Asset		Liability		Net Asset (Liability)		Balance Sheet Location	(In millions)	Asset		Liability		Net Asset (Liability)		Balance Sheet Location
Not Designated as Hedges	Not Designated as Hedges								Not Designated as Hedges

Commodity	Commodity	$	100	$	21	$	79	Derivative assets	Commodity	$	0	$	181	$	(181)	Other current liabilities

Interest Rate									Interest Rate	63		0		63		Other noncurrent assets
Interest Rate									Interest Rate	0		1		(1)		Deferred credits and other liabilities
Total Not Designated as Hedges	Total Not Designated as Hedges	$	100	$	21	$	79		Total Not Designated as Hedges	$	63	$	182	$	(119)

Cash Flow Hedges	Cash Flow Hedges										Cash Flow Hedges

Interest Rate	Interest Rate	$	—	$	26	$	(26)	Deferred credits and other liabilities	Interest Rate	$	0	$	2	$	(2)	Other current liabilities
Interest Rate	Interest Rate	2		—		2		Other noncurrent assets	Interest Rate	0		6		(6)		Deferred credits and other liabilities
Total Designated Hedges	Total Designated Hedges	$	2	$	26	$	(24)		Total Designated Hedges	$	0	$	8	$	(8)
Total	Total	$	102	$	47	$	55		Total	$	63	$	190	$	(127)


		December 31, 2019												December 31, 2020
(In millions)	(In millions)	Asset		Liability		Net Asset (Liability)		Balance Sheet Location	(In millions)	Asset		Liability		Net Asset (Liability)		Balance Sheet Location
Not Designated as Hedges	Not Designated as Hedges								Not Designated as Hedges
Commodity	Commodity	$	9	$	1	$	8	Derivative assets	Commodity	$	3	$	1	$	2	Other current assets
Commodity	Commodity	1		—		1		Other noncurrent assets	Commodity	7		32		(25)		Other current liabilities
Commodity		—		5		(5)		Other current liabilities
Interest Rate									Interest Rate	10		0		10		Other noncurrent assets
Total Not Designated as Hedges	Total Not Designated as Hedges	$	10	$	6	$	4		Total Not Designated as Hedges	$	20	$	33	$	(13)

Cash Flow Hedges	Cash Flow Hedges								Cash Flow Hedges
Interest Rate	Interest Rate	$	2	$	—	$	2	Other noncurrent assets	Interest Rate	$	19	$	0	$	19	Other noncurrent assets
Interest Rate									Interest Rate	0		16		(16)		Deferred credits and other liabilities
Total Designated Hedges	Total Designated Hedges	$	2	$	—	$	2		Total Designated Hedges	$	19	$	16	$	3
Total	Total	$	12	$	6	$	6		Total	$	39	$	49	$	(10)

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

Derivatives Not Designated as Hedges

Commodity Derivatives

We have entered into multiple crude oil, ~~and~~ 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~~U.S. sales through ~~2021.~~2022. 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 and natural gas derivatives were not designated as hedges.~~

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

2020 2021
Third Quarter Fourth Quarter Full Year
Crude Oil
NYMEX WTI Three-Way Collars
Volume (Bbls/day) 80,000 80,000 —
Weighted average price per Bbl:
Ceiling $ 64.40 $ 64.40 $ —
Floor $ 55.00 $ 55.00 $ —
Sold put $ 48.00 $ 48.00 $ —
NYMEX WTI Two-Way Collars
Volume (Bbls/day) 33,478 — —
Weighted average price per Bbl:
Ceiling $ 40.47 $ — $ —
Floor $ 30.98 $ — $ —
Fixed Price WTI Swaps
Volume (Bbls/day) 10,000 — —
Weighted average price per Bbl $ 32.77 $ — $ —
Basis Swaps - Argus WTI Midland^(a)
Volume (Bbls/day) 15,000 15,000 —
Weighted average price per Bbl $ (0.94) $ (0.94) $ —
Basis Swaps - NYMEX WTI / ICE Brent ^(b)
Volume (Bbls/day) 5,000 5,000 808
Weighted average price per Bbl $ (7.24) $ (7.24) $ (7.24)
NYMEX Roll Basis Swaps
Volume (Bbls/day) 60,000 30,000 —
Weighted average price per Bbl $ (1.58) $ (0.81) $ —
Natural Gas
Two-Way Collars
Volume (MMBtu/day) — — 62,329
Weighted average price per MMBtu:
Ceiling $ — $ — $ 3.07
Floor $ — $ — $ 2.44
Basis Swaps - WAHA / HH ^(c)
Volume (MMBtu/day) 10,000 10,000 —
Weighted average price per MMBtu $ (0.37) $ (0.37) $ —

^(a)~~The basis differential price is indexed against Argus WTI Midland.~~

^(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.~~

2017

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The following table sets forth outstanding derivative contracts ~~entered into between July 1 and August 5, 2020,~~as of June 30, 2021, and the weighted average prices for those contracts:


	2021				2022
	Third Quarter		Fourth Quarter		First Half		Second Half
Crude Oil
NYMEX WTI Three-Way Collars
Volume (Bbls/day)	40,000		40,000		10,000		0
Weighted average price per Bbl:
Ceiling	$	74.07	$	78.05	$	87.84	$	0
Floor	$	48.75	$	50.00	$	50.00	$	0
Sold put	$	38.75	$	40.00	$	40.00	$	0
NYMEX WTI Two-Way Collars
Volume (Bbls/day)	40,000		40,000		0		0
Weighted average price per Bbl:
Ceiling	$	59.41	$	58.92	$	0	$	0
Floor	$	39.25	$	39.25	$	0	$	0












NYMEX Roll Basis Swaps
Volume (Bbls/day)	0		0		45,000		45,000
Weighted average price per Bbl	$	0	$	0	$	0.56	$	0.56

Natural Gas
Henry Hub (“HH”) Two-Way Collars
Volume (MMBtu/day)	200,000		200,000		0		0
Weighted average price per MMBtu:
Ceiling	$	3.05	$	3.05	$	0	$	0
Floor	$	2.50	$	2.50	$	0	$	0

HH Fixed Price Swaps
Volume (MMBtu/day)	50,000		50,000		0		0
Weighted average price per MMBtu	$	2.88	$	2.88	$	0	$	0
NGL
Fixed Price Propane Swaps (a)
Volume (Bbls/day)	5,000		5,000		0		0
Weighted average price per Bbl	$	10.92	$	10.92	$	0	$	0
Fixed Price Propane Swaps (b)
Volume (Bbls/day)	5,000		5,000		0		0
Weighted average price per Bbl	$	23.19	$	23.19	$	0	$	0

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

(b)The fixed price propane swap is priced at OPIS Mont Belvieu Non-TET Propane.

2020 2021
Third Quarter Fourth Quarter Full Year
Crude Oil
NYMEX WTI Two-Way Collars
Volume (Bbls/day) 3,261 10,000 10,000
Weighted average price per Bbl:
Ceiling $ 48.00 $ 48.65 $ 52.37
Floor $ 36.50 $ 37.00 $ 35.00
Natural Gas
Two-Way Collars
Volume (MMBtu/day) 66,304 150,000 50,000
Weighted average price per MMBtu:
Ceiling $ 2.49 $ 2.62 $ 2.93
Floor $ 2.00 $ 2.13 $ 2.40
NGL
Fixed Price Ethane Swaps
Volume (MMBtu/day) 7,304 10,000 —
Weighted average price per Bbl $ 8.78 $ 8.78 $ —

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The ~~mark-to-market~~unrealized and realized gain (loss) 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 June 30, Six Months Ended June 30,
(In millions) 2020 2019 2020 2019
Mark-to-market gain (loss) $ (96) $ 11 $ 75 $ (102)
Net settlements of commodity derivative instruments $ 26 $ 5 $ 57 $ 27


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2021		2020		2021		2020
Unrealized gain (loss) on derivative instruments, net	$	(75)	$	(96)	$	(157)	$	75
Realized gain (loss) on derivative instruments, net(a)	$	(91)	$	26	$	(162)	$	57

~~Derivatives Designated as Cash Flow Hedges~~(a)During the second quarter and first six months of 2021, net cash paid for settled derivative positions was $84 million and $95 million, respectively. During the second quarter and first six months of2020, net cash received for settled derivative positions was $78 million and $91 million, respectively.

Interest Rate Swaps

During 2020, we entered into forward starting interest rate swaps ~~with a notional amount of $500 million~~ to hedge the variations in cash flows ~~arising from~~related to fluctuations in the London Interbank Offered Rate (“LIBOR”) benchmark interest rate related to forecasted interest payments of a future ~~debt~~debt issuance in ~~2022; and~~2022. Each respective derivative contract can be tied to an ~~additional $300~~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. In the first quarter of 2021, the net deferred loss of $2 million ~~of notional for our future debt issuance~~ in ~~2025. We expect~~accumulated other comprehensive income related to ~~refinance both of the debt maturities in 2022 and 2025. The~~these de-designated forward starting interest rate swaps ~~will terminate on or prior to the refinancing of the debt and the final value will be~~was reclassified from accumulated other comprehensive income into earnings ~~with each future~~as an adjustment to net interest, ~~payment. Subsequent~~as we fully redeemed the remainder of our outstanding 2022 notes in April 2021. Additionally, we recorded a $22 million mark-to-market loss and a $19 million mark-to-market gain within net interest to reflect the change in value of these interest rate swaps during the three and six months ended June 30, 2021, respectively.

During 2020, we entered into ~~additional~~ forward starting interest rate swaps with a notional amount of ~~$50~~$350 million ~~and a weighted average rate of 0.90%~~ 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. The expected proceeds of the ~~same LIBOR~~future debt issuance were intended to refinance the $900 million 3.85% Senior Notes due 2025 (“2025 Notes”). During the second quarter of 2021, we de-designated these forward starting interest rate swaps previously designated as cash flow hedges because we no longer plan to refinance the 2025 Notes. In August 2021, we sent an irrevocable notice of redemption to the trustee to fully redeem the 2025 Notes. See Note 16for further details. We reclassified the $31 million cumulative gain related to these hedges from accumulated other comprehensive income into earnings as an adjustment to net interest.

In addition, during the second quarter of 2021, we de-designated $25 million of the $320 million Houston office cash flow hedges (discussed further in the Derivatives Designated as Cash Flow Hedges section below), as the construction cost budget estimate was reduced. The $1 million loss of these de-designated cash flow hedges as of June 30, 2021 was reclassified from accumulated other comprehensive income into earnings as an adjustment to net interest.

The following table presents, by maturity date, information about our ~~debt due in 2025.~~de-designated forward starting interest rate swap agreements, including the rate.


	June 30, 2021				December 31, 2020
Maturity Date	Aggregate Notional Amount (in millions)		Weighted Average, LIBOR		Aggregate Notional Amount (in millions)		Weighted Average, LIBOR
November 1, 2022	$	500	0.99	%	$	500	0.99	%
June 1, 2025	$	350	0.95	%	N/A		N/A
September 9, 2026	$	25	1.45	%	N/A		N/A

Derivatives Designated as Cash Flow Hedges

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~~During the ~~first lease payment to commence sometime in~~second quarter of 2021, we de-designated $25 million of these hedges as the ~~period from December 2021 to May 2022.~~ construction cost budget estimate associated with the project was reduced. The last swap will mature onin September 9, 2026. As of June 30, 2021, amounts expected to be reclassified from accumulated other comprehensive income over the next twelve months were not material. See Note 1312 for further details regarding the lease of the new Houston office.

2119

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.

June 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 % $ — — %
June 1, 2025 $ 300 0.96 % $ — — %
September 9, 2026 $ 320 1.51 % $ 320 1.51 %

At June 30, 2020, accumulated other comprehensive income included deferred losses of $24 million related to forward starting interest rate swaps. No amounts related to these swaps are expected to impact the consolidated statements of income in the next 12 months.


	June 30, 2021				December 31, 2020
Maturity Date	Aggregate Notional Amount (in millions)		Weighted Average, LIBOR		Aggregate Notional Amount (in millions)		Weighted Average, LIBOR

June 1, 2025	N/A		N/A		$	350	0.95	%
September 9, 2026	$	295	1.52	%	$	320	1.51	%

~~16.~~15. Fair Value Measurements

Fair Values – Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of June 30, ~~2020~~2021 and December 31, ~~2019~~2020 by hierarchy level.


		June 30, 2020															June 30, 2021
(In millions)	(In millions)	Level 1		Level 2		Level 3		Total		(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets	Derivative instruments, assets									Derivative instruments, assets
Commodity^(a)		$	—	$	88	$	—	$	88
Interest rate		—		2		—		2

Interest rate - not designated as cash flow hedges										Interest rate - not designated as cash flow hedges	$	0	$	62	$	0	$	62

Derivative instruments, assets	Derivative instruments, assets	$	—	$	90	$	—	$	90	Derivative instruments, assets	$	0	$	62	$	0	$	62
Derivative instruments, liabilities	Derivative instruments, liabilities									Derivative instruments, liabilities
Commodity^(a)	Commodity^(a)	$	(9)	$	—	$	—	$	(9)	Commodity(a)	$	(30)	$	(151)	$	0	$	(181)
Interest rate		—		(26)		—		(26)

Interest rate - designated as cash flow hedges										Interest rate - designated as cash flow hedges	0		(8)		0		(8)
Derivative instruments, liabilities	Derivative instruments, liabilities	$	(9)	$	(26)	$	—	$	(35)	Derivative instruments, liabilities	$	(30)	$	(159)	$	0	$	(189)
Total	Total	$	(9)	$	64	$	—	$	55	Total	$	(30)	$	(97)	$	0	$	(127)


		December 31, 2019															December 31, 2020
(In millions)	(In millions)	Level 1		Level 2		Level 3		Total		(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets	Derivative instruments, assets									Derivative instruments, assets
Commodity^(a)		$	—	$	7	$	—	$	7
Interest rate		—		2		—		2
Interest rate - not designated as cash flow hedges										Interest rate - not designated as cash flow hedges	$	0	$	10	$	0	$	10
Interest rate - designated as cash flow hedges										Interest rate - designated as cash flow hedges	0		19		0		19
Derivative instruments, assets	Derivative instruments, assets	$	—	$	9	$	—	$	9	Derivative instruments, assets	$	0	$	29	$	0	$	29
Derivative instruments, liabilities	Derivative instruments, liabilities									Derivative instruments, liabilities
Commodity^(a)	Commodity^(a)	$	(3)	$	—	$	—	$	(3)	Commodity(a)	$	0	$	(23)	$	0	$	(23)

Interest rate - designated as cash flow hedges										Interest rate - designated as cash flow hedges	0		(16)		0		(16)
Derivative instruments, liabilities	Derivative instruments, liabilities	$	(3)	$	—	$	—	$	(3)	Derivative instruments, liabilities	$	0	$	(39)	$	0	$	(39)
Total	Total	$	(3)	$	9	$	—	$	6	Total	$	0	$	(10)	$	0	$	(10)

^(a)~~Derivative~~Commodity derivative instruments are recorded on a net basis in our consolidated balance sheet. See Note 1514.

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-~~

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

~~way~~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 1514 for detail on the forward starting interest rate swaps.

Fair Value Estimates – Goodwill

See Note 1413 for detail information relating to goodwill.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Fair Values – Nonrecurring

See Note 1110 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 June 30, ~~2020~~2021 and December 31, ~~2019.~~2020.


		June 30, 2020						December 31, 2019							June 30, 2021				December 31, 2020
(In millions)	(In millions)	Fair Value		Carrying Amount		Fair Value		Carrying Amount		(In millions)	Fair Value		Carrying Amount		Fair Value		Carrying Amount
Financial assets	Financial assets									Financial assets
Current assets	Current assets	$	4	$	4	$	4	$	4	Current assets	$	13	$	12	$	4	$	4
Other noncurrent assets	Other noncurrent assets	28		44		26		38		Other noncurrent assets	12		27		24		37
Total financial assets	Total financial assets	$	32	$	48	$	30	$	42	Total financial assets	$	25	$	39	$	28	$	41
Financial liabilities	Financial liabilities									Financial liabilities
Other current liabilities		$	61	$	97	$	62	$	90
Current liabilities										Current liabilities	$	93	$	124	$	72	$	103
Long-term debt, including current portion^(a)	Long-term debt, including current portion^(a)	5,558		5,530		6,174		5,529		Long-term debt, including current portion(a)	5,735		4,931		6,077		5,431
Deferred credits and other liabilities	Deferred credits and other liabilities	105		84		99		86		Deferred credits and other liabilities	69		50		103		76
Total financial liabilities	Total financial liabilities	$	5,724	$	5,711	$	6,335	$	5,705	Total financial liabilities	$	5,897	$	5,105	$	6,252	$	5,610

^(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.

~~17.~~16. Debt

Revolving Credit Facility

On June 21, 2021, we executed the sixth amendment to our unsecured revolving credit facility (“Credit Facility”). The primary changes resulting from this amendment are (i) increasing the size of the Credit Facility from $3.0 billion to $3.1 billion, (ii) extending the maturity of the commitments of certain consenting lenders from May 28, 2023 to June 21, 2024 (with the remaining commitment of a single non-consenting lender to mature on May 28, 2023, at which time the size of the Credit Facility will be reduced to $3.0 billion) and (iii) including certain other provisions and revisions, including provisions to provide for the eventual replacement of LIBOR as a benchmark interest rate. As of June 30, ~~2020,~~2021, we had 0 borrowings against our ~~$3.0 billion unsecured revolving credit facility (“~~Credit ~~Facility”), as described below.~~Facility.

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 June 30, ~~2020,~~2021, we were in compliance with this covenant with a ratio of ~~33%~~24%.

Debt Redemption

On March 30, 2021, we sent an irrevocable notice of redemption to the trustee to fully redeem our outstanding $500 million 2.8% Senior Notes due 2022 (“2022 Notes”). The 2022 Notes were redeemed on April 29, 2021 and as a result of the

2321

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

settlement, we incurred $19 million in costs related to a make-whole provision premium and the write off of unamortized discount and issuance costs.

Long-term debt

At June 30, ~~2020,~~2021, we had ~~$5.5~~$4.9 billion of total long-term debt outstanding. On August 4, 2021, we sent an irrevocable notice of redemption to the trustee to fully redeem our outstanding ~~with~~$900 million 3.85% Senior Notes due 2025 (“2025 Notes”). We intend to settle the 2025 Notes and pay the make-whole premium in early September 2021 using cash on hand. The amount we will pay related to the make-whole premium will be determined on or around August 31, 2021 based on the then current applicable Treasury Rate defined in the 2025 Notes’ Prospectus Supplement. Based on fluctuations in the applicable Treasury Rate in 2021, the amount of the make-whole premium is estimated to be approximately $85 million to $105 million. Subsequent to the redemption of the 2025 Notes, our next significant long-term debt maturity is in the amount of $1.0 billion due ~~November 2022.~~

2027. Refer to our 2020 Annual Report on Form 10-K for a listing of our long-term debt maturities.

~~18.~~17. Stockholders’ Equity

~~During~~NaN share repurchases were made under our share repurchases program during the six months ended June 30, ~~2020,~~2021; however, we ~~acquired approximately 9~~repurchased $9 million ~~common~~of shares ~~at a cost~~during the first quarter related to our tax withholding obligation associated with the vesting of ~~$85 million, which were held as treasury stock. Including these repurchases, the~~employee restricted stock awards. The total remaining share repurchase authorization was $1.3 billion at June 30, ~~2020.~~2021. 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.

~~19.~~18. Incentive Based Compensation

Stock options, restricted stock awards and restricted stock units

The following table presents a summary of activity for the first six months of ~~2020:~~2021:


		Stock Options					Restricted Stock Awards & Units						Stock Options			Restricted Stock Awards & Units
		Number of Shares		Weighted Average Exercise Price		Awards	Weighted Average Grant Date Fair Value			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
Outstanding at December 31, 2020									Outstanding at December 31, 2020	6,014,255	$	21.00	7,851,754	$	11.72
Granted	Granted	1,132,808	^(a)	$	10.47	5,337,796	$	8.55	Granted	0	$	0	2,297,929	$	11.20
Exercised/Vested	Exercised/Vested	(52,333)		$	7.22	(2,911,712)	$	15.93	Exercised/Vested	(384,889)	$	7.34	(2,896,748)	$	12.56
Canceled^(b)(a)	Canceled^(b)(a)	(565,219)		$	23.52	(1,405,754)	$	11.70	Canceled^(b)(a)	(1,106,590)	$	22.82	(893,808)	$	11.97
Outstanding at June 30, 2020		6,174,987		$	21.29	8,194,716	$	11.80
Outstanding at June 30, 2021									Outstanding at June 30, 2021	4,522,776	$	21.72	6,359,127	$	11.12

^(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 six months of ~~2020,~~2021, we granted ~~1,038,676~~307,473 stock-based performance units to ~~certain~~eligible officers, ~~to be~~which are settled in shares. The grant date fair value per unit was ~~$10.55,~~$18.07, as calculated using a Monte Carlo valuation model. AsAt the grant date, each unit represents the value of one share of our common stock. These units are settled in shares, and the number of shares of our common stock to be paid is based on the vesting percentage, which can be from 0 to 200% based on performance achieved during the performance period and as determined by the Compensation Committee of the Board of Directors (“Compensation Committee”). The performance goals are tied to our total shareholder return (“TSR”) as compared to TSR for a group including peer companies, the S&P Energy Index and the S&P 500 Index, which is determined by the Compensation Committee. Also, dividend equivalents accrue during the performance period and would be paid in cash following the end of the performance period based on the amount of dividends credited on shares of our common stock over the performance period multiplied by the number of units that vest.

During the first six months of 2021, we introduced a new type of stock-based performance unit award under the Marathon Oil Corporation 2019 Incentive Compensation Plan and granted 307,473 units to eligible officers, which are settled in cash.At the grant date for these new stock-based performance units, each unit represents the value of one share of our common stock. The benefit amount to be paid is based on the product of (i) the number of units granted, (ii) the vesting percentage, and (iii) the average daily closing price of our common stock during the final 30 calendar days ending on the last trading day of the

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

performance period, subject to the banking feature described below. The vesting percentage can range from 0 to 200%, which is based on performance achieved over a two-year performance period. The performance metric is a predetermined amount of cumulative free cash flow, as defined by the award agreement, generated by the Company over the performance period. The units have a banking feature whereby the stock price valuation and vesting percentage are fixed at no less than 50%, and then again at 100%, if achieved during the performance period. Once those milestones are reached, the vesting percentage will not fall below those banked percentage amounts even if cumulative free cash flow subsequently declines during the performance period, subject to the Compensation Committee’s discretion as described below. The second quarter fair value per unit was $27.32, as calculated by multiplying the estimated vesting percentage by our common stock’s closing stock price on June 30, ~~2020 there were 1,658,088~~2021. Also, dividend equivalents accrue during the performance period and would be paid in cash following the end of the performance period based on the amount of dividends credited on shares of our common stock over the performance period multiplied by the number of units ~~outstanding.~~that vest. As set forth in the award agreement terms, the Compensation Committee retains discretion to reduce the vesting percentage and any bank values and determine free cash flow achievement for these awards.

~~20.~~19. Defined Benefit Postretirement Plans

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

Three Months Ended June 30,
Pension Benefits Other Benefits
(In millions) 2020
2019^(d)
2020 2019
Service cost $ 5 $ 5 $ — $ —
Interest cost 2 7 — 1
Expected return on plan assets (2) (8) — —
Amortization:
– prior service cost (credit) (2) (2) (5) (4)
– actuarial loss 2 2 1 —
Net settlement loss^(a)
14 2 — —
Net curtailment gain^(b)
(3) — (14) —
Net periodic benefit cost (credit)^(c)
$ 16 $ 6 $ (18) $ (3)

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~


		Six Months Ended June 30,															Three Months Ended June 30,
		Pension Benefits						Other Benefits							Pension Benefits				Other Benefits
(In millions)	(In millions)	2020		2019^(d)		2020		2019		(In millions)	2021		2020		2021		2020
Service cost	Service cost	$	10	$	9	$	—	$	—	Service cost	$	4	$	5	$	0	$	0
Interest cost	Interest cost	5		14		1		2		Interest cost	2		2		1		0
Expected return on plan assets	Expected return on plan assets	(5)		(16)		—		—		Expected return on plan assets	(2)		(2)		0		0
Amortization:	Amortization:									Amortization:
– prior service cost (credit)		(4)		(4)		(9)		(8)
– prior service credit										– prior service credit	(1)		(2)		(4)		(5)
– actuarial loss	– actuarial loss	5		4		1		—		– actuarial loss	1		2		0		1
Net settlement loss^(a)	Net settlement loss^(a)	16		2		—		—		Net settlement loss(a)	5		14		0		0
Net curtailment gain^(b)	Net curtailment gain^(b)	(3)		—		(14)		—		Net curtailment gain(b)	0		(3)		0		(14)
Net periodic benefit cost (credit)^(c)		$	24	$	9	$	(21)	$	(6)
Net periodic benefit costs (credits)(c)										Net periodic benefit costs (credits)(c)	$	9	$	16	$	(3)	$	(18)

^{Six Months Ended June 30,
Pension Benefits Other Benefits
(In millions) 2021 2020 2021 2020
Service cost $ 8 $ 10 $ 0 $ 0
Interest cost 4 5 1 1
Expected return on plan assets (4) (5) 0 0
Amortization:
– prior service credit (3) (4) (8) (9)
– actuarial loss 3 5 1 1
Net settlement loss(a) 5 16 0 0
Net curtailment gain(b) — (3) 0 (14)
Net periodic benefit costs (credits)(c) $ 13 $ 24 $ (6) $ (21)}

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

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

^(d)~~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.~~

During the first six months of ~~2020,~~2021, we made contributions of ~~$12~~$14 million to our funded pension ~~plan and expect to contribute an additional $16 million this year.~~plan. During the first six months of ~~2020,~~2021, we also made payments of ~~$14~~$2 million and $8$5 million related to unfunded pension plans and other postretirement benefit plans. We expect to contribute an additional $9 million in contributions to our funded pension plan this year.

~~21.~~

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

20. 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 June 30,						Six Months Ended June 30,								Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	(In millions)	2020		2019		2020		2019		Income Statement Line	(In millions)	2021		2020		2021		2020		Income Statement Line
Postretirement and postemployment plans	Postretirement and postemployment plans												Postretirement and postemployment plans
Amortization of prior service credit	Amortization of prior service credit	$	7	$	6	$	13	$	12	Other net periodic benefit credit	Amortization of prior service credit	$	5	$	7	$	11	$	13	Other net periodic benefit costs
Amortization of actuarial loss	Amortization of actuarial loss	(3)		(2)		(6)		(4)		Other net periodic benefit credit	Amortization of actuarial loss	(1)		(3)		(4)		(6)		Other net periodic benefit costs
Net settlement loss	Net settlement loss	(14)		(2)		(16)		(2)		Other net periodic benefit credit	Net settlement loss	(5)		(14)		(5)		(16)		Other net periodic benefit costs
Net curtailment gain	Net curtailment gain	17		—		17		—		Other net periodic benefit credit	Net curtailment gain	0		17		0		17		Other net periodic benefit costs
Interest rate swaps											Interest rate swaps
Reclassification of de-designated forward interest rate swaps											Reclassification of de-designated forward interest rate swaps	(30)		0		(28)		0		Net interest and other

Total reclassifications to expense, net of tax ^(a)		$	7	$	2	$	8	$	6	Net income
Total reclassifications of (income) expense, net of tax (a)											Total reclassifications of (income) expense, net of tax (a)	$	(31)	$	7	$	(26)	$	8	Net income (loss)

^(a)During ~~2020~~2021 and ~~2019~~2020 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.

~~22.~~21. Supplemental Cash Flow Information


		Six Months Ended June 30,							Six Months Ended June 30,
(In millions)	(In millions)	2020		2019		(In millions)	2021		2020
Included in operating activities:	Included in operating activities:					Included in operating activities:
Interest paid, net of amounts capitalized	Interest paid, net of amounts capitalized	$	126	$	128	Interest paid, net of amounts capitalized	$	123	$	126
Income taxes paid to taxing authorities, net of refunds received ^(a)		4		66
Income taxes paid to (received from) taxing authorities, net of refunds (a)						Income taxes paid to (received from) taxing authorities, net of refunds (a)	$	9	$	4
Noncash investing activities:	Noncash investing activities:					Noncash investing activities:
Increase (decrease) in asset retirement costs	Increase (decrease) in asset retirement costs	$	(6)	$	29	Increase (decrease) in asset retirement costs	$	38	$	(6)
Asset retirement obligations assumed by buyer ^(b)		—		109

^(a)The six months ended June 30,2020 ~~and 2019~~ includes $4 ~~million and $89~~ million related to tax refunds.

^(b)~~In 2019, we closed on the sale of our working interest in the Droshky field (Gulf of Mexico), including our $98 million asset retirement obligation and the~~

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

~~sale of our non-operated interest in the Atrush block in Kurdistan.~~

Other noncash investing activities include accrued capital expenditures for the six months ended June 30, 2021 and 2020 of $85 million and ~~2019 of~~ $48 million, ~~and $300 million.~~respectively.

~~23.~~22. Equity Method Investments

During the periods ended June 30, ~~2020~~2021 and December 31, ~~2019~~2020 our equity method investees were considered related parties and ~~included:~~are summarized in the following table:


(In millions)	Ownership as of June 30, 2021	June 30, 2021		December 31, 2020
EGHoldings (a)	60%	$	138	$	113
Alba Plant LLC (b)	52%	168		168
AMPCO (c)	45%	152		166
Total		$	458	$	447

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

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

•(c)~~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:~~

MARATHON OIL CORPORATION

(In millions) Ownership as of June 30, 2020 June 30, 2020 December 31, 2019
EGHoldings 60% $ 139 $ 310
Alba Plant LLC 52% 168 163
AMPCO 45% 169 190
Total $ 476 $ 663

~~In the second quarter of 2020, we recorded an impairment of $152 million~~Notes 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.~~Consolidated Financial Statements (Unaudited)

Summarized financial information for equity method investees is as follows:


		Three Months Ended June 30,						Six Months Ended June 30,							Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	(In millions)	2020		2019		2020		2019		(In millions)	2021		2020		2021		2020
Income data:	Income data:									Income data:
Revenues and other income	Revenues and other income	$	111	$	233	$	283	$	453	Revenues and other income	$	246	$	111	$	481	$	283
Income (loss) from operations	Income (loss) from operations	(10)		82		(40)		131		Income (loss) from operations	111		(10)		207		(40)
Net income (loss)	Net income (loss)	(13)		63		(39)		95		Net income (loss)	$	85	$	(13)	$	157	$	(39)

Revenues from related parties were $8 million and $16 million for the three and six months ended June 30, 2021, respectively, and $10 million and $20 million for the three and six months ended ~~June 30,~~ 2020, ~~and $11 million and $21 million for the three and six months ended June 30, 2019~~respectively, with the majority related to EGHoldings in all periods.

Current receivables from related parties at June 30, 2021 and December 31, 2020 were ~~$25~~$18 million and $24 million, respectively, with the majority related to EGHoldings in both periods. Payables to related parties at June 30, 2021 were $6 million, with the majority related to EGHoldings and ~~$28~~$13 million at December 31, ~~2019 with the majority related EGHoldings and Alba Plant LLC. Payables to related parties at June 30,~~ 2020, ~~were $10 million with the majority related to EGHoldings and $11 million for December 31, 2019~~ with the majority related to Alba Plant LLC.

~~24.~~23. Commitments and Contingencies

In the second quarter of 2019, Marathon E.G. Production Limited (“MEGPL”), a consolidated and ~~wholly-owned~~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 (subject to certain limitations) 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 LLC and certain environmental liabilities ~~resulting~~arising from certain hydrocarbons in the ~~actions or inaction by~~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 ~~as completion of the plant modifications is not expected to finish until~~

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

~~2021, and as such, we do not have any history of~~or 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 approximately $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~~any 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. ~~We recorded a~~Our liability for these guarantees ofwas approximately $4 million as of June 30, ~~2020,~~2021, 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 June 30, ~~2020,~~2021, we have a ~~$101~~$121 million current liability in suspended royalty and working interest revenue, including interest, of which $111 million was included within accounts payable and $10 million related to accrued interest and was included within other current liabilities on our consolidated balance sheet. Additionally, we have a long-term receivable of ~~$25~~$24 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~~The enforcement action will likely result in monetary sanctions ~~in excess of $100,000; however,~~and corrective actions yet-to-be specified and, while the ultimate outcome and impact to us cannot be predicted with certainty, we ~~do not~~ believe these enforcement actions ~~would~~will not have a material adverse effect on our consolidated financial position, results of operations or cash ~~flow.~~ flows.

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. In addition, we may also be

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

subject to retained liabilities with respect to certain divested assets by operation of law. For example, declines in commodity prices have created an environment where there is an increased risk that owners and/or operators of assets purchased from us may no longer be able to satisfy plugging or abandonment obligations that attach to those assets. In that event, due to operation of law, we may be required to assume plugging or abandonment obligations for those assets. Although we have established reserves for such liabilities, we could be required to accrue additional amounts in the future and these amounts could be material. For instance, as the result of the declaration of bankruptcy by a third party to which we previously divested certain offshore assets, in the second quarter of 2021 we increased our existing reserve to $29 million related to the anticipated cost to decommission certain wells, pipelines and production facilities divested to such third party. We no longer own these assets nor are they related to our current operations.

Marathon Oil has been named in various lawsuits alleging royalty underpayments in our domestic operations, and plaintiffs in some of these lawsuits are seeking class certification. We intend to vigorously defend ourselves against such claims. Although we have accrued for potential liabilities associated with these lawsuits, those accruals are based on currently available information and involve elements of judgment and significant uncertainties. Accordingly, actual losses may exceed our accruals or we could be required to accrue additional amounts in the future and these amounts could be material.

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.

At June 30, 2021, accrued liabilities for remediation relating to environmental laws and regulations were not material. It is not presently possible to estimate the ultimate amount of all remediation cost that might be incurred or the penalties that may be imposed.

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

Results of Operations

Critical Accounting Estimates

Accounting Standards Not Yet Adopted

Cash Flows

Liquidity and Capital Resources

Environmental Matters and Other Contingencies

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

Executive Overview

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

~~Commodity prices declined substantially in the first half~~ Our reinvestment rate and capital allocation framework prioritizes free cash flow generation across a wide range of ~~2020. While~~ commodity prices ~~are likely~~ to ~~remain volatile, we believe we can manage through this lower commodity price macro environment as~~make available significant cash flow for investor-friendly purposes, including return of capital to shareholders and balance sheet enhancement. Keeping our ~~portfolio affords us the flexibility to respond to changing market conditions. Our primary focus remains on~~workforce safe, minimizing our environmental impact, strong corporate governance and 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~~are foundational 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~~execution of our ~~corporate~~strategy.

Throughout the COVID-19 pandemic, we leveraged our emergency response protocols and business continuity plans to help manage our operations and workforce. Our workforce ~~works~~worked remotely ~~as we plan~~for a significant period of time since the pandemic began. We implemented a process for a phased return of employees to the office last year and, during April 2021, the majority of our corporate workforce returned to the office. Working remotely ~~has~~did not significantly ~~impacted~~impact our ability to maintain operations, ~~has~~ allowed our field offices to operate without any disruption and ~~has~~did not ~~caused~~cause us to incur significant additional ~~expenses; however, we are unable to predict the duration or ultimate impact of these measures.~~expenses.

Key highlights include the following:

Maintained focus on balance sheet and liquidity

•At the end of the second quarter ~~2020,~~2021, we had approximately ~~$3.5~~$4.1 billion of liquidity, comprised of an undrawn ~~$3.0~~$3.1 billion revolving credit facility and ~~$0.5 billion~~$970 million in ~~cash, and no significant near-term debt maturities.~~cash. We r~~emain~~remain investment grade at all three primary rating agencies, with ~~recent reviews by all three primary~~Moody’s and Fitch recently upgrading their rating ~~agencies.~~outlooks to stable and positive, respectively.

•~~Continued~~In the first six months of 2021, we generated $1.3 billion of cash provided by operating activities, which was more than sufficient to fund our full redemption of our $500 million 2022 Notes, additions to property, plant and equipment of $483 million and dividends of $55 million.

•The June 30, 2021 cash balance reflects an increase of approximately $228 million from year-end, primarily due to higher commodity price realizations and continued capital discipline. Our U.S. segment average realized prices for crude oil and condensate, NGLs and natural gas for the six months ended June 30, 2021 were $60.08 per bbl, $24.06 per bbl and $4.43 per mcf, respectively.

•We continued our capital discipline ~~with an additional reduction of~~through the second quarter and are within our Capital Budget ~~to $1.2~~of $1.0 billion.

•~~Restructured a portion~~Consistent with our strategy to enhance the balance sheet, in August 2021, we sent an irrevocable notice of redemption to the trustee to fully redeem our ~~commodity derivative portfolio during~~outstanding $900 million 3.85% Senior Notes due 2025. See Note 16to the ~~quarter, which minimized the near-term crude downside~~consolidated financial statements and ~~protected basis differentials.~~

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

•Liquidity and Capital R es our c e s~~In April 2020, we took broad-based cost saving measures, including temporary base salary reductions~~ for ~~CEO and other corporate officers through year-end, a reduction in Board of Directors compensation through year-end, and U.S. employee and contractor workforce reductions.~~

•~~Temporarily suspended the quarterly dividend and share repurchases to maximize liquidity.~~

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

further information.

Financial and operational results

•In the second quarter of 2021, U.S. net sales volumes decreased by 7%8% to ~~308~~283 mboed, including a 4%13% 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.~~completion activities and natural decline.

•Our net ~~loss~~income per share was ~~$0.95~~$0.02 in the second quarter of ~~2020~~2021 as compared to a net ~~income~~loss per share of ~~$0.20~~$0.95 in the same period last year. Included in our financial results for the current quarter:

◦Revenues from contracts with customers ~~decreased $891~~increased $764 million compared to the same quarter last ~~year, largely due to lower price realizations and decreased production volumes. Average~~year. We experienced significant increases in realized prices for both crude oil ~~price realizations decreased by 64% during the first six months of 2020 as compared to the first six month of 2019.~~and condensate, NGLs and natural gas.

◦Net loss on commodity derivatives of $166 million, as compared to a net loss of $70 million ~~for the second quarter~~in 2020. The increase in derivative losses were a direct result of ~~2020,~~higher commodity prices.

◦Income from equity method investments of $49 million, an ~~$86~~increase of $201 million ~~decrease~~ from the same period in ~~2019, which was a net gain~~2020. The current quarter included higher price realizations whereas the same period in 2020 included impairments of ~~$16~~$152 million.

◦~~A non-cash impairment~~Lower depreciation, depletion and amortization expenses of ~~an investment in one of our equity method investees of $152 million.~~

•~~Net cash provided by operating activities in the first six months of 2020 decreased to $710~~$65 million, ~~or 46%~~ primarily as a result of lower ~~commodity price realizations, compared to the first six months~~production.

Compensation and ESG Highlights and Initiatives

•CEO and Board of ~~2019.~~Director total compensation reduced by approximately 25% with Board compensation mix shifted more toward equity and CEO mix further aligned with broader industry norms (exclusive of temporary reductions announced in 2020).

•~~The June 30, 2020~~Short-term incentive scorecard for compensation updated to focus on safety, environmental performance, capital efficiency, capital discipline/free cash flow generation and financial/balance ~~reflects~~sheet strength.

•Added a ~~decrease~~2021 GHG emissions intensity target to short-term incentive scorecard.

•Adopted a medium-term goal for GHG emissions intensity reduction by 2025.

•Continued Board of ~~approximately $336 million from year-end, due in part~~Director refreshment with two Directors added during the first quarter of 2021, reflecting commitment to ~~working capital changes reflecting the slowdown of 2020 capital activity.~~refreshment, independence, and diversity.

Outlook

Capital Budget

~~Earlier this year,~~In February 2021, we announced ~~an approved 2020~~a 2021 Capital Budget of ~~$2.4~~$1.0 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~~which is effectively a ~~reduction to our~~maintenance Capital Budget. We expect this maintenance-level Capital Budget ~~earlier~~will allow us to keep total company oil production in ~~the year to a level of $1.3 billion. Due to strong execution and capital efficiency improvement, in August we further reduced~~2021 consistent with our ~~full year~~fourth quarter 2020 ~~capital spending budget to $1.2 billion. This revised~~exit rate. Our 2021 Capital Budget ~~represents a 50% reduction of~~is consistent with our ~~original budget.~~ capital allocation framework that prioritizes corporate returns and free cash flow generation over production growth.

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~~2021 Capital Budget is weighted towards 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~~four U.S. resource plays with approximately 90% allocated to the ~~shifts in the macro environment.~~

~~Commensurate with our revised budget of $1.2 billion for 2020, we believe our full year production volumes will be between 370 mboed to 384 mboed.~~Eagle Ford and Bakken.

Operations

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

Three Months Ended June 30, Six Months Ended June 30,
Net Sales Volumes 2020 2019 Increase (Decrease) 2020 2019 Increase (Decrease)
United States (mboed)
308 330 (7) % 323 314 3 %
International (mboed)^(a)
84 107 (21) % 83 98 (15) %
Total (mboed)
392 437 (10) % 406 412 (1) %

^(a)In the first quarter of 2019, we announced the sale of our U.K. business, which closed in the third quarter of 2019. The six months ended June 30, 2019 includes net sales volumes related to the U.K. of 11 mboed. See ~~Note 4~~ ~~to the consolidated financial statements for further information.~~


	Three Months Ended June 30,				Six Months Ended June 30,
Net Sales Volumes	2021	2020	Increase (Decrease)		2021	2020	Increase (Decrease)
United States (mboed)	283	308	(8)	%	279	323	(14)	%
International (mboed)	65	84	(23)	%	66	83	(20)	%
Total (mboed)	348	392	(11)	%	345	406	(15)	%

United States

Net sales volumes in the segment were lower in the second quarter of ~~2020 but higher in~~2021 and the first six months of ~~2020~~2021 as compared to their respective ~~2019 periods. In the second quarter of~~ 2020 ~~we began the process of transitioning to a significantly~~periods with lower ~~level of drilling and completion activity across our domestic portfolio. This lower pace of activity had the biggest effect~~capital investment resulting in ~~Oklahoma, where we did not bring any~~fewer wells to sales ~~during~~year to date, coupled with natural decline. The decrease in capital investment is a direct result of the ~~quarter and experienced a significant decline~~demand contraction, beginning in ~~production. Overall sales volumes increased in~~2020, related to the ~~first six months of 2020 due to an increase in the absolute number of producing wells since June 30, 2019, primarily in the Bakken and Eagle Ford.~~

global pandemic.

We continue to expect that our planned pace of drilling and completions activity during the ~~second half~~remainder of the year will enable us to meet our ~~2020~~2021 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 June 30,						Six Months Ended June 30,								Three Months Ended June 30,			Six Months Ended June 30,
Net Sales Volumes	Net Sales Volumes	2020	2019	Increase (Decrease)		2020	2019	Increase (Decrease)		Net Sales Volumes	2021	2020	Increase (Decrease)		2021	2020	Increase (Decrease)
Equivalent Barrels (mboed)	Equivalent Barrels (mboed)									Equivalent Barrels (mboed)
Eagle Ford	Eagle Ford	108	109	(1)	%	111	107	4	%	Eagle Ford	91	108	(16)	%	84	111	(24)	%
Bakken	Bakken	103	103	—	%	106	98	8	%	Bakken	107	103	4	%	109	106	3	%
Oklahoma	Oklahoma	60	82	(27)	%	67	72	(7)	%	Oklahoma	54	60	(10)	%	54	67	(19)	%
Northern Delaware	Northern Delaware	30	27	11	%	30	27	11	%	Northern Delaware	24	30	(20)	%	25	30	(17)	%
Other United States	Other United States	7	9	(22)	%	9	10	(10)	%	Other United States	7	7	—	%	7	9	(22)	%
Total United States	Total United States	308	330	(7)	%	323	314	3	%	Total United States	283	308	(8)	%	279	323	(14)	%

Three Months Ended June 30, 2020
Sales Mix - U.S. Resource Plays Eagle Ford Bakken Oklahoma Northern Delaware Total
Crude oil and condensate 61 % 78 % 26 % 54 % 60 %
Natural gas liquids 18 % 12 % 28 % 21 % 18 %
Natural gas 21 % 10 % 46 % 25 % 22 %


	Three Months Ended June 30, 2021
Sales Mix - U.S. Resource Plays	Eagle Ford		Bakken		Oklahoma		Northern Delaware		Total
Crude oil and condensate	65	%	66	%	22	%	54	%	56	%
Natural gas liquids	16	%	20	%	32	%	23	%	21	%
Natural gas	19	%	14	%	46	%	23	%	23	%


	Three Months Ended June 30,		Six Months Ended June 30,
Drilling Activity - U.S. Resource Plays	2021	2020	2021	2020
Gross Operated
Eagle Ford:
Wells drilled to total depth	23	9	53	41
Wells brought to sales	45	20	70	58
Bakken:
Wells drilled to total depth	17	8	39	35
Wells brought to sales	16	8	19	33
Oklahoma:
Wells drilled to total depth	—	—	—	9
Wells brought to sales	—	—	—	13
Northern Delaware:
Wells drilled to total depth	—	3	—	15
Wells brought to sales	—	6	—	12

Three Months Ended June 30, Six Months Ended June 30,
Drilling Activity - U.S. Resource Plays 2020 2019 2020 2019
Gross Operated
Eagle Ford:
Wells drilled to total depth 9 36 41 66
Wells brought to sales 20 41 58 82
Bakken:
Wells drilled to total depth 8 20 35 32
Wells brought to sales 8 30 33 59
Oklahoma:
Wells drilled to total depth — 18 9 38
Wells brought to sales — 18 13 36
Northern Delaware:
Wells drilled to total depth 3 14 15 27
Wells brought to sales 6 16 12 31

•~~Eagle Ford~~– Our net sales volumes were 108 mboed in the second quarter of 2020, including oil sales of 66 mbbld and we brought 20 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 and plan to average 2 rigs and 1 frac crew over the second half of 2020.

•~~Bakken~~– Our net sales volumes were 103 mboed, including 81 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 over the second half of 2020.

•~~Oklahoma~~– Our net sales volumes were 60 mboed, including 16 mbbld of oil sales. During the quarter, we suspended all drilling and completions operations in Oklahoma; we do not plan to drill any additional wells in Oklahoma during 2020.

3029

•~~Northern Delaware~~ – Our net sales volumes were 30 mboed, including 16 mbbld of oil sales and we brought 6 gross company-operated wells to sales. We suspended all drilling and completions operations during the 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 second quarter of ~~2020~~2021 and the first six months of 2021 as compared to ~~the second quarter of 2019~~their respective 2020 periods primarily due to ~~timing of E.G~~fewer E.G. liftings ~~and disposition of our U.K. business.~~due to natural decline. The following table provides details regarding net sales volumes for our operations within this segment:

Three Months Ended June 30, Six Months Ended June 30,
Net Sales Volumes 2020 2019 Increase (Decrease) 2020 2019 Increase (Decrease)
Equivalent Barrels (mboed)
Equatorial Guinea 84 95 (12) % 83 85 (2) %
United Kingdom^(a)
— 10 (100) % — 11 (100) %
Other International — 2 (100) % — 2 (100) %
Total International
84 107 (21) % 83 98 (15) %
Equity Method Investees
LNG (mtd)
4,635 5,321 (13) % 4,850 4,981 (3) %
Methanol (mtd)
738 1,134 (35) % 962 1,069 (10) %
Condensate and LPG (boed)
10,896 11,080 (2) % 10,767 10,488 3 %

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


	Three Months Ended June 30,				Six Months Ended June 30,
Net Sales Volumes	2021	2020	Increase (Decrease)		2021	2020	Increase (Decrease)
Equivalent Barrels (mboed)
Equatorial Guinea	65	84	(23)	%	66	83	(20)	%



Equity Method Investees
LNG (mtd)	3,094	4,635	(33)	%	3,220	4,850	(34)	%
Methanol (mtd)	744	738	1	%	917	962	(5)	%
Condensate and LPG (boed)	7,892	10,896	(28)	%	9,303	10,767	(14)	%

•Equatorial Guinea – Net sales volumes in the second quarter and the first six months of ~~2020~~2021 were lower compared to the same period in ~~2019~~2020 primarily due to timing of liftings. We expect our production in the third quarter of 2020 to decline sequentially due to the impact of expected higher realized prices, which would reduce our net interest under the production sharing contract, higher third quarter facility downtime,fewer liftings and natural ~~field~~ decline.

•~~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.~~

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, redemption of our debt, 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 early second quarter of 2020 and ~~oil~~ prices partially recovered inthrough the ~~latter part~~end of the ~~second quarter. However, given~~year. Beginning in December 2020 and continuing through the ~~scale~~first six months of 2021, commodity prices continued to increase due to rising oil demand as COVID-19 vaccination rates and global economic activity increased. This was also supported by ongoing petroleum supply limitations by OPEC. Extreme winter weather in February 2021 also put upward pressure on natural gas prices during the first quarter of 2021. We continue to expect commodity price volatility as a result of the continuing impact of COVID-19 on worldwide demand, ~~contraction, we expect commodity prices~~the uneven pace of global economic recovery and OPEC supply policy. Refer to ~~remain volatile. Refer to Item~~Item 1A. Risk Factors in our ~~2019~~2020 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 second quarter and first six months of ~~2020~~2021 and ~~2019.~~2020.


		Three Months Ended June 30,										Six Months Ended June 30,											Three Months Ended June 30,				Six Months Ended June 30,
		2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)			2021		2020		Increase (Decrease)		2021		2020		Increase (Decrease)
Average Price Realizations^(a)	Average Price Realizations^(a)													Average Price Realizations(a)
Crude oil and condensate (per bbl)^(b)	Crude oil and condensate (per bbl)^(b)	$	21.65	$	59.18	(63)	%	$	33.60	$	56.72	(41)	%	Crude oil and condensate (per bbl)(b)	$	64.73	$	21.65	199	%	$	60.08	$	33.60	79	%
Natural gas liquids (per bbl)	Natural gas liquids (per bbl)	7.09		14.60		(51)	%	8.54		15.09		(43)	%	Natural gas liquids (per bbl)	24.17		7.09		241	%	24.06		8.54		182	%
Natural gas (per mcf)^(c)	Natural gas (per mcf)^(c)	1.44		1.89		(24)	%	1.52		2.36		(36)	%	Natural gas (per mcf)(c)	2.61		1.44		81	%	4.43		1.52		191	%
Benchmarks	Benchmarks													Benchmarks
WTI crude oil average of daily prices (per bbl)	WTI crude oil average of daily prices (per bbl)	$	28.00	$	59.91	(53)	%	$	36.82	$	57.45	(36)	%	WTI crude oil average of daily prices (per bbl)	$	66.17	$	28.00	136	%	$	62.22	$	36.82	69	%
Magellan East Houston (“MEH”) crude oil average of daily prices (per bbl)	Magellan East Houston (“MEH”) crude oil average of daily prices (per bbl)	25.66		66.32		(61)	%	37.60		63.37		(41)	%	Magellan East Houston (“MEH”) crude oil average of daily prices (per bbl)	67.13		25.66		162	%	63.22		37.60		68	%
Mont Belvieu NGLs (per bbl)^(d)	Mont Belvieu NGLs (per bbl)^(d)	12.25		19.20		(36)	%	12.70		21.19		(40)	%	Mont Belvieu NGLs (per bbl)(d)	24.81		12.25		103	%	24.40		12.70		92	%
Henry Hub natural gas settlement date average (per mmbtu)	Henry Hub natural gas settlement date average (per mmbtu)	1.72		2.64		(35)	%	1.83		2.89		(37)	%	Henry Hub natural gas settlement date average (per mmbtu)	2.83		1.72		65	%	2.76		1.83		51	%

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

^(b)Inclusion of realized gains (losses) on crude oil derivative instruments would have decreased average price realizations by $5.54 per bbl and increased average price realizations by $1.59 per bbl ~~and $0.32 per bbl~~ for the second quarter 2021 and 2020, ~~and 2019 and $1.53~~respectively. Inclusion of realized gain (losses) on crude oil derivative instruments would have decreased average price realizations by $5.08 per bbl and ~~$0.70~~increased average price realizations by $1.53 per bbl for the first six months of 2021 and 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 second quarter and first six months of ~~2020~~2021 and ~~2019.~~2020.


		Three Months Ended June 30,										Six Months Ended June 30,											Three Months Ended June 30,				Six Months Ended June 30,
		2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)			2021		2020		Increase (Decrease)		2021		2020		Increase (Decrease)
Average Price Realizations	Average Price Realizations													Average Price Realizations
Crude oil and condensate (per bbl)	Crude oil and condensate (per bbl)	$	13.79	$	58.21	(76)	%	$	24.40	$	56.36	(57)	%	Crude oil and condensate (per bbl)	$	52.78	$	13.79	283	%	$	49.06	$	24.40	101	%
Natural gas liquids (per bbl)	Natural gas liquids (per bbl)	1.00		1.67		(40)	%	1.00		1.81		(45)	%	Natural gas liquids (per bbl)	1.00		1.00		—	%	1.00		1.00		—	%
Natural gas (per mcf)	Natural gas (per mcf)	0.24		0.35		(31)	%	0.24		0.41		(41)	%	Natural gas (per mcf)	0.24		0.24		—	%	0.24		0.24		—	%
Benchmark	Benchmark													Benchmark
Brent (Europe) crude oil (per bbl)^(a)	Brent (Europe) crude oil (per bbl)^(a)	$	29.34	$	68.92	(57)	%	$	39.89	$	66.05	(40)	%	Brent (Europe) crude oil (per bbl)(a)	$	68.83	$	29.34	135	%	$	64.83	$	39.89	63	%

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

~~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 June 30, ~~2020~~2021 vs. Three Months Ended June 30, ~~2019~~2020

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


		Three Months Ended June 30,							Three Months Ended June 30,
(In millions)	(In millions)	2020		2019		(In millions)	2021		2020
Revenues from contracts with customers	Revenues from contracts with customers					Revenues from contracts with customers
United States	United States	$	462	$	1,200	United States	$	1,189	$	462
International	International	28		181		International	65		28
Segment revenues from contracts with customers	Segment revenues from contracts with customers	$	490	$	1,381	Segment revenues from contracts with customers	$	1,254	$	490

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 June 30, 2019 Price Realizations Net Sales Volumes Three Months Ended June 30, 2020
United States Price/Volume Analysis
Crude oil and condensate $ 1,021 $ (625) $ (35) $ 361
Natural gas liquids 84 (38) (9) 37
Natural gas 79 (17) (8) 54
Other sales 16 10
Total $ 1,200 $ 462
International Price/Volume Analysis
Crude oil and condensate $ 161 $ (63) $ (78) $ 20
Natural gas liquids 1 — — 1
Natural gas 13 (4) (2) 7
Other sales 6 —
Total $ 181 $ 28


			Increase (Decrease) Related to
(In millions)	Three Months Ended June 30, 2020		Price Realizations		Net Sales Volumes		Three Months Ended June 30, 2021
United States Price/Volume Analysis
Crude oil and condensate	$	361	$	623	$	(48)	$	936
Natural gas liquids	37		92		2		131
Natural gas	54		41		(4)		91
Other sales	10						31
Total	$	462					$	1,189
International Price/Volume Analysis
Crude oil and condensate	$	20	$	43	$	(5)	$	58
Natural gas liquids	1		—		—		1
Natural gas	7		—		(2)		5
Other sales	—						1
Total	$	28					$	65

Net gain (loss) on commodity derivatives Inin the second quarter of ~~2020, the~~2021, was a loss of $166 million, compared to a net loss ~~on commodity derivatives was~~of $70 million ~~compared to~~for the same period in ~~2019, which was a net gain of $16 million.~~2020. We have multiple crude oil, ~~and~~ 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 1514 to the consolidated financial statements for further information.

Income from equity method investments ~~decreased $183~~increased $201 million ~~for the~~in second quarter of ~~2020 from the comparable 2019 period~~2021 primarily due to ~~an impairment~~impairments of $152 million to an investment in an equity method investee ~~and lower volumes and~~in second quarter of 2020 coupled with higher price ~~realizations associated with our investees. See~~ ~~Note 11~~ ~~to the consolidated financial statements for further information on the equity method investee impairment.~~realizations.

Production expenses decreased ~~$64~~$3 million in the second quarter of ~~2020~~2021 versus the same period in ~~2019, primarily as a result of lower well workover and maintenance activities, lower~~2020. Our U.S. ~~contract labor, and the sale of our U.K. business which closed during the third quarter of 2019.~~

~~The second quarter of 2020~~segment production expense rate ~~(expense per boe) was lower for~~increased due to fewer wells to sales and natural decline. International ~~as a result of the sale of our U.K. business which closed during the third quarter of 2019. Our U.S.~~segment production expense rate ~~was lower as a result of the same reasons identified in the preceding paragraph in the second quarter of 2020. While the production expense rates for each of our U.S.~~increased due to fewer liftings and International segments were significantly lower than the prior period, we still expect our full year production expense rates to be consistent with previously provided guidance of $4.25 - $5.25 per boe and $2.15 - $2.65 per boe, respectively.natural decline.

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

Three Months Ended June 30,
($ per boe) 2020 2019 Increase (Decrease) 2020 2019 Increase (Decrease)
Production Expense and Rate Expense Rate
United States $ 114 $ 147 (22) % $ 4.09 $ 4.89 (16) %
International $ 15 $ 46 (67) % $ 1.88 $ 4.72 (60) %


	Three Months Ended June 30,
($ in millions; rate in $ per boe)	2021		2020		Increase (Decrease)		2021		2020		Increase (Decrease)
Production Expense and Rate	Expense						Rate
United States	$	113	$	114	(1)	%	$	4.41	$	4.09	8	%
International	$	13	$	15	(13)	%	$	2.17	$	1.88	15	%

Shipping, handling and other operating ~~decreased $65~~increased $62 million in the second quarter of ~~2020 primarily due to lower NGL~~2021 versus the same period in 2020. As disclosed in our Form 10-K, certain of our processing arrangements with midstream entities are percentage-of-proceeds contracts. We classify the proceeds retained by the midstream companies as shipping and handling ~~rates realized~~cost. The increase in ~~Bakken along with lower net sales volumes in Oklahoma. To the extent that our future Bakken realized NGL prices exceed those as compared to the second quarter, we expect our~~ shipping and handling costs toof these percentage-of-proceeds contracts coincides with the increase ~~as well.~~in realized natural gas liquids prices.

Exploration expenses include unproved property impairments, dry well costs, geological and geophysical, and other ~~costs, whichremained flat~~costs. The increase in ~~comparison~~unproved property impairments were primarily driven by our decision not to drill certain leases related to resource exploration in the second quarter of ~~2019.~~2021.

The following table summarizes the components of exploration expenses:


		Three Months Ended June 30,											Three Months Ended June 30,
(In millions)	(In millions)	2020		2019		Increase (Decrease)		(In millions)	2021		2020		Increase (Decrease)
Exploration Expenses	Exploration Expenses							Exploration Expenses
Unproved property impairments	Unproved property impairments	$	17	$	20	(15)	%	Unproved property impairments	$	22	$	17	29	%
Dry well costs	Dry well costs	1		—		—	%	Dry well costs	—		1		(100)	%
Geological and geophysical	Geological and geophysical	3		3		—	%	Geological and geophysical	1		3		(67)	%
Other	Other	5		3		67	%	Other	2		5		(60)	%
Total exploration expenses	Total exploration expenses	$	26	$	26	—	%	Total exploration expenses	$	25	$	26	(4)	%

Depreciation, depletion and amortization decreased $8$65 million in the second quarter of ~~2020 primarily due to the sale~~2021 as a result of lower sales volumes in our ~~U.K. business which closed during the third quarter of 2019.~~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)~~, which~~ is impacted by field-level changes in reserves, capitalized costs and sales ~~volumes, can also impact our DD&A expense. Our International DD&A rate decreased primarily due to the sale of our U.K. business which closed during the third quarter of 2019.~~

volume mix between fields. The following table provides DD&A expense and DD&A expense rates for each segment:


		Three Months Ended June 30,																				Three Months Ended June 30,
($ per boe)		2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
($ in millions; rate in $ per boe)														($ in millions; rate in $ per boe)	2021		2020			Increase (Decrease)		2021		2020		Increase (Decrease)
DD&A Expense and Rate	DD&A Expense and Rate	Expense										Rate							DD&A Expense and Rate	Expense						Rate
United States	United States	$	569	$	561	1	%	$	20.28	$	18.72	8	%	United States	$	506	$	569		(11)	%	$	19.65	$	20.28	(3)	%
International	International	$	22	$	38	(42)	%	$	2.86	$	3.92	(27)	%	International	$	18	$	22		(18)	%	$	3.08	$	2.86	8	%

Impairments~~decreased $18~~ increased $46 million ~~primarily as a result of impairments to certain non-core proved properties in our United States segment~~ in the second quarter of ~~2019.~~2021 due to a $24 million impairment as we decommissioned certain Eagle Ford central facilities and a $22 million impairment related to an increase in the estimated future decommissioning costs of certain non-producing wells, pipelines and production facilities for previously divested offshore assets located in the Gulf of Mexico. See Note 10, Note 11, and Note 23 to the consolidated financial statements for more detail.

Taxes other than incomeinclude production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. Taxes other than income ~~decreased $49~~increased $44 million primarily due to ~~lower~~higher price realizations ~~and lower sales volumes~~ in the U.S. segment in the second quarter of 2021.

General and administrative expenses decreased $20 million in the second quarter of 2021 as a result of cost savings realized from workforce reductions in the first quarters of 2021 and 2020.

Loss on early extinguishment of debt increased $19 million due to make-whole call provisions paid upon redemption of $500 million in senior unsecured notes in the second quarter of 2021. See Note 1 6 to the consolidated financial statements for further detail.

Provision (benefit) for income taxes reflects an effective income tax rate of 38% in the second quarter of 2021, as compared to an effective income tax rate of 2% in the ~~second quarter of 2020, as compared to an effective income tax rate of 17%~~same period in ~~the second quarter of 2019.~~2020. See~~Note 7~~Not e 6 to the consolidated financial statements for a more detailed discussion concerning the rate changes.

Segment Income

Segment income represents income ~~which~~that 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,~~and certain unproved properties, 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 June 30,											Three Months Ended June 30,
(In millions)	(In millions)	2020		2019		Increase (Decrease)		(In millions)	2021		2020
United States	United States	$	(365)	$	215	(270)	%	United States	$	207	$	(365)
International	International	(6)		96		(106)	%	International	68		(6)
Segment income (loss)	Segment income (loss)	(371)		311		(219)	%	Segment income (loss)	275		(371)
Items not allocated to segments, net of income taxes	Items not allocated to segments, net of income taxes	(379)		(150)		(153)	%	Items not allocated to segments, net of income taxes	(259)		(379)
Net income (loss)	Net income (loss)	$	(750)	$	161	(566)	%	Net income (loss)	$	16	$	(750)

United States segment ~~loss~~income (loss) Inin the second quarter of ~~2020, U.S. segment loss~~2021 was $~~365~~207 million ~~after-tax~~of income versus ~~$215~~a $365 million ~~income after-tax~~loss for the same period in ~~2019,~~2020. The increase in income was primarily due to ~~lower~~higher price realizations and ~~sales volumes in the current quarter, which was~~lower DD&A expenses. These favorable changes were partially offset by ~~lower production taxes,~~higher realized losses on commodity derivatives and higher shipping and handling ~~expense, and production expense.~~in the second quarter of 2021.

International segment ~~loss~~income (loss) Inin the second quarter of ~~2020, International segment loss~~2021 was $668 million ~~after-tax~~of income versus ~~$96~~a $6 million ~~income after-tax~~loss for the same period in ~~2019,~~2020, primarily due to ~~lower~~higher price realizations ~~in E.G. resulting in lower income from~~that yielded positive effects on both consolidated operations and our equity method ~~investments and the sale of our U.K. business in the third quarter of 2019.~~investees.

Results of Operations

Six Months Ended June 30, ~~2020~~2021 vs. Six Months Ended June 30, ~~2019~~2020

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


		Six Months Ended June 30,					Six Months Ended June 30,
(In millions)	(In millions)	2020		2019		(In millions)	2021		2020
Revenues from contracts with customers	Revenues from contracts with customers					Revenues from contracts with customers
United States	United States	$	1,432	$	2,262	United States	$	2,321	$	1,432
International	International	82		319		International	110		82
Segment revenues from contracts with customers	Segment revenues from contracts with customers	$	1,514	$	2,581	Segment revenues from contracts with customers	$	2,431	$	1,514

Increase (Decrease) Related to
(In millions) Six Months Ended June 30, 2019 Price Realizations Net Sales Volumes Six Months Ended June 30, 2020
United States Price/Volume Analysis
Crude oil and condensate $ 1,880 $ (818) $ 127 $ 1,189
Natural gas liquids 161 (68) (5) 88
Natural gas 182 (66) 5 121
Other sales 39 34
Total $ 2,262 $ 1,432
International Price/Volume Analysis
Crude oil and condensate $ 274 $ (84) $ (125) $ 65
Natural gas liquids 3 (1) — 2
Natural gas 28 (11) (2) 15
Other sales 14 —
Total $ 319 $ 82


			Increase (Decrease) Related to
(In millions)	Six Months Ended June 30, 2020		Price Realizations		Net Sales Volumes		Six Months Ended June 30, 2021
United States Price/Volume Analysis
Crude oil and condensate	$	1,189	$	761	$	(223)	$	1,727
Natural gas liquids	88		159		—		247
Natural gas	121		200		(15)		306
Other sales	34						41
Total	$	1,432					$	2,321
International Price/Volume Analysis
Crude oil and condensate	$	65	$	48	$	(18)	$	95
Natural gas liquids	2		—		—		2
Natural gas	15		—		(3)		12
Other sales	—						1
Total	$	82					$	110

Net gain (loss) on commodity derivatives Inin the first six months of ~~2020, the~~2021 was a loss of $319 million, of which $162 million related to realized net losses and $157 million related to unrealized net losses, compared to a net gain ~~on commodity derivatives was~~of $132 million ~~compared to~~for the same period in ~~2019 which was a net loss of $75 million.~~2020. We have multiple crude oil, ~~and~~ 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 1514 to the consolidated financial statements for further information.

Income (loss) from equity method investments ~~decreased $206~~increased $257 million for the first six months of ~~2020 primarily due to~~2021. We recognized an impairment of $152 million related to an investment in an equity method investee in the ~~second quarter of 2020 as well as lower price realizations and lower net sales volumes from equity method investments in E.G. due to the planned triennial turnaround in the first quarter of 2020.~~

~~Net gain on disposal of assetsdecreased $27 million for the~~ first six months of ~~2020 primarily as a result of the sale of our working interest in the Droshky field (Gulf of Mexico), which closed during the first quarter of 2019.~~

~~Other incomedecreased $35 million~~2020. Additionally, we experienced higher price realizations in the first six 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 IRS Audit in the first quarter of 2019.2021.

Production expenses for the first six months of ~~2020~~2021 decreased by ~~$91~~$42 million compared to the same period in ~~2019. Production expense in our International segment decreased $64 million~~2020, primarily as a result of the ~~sale of our U.K. business, which closed during the third quarter of 2019. Production~~U.S. segment’s lower operational costs and continued cost management, specifically staffing and contract labor. International segment production expense ~~in our United States segment~~amounts and rate decreased ~~$29 million primarily~~ due to lower ~~well workover~~contract services and ~~maintenance activities, and lower contract labor.~~

~~The first six months~~timing 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 sale of the U.K. business, which closed during the third quarter of 2019.

project activity.

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


		Six Months Ended June 30,																								Six Months Ended June 30,
($ per boe)		2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
($ in millions; rate in $ per boe)														($ in millions; rate in $ per boe)	2021		2020		Increase (Decrease)			2021		2020		Increase (Decrease)
Production Expense and Rate	Production Expense and Rate	Expense										Rate									Production Expense and Rate	Expense						Rate
United States	United States	$	257	$	286	(10)	%	$	4.37	$	5.04	(13)	%	United States	$	224	$	257	(13)	%		$	4.43	$	4.37	1	%
International	International	$	32	$	96	(67)	%	$	2.11	$	5.40	(61)	%	International	$	23	$	32	(28)	%		$	1.93	$	2.11	(9)	%

Shipping, handling and other operating expenses ~~decreased~~increased $7570 million in the first six months of ~~2020~~2021 from the comparable ~~2019 period, primarily~~2020 period. As disclosed in our Form 10-K, certain of our processing arrangements with midstream entities are percentage-of-proceeds contracts. We classify the proceeds retained by the midstream companies as ~~a result of lower NGL~~ shipping and handling ~~rates~~cost. The increase in shipping and handling costs of these percentage-of-proceeds contracts coincides with the increase in realized ~~in Bakken as well as lower net sales volumes in Oklahoma.~~natural gas liquids prices.

Exploration expenses include unproved property impairments, dry well costs, geological and geophysical, and other which decreased $31 million in the first six 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.costs.

The following table summarizes the components of exploration expenses:


		Six Months Ended June 30,											Six Months Ended June 30,
(In millions)	(In millions)	2020		2019		Increase (Decrease)		(In millions)	2021		2020		Increase (Decrease)
Exploration Expenses	Exploration Expenses							Exploration Expenses
Unproved property impairments	Unproved property impairments	$	39	$	64	(39)	%	Unproved property impairments	$	37	$	39	(5)	%
Dry well costs	Dry well costs	1		5		(80)	%	Dry well costs	2		1		100	%
Geological and geophysical	Geological and geophysical	4		9		(56)	%	Geological and geophysical	3		4		(25)	%
Other	Other	10		7		43	%	Other	4		10		(60)	%
Total exploration expenses	Total exploration expenses	$	54	$	85	(36)	%	Total exploration expenses	$	46	$	54	(15)	%

Depreciation, depletion and amortization ~~increased $82~~decreased $213 million in the first six months of ~~2020~~2021 from the comparable ~~2019~~2020 period, primarily ~~due to the higher net~~as a result of lower sales volumes in our U.S. ~~segment driven by first quarter 2020 activity, partially offset by the sale of our U.K. business, which closed during the third quarter of 2019.~~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)~~, which~~ is impacted by field-level changes in reserves, capitalized costs and sales ~~volumes, can also impact our DD&A expense. The DD&A rate for International decreased primarily as a result of dispositions.~~

volume mix between fields. The following table provides DD&A expense and DD&A expense rates for each segment:


		Six Months Ended June 30,																								Six Months Ended June 30,
($ per boe)		2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
($ in millions; rate in $ per boe)														($ in millions; rate in $ per boe)	2021		2020		Increase (Decrease)			2021		2020		Increase (Decrease)
DD&A Expense and Rate	DD&A Expense and Rate	Expense										Rate									DD&A Expense and Rate	Expense						Rate
United States	United States	$	1,186	$	1,075	10	%	$	20.15	$	18.98	6	%	United States	$	978	$	1,186	(18)	%		$	19.36	$	20.15	(4)	%
International	International	$	43	$	72	(40)	%	$	2.86	$	4.06	(30)	%	International	$	37	$	43	(14)	%		$	3.09	$	2.86	8	%

Impairments ~~increased $73~~decreased $50 million in the first six months of 2021. Impairments in 2021 consisted of a $24 million impairment as we decommissioned certain Eagle Ford central facilities and a $22 million impairment related to an increase in the estimated future decommissioning costs of certain non-producing wells, pipelines and production facilities for previously divested offshore assets located in the Gulf of Mexico. In 2020, ~~primarily as a result of impairment to~~we impaired goodwill for $95 million related to our International reporting unit in the first quarter of 2020. See NoNote 10, ~~te 1~~Note 11, and 1Note 23 for discussion of the impairments in further detail.

Taxes other than incomeinclude production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. Taxes other than income ~~decreased $55~~increased $52 million primarily due to ~~lower~~higher price realizations in the U.S. segment in the first six months of ~~2020.~~2021.

~~General~~Net interest and ~~administrative~~ otherdecreased $61 million ~~$17 million~~ in the first six months of 2021 versus the same period in 2020, primarily as a result of $49 million mark-to-market gains on forward starting interest rate swaps in the ~~change~~first six months of 2021. See Note 14 for further detail discussion of the interest rate swaps in ~~value of stock-based performance units tied to our total shareholder return (“TSR”) as compared to our peer group and a decrease in other compensation costs.~~the consolidated financial statements.

Loss on early extinguishment of debt

increased $19 million due to make-whole call provisions paid upon redemption of $500 million in senior unsecured notes in the second quarter of 2021. See Note 16 to the consolidated financial statements for further detail.

Provision (benefit) for income taxes reflects an effective income tax rate of 2%15% in the first six months of ~~2020,~~2021, as compared to an effective income tax rate of ~~(52)% for~~2% in the ~~comparable 2019 period.~~same period in 2020. SeeNote 76 to the consolidated financial statements for a more detailed discussion concerning the ~~components impacting the~~ rate ~~change.~~changes.

Segment Income

Segment income represents income ~~which~~that 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,~~and certain unproved properties, 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):


		Six Months Ended June 30,											Six Months Ended June 30,
(In millions)	(In millions)	2020		2019		Increase (Decrease)		(In millions)	2021		2020
United States	United States	$	(385)	$	347	(211)	%	United States	$	419	$	(385)
International	International	(7)		157		(104)	%	International	118		(7)
Segment income (loss)	Segment income (loss)	(392)		504		(178)	%	Segment income (loss)	537		(392)
Items not allocated to segments, net of income taxes	Items not allocated to segments, net of income taxes	(404)		(169)		(139)	%	Items not allocated to segments, net of income taxes	(424)		(404)
Net income (loss)	Net income (loss)	$	(796)	$	335	(338)	%	Net income (loss)	$	113	$	(796)

United States segment ~~loss~~income (loss) ~~For~~for the first six months of ~~2020, U.S. segment loss~~2021 was $419 million of income versus a $385 million ~~after-tax versus $347 million income after-tax~~loss loss for the same period in ~~2019,~~2020. This increase was primarily ~~as a result of lower crude~~due to higher price realizations and ~~higher~~lower DD&A ~~due to higher net sales volumes, which was~~expenses. These favorable changes were partially offset by lower ~~production taxes,~~sales volumes, realized losses on commodity derivatives (as compared to realized gains in the prior period), and higher shipping and handling ~~expense, and production expense.~~

~~International segment loss~~ ~~For~~costs in the first six months of ~~2020,~~ 2021.

International segment ~~loss~~income (loss) for the first six months of 2021 was $118 million of income versus a $7 million ~~after-tax versus $157 million income after-tax~~loss for the same period in ~~2019,~~2020, primarily due to ~~lower~~higher price realizations ~~and sales volumes partially offset by lower costs due to sale of our U.K. business~~ in ~~third~~E.G. in the second quarter of ~~2019.~~2021.

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~~

In the second quarter of 2020, we recorded an impairment of $152 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.

•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 field 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 field were based on forecasts received from the operator of the Alen field.

•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 Field 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.

~~SeeNote~~ 1 1 ~~to the consolidated financial statements for further information regarding the impairment recognized during the second 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. To the extent that commodity prices decline further throughout 2020, 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, principal debt repayments, payment of dividends and funding of share repurchases. ~~While we generated cash flows from operations~~As commodity prices increased during the first six months of ~~2020, the lower price environment reduced our~~2021, we generated positive cash flow ~~generation compared~~from operations. We continue to ~~the prior year. Should lower~~expect volatility in commodity prices ~~continue, our ability to generate~~and that could impact how much cash flow from operations ~~could be negatively affected.~~we generate. The following table presents sources and uses of cash and cash equivalents:


		Six Months Ended June 30,							Six Months Ended June 30,
(In millions)	(In millions)	2020		2019		(In millions)	2021		2020
Sources of cash and cash equivalents	Sources of cash and cash equivalents					Sources of cash and cash equivalents
Operating activities	Operating activities	$	710	$	1,312	Operating activities	$	1,277	$	710

Disposal of assets, net of cash transferred to the buyer	Disposal of assets, net of cash transferred to the buyer	9		69		Disposal of assets, net of cash transferred to the buyer	15		9
Other	Other	11		50		Other	6		11
Total sources of cash and cash equivalents	Total sources of cash and cash equivalents	$	730	$	1,431	Total sources of cash and cash equivalents	$	1,298	$	730
Uses of cash and cash equivalents	Uses of cash and cash equivalents					Uses of cash and cash equivalents
Additions to property, plant and equipment	Additions to property, plant and equipment	$	(946)	$	(1,262)	Additions to property, plant and equipment	$	(483)	$	(946)
Additions to other assets	Additions to other assets	12		42		Additions to other assets	—		12

Debt repayment						Debt repayment	(500)		—
Purchases of common stock	Purchases of common stock	(92)		(266)		Purchases of common stock	(9)		(92)
Dividends paid	Dividends paid	(40)		(82)		Dividends paid	(55)		(40)
Other	Other	—		(29)		Other	(23)		—
Total uses of cash and cash equivalents	Total uses of cash and cash equivalents	$	(1,066)	$	(1,597)	Total uses of cash and cash equivalents	$	(1,070)	$	(1,066)

Cash flows generated from operating activities in the first six months of ~~2020~~2021 were ~~46% lower~~80% higher compared to the same period in 2020, primarily as a result of higher realized commodity prices. These were partially offset by net realized losses on commodity derivatives (compared to realized gains in the prior period), lower ~~commodity price realizations.~~production volumes, and increased working capital usage.

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:


		Six Months Ended June 30,							Six Months Ended June 30,
(In millions)	(In millions)	2020		2019		(In millions)	2021		2020
United States	United States	$	698	$	1,292	United States	$	467	$	698
International	International	—		15		International	2		—
Corporate	Corporate	9		8		Corporate	4		9
Total capital expenditures	Total capital expenditures	707		1,315		Total capital expenditures	473		707
Change in capital expenditure accrual	Change in capital expenditure accrual	239		(53)		Change in capital expenditure accrual	10		239
Total use of cash and cash equivalents for property, plant and equipment	Total use of cash and cash equivalents for property, plant and equipment	$	946	$	1,262	Total use of cash and cash equivalents for property, plant and equipment	$	483	$	946

The decline in our capital expenditures for the U.S. segment in the first six months of 2021 compared to the same period in 2020, 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.~~resource plays.

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 June 30, ~~2020,~~2021, we had approximately ~~$3.5~~$4.1 billion of liquidity consisting of ~~$0.5 billion~~$970 million in cash and cash equivalents and ~~$3.0~~$3.1 billion available under our revolving Credit Facility. Additionally, in early July, we collected an $89 million cash refund related to alternative minimum tax credits and associated interest. We expect cash flow from operations to improve during each of the third and fourth quarters of 2020, relative to the second quarter 2020, commensurate with an expected increase in commodity prices relative to the second quarter. 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, dividends 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.~~

~~On May 6, 2020, our Board of Directors temporarily suspended our quarterly dividend payment as we prioritize our liquidity and balance sheet.~~

~~Capital Resources~~

~~Credit Arrangements and Borrowings~~

At June 30, 2020, we had no borrowings against our Credit Facility. At June 30, 2020, we had $5.5 billion of total debt outstanding, with our next significant debt maturity of $1.0 billion due 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. See Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2020 for a discussion of how a downgrade in our credit ratings could affect us.

On July 28, 2021, our Board of Directors approved a dividend of $0.05 per share payable September 10, 2021 to stockholders of record at the close of business on August 18, 2021.

Capital Resources

Credit Arrangements and Borrowings

~~We continue~~In June 2021, we executed the sixth amendment to ~~own $400 million~~our unsecured Credit Facility. The primary changes resulting from this amendment are (i) increasing the size of ~~St. John~~ the ~~Baptist, State~~Credit Facility from $3.0 billion to $3.1 billion, (ii) extending the maturity of ~~Louisiana revenue refunding bonds that were originally issued in December 2017. In July, we announced that~~the commitments of certain consenting lenders from May 2023 to June 2024 (with the remaining commitment of a single non-consenting lender to mature on May 28, 2023, at which time the size of the Credit Facility will be reduced to $3.0 billion) and (iii) including certain other provisions and revisions, including provisions to provide for the eventual replacement of LIBOR as a benchmark interest rate. See Note 16 to the consolidated financial statements for further information.

At June 30, 2021, we had ~~delivered~~no borrowings against our Credit Facility and $4.9 billion of total long-term debt outstanding. In April 2021, we fully redeemed our outstanding $500 million 2.8% Senior Notes due 2022 and the redemption reduced annual cash interest expense by $14 million. As a result of the redemption, we incurred $19 million in costs related to a make-whole provision premium and the write off of unamortized discount and issuance costs in the second quarter of 2021. In August 2021, we sent an irrevocable notice of redemption to the trustee to fully redeem our outstanding $900 million 3.85% 2025 Notes. We intend to settle the 2025 Notes and ~~remarketing agent a conditional notice of conversion of up~~pay the make-whole premium in September 2021 using cash on hand. The redemption will reduce annual cash interest expense by approximately $35 million. See Note 16 for further details related to ~~$400 million~~this redemption. Subsequent to the redemption of the ~~bonds~~2025 Notes, our next significant long-term debt maturity is in the amount of $1.0 billion due 2027. Refer to ~~remarket them in August. Information about these bonds are available~~our 2020 Annual Report on ~~the website~~Form 10-K for a listing 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.~~our long-term debt maturities.

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 ~~new Houston office location is expected to be completed in 2021. The~~ lessor and other participants are providing financing for up to ~~$380~~$340 million to fund the estimated project costs. As of June 30, ~~2020,~~2021, project costs incurred totaled approximately ~~$87~~$214 million, including land acquisition and construction costs. In June 2020, we submitted a notice to the lessor, as the construction agent, to reduce the financing capacity to $340 million to align with our revised estimate of the project costs. We expect the reduction to become effective in August 2020.

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 ~~33%~~24% and ~~31%~~26% at June 30, ~~2020~~2021 and at December 31, ~~2019, respectively.~~2020.

Capital Requirements

Share Repurchase Program

InNo share repurchases were made under our share repurchases program during the six months ended June 30, 2021; however, we repurchased $9 million of shares during the first quarter related to our tax withholding obligation associated with the vesting of ~~2020, we acquired approximately 9 million common shares at a cost of $85 million under our share repurchase program. While the~~employee restricted stock awards. Our share repurchase program has $1.3 billion of remaining ~~authorization, we elected to suspend additional share repurchases to preserve liquidity.~~authorization.

Contractual Cash Obligations

As of June 30, ~~2020,~~2021, there are no material changes to our ~~contractual~~consolidated cash obligations to make future payments under existing contracts, as ~~it relates to~~disclosed in 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. 2020 Annual Report on Form 10-K.

Environmental Matters and Other Contingencies

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

~~There~~Other than the items set forth in Part II - 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~~2020 Annual Report on Form 10-K. See Note 2423 to the consolidated financial statements for a description of other contingencies.

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~~future performance, business strategy, reserve estimates, asset quality, production guidance, drilling plans, capital plans, cost and ~~projects, planned wells, rig count, inventory, seismic, exploration plans, maintenance activities, drilling~~expense estimates, asset acquisitions 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 regardingdispositions, 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,~~other plans and ~~the benefits thereof; resource and asset potential; reserve estimates; growth expectations; and~~objectives for future ~~production and sales expectations, and the drivers thereof,~~cash flow from operations, are forward-looking statements. Words such as “anticipate,” “believe,” “continue,” “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;~~litigation or other proceedings and investigations;

•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 or legal obligations, including due to bankruptcy;

•changes in our credit ratings;

•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;~~security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business;

•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~~2020 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.

4441

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 1514 and Note 1615 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 June 30, ~~2020,~~2021, we had various open commodity derivatives. Based on the June 30, ~~2020~~2021 published NYMEX WTI, natural gas and natural gas liquids futures prices, a hypothetical 10% change (per bbl for crude oil, per MMbtu for ~~gas)~~gas and per bbl for NGL) would change the fair values of our ~~$79 million net asset position~~commodity derivative positions to the following:


(In millions)	(In millions)	Hypothetical Price Increase of 10%		Hypothetical Price Decrease of 10%		(In millions)	Fair Value		Hypothetical Price Increase of 10%		Hypothetical Price Decrease of 10%
Derivative asset - Crude Oil		$	57	$	93
Derivative asset (liability) - Crude Oil						Derivative asset (liability) - Crude Oil	$	(133)	$	(157)	$	(37)
Derivative asset (liability) - Natural Gas	Derivative asset (liability) - Natural Gas	(4)		5		Derivative asset (liability) - Natural Gas	(26)		(39)		(14)
Derivative asset (liability) - NGL						Derivative asset (liability) - NGL	(22)		(28)		(17)
Total	Total	$	53	$	98	Total	$	(181)	$	(224)	$	(68)

Interest Rate Risk

At June 30, ~~2020~~2021, our portfolio of current and long-term debt is comprised of fixed-rate instruments with an outstanding balance of ~~$5.5~~$4.9 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 June 30, ~~2020,~~2021, we had forward starting interest rate swap agreements with a total notional amount of ~~$1.1 billion~~$295 million designated as cash flow hedges and $875 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 2022 and 2025.~~office. A hypothetical 10% change in interest rates would change the fair values of our ~~$24 million net liability position~~cash flow hedge and de-designated cash flow hedge positions to the following as of June 30, ~~2020:~~2021:


(In millions)	(In millions)	Hypothetical Interest Rate Increase of 10%		Hypothetical Interest Rate Decrease of 10%		(In millions)	Fair Value		Hypothetical Interest Rate Increase of 10%		Hypothetical Interest Rate Decrease of 10%
Interest rate cash flow hedges		$	16	$	32
Interest rate asset (liability) - designated as cash flow hedges						Interest rate asset (liability) - designated as cash flow hedges	$	(8)	$	(7)	$	(9)
Interest rate asset (liability) - not designated as cash flow hedges						Interest rate asset (liability) - not designated as cash flow hedges	62		79		50
Total						Total	$	54	$	72	$	41

Item 4. Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this Report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as of June 30, ~~2020.~~2021.

During the first six months of ~~2020,~~2021, 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.

4542

Part II – OTHER INFORMATION

Item 1. Legal Proceedings

In January 2020, we received a Notice of Violation from the EPA related to the Clean Air Act. The enforcement action will likely result in monetary sanctions and corrective actions yet-to-be specified and while the ultimate outcome and impact to us cannot be predicted with certainty, we believe these enforcement actions will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

~~There~~Marathon Oil has been named in various lawsuits alleging royalty underpayments in our domestic operations, and plaintiffs in some of these lawsuits are seeking class certification. We intend to vigorously defend ourselves against such claims. Although we have accrued for potential liabilities associated with these lawsuits, those accruals are based on currently available information and involve elements of judgment and significant uncertainties. Accordingly, actual losses may exceed our accruals or we could be required to accrue additional amounts in the future and these amounts could be material.

Other than the items set forth above, there have been no significant changes to Item 3. Legal Proceedings in our ~~2019~~2020 Annual Report on Form 10-K. See Note 2423 to the consolidated financial statements included in Part I, Item I for a description of such legal and administrative ~~proceedings.~~proceedings and Item 3. Legal Proceedings in our 2020 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~~2020 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~~2020 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

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.10-K.

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 June 30, ~~2020~~2021 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)
04/01/2020 - 04/30/2020 21,168 $ 3.65 — $ 1,320,335,751
05/01/2020 - 05/31/2020 1,718 $ 5.50 — $ 1,320,335,751
06/01/2020 - 06/30/2020 1,050 $ 5.69 — $ 1,320,335,751
Total 23,936 $ 3.88 —


Period	Total Number of Shares Purchased(a)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(b)	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(b)
04/01/2021 - 04/30/2021	5,032	$	11.47	—	$	1,320,335,751
05/01/2021 - 05/31/2021	—	$	—	—	$	1,320,335,751
06/01/2021 - 06/30/2021	1,259	$	13.34	—	$	1,320,335,751
Total	6,291	$	11.85	—

^(a)~~23,936~~6,291 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.~~2019 for a total authorized amount of $7.15 billion.

As of June 30, ~~2020,~~2021, we have repurchased 191 million common shares at a cost of approximately ~~$5.9~~$5.8 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, or proceeds from potential asset ~~sales or cash from available borrowings to acquire shares.~~sales. 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 June 30, ~~2020~~2021 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.

4743

SIGNATURES

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


August ~~6, 2020~~5, 2021		MARATHON OIL CORPORATION

	By:	/s/ Gary E. Wilson
		Gary E. Wilson
		Vice President, Controller and Chief Accounting Officer
		(Duly Authorized Officer)

4844

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.

Incorporated by Reference
(File No. 001-05153, unless otherwise indicated)

Exhibit Number

Exhibit Description

Form

Exhibit

Filing Date

3.1

Restated Certificate of Incorporation of Marathon Oil Corporation

8-K

3.1

6/1/2018

3.2

Marathon Oil Corporation By-laws (amended and restated as of February 24, 2016)

10-Q

3.2

8/4/2016

3.3

Specimen of Common Stock Certificate

10-K

3.3

2/28/2014

4.1

Indenture, dated as of February��26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the SEC upon its request

10-K

4.2

2/28/2014

10.1

Sixth Amendment, dated as of June 21, 2021, to the Amended and Restated Credit Agreement dated as of May 28, 2014, as amended by the First Amendment, dated as of May 5, 2015, the Second Amendment, dated as of June 22, 2017, the Third Amendment, dated as of October 18, 2018, the Fourth Amendment, dated as of September 24, 2019, and the Fifth Amendment, dated as of December 4, 2020 and as supplemented by the Incremental Commitments Supplement, dated as of March 4, 2016 and Incremental Commitments Supplement, dated as July 11, 2017, among Marathon Oil Corporation, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions named therein

8-K

10.1

6/23/2021

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.


	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)	7
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	2827
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4542
Item 4.	Controls and Procedures	4542

Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	4643
Item 1A.	Risk Factors	4643
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4743

Item 6.	Exhibits	4743
	Signatures	4844


(In millions)	Ownership as of June 30, 2020	June 30, 2020		December 31, 2019
EGHoldings	60%	$	139	$	310
Alba Plant LLC	52%	168		163
AMPCO	45%	169		190
Total		$	476	$	663


Period	Total Number of Shares Purchased^(a)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs^(b)	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs^(b)
04/01/2020 - 04/30/2020	21,168	$	3.65	—	$	1,320,335,751
05/01/2020 - 05/31/2020	1,718	$	5.50	—	$	1,320,335,751
06/01/2020 - 06/30/2020	1,050	$	5.69	—	$	1,320,335,751
Total	23,936	$	3.88	—