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, ~~2019~~2020



☐			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 ~~804,042,151~~789,439,221 shares of Marathon Oil Corporation common stock outstanding as of July 31, ~~2019.~~2020.

MARATHON OIL CORPORATION

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

For certain industry specific terms used in this Form 10-Q, please see “Definitions” in our ~~2018~~2019 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)	2019			2018			2019			2018			(In millions, except per share data)	2020		2019		2020		2019
Revenues and other income:													Revenues and other income:
Revenues from contracts with customers	$	1,381		$	1,447		$	2,581		$	2,984		Revenues from contracts with customers	$	490	$	1,381	$	1,514	$	2,581
Net gain (loss) on commodity derivatives	16			(152		)	(75		)	(254		)	Net gain (loss) on commodity derivatives	(70)		16		132		(75)
Income from equity method investments	31			60			42			97
Income (loss) from equity method investments													Income (loss) from equity method investments	(152)		31		(164)		42
Net gain (loss) on disposal of assets	(8		)	50			34			307			Net gain (loss) on disposal of assets	(2)		(8)		7		34
Other income	13			12			48			16			Other income	6		13		13		48
Total revenues and other income	1,433			1,417			2,630			3,150			Total revenues and other income	272		1,433		1,502		2,630
Costs and expenses:													Costs and expenses:
Production	193			205			380			422			Production	129		193		289		380
Shipping, handling and other operating	170			126			324			256			Shipping, handling and other operating	105		170		249		324
Exploration	26			65			85			117			Exploration	26		26		54		85
Depreciation, depletion and amortization	605			612			1,159			1,202			Depreciation, depletion and amortization	597		605		1,241		1,159
Impairments	18			34			24			42			Impairments	—		18		97		24
Taxes other than income	79			65			151			129			Taxes other than income	30		79		96		151
General and administrative	87			105			181			205			General and administrative	88		87		164		181
Total costs and expenses	1,178			1,212			2,304			2,373			Total costs and expenses	975		1,178		2,190		2,304
Income from operations	255			205			326			777
Income (loss) from operations													Income (loss) from operations	(703)		255		(688)		326
Net interest and other	(64		)	(65		)	(113		)	(110		)	Net interest and other	(69)		(64)		(133)		(113)
Other net periodic benefit costs	2			—			7			(3		)
Income before income taxes	193			140			220			664
Other net periodic benefit credit													Other net periodic benefit credit	7		2		7		7
Income (loss) before income taxes													Income (loss) before income taxes	(765)		193		(814)		220
Provision (benefit) for income taxes	32			44			(115		)	212			Provision (benefit) for income taxes	(15)		32		(18)		(115)
Net income	$	161		$	96		$	335		$	452
Net income per share:
Net income (loss)													Net income (loss)	$	(750)	$	161	$	(796)	$	335
Net income (loss) per share:													Net income (loss) per share:
Basic	$	0.20		$	0.11		$	0.41		$	0.53		Basic	$	(0.95)	$	0.20	$	(1.00)	$	0.41
Diluted	$	0.20		$	0.11		$	0.41		$	0.53		Diluted	$	(0.95)	$	0.20	$	(1.00)	$	0.41
Weighted average common shares outstanding:													Weighted average common shares outstanding:
Basic	813			854			817			853			Basic	790		813		793		817
Diluted	814			855			817			854			Diluted	790		814		793		817

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
June 30, June 30,
(In millions) 2019 2018 2019 2018
Net income $ 161
$ 96
$ 335
$ 452
Other comprehensive income (loss), net of tax

Postretirement and postemployment plans:

Change in actuarial loss in postretirement and postemployment plans (9 ) 13
(13 ) 17
Postretirement and postemployment plans, net of tax (9 ) 13
(13 ) 17
Other, net of tax —
4
—
4
Other comprehensive income (loss) (9 ) 17
(13 ) 21
Comprehensive income $ 152

$ 113

$ 322

$ 473


	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2020		2019		2020		2019
Net income (loss)	$	(750)	$	161	$	(796)	$	335
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)		—





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

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)	2019			2018			(In millions, except par value and share amounts)	2020		2019
Assets							Assets
Current assets:							Current assets:
Cash and cash equivalents	$	961		$	1,462		Cash and cash equivalents	$	522	$	858
Receivables, less reserve of $12 and $11	1,144			1,079
Receivables, less reserve of $23 and $11							Receivables, less reserve of $23 and $11	620		1,122
Inventories	72			96			Inventories	77		72
Derivative assets							Derivative assets	79		9
Other current assets	101			257			Other current assets	107		74
Current assets held for sale	410			27
Total current assets	2,688			2,921			Total current assets	1,405		2,135
Equity method investments	684			745			Equity method investments	476		663
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $17,260 and $21,830	16,730			16,804
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $19,216 and $18,003							Property, plant and equipment, less accumulated depreciation, depletion and amortization of $19,216 and $18,003	16,424		17,000
Goodwill	95			97			Goodwill	—		95
Other noncurrent assets	420			723			Other noncurrent assets	262		352
Noncurrent assets held for sale	665			31
Total assets	$	21,282		$	21,321		Total assets	$	18,567	$	20,245
Liabilities							Liabilities
Current liabilities:							Current liabilities:
Accounts payable	$	1,401		$	1,320		Accounts payable	$	696	$	1,307
Payroll and benefits payable	88			154			Payroll and benefits payable	76		112
Accrued taxes	77			181			Accrued taxes	77		118
Other current liabilities	216			170			Other current liabilities	216		208
Long-term debt due within one year	600			—
Current liabilities held for sale	89			7
Total current liabilities	2,471			1,832			Total current liabilities	1,065		1,745
Long-term debt	4,902			5,499			Long-term debt	5,503		5,501
Deferred tax liabilities	184			199			Deferred tax liabilities	171		186
Defined benefit postretirement plan obligations	179			195			Defined benefit postretirement plan obligations	194		183
Asset retirement obligations	189			1,081			Asset retirement obligations	242		243
Deferred credits and other liabilities	292			279			Deferred credits and other liabilities	217		234
Noncurrent liabilities held for sale	964			108
Total liabilities	9,181			9,193			Total liabilities	7,392		8,092
Commitments and contingencies							Commitments and contingencies
Stockholders’ Equity							Stockholders’ Equity
Preferred stock - no shares issued or outstanding (no par value, 26 million shares authorized)	$	—		$	—
Preferred stock – no shares issued or outstanding (no par value, 26 million shares authorized)							Preferred stock – no shares issued or outstanding (no par value, 26 million shares authorized)	$	—	$	—
Common stock:							Common stock:
Issued – 937 million shares (par value $1 per share, 1.925 billion shares authorized at June 30, 2019 and December 31, 2018)	937			937
Held in treasury, at cost – 133 million shares and 118 million shares	(3,984		)	(3,816		)
Issued – 937 million shares (par value $1 per share, 1.925 billion shares authorized at June 30, 2020 and December 31, 2019)							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							Held in treasury, at cost – 147 million shares and 141 million shares	(4,087)		(4,089)
Additional paid-in capital	7,170			7,238			Additional paid-in capital	7,143		7,207
Retained earnings	7,928			7,706			Retained earnings	7,145		7,993
Accumulated other comprehensive income	50			63			Accumulated other comprehensive income	37		105
Total stockholders’ equity	12,101			12,128			Total stockholders’ equity	11,175		12,153
Total liabilities and stockholders’ equity	$	21,282		$	21,321		Total liabilities and stockholders’ equity	$	18,567	$	20,245

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)	2019			2018			(In millions)	2020		2019
Increase (decrease) in cash and cash equivalents							Increase (decrease) in cash and cash equivalents
Operating activities:							Operating activities:
Net income	$	335		$	452
Adjustments to reconcile net income to net cash provided by operating activities:
Net income (loss)							Net income (loss)	$	(796)	$	335
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	1,159			1,202			Depreciation, depletion and amortization	1,241		1,159
Impairments	24			42			Impairments	97		24
Exploratory dry well costs and unproved property impairments	69			93			Exploratory dry well costs and unproved property impairments	40		69
Net gain on disposal of assets	(34		)	(307		)	Net gain on disposal of assets	(7)		(34)
Deferred income taxes	(33		)	(6		)	Deferred income taxes	(14)		(33)
Net loss on derivative instruments	75			254
Net (gain) loss on derivative instruments							Net (gain) loss on derivative instruments	(132)		75
Net settlements of derivative instruments	27			(166		)	Net settlements of derivative instruments	57		27
Pension and other post retirement benefits, net	(41		)	(51		)	Pension and other post retirement benefits, net	(31)		(41)
Stock-based compensation	32			28			Stock-based compensation	28		32
Equity method investments, net	12			27			Equity method investments, net	180		12
Changes in:							Changes in:
Current receivables	(95		)	(256		)	Current receivables	489		(95)
Inventories	3			(17		)	Inventories	(5)		3
Current accounts payable and accrued liabilities	(158		)	133			Current accounts payable and accrued liabilities	(456)		(158)
Other current assets and liabilities	119			(8		)	Other current assets and liabilities	46		119
All other operating, net	(182		)	(4		)	All other operating, net	(27)		(182)
Net cash provided by operating activities	1,312			1,416			Net cash provided by operating activities	710		1,312
Investing activities:							Investing activities:
Additions to property, plant and equipment	(1,262		)	(1,300		)	Additions to property, plant and equipment	(946)		(1,262)
Additions to other assets	42			(129		)	Additions to other assets	12		42
Acquisitions, net of cash acquired	—			(25		)	Acquisitions, net of cash acquired	3		—
Disposal of assets, net of cash transferred to the buyer	69			1,183			Disposal of assets, net of cash transferred to the buyer	9		69
Equity method investments - return of capital	49			32			Equity method investments - return of capital	7		49
All other investing, net	(27		)	7			All other investing, net	—		(27)
Net cash used in investing activities	(1,129		)	(232		)	Net cash used in investing activities	(915)		(1,129)
Financing activities:							Financing activities:
Purchases of common stock	(266		)	(11		)	Purchases of common stock	(92)		(266)
Dividends paid	(82		)	(85		)	Dividends paid	(40)		(82)
All other financing, net	(2		)	18			All other financing, net	1		(2)
Net cash used in financing activities	(350		)	(78		)	Net cash used in financing activities	(131)		(350)
Effect of exchange rate on cash and cash equivalents	1			(2		)	Effect of exchange rate on cash and cash equivalents	—		1
Net increase (decrease) in cash and cash equivalents	(166		)	1,104
Net decrease in cash and cash equivalents							Net decrease in cash and cash equivalents	(336)		(166)
Cash and cash equivalents at beginning of period	1,462			563			Cash and cash equivalents at beginning of period	858		1,462
Cash and cash equivalents at end of period	$	1,296		$	1,667		Cash and cash equivalents at end of period	$	522	$	1,296

Reconciliation of cash and cash equivalents							Reconciliation of cash and cash equivalents
Cash and cash equivalents	$	961		$	1,667		Cash and cash equivalents	$	522	$	961
Cash and cash equivalents included in current assets held for sale	335			—			Cash and cash equivalents included in current assets held for sale	—		335
Total cash and cash equivalents	$	1,296		$	1,667		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)	Preferred Stock		Common Stock		Treasury Stock			Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Equity
Six Months Ended June 30, 2018
December 31, 2017 Balance	$	—	$	937	$	(3,325	)	$	7,379		$	6,779		$	(62	)	11,708
Shares issued - stock-based compensation	—		—		158			(93		)	—			—			65
Shares repurchased	—		—		(8		)	—			—			—			(8		)
Stock-based compensation	—		—		—			(49		)	—			—			(49		)
Net income	—		—		—			—			356			—			356
Other comprehensive income (loss)	—		—		—			—			—			4			4
Dividends paid (per share amount of $0.05)	—		—		—			—			(42		)	—			(42		)
March 31, 2018 Balance	$	—	$	937	$	(3,175	)	$	7,237		$	7,093		$	(58	)	$	12,034
Shares issued - stock-based compensation	—		—		40			(15		)	—			—			25
Shares repurchased	—		—		(2		)	—			—			—			(2		)
Stock-based compensation	—		—		—			5			—			—			5
Net income	—		—		—			—			96			—			96
Other comprehensive income (loss)	—		—		—			—			—			17			17
Dividends paid (per share amount of $0.05)	—		—		—			—			(43		)	—			(43		)
June 30, 2018 Balance	$	—	$	937	$	(3,137	)	$	7,227		$	7,146		$	(41	)	$	12,132

Six Months Ended June 30, 2019
December 31, 2018 Balance	$	—	$	937	$	(3,816	)	$	7,238		$	7,706		$	63		12,128
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
Cumulative-effect adjustment (Note 2)	—		—		—			—			(31		)	—			(31		)	Cumulative-effect adjustment (Note 2)	—		—		—		—		(12)		—		(12)
Shares issued - stock based compensation	—		—		101			(39		)	—			—			62			Shares issued - stock based compensation	—		—		121		(83)		—		—		38
Shares repurchased	—		—		(30		)	—			—			—			(30		)	Shares repurchased	—		—		(91)		—		—		—		(91)
Stock-based compensation	—		—		—			(50		)	—			—			(50		)	Stock-based compensation	—		—		—		(22)		—		—		(22)
Net income (loss)	—		—		—			—			174			—			174
Other comprehensive income (loss)	—		—		—			—			—			(4		)	(4		)
Net loss																				Net loss	—		—		—		—		(46)		—		(46)
Other comprehensive loss																				Other comprehensive loss	—		—		—		—		—		(22)		(22)
Dividends paid (per share amount of $0.05)	—		—		—			—			(41		)	—			(41		)	Dividends paid (per share amount of $0.05)	—		—		—		—		(40)		—		(40)
March 31, 2019 Balance	$	—	$	937	$	(3,745	)	$	7,149		$	7,808		$	59		$	12,208
March 31, 2020 Balance																				March 31, 2020 Balance	$	—	$	937	$	(4,059)	$	7,102	$	7,895	$	83	$	11,958
Shares issued - stock-based compensation	—		—		(3		)	5			—			—			2			Shares issued - stock-based compensation	—		—		(28)		20		—		—		(8)
Shares repurchased	—		—		(236		)	—			—			—			(236		)

Stock-based compensation	—		—		—			16			—			—			16			Stock-based compensation	—		—		—		21		—		—		21
Net income	—		—		—			—			161			—			161
Other comprehensive income (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
Net loss																				Net loss	—		—		—		—		(750)		—		(750)
Other comprehensive loss																				Other comprehensive loss	—		—		—		—		—		(46)		(46)

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

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


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 ~~2018~~2019 Annual Report on Form 10-K. The results of operations for the second quarter and first six months of ~~2019~~2020 are not necessarily indicative of the results to be expected for the full year.

As a result of the announcement to sell our U.K. business in the first quarter of 2019, we have reflected these assets and liabilities as held for sale at June 30, 2019 in the consolidated balance sheet and the consolidated statement of cash flows. The related disclosures in this report exclude these held for sale amounts, unless otherwise noted. This divestiture is discussed in further detail in ~~Note 4~~.

~~Reclassifications~~

We have reclassified certain prior year amounts within operating cash flow to present it on a basis comparable with the current year’s presentation with no impact on net cash provided by operating activities.

2. Accounting Standards

~~Not Yet~~Recently Adopted

Financial instruments – credit losses

In June 2016, the FASB issued a new accounting standards update that changes the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. On January 1, 2020 we adopted this standard using the modified retrospective transition method through a cumulative-effect adjustment of $12 million to retained earnings as of the beginning of the adoption period. The standard requires the use of a forward-looking “expected loss” model as opposed to the ~~current~~ “incurred loss” ~~model. This standard is effective~~model used previously. See Note 8 for ~~us in the first quarter of 2020 and will be adopted~~more information on a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period. Early adoption is permitted starting January 2019. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows.credit losses.

~~Recently Adopted~~

~~Lease accounting standard~~

In February 2016, the FASB issued a new leasing accounting standard, which modified the definition of a lease and established comprehensive accounting and financial reporting requirements for leasing arrangements. It requires lessees to recognize a lease liability and a right-of-use (“ROU”) asset for all leases, including operating leases, with a term of greater than 12 months on the balance sheet. On January 1, 2019, we adopted the new lease accounting standard using the modified retrospective method and applied to all leases that existed as of that date. It does not apply to leases to explore for or use minerals, oil, natural gas and similar non-regenerative resources, including the intangible right to explore for those natural resources and rights to use the land in which those natural resources are contained.

The new lease standard requires certain accounting policy decisions while also providing a number of optional practical expedients for transition accounting. Our accounting policies and the practical expedients utilized are summarized below:

~~Implemented an accounting policy to not recognize any right-of-use assets and lease liabilities related to short-term leases on the balance sheet.~~

~~Implemented an accounting policy to not separate the lease and nonlease components for all asset classes, except for vessels.~~

Elected the package of practical expedients which allows us to not reassess our prior conclusions regarding the lease identification and lease classification for contracts that commenced or expired prior to the effective date.

~~MARATHON OIL CORPORATION~~

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

Elected the practical expedient pertaining to land easements which allows us to continue accounting for existing agreements under the previous accounting policies as nonlease transactions. Any modifications of existing contracts or new agreements will be assessed under the new lease accounting guidance and may become leases in the future.

As a result of the adoption, we recorded a cumulative-effect adjustment to stockholders’ equity on the date of adoption of $31 million. We continue presenting all prior comparative periods without any restatements.

~~Hedge accounting standard~~

In August 2017, the FASB issued a new accounting standards update that amends the hedge accounting model to enable entities to hedge certain financial and nonfinancial risk attributes previously not allowed. The amendment also reduces the overall complexity of documenting, assessing and measuring hedge effectiveness. This standard was effective for us in the first quarter of 2019. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

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

Three Months Ended June 30, Six Months Ended June 30,
(In millions, except per share data) 2019 2018 2019 2018
Net income $ 161
$ 96
$ 335
$ 452

Weighted average common shares outstanding 813
854
817
853
Effect of dilutive securities 1
1
—
1
Weighted average common shares, diluted 814
855
817
854
Net income per share:
Basic $ 0.20
$ 0.11
$ 0.41
$ 0.53
Diluted $ 0.20
$ 0.11
$ 0.41
$ 0.53

Dividends per share $ 0.05
$ 0.05
$ 0.10
$ 0.10


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

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

Dividends per share	$	—	$	0.05	$	0.05	$	0.10

4. Dispositions

~~United States Segment~~

In the second quarter of 2019, we entered into agreements to sell non-core, proved properties and classified these transactions as held for sale in the consolidated balance sheet at June 30, 2019, with total assets of $26 million and total liabilities of $7 million.

In the second quarter of 2018, we entered into separate agreements to sell non-core, non-operated conventional properties, primarily in the Gulf of Mexico. These transactions closed during the third quarter of 2018.

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)~~, which resulted in~~ for proceeds of approximately $95 million ~~and~~which reflects the assumption by RockRose Energy PLC (the buyer) of the U.K. business’ cash equivalent balance and working capital ~~and cash equivalent balances~~balance as of ~~approximately $345 million on December 31,~~year-end 2018. ~~The transaction has an effective date of January 1, 2019.~~

~~MARATHON OIL CORPORATION~~

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

Our U.K. business was classified as held for sale in the consolidated balance sheets at June 30, 2019, with total assets of $1,049 million (including $125 million in cash restricted by escrow agreement terms with the balance transferring to buyer upon close) and total liabilities of $1,046 million, including asset retirement obligations of $966 million. For the second quarter of 2019 and 2018, we had approximately $22 million and $48 million, in income before income taxes relating to our ~~U.K business. For~~U.K. business for the three and six months ended June 30, 2019, ~~and 2018, we had approximately $37~~was $18 million and ~~$107 million, in income before income taxes relating to our U.K business.~~$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. ~~This property was classified as held for sale in the consolidated balance sheet at December 31, 2018, with total assets of $58 million and total liabilities of $17 million.~~

~~In the first quarter of 2018, we closed on the sale of our subsidiary, Marathon Oil Libya Limited, which held our 16.33% non-operated interest in the Waha concessions in Libya,~~

MARATHON OIL CORPORATION

Notes to ~~a subsidiary of Total S.A. (Elf Aquitaine SAS) for proceeds of approximately $450 million, excluding closing adjustments, and recognized a pre-tax gain of $255 million.~~Consolidated Financial Statements (Unaudited)

5. Revenues

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

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

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

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


	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


	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, 2019
(In millions)	E.G.		U.K.		Other Int’l		Total
Crude oil and condensate	$	101	$	51	$	9	$	161
Natural gas liquids	1		—		—		1
Natural gas	9		4		—		13
Other	—		6		—		6
Revenues from contracts with customers	$	111	$	61	$	9	$	181


	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, 2019
(In millions)	E.G.		U.K.		Other Int’l		Total
Crude oil and condensate	$	148	$	107	$	19	$	274
Natural gas liquids	2		1		—		3
Natural gas	16		12		—		28
Other	—		14		—		14
Revenues from contracts with customers	$	166	$	134	$	19	$	319

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

~~International~~

Three Months Ended June 30, 2019
(In millions) E.G. U.K. Other International Total
Crude oil and condensate $ 101
$ 51
$ 9
$ 161
Natural gas liquids 1
—
—
1
Natural gas 9
4
—
13
Other —
6
—
6
Revenues from contracts with customers $ 111
$ 61
$ 9
$ 181

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

Six Months Ended June 30, 2019
(In millions) E.G. U.K. Other International Total
Crude oil and condensate $ 148
$ 107
$ 19
$ 274
Natural gas liquids 2
1
—
3
Natural gas 16
12
—
28
Other —
14
—
14
Revenues from contracts with customers $ 166
$ 134
$ 19
$ 319

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~Contract receivables and liabilities~~

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

(In millions) June 30, 2019 January 1, 2019
Receivables from contracts with customers, included in receivables, less reserves $ 797
$ 714
Contract asset (liability) $ 21
$ (1 )

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

~~Changes in the contract asset (liability) balance during the period are as follows.~~

Six Months Ended
(In millions) June 30, 2019
Contract asset (liability) balance as of January 1, 2019 $ (1 )
Revenue recognized as performance obligations are satisfied 74
Amounts invoiced to customers (52 )
Contract asset (liability) balance as of June 30, 2019 $ 21

6. Segment Information

We have ~~two~~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.~~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~~ ~~and produces and markets products manufactured from natural gas, such as LNG and methanol, in Equatorial Guinea (“E.G.”)~~

~~Information regarding assets by segment is not presented because it is not reviewed by~~ the ~~chief operating decision maker~~United States

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

Segment income represents income which excludes certain items not allocated to our operating segments, net of income taxes. A portion of our corporate and operations general and administrative support costs are not allocated to the operating segments. These unallocated costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Additionally, items which affect comparability such as: gains or losses on dispositions, impairments of proved property, ~~impairments,~~goodwill, and equity method investments, unrealized gains or losses on commodity derivative instruments, effects of pension ~~settlement losses~~settlements and curtailments, or other items (as determined by the ~~CODM)~~chief operating decision maker (“CODM”)) are not allocated to operating segments.


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

Taxes other than income	30		—		—			30
General and administrative	32		3		53		^(d)	88
Net interest and other	—		—		69			69
Other net periodic benefit credit	—		—		(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	$	—	$	2		$	139

^(a)Includes accruals.

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

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

^(d)Includes severance expenses 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).

Three Months Ended June 30, 2019
Not Allocated
(In millions) U.S. Int’l 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 costs —
(1 ) (1 ) (2 )
Income tax provision (benefit) 3
17
12
32
Segment income $ 215
$ 96
$ (150 ) $ 161
Capital expenditures^(a)
$ 686
$ 10
$ 5
$ 701


^(a)	~~Includes accruals.~~


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


^(c)	~~Primarily related to the sale of our certain non-core proved properties in our International segment (See~~ ~~Note 4~~).


^(d)	~~Primarily a result of the anticipated sale of non-core proved properties in the United States segment (See~~ ~~Note 10~~).

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
Revenues from contracts with customers	$	1,432	$	82	$	—		$	1,514
Net gain on commodity derivatives	57		—		75		^(b)	132
Loss from equity method investments	—		(12)		(152)		^(c)	(164)
Net gain on disposal of assets	—		—		7			7
Other income	7		4		2			13
Less costs and expenses:
Production	257		32		—			289
Shipping, handling and other operating	231		4		14			249
Exploration	54		—		—			54
Depreciation, depletion and amortization	1,186		43		12			1,241
Impairments	—		—		97		^(d)	97
Taxes other than income	96		—		—			96
General and administrative	64		7		93		^(e)	164
Net interest and other	—		—		133			133
Other net periodic benefit credit	—		—		(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	$	—	$	9		$	707

^(a)Includes accruals.

Three Months Ended June 30, 2018
Not Allocated
(In millions) U.S. Int’l to Segments Total
Revenues from contracts with customers $ 1,221
$ 226
$ —
$ 1,447
Net loss on commodity derivatives (107 ) —
(45 )
^(b)
(152 )
Income from equity method investments —
60
—
60
Net gain on disposal of assets —
—
50
50
Other income 2
2
8
12
Less costs and expenses:
Production 153
52
—
205
Shipping, handling and other operating 117
10
(1 ) 126
Exploration 64
1
—
65
Depreciation, depletion and amortization 556
50
6
612
Impairments —
—
34
^(c)
34
Taxes other than income 68
—
(3 ) 65
General and administrative 35
9
61
�� 105
Net interest and other —
—
65
65
Other net periodic benefit costs —
(2 ) 2
—
Income tax provision (benefit) —
26
18
44
Segment income (loss) $ 123
$ 142
$ (169 ) $ 96
Capital expenditures^(a)
$ 641
$ 16
$ 5
$ 662
^(b)Unrealized gain on commodity derivative instruments (SeeNote 15).

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

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

^(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 (SeeNote 20).


^(a)	~~Includes accruals.~~


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


^(c)	~~Primarily a result of anticipated sales of certain non-core proved properties in our International and United States segments (See~~ ~~Note 10~~).

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Six Months Ended June 30, 2019
Not Allocated
(In millions) U.S. Int’l to Segments Total
Revenues 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 costs —
(3 ) (4 )
(7 )
Income tax provision (benefit) 1
6
(122 )
^(f)
(115 )
Segment income $ 347
$ 157
$ (169 ) $ 335
Capital expenditures^(a)
$ 1,292
$ 15
$ 8
$ 1,315


^(a)	~~Includes accruals.~~


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


^(c)	~~Primarily related to the sale of our working interest in the Droshky field (Gulf of Mexico) (See~~ ~~Note 4~~).


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


^(e)	~~Primarily a result of anticipated sales of our certain non-core proved properties in our International and United States segments (See~~ ~~Note 10~~).


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


	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).

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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


^(a)	~~Includes accruals.~~


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


^(c)	~~Primarily related to the gain on sale of our Libya subsidiary (See~~ ~~Note 4~~).


^(d)	~~Primarily a result of anticipated sales of certain non-core proved properties in our International and United States segments (See~~ ~~Note 4~~).

~~MARATHON OIL CORPORATION~~

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

7. Income Taxes

Effective Tax Rate

The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The difference between the total provision and the sum of the amounts allocated to segments is reported in the “Not Allocated to Segments” column of the tables in Note 6.

For the three and six months ended June 30, ~~2019~~2020 and ~~2018,~~2019, our effective income tax rates were as follows:

Three Months Ended June 30, Six Months Ended June 30,
2019 2018 2019 2018
Effective income tax expense (benefit) rate^(a)
17 % 31 % (52 )% 32 %


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

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


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

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

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

•For the three and six months ended June 30, 2019, ~~and 2018:~~

~~Income taxes for~~ the ~~second quarter~~mix of ~~2019 were impacted by~~ pre-tax income ~~and foreign currency revaluation.~~ in our international operations reduced the annual effective tax rate below the statutory tax rate. Income ~~taxes~~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%.

~~Income taxes~~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.

8. Credit Losses

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

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

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.

Changes in the allowance for doubtful accounts balance for the ~~second quarter of 2018~~six months ended were ~~impacted by foreign currency revaluation. During~~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

^(a)For the six months ended June 30, ~~2018, income taxes were impacted~~2020, the current period provision increased by ~~the tax expense~~$7 million in ~~Libya of $162 million.~~joint interest receivables and decreased by $1 million in trade receivables.

9. Inventories

As a result of the IRS Audit settlement in the first quarter of 2019, the uncertain tax positions previously established are now effectively settled. The release of the accrued uncertain tax positions resulted in a $126 million tax benefit, primarily related to the additional alternative minimum tax (“AMT”) credits, see ~~Note 22~~ ~~for further detail.~~

Pursuant to the Tax Sharing Agreement we entered into with Marathon Petroleum Corporation (“MPC”) in connection with the 2011 spin-off transaction, MPC agreed to indemnify us for certain liabilities. In addition to the benefit from the settlement of the IRS Audit in the first quarter of 2019, we recorded a current receivable and other income of $42 million for indemnity payments due from MPC for tax expense and interest we had previously recognized. The indemnity relates to tax and interest allocable to MPC as a result of the IRS Audit. During the second quarter of 2019, we paid the IRS and were subsequently reimbursed by MPC for settlement of their indemnity obligation.

During the first quarter of 2019, we withdrew our appeal related to the Brae area decommissioning costs in the U.K., thus the uncertain tax positions previously established are now considered effectively settled with no tax expense or benefit impact.

~~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.

(In millions) June 30, 2019 December 31, 2018
Crude oil and natural gas $ 9
$ 11
Supplies and other items 63
85
Inventories $ 72
$ 96

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

~~MARATHON OIL CORPORATION~~

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

9.10. 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

(In millions) June 30, 2019 December 31, 2018
United States $ 16,112
$ 16,011
International 540
710
Corporate 78
83
Net property, plant and equipment $ 16,730

$ 16,804

We had no0 exploratory well costs capitalized greater than one year as of June 30, ~~2019~~2020 and December 31, ~~2018.~~2019.

~~10.~~11. Impairments

During the first quarter of 2020, a global pandemic caused a substantial deterioration in the worldwide demand of hydrocarbons. The ~~following table summarizes~~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 ~~proved properties. Additionally, it presents~~impairment. Equity method investments are assessed for impairment whenever changes in the ~~values~~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 ~~assets, by major category, measured at~~the equity method investment is written down to fair ~~value on a nonrecurring basis in periods subsequent to their initial recognition.~~

Three Months Ended June 30,
2019 2018
(In millions) Fair Value Impairment Fair Value Impairment
Long-lived assets held for use $ 19
$ 18
$ 69
$ 34

Six Months Ended June 30,
2019 2018
(In millions) Fair Value Impairment Fair Value Impairment
Long-lived assets held for use $ 56
$ 24
$ 69
$ 42

•

~~2019~~ – During the six months ended June 30, 2019, we recorded pre-tax non-cash proved property impairments of $24 million, primarily as a result of 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 discussion of the divestiture in further detail.~~

•

~~2018~~– During the six months ended June 30, 2018, we recorded pre-tax non-cash proved property impairments of $42 million, to a fair value of $69 million, primarily as a result of anticipated sales proceeds for certain non-core proved properties in our International and United States segments. The related fair value measurement utilized the market approach, based upon anticipated sales proceeds less costs to sell which resulted in a Level 2 classification. See ~~Note 4~~ ~~for discussion of the divestiture in further detail.~~

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

value. Our first quarter review concluded that any potential losses in values of our equity method investments were temporary because the underlying declines in both commodity prices and demand did not materially manifest until early March. However, during the second quarter of 2020, we did recognize an impairment related to one of our equity method investees as noted in the table below.

~~11.~~

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


	Three Months Ended June 30,
	2020						2019
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	—	$	—	$	19	$	18
Equity method investment	$	142	$	152	N/A		$	—



	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		$	—

•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. 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 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 differential is $126 million and will be accreted into income over the next 6.5 years, which is consistent with the remaining useful life of the investee’s primary assets.

Impairments for the six months ended June 30, 2020 also included $95 million of goodwill impairment in the International reporting unit. See No te 1 4 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. 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,
(In millions)	2020		2019
Beginning balance as of January 1	$	255	$	1,145
Incurred liabilities, including acquisitions	2		18
Settled liabilities, including dispositions	(3)		(129)
Accretion expense (included in depreciation, depletion and amortization)	6		26
Revisions of estimates	(8)		11
Held for sale	—		(864)
Ending balance as of June 30	$	252	$	207

June 30,
(In millions) 2019 2018
Beginning balance $ 1,145
$ 1,483
Incurred liabilities, including acquisitions 18
8
Settled liabilities, including dispositions (129 ) (14 )
Accretion expense (included in depreciation, depletion and amortization) 26
36
Revisions of estimates 11
(9 )
Held for sale (864 ) (89 )
Ending balance $ 207
$ 1,415
June 30, 2020

•Ending balance includes $10 million 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. See Note 4 for discussion of the divestitures in further detail. •	~~Settled liabilities~~ ~~are primarily related 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. See ~~Note 4for discussion of the divestitures in further detail.~~


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

June 30, ~~2018~~


•	~~Held for sale~~ ~~includes the asset retirement obligations associated with the sale of non-core, non-operated conventional properties, primarily in the Gulf of Mexico. See~~ ~~Note 4for discussion of the divestitures in further detail.~~


•	~~Ending balance~~ ~~includes $51 million classified as short-term at June 30, 2018.~~

~~12. Leases~~2019.

~~Supplemental balance sheet information related to leases was as follows:~~

(In millions) June 30, 2019
Operating Leases: Balance Sheet Location:
ROU asset Other noncurrent assets $ 248
Current portion of long-term lease liability Other current liabilities $ 104
Long-term lease liability Deferred credits and other liabilities $ 151

In determining our ROU assets and long-term lease liabilities, the new lease standard requires certain accounting policy decisions, while also providing a number of optional practical expedients for transition accounting. Our accounting policies and the practical expedients utilized are summarized below:

~~Implemented an accounting policy to not recognize any right-of-use assets and lease liabilities related to short-term leases on the balance sheet.~~

~~Implemented an accounting policy to not separate the lease and nonlease components for all asset classes, except for vessels.~~

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

13. Leases

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

The majority of the drilling rig agreements and all of fracturing equipment agreements are classified as short-term leases based on the noncancellable period for which we have the right to use the equipment and assessment of options present in each agreement. We also incur variable lease costs under these agreements primarilySupplemental balance sheet information related to chemicals and sand used in fracturing operations or various additional on-demand equipment and labor. The lease costs associated with the drilling rigs and fracturing equipment are primarily capitalizedleases was as ~~part of the well costs.~~follows:

Our long-term leases are comprised of compressors, buildings, drilling rigs, aircraft, vessels, vehicles and miscellaneous field equipment. Our lease agreements may require both fixed and variable payments; none of the variable payments are rate or index-based, therefore only fixed payments were considered for recognizing lease liabilities and ROU assets related to long-term leases. Also, based on our election not to separate the lease and nonlease components, fixed payments related to equipment, crew and other nonlease components are included in the initial measurement of lease liabilities and ROU assets for all asset classes, except for vessels. For vessels, the contractual consideration was allocated between lease and nonlease components based on estimates provided by service providers.

Our leased assets may be used in joint oil and gas operations with other working interest owners. We recognize lease liabilities and ROU assets only when we are the signatory to a contract as an operator of joint properties. Such lease liabilities and ROU assets are determined based on gross contractual obligations. As we use the leased assets for joint operations, we have the contractual right to recover the other working interest owners’ share of lease costs. As a result, our lease costs are presented on a net basis, reduced for any costs recoverable from other working interest owners. The table below presents our net lease costs as of June 30, 2019 with the majority of operating lease costs expensed as incurred, while the majority of the short-term and variable term lease costs are capitalized into property, plant and equipment.

(In millions) Three Months Ended June 30, 2019 Six Months Ended June 30, 2019
Lease costs:
Operating lease costs^(a)
$ 19
$ 40
Short-term lease costs^(b)
76
157
Variable lease costs^(c)
12
72
Total lease costs $ 107
$ 269

Other information:
Cash paid for amounts included in the measurement of operating lease liabilities $ 27
ROU assets obtained in exchange for new operating lease liabilities^(d)
$ 293


^(a)(In millions)			~~Represents our net share of the ROU asset amortization and the interest expense.~~			June 30, 2020

Operating Leases:			Balance Sheet Location:
^(b)Right-of-use asset			~~Represents our net share of lease costs arising from leases of less than one year but longer than one month that were not included in the lease liability.~~

Other noncurrent assets	$	153
^(c)Current portion of long-term lease liability			~~Represents our net share of variable lease payments that were not included in the lease liability.~~

Other current liabilities	$	83
^(d)Long-term lease liability			Represents the cumulative value of ROU assets recognized at lease inception during the first six months of 2019. This amount is then amortized as we utilize the ROU asset, the net effect of which is the ending ROU asset of $248 million (first table above).Deferred credits and other liabilities			$	74

~~MARATHON OIL CORPORATION~~

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

We use our periodic incremental borrowing rate to discount future contractual payments to their present values. The weighted average lease term and the discount rate relevant to long-term leases were three years and 4% as of June 30, 2019. The remaining annual undiscounted cash flows associated with long-term leases and the reconciliation of these cash flows to the lease liabilities recognized on the consolidated balance sheet is summarized below.

(In millions) Operating Lease Obligations
2019 $ 61
2020 106
2021 62
2022 35
2023 5
Thereafter 1
Total undiscounted lease payments $ 270
Less: amount representing interest 15
Total operating lease liabilities $ 255
Less: current portion of long-term lease liability as of June 30, 2019 104
Long-term lease liability as of June 30, 2019 $ 151

At December 31, 2018, future minimum commitments under the previous accounting standard, ASC 840, for operating lease obligations having noncancellable lease terms in excess of one year were as follows:

(In millions) Operating Lease Obligations
2019 $ 62
2020 54
2021 35
2022 12
2023 5
Thereafter 49
Sublease rentals —
Total minimum lease payments $ 217

^*~~Future minimum commitments for capital lease obligations were nil as of December 31, 2018.~~

Our wholly-owned subsidiary, Marathon E.G. Production Limited, is a lessor for residential housing in Equatorial Guinea, which is occupied by EGHoldings, a related party equity method investee – see Note 2124. The lease was classified as an operating lease and expires in 2024, with a lessee option to extend through 2034. Lease payments are fixed for the entire duration of the agreement at approximately $6 million per year. Our lease income is reported in other income in our consolidated statements of income for all periods presented. The undiscounted cash flows to be received under this lease agreement are summarized below.

(In millions) Operating Lease Future Cash Receipts
2019 $ 4
2020 6
2021 6
2022 6
2023 6
Thereafter 66
Total undiscounted cash flows $ 94

~~MARATHON OIL CORPORATION~~

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


(In millions)	Operating Lease Future Cash Receipts
2020	$	3
2021	6
2022	6
2023	6
2024	6
Thereafter	60
Total undiscounted cash flows	$	87

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 million, to fund the estimated project costs. As of June 30, ~~2019,~~2020, project costs incurred totaled approximately ~~$50~~$87 million, ~~primarily for~~including land acquisition and ~~initial design~~construction costs. The initial lease term is five years and will commence once construction is substantially complete and the new Houston office is ready for occupancy. At the end of the initial lease term, we can negotiate to extend the lease term for an additional five years, subject to the approval of the participants; purchase the property subject to certain terms and conditions; or remarket the property to an unrelated third party. The lease contains a residual value guarantee of approximately 89% of the total acquisition and construction costs.

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.

~~13.~~

14. Goodwill

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

We estimated the fair value of our International reporting unit using a combination of market and income approaches. The market approach referenced observable inputs specific to us and our industry, such as the price of our common equity, our

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

15. Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note 1416. All of our commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we report net amounts. The following tables present the gross fair values of derivative instruments and the reported net amounts along with where they appear on the consolidated balance sheets.


	June 30, 2020
(In millions)	Asset		Liability		Net Asset (Liability)		Balance Sheet Location
Not Designated as Hedges
Commodity	$	100	$	21	$	79	Derivative assets



Total Not Designated as Hedges	$	100	$	21	$	79

Cash Flow Hedges

Interest Rate	$	—	$	26	$	(26)	Deferred credits and other liabilities
Interest Rate	2		—		2		Other noncurrent assets
Total Designated Hedges	$	2	$	26	$	(24)
Total	$	102	$	47	$	55


	June 30, 2019									December 31, 2019
(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
Commodity	$	33	$	4	$	29		Other current assets	Commodity	$	9	$	1	$	8	Derivative assets
Commodity	—		4		(4		)	Deferred credits and other liabilities	Commodity	1		—		1		Other noncurrent assets
Commodity									Commodity	—		5		(5)		Other current liabilities
Total Not Designated as Hedges	$	33	$	8	$	25			Total Not Designated as Hedges	$	10	$	6	$	4

Cash Flow Hedges									Cash Flow Hedges
Interest Rate									Interest Rate	$	2	$	—	$	2	Other noncurrent assets
Total Designated Hedges									Total Designated Hedges	$	2	$	—	$	2
Total									Total	$	12	$	6	$	6

December 31, 2018
(In millions) Asset Liability Net Asset (Liability) Balance Sheet Location
Not Designated as Hedges
Commodity $ 131
$ —
$ 131
Other current assets
Commodity —
4
(4 ) Deferred credits and other liabilities
Total Not Designated as Hedges $ 131
$ 4
$ 127

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

The following table sets forth outstanding derivative contracts as of June 30, ~~2019,~~2020, and the weighted average prices for those contracts:


														2020						2021
	2019						2020			2021				Third Quarter		Fourth Quarter		Full Year
Crude Oil	Third Quarter			Fourth Quarter			Full Year			Full Year			Crude Oil
NYMEX WTI Three-Way Collars ^(a)
Volume (Bbls/day)	80,000			80,000			9,945			—			Volume (Bbls/day)	80,000		80,000		—
Weighted average price per Bbl:													Weighted average price per Bbl:
Ceiling	$	74.19		$	74.19		$	70.00		$	—		Ceiling	$	64.40	$	64.40	$	—
Floor	$	56.75		$	56.75		$	55.00		$	—		Floor	$	55.00	$	55.00	$	—
Sold put	$	49.50		$	49.50		$	47.00		$	—		Sold put	$	48.00	$	48.00	$	—
Basis Swaps - Argus WTI Midland^(b)
NYMEX WTI Two-Way Collars													NYMEX WTI Two-Way Collars
Volume (Bbls/day)													Volume (Bbls/day)	33,478		—		—
Weighted average price per Bbl:													Weighted average price per Bbl:
Ceiling													Ceiling	$	40.47	$	—	$	—
Floor													Floor	$	30.98	$	—	$	—
Fixed Price WTI Swaps													Fixed Price WTI Swaps
Volume (Bbls/day)	15,000			15,000			15,000			—			Volume (Bbls/day)	10,000		—		—
Weighted average price per Bbl	$	(1.40	)	$	(1.40	)	$	(0.94	)	$	—		Weighted average price per Bbl	$	32.77	$	—	$	—
Basis Swaps - Net Energy Clearbrook ^(c)
Basis Swaps - Argus WTI Midland^(a)													Basis Swaps - Argus WTI Midland^(a)
Volume (Bbls/day)	1,000			1,000			—			—			Volume (Bbls/day)	15,000		15,000		—
Weighted average price per Bbl	$	(3.50	)	$	(3.50	)	$	—		$	—		Weighted average price per Bbl	$	(0.94)	$	(0.94)	$	—
Basis Swaps - NYMEX WTI / ICE Brent ^(d)
Basis Swaps - NYMEX WTI / ICE Brent ^(b)													Basis Swaps - NYMEX WTI / ICE Brent ^(b)
Volume (Bbls/day)	5,000			5,000			5,000			808			Volume (Bbls/day)	5,000		5,000		808
Weighted average price per Bbl	$	(7.24	)	$	(7.24	)	$	(7.24	)	$	(7.24	)	Weighted average price per Bbl	$	(7.24)	$	(7.24)	$	(7.24)
Basis Swaps - Argus WTI Houston ^(e)
Volume (Bbls/day)	10,000			10,000			—			—
Weighted average price per Bbl	$	5.51		$	5.51		$	—		$	—

NYMEX Roll Basis Swaps													NYMEX Roll Basis Swaps
Volume (Bbls/day)	60,000			60,000			—			—			Volume (Bbls/day)	60,000		30,000		—
Weighted average price per Bbl	$	0.38		$	0.38		$	—		$	—		Weighted average price per Bbl	$	(1.58)	$	(0.81)	$	—

Natural Gas													Natural Gas
Two-Way Collars													Two-Way Collars
Volume (MMBtu/day)													Volume (MMBtu/day)	—		—		62,329
Weighted average price per MMBtu:													Weighted average price per MMBtu:
Ceiling													Ceiling	$	—	$	—	$	3.07
Floor													Floor	$	—	$	—	$	2.44

Basis Swaps - WAHA / HH ^(c)													Basis Swaps - WAHA / HH ^(c)
Volume (MMBtu/day)													Volume (MMBtu/day)	10,000		10,000		—
Weighted average price per MMBtu													Weighted average price per MMBtu	$	(0.37)	$	(0.37)	$	—

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


^(a) ^(b)The basis differential price is indexed against Intercontinental Exchange (“ICE”) Brent and NYMEX WTI.	~~Between July 1, 2019 and August 5, 2019, we entered into 10,000 Bbls/day of three-way collars for January - December 2020, with a ceiling of $65.12, a sold put of $48.00, and a floor of $55.00.~~


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


^(c)	~~The basis differential price is indexed against Net Energy Canada Bakken SW at Clearbrook (“UHC”).~~


^(d)	~~The basis differential price is indexed against International Commodity Exchange (“ICE”) Brent and NYMEX WTI.~~


^(e)	~~The basis differential price is indexed against Argus WTI Houston.~~

^(c)The ~~mark-to-market impact~~basis differential price is indexed against Waha and settlement of these commodity derivative instruments appears in net gain (loss) on commodity derivatives in our consolidated statements of income. The mark-to-market impact for the three and six months ended June 30, 2019 was a gain of $11 million and a loss of $102 million compared to a loss of $45 million and a loss of $88 million for the same respective periods in 2018. Net settlements of commodity derivative instruments for the three and six months ended June 30, 2019 was a gain of $5 million and a gain of $27 million compared to a loss of $107 million and a loss of $166 million for the same respective periods in 2018.NYMEX Henry Hub.

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, and the weighted average prices for those contracts:

~~14.~~


	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	$	—

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


	Three Months Ended 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

Derivatives Designated as Cash Flow Hedges

During 2020, we entered into forward starting interest rate swaps with a notional amount of $500 million to hedge variations in cash flows arising from fluctuations in the London Interbank Offered Rate (“LIBOR”) benchmark interest rate related to forecasted interest payments of a future debt issuance in 2022; and an additional $300 million of notional for our future debt issuance in 2025. We expect to refinance both of the debt maturities in 2022 and 2025. The swaps will terminate on or prior to the refinancing of the debt and the final value will be reclassified from accumulated other comprehensive income into earnings with each future interest payment. Subsequent to June 30, 2020, we entered into additional forward starting interest rate swaps with a notional amount of $50 million and a weighted average rate of 0.90% to hedge variations in cash flows related to the same LIBOR interest rate for our debt due in 2025.

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

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.

16. Fair Value Measurements

Fair Values – Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of June 30, ~~2019~~2020 and December 31, ~~2018~~2019 by hierarchy level.


	June 30, 2020
(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets
Commodity^(a)	$	—	$	88	$	—	$	88
Interest rate	—		2		—		2
Derivative instruments, assets	$	—	$	90	$	—	$	90
Derivative instruments, liabilities
Commodity^(a)	$	(9)	$	—	$	—	$	(9)
Interest rate	—		(26)		—		(26)
Derivative instruments, liabilities	$	(9)	$	(26)	$	—	$	(35)
Total	$	(9)	$	64	$	—	$	55


	June 30, 2019											December 31, 2019
(In millions)	Level 1			Level 2		Level 3		Total			(In millions)	Level 1		Level 2		Level 3		Total
Derivative instruments, assets											Derivative instruments, assets
Commodity^(a)	$	—		$	30	$	—	$	30		Commodity^(a)	$	—	$	7	$	—	$	7
Interest rate											Interest rate	—		2		—		2
Derivative instruments, assets	$	—		$	30	$	—	$	30		Derivative instruments, assets	$	—	$	9	$	—	$	9
Derivative instruments, liabilities											Derivative instruments, liabilities
Commodity^(a)	$	(5	)	$	—	$	—	$	(5	)	Commodity^(a)	$	(3)	$	—	$	—	$	(3)

Derivative instruments, liabilities	$	(5	)	$	—	$	—	$	(5	)	Derivative instruments, liabilities	$	(3)	$	—	$	—	$	(3)
Total											Total	$	(3)	$	9	$	—	$	6

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


^(a)Note 15	~~Derivative instruments are recorded on a net basis in our consolidated balance sheet. See~~ ~~Note 13~~.

December 31, 2018
(In millions) Level 1 Level 2 Level 3 Total
Derivative instruments, assets
Commodity^(a)
$ 21
$ 106
$ —
$ 127
Derivative instruments, assets $ 21
$ 106
$ —
$ 127
Derivative instruments, liabilities
Derivative instruments, liabilities $ —
$ —
$ —
$ —


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

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 ~~basis swaps and NYMEX roll basis~~ swaps, inputs to the models include only commodity prices and interest rates and are categorized as Level 1 because all assumptions and inputs are observable in active markets throughout the term of the instruments. For three-way collars and two-

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

way collars, inputs to the models include commodity prices and implied volatility and are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.

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

Fair Value Estimates -– Goodwill

~~As of June 30, 2019, our consolidated balance sheet included goodwill of $95 million. Goodwill is tested~~See Note 14 for impairment on an annual basis, or between annual tests when events or changes in circumstances indicate the fair value may have been reduced below its carrying value. Goodwill is tested for impairment at the reporting unit level. Our reporting units are the same as our reporting segments, of which only the International reporting unit includesdetail information relating to goodwill. Our policy is to first assess the qualitative factors in order to determine whether the fair value of our International reporting unit is more likely than not less than its carrying amount. Certain qualitative factors used in our evaluation include, among other things, the results of the most recent quantitative assessment of goodwill (second quarter of 2017); macroeconomic conditions; industry and market conditions (including commodity prices and cost factors); overall financial performance; and other relevant entity-specific events. If, after considering these events and circumstances we determine that it is more likely than not the fair value of the International reporting unit is less than its carrying amount, the quantitative goodwill test is performed.

During the second quarter of 2019, we performed our annual impairment test of goodwill using the qualitative assessment. Our qualitative assessment considered the significant excess fair value over carrying value in our most recent step one test and noted there are more positive/neutral indicators than negative. After assessing the totality of these qualitative factors, our assessment did not indicate that it is more likely than not that the fair value is less than its carrying value. As a result, we concluded that no impairment to goodwill was required for our International reporting unit.

Fair Values – Nonrecurring

See Note 411 ~~and~~ ~~Note 10~~ for detail on our fair values ~~for nonrecurring items, such as~~related to impairments.

~~MARATHON OIL CORPORATION~~

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

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, ~~2019~~2020 and December 31, ~~2018.~~2019.


	June 30, 2019				December 31, 2018					June 30, 2020						December 31, 2019
(In millions)	Fair Value		Carrying Amount		Fair Value		Carrying Amount		(In millions)	Fair Value		Carrying Amount		Fair Value		Carrying Amount
Financial assets									Financial assets
Current assets	$	4	$	4	$	3	$	3	Current assets	$	4	$	4	$	4	$	4
Other noncurrent assets	25		31		76		81		Other noncurrent assets	28		44		26		38
Total financial assets	$	29	$	35	$	79	$	84	Total financial assets	$	32	$	48	$	30	$	42
Financial liabilities									Financial liabilities
Other current liabilities	$	76	$	101	$	37	$	58	Other current liabilities	$	61	$	97	$	62	$	90
Long-term debt, including current portion^(a)	6,048		5,528		5,469		5,528		Long-term debt, including current portion^(a)	5,558		5,530		6,174		5,529
Deferred credits and other liabilities	109		98		93		88		Deferred credits and other liabilities	105		84		99		86
Total financial liabilities	$	6,233	$	5,727	$	5,599	$	5,674	Total financial liabilities	$	5,724	$	5,711	$	6,335	$	5,705

^(a)
Excludes debt issuance costs.


^(a)	~~Excludes capital leases and 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.

~~15.~~17. Debt

Revolving Credit Facility

As of June 30, ~~2019,~~2020, we had no0 borrowings against our ~~$3.4~~$3.0 billion unsecured revolving credit facility ~~(the “Credit~~(“Credit Facility”), as described ~~below or under our U.S. commercial paper program that is backed by the Credit Facility.~~below.

The Credit Facility includes a covenant requiring ~~that~~ our ~~ratio of~~ total debt to total capitalization ratio not to exceed 65% as of the last day of each fiscal quarter. ~~If an~~In the event of a default, ~~occurs,~~ the lenders holding more than half of the commitments may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility. As of June 30, ~~2019,~~2020, we were in compliance with this covenant with a ~~debt-to-capitalization~~ ratio of ~~31%~~33%.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Long-term debt

At June 30, ~~2019,~~2020, we had $5.5 billion of total debt outstanding, with our next significant debt maturity in the amount of ~~which~~ ~~$600 million~~ is$1.0 billion due ~~June 2020.~~November 2022.

~~16.~~

18. Stockholders’ Equity

InDuring the six months ended June 30, ~~2019,~~2020, we acquired approximately 169 million common shares at a cost of ~~$250~~$85 million, which were held as treasury stock. Including these repurchases, the total remaining share repurchase authorization was ~~$550 million~~$1.3 billion at June 30, ~~2019. On July 31, 2019, the Board of Directors authorized an extension of the share repurchase program, which increased the remaining share repurchase authorization to $1.5 billion.~~2020. Purchases under the program are made at our discretion and may be in either open market transactions, including block purchases, or in privately negotiated transactions using cash on hand, cash generated from operations or proceeds from potential asset sales. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion.

~~MARATHON OIL CORPORATION~~

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

~~17.~~19. 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 ~~2019:~~2020:


	Stock Options					Restricted Stock Awards & Units
	Number of Shares		Weighted Average Exercise Price		Awards	Weighted Average Grant Date Fair Value
Outstanding at December 31, 2019	5,659,731		$	23.55	7,174,386	$	15.88
Granted	1,132,808	^(a)	$	10.47	5,337,796	$	8.55
Exercised/Vested	(52,333)		$	7.22	(2,911,712)	$	15.93
Canceled^(b)	(565,219)		$	23.52	(1,405,754)	$	11.70
Outstanding at June 30, 2020	6,174,987		$	21.29	8,194,716	$	11.80

Stock Options Restricted Stock Awards & Units
Number of Shares Weighted Average Exercise Price Awards Weighted Average Grant Date Fair Value
Outstanding at December 31, 2018 6,180,007
$ 24.39
8,504,946
$ 14.04
Granted 648,526
^(a)
$ 16.79
3,846,526
$ 16.96
Exercised/Vested (10,470 ) $ 14.92
(3,562,277 ) $ 12.41
Canceled (590,624 ) $ 24.01
(377,692 ) $ 15.35
Outstanding at June 30, 2019 6,227,439
$ 23.65
8,411,503
$ 16.00

^(a)The weighted average grant date fair value of stock option awards granted was ~~$6.62~~$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 ~~2019,~~2020, we granted ~~656,636~~1,038,676 stock-based performance units to certain officers to be settled in shares. The grant date fair value per unit was ~~$20.66,~~$10.55, as calculated using a Monte Carlo valuation model. ~~At the grant date, each unit represents the value~~As of ~~one share of our common stock. These~~ June 30, 2020 there were 1,658,088units 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 zero to 200% based on performance achieved and as determined by the Compensation Committee of the Board of Directors. The performance goals are tied to our total shareholder return (“TSR”) as compared to TSR for a group of peer companies determined by the Compensation Committee of our Board of Directors. Dividend equivalents may accrue during the performance period and would be paid in cash at the end of the performance period based on the amount of dividends credited generally over the performance period on shares of our common stock that represent the number of the units granted multiplied by the vesting percentage.outstanding.

~~18.~~20. Defined Benefit Postretirement Plans

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


	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)

Three Months Ended June 30,
Pension Benefits Other Benefits
(In millions) 2019 2018 2019 2018
Service cost $ 5
$ 5
$ —
$ —
Interest cost 7
6
1
2
Expected return on plan assets (8 ) (8 ) —
—
Amortization:

– prior service cost (credit) (2 ) (3 ) (4 ) (2 )
– actuarial loss 2
3
—
1
Net settlement loss^(a)
2
2
—
—
Net periodic benefit cost^(b)
$ 6
$ 5
$ (3 ) $ 1

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


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

Six Months Ended June 30,
Pension Benefits Other Benefits
(In millions) 2019 2018 2019 2018
Service cost $ 9
$ 9
$ —
$ 1
Interest cost 14
13
2
4
Expected return on plan assets (16 ) (17 ) —
—
Amortization:

– prior service credit (4 ) (5 ) (8 ) (4 )
– actuarial loss 4
6
—
1
Net settlement loss^(a)
2
6
—
—
Net periodic benefit cost^(b)
$ 9

$ 12

$ (6 )
$ 2

^(a)

^(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) 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.

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


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

During the first six months of ~~2019,~~2020, we made contributions of ~~$29~~$12 million to our funded pension ~~plans~~plan and we expect to ~~make~~contribute an additional ~~contributions up to an estimated $12~~$16 million ~~over the remainder of 2019.~~this year. During the first six months of ~~2019,~~2020, we made payments of $3$14 million and ~~$11~~$8 million related to unfunded pension plans and other postretirement benefit plans. ~~The net U.K. pension assets are classified as held for sale in the consolidated balance sheet as of June 30, 2019. See~~ ~~Note 4~~ ~~for further information on this disposition.~~

~~19.~~

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

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


	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2020		2019		2020		2019		Income Statement Line
Postretirement and postemployment plans
Amortization of prior service credit	$	7	$	6	$	13	$	12	Other net periodic benefit credit
Amortization of actuarial loss	(3)		(2)		(6)		(4)		Other net periodic benefit credit
Net settlement loss	(14)		(2)		(16)		(2)		Other net periodic benefit credit
Net curtailment gain	17		—		17		—		Other net periodic benefit credit










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

^(a)During 2020 and 2019 we had a full valuation allowance on net federal deferred tax assets and as such, there is no tax impact to our postretirement and postemployment plans.

22. Supplemental Cash Flow Information

Three Months Ended June 30, Six Months Ended June 30,
(In millions) 2019 2018 2019 2018 Income Statement Line
Postretirement and postemployment plans
Amortization of prior service credit $ 6
$ 5
$ 12
$ 9
Other net periodic benefit costs
Amortization of actuarial loss (2 ) (4 ) (4 ) (7 ) Other net periodic benefit costs
Net settlement loss (2 ) (2 ) (2 ) (6 ) Other net periodic benefit costs
2
(1 ) 6
(4 ) Income (loss) before income taxes
Other insignificant, net of tax —
(4 ) —
(4 ) Net interest and other
—
—
—
—

(Provision) benefit for income taxes^(a)
Total reclassifications to expense, net of tax $ 2
$ (5 ) $ 6
$ (8 ) Net income (loss)


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


^(a)	~~During 2019 and 2018 we had a full valuation allowance on net federal deferred tax assets and as such, there is no tax impact to our postretirement and postemployment plans.~~

^(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)

~~20. Supplemental Cash Flow Information~~

Six Months Ended June 30,
(In millions) 2019 2018
Included in operating activities:
Interest paid, net of amounts capitalized $ 70
$ 134
Income taxes paid to taxing authorities 149
282
Noncash investing activities:

Increase (decrease) in asset retirement costs $ 29
$ (1 )
Asset retirement obligations assumed by buyer^(a)
109
3

^(a)~~In 2019, we closed the sale of the Droshky field (Gulf of Mexico) and the~~ 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, 2020 and 2019 ~~and 2018~~ of ~~$300~~$48 million and ~~$303~~$300 million.

~~21.~~23. Equity Method Investments

During the periods ended June 30, ~~2019~~2020 and December 31, ~~2018~~2019 our equity method investees were considered related parties and included:

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

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

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

Our equity method investments are summarized in the following table:


	Ownership as of	June 30,		December 31,
(In millions)	June 30, 2019	2019		2018		(In millions)	Ownership as of June 30, 2020	June 30, 2020		December 31, 2019
EGHoldings	60%	$	331	$	402	EGHoldings	60%	$	139	$	310
Alba Plant LLC	52%	173		167		Alba Plant LLC	52%	168		163
AMPCO	45%	180		176		AMPCO	45%	169		190
Total		$	684	$	745	Total		$	476	$	663

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. See Note 11 to the consolidated financial statements for further information on the equity method investee impairment.

Summarized financial information for equity method investees is as follows:


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

Three Months Ended June 30, Six Months Ended June 30,
(In millions) 2019 2018 2019 2018
Income data:
Revenues and other income $ 233
$ 228
$ 453
$ 426
Income from operations $ 82
$ 143
$ 131
$ 240
Net income $ 63
$ 123
$ 95
$ 202

Revenues from related parties were $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 with the majority related to EGHoldings in all periods.

~~22.~~Current receivables from related parties at June 30, 2020 were $25 million with the majority related to EGHoldings and $28 million at December 31, 2019 with the majority related EGHoldings and Alba Plant LLC. Payables to related parties at 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. Commitments and Contingencies

In the second quarter of 2019, Marathon E.G. Production Limited (“MEGPL”), a consolidated and wholly-owned subsidiary, signed a series of agreements to process third-party Alen Unit gas through existing infrastructure located in Punta Europa, E.G. ~~MEGPL is a signatory to the agreements related to our~~Our equity method investee, Alba Plant ~~LLC.~~LLC, is also a party to some of the agreements. These agreements contain clauses that ~~cause~~require MEGPL to indemnify the owners of the Alen Unit against injury to Alba Plant LLC’s personnel and damage to or loss of Alba Plant LLC’s automobiles, as well as third party claims caused by Alba Plant and certain environmental liabilities resulting from the actions or inaction by Alba Plant LLC. Pursuant to these agreements, MEGPL agreed to indemnify third party property or events, including environmental ~~assessments,~~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 environmental discharge or contamination. Therefore, we have not recorded a liability with respect to these ~~indemnification clauses~~indemnities since the amount of potential future payments under ~~such guarantees~~these indemnification clauses is not determinable.

~~MARATHON OIL CORPORATION~~

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

Inprocess the ~~fourth~~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 ~~2017,~~2020; one for a maximum of $91 million pertaining to the ~~U.K. tax authorities challenged~~payment obligations of Equatorial Guinea LNG Operations, S.A. and another for a maximum of $25 million pertaining to the ~~deductibility~~payment obligations of Alba Plant LLC. Payment by us would be required if either of those entities fails to honor its payment obligations pursuant to the relevant agreements with the owners of the Alen Unit. Certain owners of the Alen Unit, or their affiliates, are also direct or indirect shareholders in Equatorial Guinea LNG Operations, S.A. and Alba Plant LLC. Each guarantee expires no later than December 31, 2027. We measured these guarantees at fair value using the net present value of premium payments we expect to receive from our investees. We recorded a liability for these guarantees of $4 million as of June 30, 2020, with a corresponding receivable from our investees. Each of Equatorial Guinea LNG Operations, S.A. and Equatorial Guinea LNG Train 1, S.A. provided us with a pledge of its receivables as recourse against any payments we may make under the guaranty of Equatorial Guinea LNG Operations, S.A.’s performance.

Various groups, including the State of North Dakota and three Indian tribes represented by the Bureau of Indian Affairs, have been involved in a dispute regarding the ownership of certain ~~Brae area decommissioning costs, which~~lands underlying the Missouri River and Little Missouri River. As a result, as of June 30, 2020, we ~~claimed~~have a $101 million current liability in suspended royalty and working interest revenue, including interest, and have a long-term receivable of $25 million for ~~U.K. corporation tax purposes. The dispute~~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 ~~timing~~Clean Air Act. Each enforcement action will likely result in monetary sanctions in excess of ~~the deduction and did~~$100,000; however, we do not dispute the general deductibility of decommissioning costs. In accordance with U.K. regulations, we paid the amount of tax and interest in question, approximately $108 million, and filed our appeal. In the first quarter of 2019, we withdrew our appeal on this matter, and the corresponding revisions to current and deferred tax liabilitiesbelieve these enforcement actions would have ~~no cumulative~~a material adverse ~~earnings impact~~effect on our consolidated financial position, results of ~~operations.~~

~~We are continuously undergoing examination of our U.S. federal income tax returns by the IRS. With the closure of the 2010-2011 IRS Audit referenced in~~ ~~Note 7~~, these audits have been completed through the 2014 tax year with the exception of the following item. During the third quarter of 2017, we received a partnership adjustment notification related to the 2010 and 2011 tax years, for which we have filed a Tax Court Petition in the fourth quarter of 2017. We believe that it is more likely than not that we will prevail.operations or cash flow.

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

We have incurred and will continue to incur capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately offset by the prices we receive for our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance.

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

Executive Overview

~~Operations~~Outlook

Operations

Market Conditions

Results of Operations

Critical Accounting Estimates

Accounting Standards Not Yet Adopted

Cash Flows

Liquidity and Capital Resources

Environmental Matters and Other Contingencies

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

Executive Overview

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

Commodity prices declined substantially in the ~~Bakken in North Dakota.~~first half of 2020. While commodity prices are likely to remain volatile, we believe we can manage through this lower commodity price macro environment as our portfolio affords us the flexibility to respond to changing market conditions. Our primary focus remains on protecting our balance sheet and maintaining a strong liquidity position. We ~~also have international operations only in Equatorial Guinea after closing~~believe our financial strength, quality portfolio, and ongoing focus on reducing our cost structure better position us to navigate during this unprecedented time.

The risks associated with COVID-19 impacted our workforce and the ~~sale~~way we meet our business objectives. Due to concerns over health and safety, the vast majority of our ~~U.K. business on July 1, 2019. Total proved reserves were 1.3 billion boe (including 21 million boe~~corporate workforce works remotely as we plan a process for a phased return of ~~proved reserves for~~employees to the office. Working remotely has not significantly impacted our ~~U.K. business) at December 31, 2018,~~ability to maintain operations, has allowed our field offices to operate without any disruption, and ~~total assets were $21.3 billion at June 30, 2019. During~~has not caused us to incur significant additional expenses; however, we are unable to predict the ~~second quarter~~duration or ultimate impact of ~~2019, we continued the focus on our strategy with simplifying and concentrating our portfolio, a strengthened balance sheet, relentless focus on costs, and profitable growth within cash flows.~~these measures.

Key highlights include the following:

~~Simplifying and concentrating our portfolio~~

~~In July 2019, we closed~~Maintained focus on the sale of our U.K. business for proceeds of approximately $95 million, reflecting the assumption by the buyer of: working capital and cash equivalent balances of approximately $345 million and the U.K. asset retirement obligations of $966 million.

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

~~Strengthened~~ balance sheet and liquidity

~~Returned additional capital to shareholders by acquiring approximately 15 million common shares at a cost of $236 million, with $550 million of repurchase authorization remaining at June 30, 2019.~~

~~On July 31, 2019,~~•At the ~~Board of Directors authorized an extension~~end of the ~~share repurchase program, which increased the remaining share repurchase authorization to $1.5 billion.~~


•	~~At the end of the second quarter 2019, we had approximately $4.4 billion of liquidity, comprised of $1.0 billionin cash and an undrawn $3.4 billion revolving credit facility.~~

~~Strong financial position with~~second quarter 2020, we had approximately $3.5 billion of liquidity, comprised of an undrawn $3.0 billion revolving credit facility and $0.5 billion in cash, and no significant near-term debt maturities. We remain investment grade at all three primary ~~credit ratings~~rating agencies, with recent reviews by all three primary rating agencies.

•Continued our capital discipline, with an additional reduction of our Capital Budget to $1.2 billion.

•Restructured a portion of our commodity derivative portfolio during the quarter, which minimized the near-term crude downside and protected basis differentials.

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

•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.

Financial and operational results

~~Total~~•U.S. net sales volumes ~~for the quarter were 437~~decreased by 7% to 308 mboed, including ~~330 mboed~~a 4% reduction in ~~the~~ U.S. ~~resource plays. Our U.S.~~crude oil net sales volumes ~~increased 13%~~ compared to the same quarter last ~~year.~~year as a result of overall lower wells to sales activity driven by the lower drilling and completions activity.

•Our net ~~income~~loss per share was ~~$0.20~~$0.95 in the second quarter of ~~2019~~2020 as compared to a net income per share of ~~$0.11~~$0.20 in the same period last year. Included in ~~net income~~our financial results for the current quarter:


◦	A decrease in revenues from contracts with customers of approximately 5% to $1.4 billion, compared to the same quarter last year, primarily as a result of lower price realizations partially offset by higher net sales volumes in the current quarter.

◦Revenues from contracts with customers decreased $891 million compared to the same quarter last year, largely due to lower price realizations and decreased production volumes. Average crude oil price realizations decreased by 64% during the first six months of 2020 as compared to the first six month of 2019.


◦	Despite higher sales volumes, total costs and expenses from operations decreased $34 million during the quarter compared to the same quarter last year primarily as a result of lower production expenses.

◦Net loss on commodity derivatives of $70 million for the second quarter of 2020, an $86 million decrease from the same period in 2019, which was a net gain of $16 million.

◦A non-cash impairment of an investment in one of our equity method investees of $152 million.

•Net cash provided by operating activities ~~decreased 7% as commodity price realizations decreased while net sales volumes remained flat~~ in the first six months of ~~2019 versus~~2020 decreased to $710 million or 46% primarily as a result of lower commodity price realizations, compared to the ~~same period last year.~~first six months of 2019.

•The June 30, 2020 cash balance reflects a decrease of approximately $336 million from year-end, due in part to working capital changes reflecting the slowdown of 2020 capital activity.

Outlook

Capital Budget

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

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

Operations

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


	Three Months Ended 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)	%

Three Months Ended June 30, Six Months Ended June 30,
Net Sales Volumes 2019 2018 Increase (Decrease) 2019 2018 Increase (Decrease)
United States (mboed)
330 298 11% 314 291 8%
International (mboed)^(a)
107 121 (12)% 98 133 (26)%
Total (mboed)
437 419 4% 412 424 (3)%


^(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.^(a)	We closed on the sale of our Libya subsidiary in the first quarter of 2018. The six months ended June 30, 2018 includes net sales volumes relating to Libya of 16 mboed. See further detail of International net sales volumes below. See ~~Note 4~~ ~~to the consolidated financial statements for further information.~~

United States

Net sales volumes in the segment were ~~higher~~lower in the second quarter of 2020 but higher in the first six months of 2020 as compared to their respective 2019 ~~primarily as~~periods. In the second quarter of 2020, we began the process of transitioning to a ~~result~~significantly lower level of ~~new~~drilling and completion activity across our domestic portfolio. This lower pace of activity had the biggest effect in Oklahoma, where we did not bring any wells to sales ~~across all U.S. resource plays.~~during the quarter and experienced a significant decline in production. Overall sales volumes increased in 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.

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


	Three Months Ended June 30,			Six Months Ended June 30,				Three Months Ended June 30,						Six Months Ended June 30,
Net Sales Volumes	2019	2018	Increase (Decrease)	2019	2018	Increase (Decrease)	Net Sales Volumes	2020	2019	Increase (Decrease)		2020	2019	Increase (Decrease)
Equivalent Barrels (mboed)							Equivalent Barrels (mboed)
Eagle Ford	109	106	3%	107	105	2%	Eagle Ford	108	109	(1)	%	111	107	4	%
Bakken	103	82	26%	98	78	26%	Bakken	103	103	—	%	106	98	8	%
Oklahoma	82	80	3%	72	77	(6)%	Oklahoma	60	82	(27)	%	67	72	(7)	%
Northern Delaware	27	17	59%	27	17	59%	Northern Delaware	30	27	11	%	30	27	11	%
Other United States	9	13	(31)%	10	14	(29)%	Other United States	7	9	(22)	%	9	10	(10)	%
Total United States (mboed)	330	298	11%	314	291	8%
Total United States							Total United States	308	330	(7)	%	323	314	3	%


	Three Months Ended June 30, 2019						Three Months Ended June 30, 2020
Sales Mix - U.S. Resource Plays	Eagle Ford	Bakken	Oklahoma	Northern Delaware	Total	Sales Mix - U.S. Resource Plays	Eagle Ford		Bakken		Oklahoma		Northern Delaware		Total
Crude oil and condensate	56%	85%	26%	57%	58%	Crude oil and condensate	61	%	78	%	26	%	54	%	60	%
Natural gas liquids	23%	8%	29%	21%	19%	Natural gas liquids	18	%	12	%	28	%	21	%	18	%
Natural gas	21%	7%	45%	22%	23%	Natural gas	21	%	10	%	46	%	25	%	22	%


	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.

Three Months Ended June 30, Six Months Ended June 30,
Drilling Activity - U.S. Resource Plays 2019 2018 2019 2018
Gross Operated
Eagle Ford:
Wells drilled to total depth 36 33 66 67
Wells brought to sales 41 39 82 73
Bakken:
Wells drilled to total depth 20 24 32 43
Wells brought to sales 30 21 59 32
Oklahoma:
Wells drilled to total depth 18 10 38 23
Wells brought to sales 18 17 36 34
Northern Delaware:
Wells drilled to total depth 14 21 27 41
Wells brought to sales 16 13 31 22

•

~~Eagle Ford~~– Our net sales volumes were 109 mboed in the second quarter of 2019 which was 3% higher compared to the prior year quarter. During the second quarter of 2019, we continued to deliver strong results from the expanded core of Atascosa County in terms of well performance. Additionally, we continued efforts to uplift performance outside of the Karnes and Atascosa core, by applying enhanced completion techniques in Gonzales County. Overall, despite a majority of wells to sales outside of Karnes County during second quarter, the Eagle Ford asset achieved a quarterly record for average 30 day initial well productivity, while continuing to drive a trend of lower completed well costs per lateral foot.

•

~~Bakken~~– Our net sales volumes of 103 mboed represent a 26% increase over the prior year quarter of 82 mboed with company-operated wells to sales balanced between Myrmidon and Hector. We continued to improve capital efficiency, which was highlighted by a six well pad in Myrmidon, with an average completed well cost of $5.3 million. The average completed well cost for all second quarter wells was just $5.2 million.

•

~~Oklahoma– Our net sales volumes in the second quarter of 2019 increased by 3% from the prior year quarter, with net sales volumes of 82 mboed. We~~continued to deliver strong results from the over-pressured STACK where the eight-well per section Mike Stroud infill achieved average completed well costs more than 30% below the previously drilled parent well. We continued to make significant progress in reducing our cost structure with our two most recent over-pressured STACK infills completed at an average completed well cost of $6.3 million normalized to a 10,000 foot lateral.

•

~~Northern Delaware~~ ~~– Our net sales volumes were 27 mboed in the second quarter of 2019 which was 59% higher compared to the prior year quarter. We~~continued to make progress in reducing our cost structure and improving margins, with second quarter cash costs down over the prior year on a per boe basis, 100% of water on pipe for all second quarter wells to sales, and a rising percentage of total oil production on pipe. Second quarter again featured strong Upper Wolfcamp productivity in Malaga, with the second quarter completed well costs per lateral foot below the 2018 average.

•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 ~~2019~~2020 compared to the second quarter of ~~2018~~2019 primarily due to ~~natural field decline in E.G. and~~ timing of E.G liftings ~~in the~~and disposition of our U.K. business. The following table provides details regarding net sales volumes for our ~~significant~~ operations within this segment:


	Three Months Ended June 30,						Six Months Ended June 30,
Net Sales Volumes	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	%

Three Months Ended June 30, Six Months Ended June 30,
Net Sales Volumes 2019 2018 Increase (Decrease) 2019 2018 Increase (Decrease)
Equivalent Barrels (mboed)

Equatorial Guinea 95 103 (8)% 85 98 (13)%
United Kingdom^(a)
10 14 (29)% 11 15 (27)%
Libya — — —% — 16 (100)%
Other International 2 4 (50)% 2 4 (50)%
Total International (mboed)
107 121 (12)% 98 133 (26)%
Equity Method Investees

LNG (mtd)
5,321 6,141 (13)% 4,981 5,843 (15)%
Methanol (mtd)
1,134 1,316 (14)% 1,069 1,256 (15)%
Condensate and LPG (boed)
11,080 12,689 (13)% 10,488 12,553 (16)%
^(a)Includes natural gas acquired for injection and subsequent resale.


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


•	Equatorial Guinea – Net sales volumes ~~in the second quarter of 2019 were lower compared to the same period in 2018 as a result of natural field decline.~~


•	~~United Kingdom~~ – Second quarter of 2019 net sales volumes were lower compared to the second quarter of 2018 primarily due to timing of liftings in the non-operated Foinaven complex. In July 2019, we closed on the sale of our U.K. business. See ~~Note 4~~ ~~to the consolidated financial statements for further information.~~


•	~~Libya~~ ~~– During the first quarter of 2018 we closed on the sale of our subsidiary in Libya. See~~ ~~Note 4~~ ~~to the consolidated financial statements for further information.~~

~~Market Conditions~~

~~Crude oil and condensate and NGLs benchmarks decreased~~ in the second quarter ~~and first six months~~ of ~~2019 as~~2020 were lower compared to the same period in ~~2018. As a result,~~2019 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, and natural field decline.

•United Kingdom – In July 2019, we ~~experienced decreased price realizations associated with those benchmarks.~~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, payment of dividends and funding of share repurchases. Commodity prices declined substantially in the first half of 2020 resulting from demand contraction related to the global pandemic and increased supply following the OPEC decision to increase production. A revised OPEC deal to reduce production was agreed early in the second quarter of 2020 and oil prices partially recovered in the latter part of the second quarter. However, given the scale of worldwide demand contraction, we expect commodity prices to remain volatile. Refer to Item 1A. Risk Factors in our 2019 Annual Report on Form 10-K for further discussion on how further declines in commodity prices could impact us.

United States

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


	Three Months Ended June 30,										Six Months Ended June 30,
	2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
Average Price Realizations^(a)
Crude oil and condensate (per bbl)^(b)	$	21.65	$	59.18	(63)	%	$	33.60	$	56.72	(41)	%
Natural gas liquids (per bbl)	7.09		14.60		(51)	%	8.54		15.09		(43)	%
Natural gas (per mcf)^(c)	1.44		1.89		(24)	%	1.52		2.36		(36)	%
Benchmarks
WTI crude oil average of daily prices (per bbl)	$	28.00	$	59.91	(53)	%	$	36.82	$	57.45	(36)	%
Magellan East Houston (“MEH”) crude oil average of daily prices (per bbl)	25.66		66.32		(61)	%	37.60		63.37		(41)	%
Mont Belvieu NGLs (per bbl)^(d)	12.25		19.20		(36)	%	12.70		21.19		(40)	%
Henry Hub natural gas settlement date average (per mmbtu)	1.72		2.64		(35)	%	1.83		2.89		(37)	%

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

^(b)Inclusion of realized gains (losses) on crude oil derivative instruments would have increased average price realizations by $1.59 per bbl and $0.32 per bbl for the second quarter 2020 and 2019 and ~~2018.~~$1.53 per bbl and $0.70 per bbl for the first six months of 2020 and 2019.

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

Three Months Ended June 30, Six Months Ended June 30,
2019 2018 Increase (Decrease) 2019 2018 Increase (Decrease)
Average Price Realizations^(a)

Crude oil and condensate (per bbl)^(b)
$ 59.18
$ 66.03
(10)% $ 56.72
$ 64.16
(12)%
Natural gas liquids (per bbl)
14.60
22.09
(34)% 15.09
22.49
(33)%
Natural gas (per mcf)
1.89
2.18
(13)% 2.36
2.38
(1)%
Benchmarks
WTI crude oil average of daily prices (per bbl)
$ 59.91
$ 67.91
(12)% $ 57.45
$ 65.46
(12)%
Magellan East Houston (“MEH”) crude oil average of daily prices (per bbl)^(c)
66.32
63.37

LLS crude oil average of daily prices (per bbl)^(c)
72.96

69.48

Mont Belvieu NGLs (per bbl)^(d)
19.20
28.28
(32)% 21.19
27.29
(22)%
Henry Hub natural gas settlement date average (per mmbtu)
2.64
2.80
(6)% 2.89
2.90
—%


^(a)^(d)Bloomberg Finance LLP: Y-grade Mix NGL of 55% ethane, 25% propane, 5% butane, 8% isobutane and 7% natural gasoline.	~~Excludes gains or losses on commodity derivative instruments.~~


^(b)	Inclusion of realized gains (losses) on crude oil derivative instruments would have impacted average price realizations by $0.32 per bbl and $(7.04) per bbl for the second quarter 2019 and 2018 and $0.70 per bbl and $(5.71) per bbl for the first six months of 2019 and 2018.


^(c)	~~Benchmark change due to industry shift to MEH in the first quarter of 2019.~~


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

Crude oil and condensate – 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 ~~specific~~ 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~~2019~~ 2020 and 2019.


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

^(a)~~2018~~.Average of monthly prices obtained from the United States Energy Information Agency website.

Three Months Ended June 30, Six Months Ended June 30,
2019 2018 Increase (Decrease) 2019 2018 Increase (Decrease)
Average Price Realizations
Crude oil and condensate (per bbl)
$ 58.21
$ 66.12
(12)% $ 56.36
$ 66.19
(15)%
Natural gas liquids (per bbl)
1.67
2.91
(43)% 1.81
2.40
(25)%
Natural gas (per mcf)
0.35
0.52
(33)% 0.41
0.59
(31)%
Benchmark

Brent (Europe) crude oil (per bbl)^(a)
$ 68.92
$ 74.50
(7)%
$66.05
$ 70.65
(7)%


^(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~~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~~field under a fixed price long term contract. Alba Plant LLC extracts ~~NGL’s~~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~~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~~field is sold by the Alba ~~Field~~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. ~~EGLNG~~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, ~~2019~~2020 vs. Three Months Ended June 30, ~~2018~~2019

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)	2019		2018		(In millions)	2020		2019
Revenues from contracts with customers					Revenues from contracts with customers
United States	$	1,200	$	1,221	United States	$	462	$	1,200
International	181		226		International	28		181
Segment revenues from contracts with customers	$	1,381	$	1,447	Segment revenues from contracts with customers	$	490	$	1,381

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, 2018 Price Realizations Net Sales Volumes Three Months Ended June 30, 2019
United States Price/Volume Analysis
Crude oil and condensate $ 1,013
$ (118 ) $ 126
$ 1,021
Natural gas liquids 115
(43 ) 12
84
Natural gas 86
(12 ) 5
79
Other sales 7
16
Total $ 1,221
$ 1,200
International Price/Volume Analysis
Crude oil and condensate $ 193
$ (23 ) $ (9 ) $ 161
Natural gas liquids 4
(2 ) (1 ) 1
Natural gas 22
(6 ) (3 ) 13
Other sales 7
6
Total $ 226
$ 181

Net gain (loss) on commodity derivatives In the second quarter of ~~2019~~2020, the net ~~gain~~loss on commodity derivatives was ~~$16~~$70 million, compared to the same period in ~~2018,~~2019, which was a net ~~loss~~gain of ~~$152~~$16 million. We have multiple crude oil and natural gas 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 1315 to the consolidated financial statements for further information.

Income from equity method investments decreased ~~$29~~$183 million for the second quarter of ~~2019~~2020 from the comparable ~~2018~~2019 period primarily due to ~~lower prices~~an impairment of $152 million to an investment in an equity method investee, and lower ~~sales~~ volumes ~~of LPG at our Alba plant, methanol at our AMPCO facility~~ and ~~LNG at our EGLNG production facility.~~

~~Net gain on disposal of assets~~ ~~decreased $58 millionin the second quarter of 2019 primarily related to gain on sale~~price realizations associated with ~~an acreage swap in~~ our ~~Unites States segment in~~investees. See Note 11 to the ~~second quarter of 2018.~~consolidated financial statements for further information on the equity method investee impairment.

Production expenses decreased ~~$12~~$64 million in the second quarter of ~~2019~~2020 versus the same period in 2018. Production expenses across our United States segment decreased $6 million primarily due to reduced water hauling costs in the Northern Delaware, with all new wells on pipe in the second quarter; partially offset by increase in other resource plays due to volume. International decreased $6 million2019, primarily as a result of lower well workover and maintenance activities, lower U.S. contract labor, and the sale of our U.K. ~~liftings,~~business which ~~resulted in lower sales volumes~~closed during the ~~second~~third quarter of 2019.

The second quarter of ~~2019~~2020 production expense rate (expense per boe) ~~for United States~~ was lower ~~primarily due to higher sales volumes and reduced costs~~for International as a result of the sale of our U.K. business which closed during the third quarter of 2019. Our U.S. production expense rate was lower as a result of the same reasons identified in the preceding paragraph in the second quarter of ~~2019.~~2020. While the production expense rates for each of our U.S. 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.

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


	Three Months Ended June 30,													Three Months Ended June 30,
($ per boe)	2019		2018		Increase (Decrease)		2019		2018		Increase (Decrease)		($ per boe)	2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
Production Expense and Production Expense Rate	Expense						Rate
Production Expense and Rate													Production Expense and Rate	Expense										Rate
United States	$	147	$	153	(4	)%	$	4.89	$	5.66	(14	)%	United States	$	114	$	147	(22)	%	$	4.09	$	4.89	(16)	%
International	$	46	$	52	(12	)%	$	4.72	$	4.71	—	%	International	$	15	$	46	(67)	%	$	1.88	$	4.72	(60)	%

Shipping, handling and other operating ~~expensesincreased$44~~decreased $65 million in the second quarter of ~~2019~~2020 primarily ~~as a result of increased~~due to lower NGL shipping and handling rates realized in Bakken along with lower net sales volumes in Oklahoma. To the extent that our ~~United States~~ ~~segment.~~future Bakken realized NGL prices exceed those as compared to the second quarter, we expect our shipping and handling costs to increase as well.

Exploration expenses include unproved property impairments, dry well costs, geological and geophysical, and other costs, which ~~decreased $39 million~~remained flat in comparison to the second quarter of 2019.

The following table summarizes the components of exploration expenses:


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

Three Months Ended June 30,
(In millions) 2019 2018 Increase (Decrease)
Exploration Expenses
Unproved property impairments $ 20
$ 41
(51 )%
Dry well costs —
10
(100 )%
Geological and geophysical 3
8
(63 )%
Other 3
6
(50 )%
Total exploration expenses $ 26
$ 65
(60 )%

Depreciation, depletion and amortization decreased $7$8 million in the second quarter of ~~2019. In our International segment, we had a decrease of $12 million~~2020 primarily due to ~~lower~~the sale of our U.K. ~~liftings~~business which closed during the ~~second~~third quarter of ~~2019 partially offset by higher production in the U.S.~~2019. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore volumes have an impact on DD&A expense.

The DD&A rate (expense per boe), 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 ~~timing~~the sale of ~~liftings in the~~our U.K. ~~Our United States DD&A rate decreased primarily due to non-core asset dispositions in the Gulf of Mexico in~~business which closed during the third quarter ~~2018 and first quarter~~of 2019.

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

Three Months Ended June 30,
($ per boe) 2019 2018 Increase (Decrease) 2019 2018 Increase (Decrease)
DD&A Expense and DD&A Expense Rate Expense Rate
United States $ 561
$ 556
1 % $ 18.72
$ 20.48
(9 )%
International $ 38
$ 50
(24 )% $ 3.92
$ 4.53
(13 )%


	Three Months Ended June 30,
($ per boe)	2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
DD&A Expense and Rate	Expense										Rate
United States	$	569	$	561	1	%	$	20.28	$	18.72	8	%
International	$	22	$	38	(42)	%	$	2.86	$	3.92	(27)	%

Impairments decreased ~~$16~~$18 million primarily as a result of impairments to certain non-core proved properties in our United States segment in the second quarter of ~~2019~~2019. See Note 11 to the consolidated financial statements for more detail.

Taxes other than income include production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. Taxes other than income decreased $49 million primarily due to ~~timing of non-core proved property dispositions~~lower price realizations and lower sales volumes in ~~our International and United States segments. See~~ ~~Note 10~~ ~~for discussion of~~ the ~~impairments in further detail.~~

~~General and administrative~~ ~~decreased$18 million~~U.S. segment in the second quarter of ~~2019 primarily as a result of change in value of stock-based performance units tied to our total shareholder return (“TSR”) as compared to our peer group.~~2020.

Provision (benefit) for income taxes reflects an effective income tax rate ~~from continuing operations~~of 2% in the second quarter of 2020, as compared to an effective income tax rate of 17% in the second quarter of ~~2019, as compared to an effective tax rate of 31% in the second quarter of 2018.~~2019. See Note 7 to the consolidated financial statements for a more ~~detail~~detailed discussion concerning the rate changes.

Segment Income

Segment income represents income ~~from continuing operations excluding~~which excludes certain items not allocated to our operating segments, net of income taxes. A portion of our corporate and operations general and administrative support costs are not allocated to the operating segments. ~~Gains~~These unallocated costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Additionally, items which affect comparability such as: gains or losses on dispositions, ~~certain~~ impairments of proved property, goodwill and equity method investments, unrealized gains or losses on commodity derivative instruments, effects of pension ~~settlement losses,~~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:~~

income (loss):


	Three Months Ended June 30,										Three Months Ended June 30,
(In millions)	2019			2018			Increase (Decrease)			(In millions)	2020		2019		Increase (Decrease)
United States	$	215		$	123		$	92		United States	$	(365)	$	215	(270)	%
International	96			142			(46		)	International	(6)		96		(106)	%
Segment income	311			265			46
Segment income (loss)										Segment income (loss)	(371)		311		(219)	%
Items not allocated to segments, net of income taxes	(150		)	(169		)	19			Items not allocated to segments, net of income taxes	(379)		(150)		(153)	%
Net income	$	161		$	96		$	65
Net income (loss)										Net income (loss)	$	(750)	$	161	(566)	%

United States segment loss ~~income increased$92 million after-tax in~~In the second quarter of ~~2019 primarily due to a net gain on commodity derivatives second quarter of 2019 versus a net~~2020, U.S. segment loss ~~in the second quarter of 2018.~~

~~International segment~~was ~~incomedecreased $46~~$365 million after-tax inversus $215 million income after-tax for the ~~second quarter of~~same period in 2019, primarily due to lower ~~prices and net sales volumes as a result of natural field decline and additionally lower income from our equity method investments as a result of lower~~ price realizations and sales ~~volumes.~~volumes in the current quarter, which was partially offset by lower production taxes, shipping and handling expense, and production expense.

International segment loss In the second quarter of 2020, International segment loss was$6 million after-tax versus $96 million income after-tax for the same period in 2019, primarily due to lower price realizations in E.G. resulting in lower income from equity method investments and the sale of our U.K. business in the third quarter of 2019.

Results of Operations

Six Months Ended June 30, ~~2019~~2020 vs. Six Months Ended June 30, ~~2018~~2019

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

Six Months Ended June 30,
(In millions) 2019 2018
Revenues from contracts with customers
United States $ 2,262
$ 2,346
International 319
638
Segment revenues from contracts with customers $ 2,581
$ 2,984


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


				Increase (Decrease) Related to											Increase (Decrease) Related to
(In millions)		Six Months Ended June 30, 2018		Price Realizations			Net Sales Volumes			Six Months Ended June 30, 2019		(In millions)	Six Months Ended June 30, 2019		Price Realizations		Net Sales Volumes		Six Months Ended June 30, 2020
United States Price/Volume Analysis	United States Price/Volume Analysis											United States Price/Volume Analysis
Crude oil and condensate		$	1,932	$	(247	)	$	195		$	1,880	Crude oil and condensate	$	1,880	$	(818)	$	127	$	1,189
Natural gas liquids		218		(79		)	22			161		Natural gas liquids	161		(68)		(5)		88
Natural gas		184		(1		)	(1		)	182		Natural gas	182		(66)		5		121
Other sales		12								39		Other sales	39						34
Total		$	2,346							$	2,262	Total	$	2,262					$	1,432
International Price/Volume Analysis	International Price/Volume Analysis											International Price/Volume Analysis
Crude oil and condensate		$	569	$	(48	)	$	(247	)	$	274	Crude oil and condensate	$	274	$	(84)	$	(125)	$	65
Natural gas liquids		5		(1		)	(1		)	3		Natural gas liquids	3		(1)		—		2
Natural gas		48		(12		)	(8		)	28		Natural gas	28		(11)		(2)		15
Other sales		16								14		Other sales	14						—
Total		$	638							$	319	Total	$	319					$	82

Net ~~loss~~gain (loss) on commodity derivatives In the first six months of ~~2019,~~2020, the net ~~loss~~gain on commodity derivatives was ~~$75~~$132 million, compared to the same period in ~~2018~~2019 which was a net loss of ~~$254~~$75 million. We have multiple crude oil and natural gas derivative contracts that settle against various indices. We record commodity derivative gains/losses as the index pricing and forward curves change each period. SeeNote 1315 to the consolidated financial statements for further information.

Income from equity method investments decreased ~~$55~~$206 million for the first six months of ~~2019 from the comparable 2018 period~~2020 primarily due to ~~lower prices~~an impairment of $152 million 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 ~~driven by our planned turnaround~~from equity method investments in E.G. ~~during~~due to the planned triennial turnaround in the first quarter ~~2019.~~of 2020.

Net gain on disposal of assets decreased ~~$273~~$27 million for the first six months of ~~2019~~2020 primarily as a result of the sale of our ~~Libya subsidiary for a pre-tax gain~~working interest in the Droshky field (Gulf of ~~$255 million in~~Mexico), which closed during the first quarter of ~~2018. See~~ ~~Note 4~~ ~~to the consolidated financial statements for information about dispositions.~~2019.

Other income ~~increased $32~~decreased $35 million in the first six months of 2020 primarily due to income recognized in 2019 ~~primarily as a result of~~arising from indemnification ~~of certain tax liabilities~~payments received from Marathon Petroleum Corporation (“MPC”). Pursuant to the Tax Sharing Agreement we entered into with MPC, in connection with the ~~closure of the 2010-2011 Federal Tax Audit with the IRS.~~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 ~~accordance with~~ the ~~Tax Sharing Agreement. See~~ ~~Note 7~~ ~~for further detail.~~first quarter of 2019.

Production expenses for the first six months of ~~2019~~2020 decreased by ~~$42~~$91 million compared to the same period in ~~2018.~~2019. Production expense in our International segment decreased ~~$23~~$64 million primarily as a result of the sale of our U.K. business, which closed during the third quarter of 2019. Production expense in our United States segment decreased $29 million primarily due to ~~the timing of our U.K. liftings, which resulted in~~ lower ~~sales volumes, as~~ well ~~as the sale of our Libya subsidiary in the first quarter of 2018. United States decreased $18 million primarily due to non-core asset dispositions in the Gulf of Mexico during the third quarter 2018~~workover and ~~due to reduced water hauling costs in the Northern Delaware, with all new wells on pipe in the second quarter.~~maintenance activities, and lower contract labor.

The first six months of ~~2019~~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 ~~change in sales volume mix, which was impacted by the timing of liftings and the~~ sale of ~~our Libya subsidiary in 2018.~~the U.K. business, which closed during the third quarter of 2019.

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)	2019		2018		Increase (Decrease)		2019		2018		Increase (Decrease)		($ per boe)	2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
Production Expense and Production Expense Rate	Expense						Rate
Production Expense and Rate													Production Expense and Rate	Expense										Rate
United States	$	286	$	304	(6	)%	$	5.04	$	5.77	(13	)%	United States	$	257	$	286	(10)	%	$	4.37	$	5.04	(13)	%
International	$	96	$	119	(19	)%	$	5.40	$	4.91	10	%	International	$	32	$	96	(67)	%	$	2.11	$	5.40	(61)	%

Shipping, handling and other operating expenses ~~increased~~decreased $6875 million in the first six months of ~~2019~~2020 from the comparable ~~2018~~2019 period, primarily as a result of ~~increased~~lower NGL shipping and handling rates realized in Bakken as well as lower net sales volumes in ~~our~~ ~~United States~~ ~~segment.~~Oklahoma.

Exploration expenses include unproved property impairments, dry well costs, geological and geophysical, and other, which decreased ~~$32~~$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.

The following table summarizes the components of exploration expenses:


	Six Months Ended June 30,							Six Months Ended June 30,
(In millions)	2019		2018		Increase (Decrease)		(In millions)	2020		2019		Increase (Decrease)
Exploration Expenses							Exploration Expenses
Unproved property impairments	$	64	$	81	(21	)%	Unproved property impairments	$	39	$	64	(39)	%
Dry well costs	5		12		(58	)%	Dry well costs	1		5		(80)	%
Geological and geophysical	9		14		(36	)%	Geological and geophysical	4		9		(56)	%
Other	7		10		(30	)%	Other	10		7		43	%
Total exploration expenses	$	85	$	117	(27	)%	Total exploration expenses	$	54	$	85	(36)	%

Depreciation, depletion and amortization ~~decreased $43~~increased $82 million in the first six months of ~~2019~~2020 from the comparable ~~2018~~2019 period, primarily ~~as a result of a decrease of $32 million~~due to the higher net sales volumes in our ~~International~~U.S. segment ~~due to lower net sales volumes.~~driven by first quarter 2020 activity, partially offset by the sale of our U.K. business, which closed during the third quarter of 2019. Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore volumes have an impact on DD&A expense.

The DD&A rate (expense per boe), 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.

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

Six Months Ended June 30,
($ per boe) 2019 2018 Increase (Decrease) 2019 2018 Increase (Decrease)
DD&A Expense and DD&A Expense Rate Expense Rate
United States $ 1,075
$ 1,084
(1 )% $ 18.98
$ 20.56
(8 )%
International $ 72
$ 104
(31 )% $ 4.06
$ 4.31
(6 )%


	Six Months Ended June 30,
($ per boe)	2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
DD&A Expense and Rate	Expense										Rate
United States	$	1,186	$	1,075	10	%	$	20.15	$	18.98	6	%
International	$	43	$	72	(40)	%	$	2.86	$	4.06	(30)	%

Impairments ~~decreased $18~~increased $73 million in the first six months of ~~2019 from the comparable 2018 period,~~2020, primarily as a result of ~~second quarter 2018 proved property impairments as a result of anticipated sales of certain non-core proved properties in~~impairment to goodwill for $95 million related to our International ~~and United States segments.~~reporting unit in the first quarter of 2020. See ~~Note 10~~No te 1 1 for discussion of the impairments in further detail.

General and administrative decreased $2417 million in the first six months of ~~2019~~2020 primarily as a result of the change in value of stock-based performance units tied to our total shareholder return (“TSR”) as compared to our peer ~~group.~~group and a decrease in other compensation costs.

Provision (benefit) for income taxes reflects an effective income tax rate of ~~(52)%~~2% in the first six months of ~~2019,~~2020, as compared to an effective income tax rate of ~~32% from~~(52)% for the comparable ~~2018~~2019 period. See Note 7 to the consolidated financial statements for a more ~~detail~~detailed discussion concerning the components impacting the rate change.

Segment Income

Segment income represents income ~~excluding~~which excludes certain items not allocated to our operating segments, net of income taxes. ~~Aportion~~A portion of our corporate and operations general and administrative support costs are not allocated to the operating segments. ~~Gains~~These unallocated costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Additionally, items which affect comparability such as: gains or losses on dispositions, ~~certain~~ impairments of proved property, goodwill and equity method investments, unrealized gains or losses on commodity derivative instruments, effects of pension ~~settlement losses,~~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)	2019			2018			Increase (Decrease)		(In millions)	2020		2019		Increase (Decrease)
United States	$	347		$	248		40	%	United States	$	(385)	$	347	(211)	%
International	157			274			(43	)%	International	(7)		157		(104)	%
Segment income	504			522			(3	)%
Segment income (loss)									Segment income (loss)	(392)		504		(178)	%
Items not allocated to segments, net of income taxes	(169		)	(70		)	141	%	Items not allocated to segments, net of income taxes	(404)		(169)		(139)	%
Net income	$	335		$	452		(26	)%
Net income (loss)									Net income (loss)	$	(796)	$	335	(338)	%

United States segment loss ~~income increased$99 million after-tax in~~For the first six months of 2020, U.S. segment loss was $385 million after-tax versus $347 million income after-tax for the same period in 2019, ~~from the comparable 2018 period~~ primarily as a result of lower crude price realizations and higher DD&A due to ~~the~~higher net sales volumes, which was partially offset by lower production taxes, shipping and handling expense, and production expense.

International segment loss ~~related to commodity derivative positions in~~For the first six months of ~~2018.~~

2020, International segment loss was $7 million after-tax versus $157 million income after-tax for the same period in 2019, ~~incomedecreased $117 million after-tax in the first six months of 2019 from the comparable 2018 period~~ primarily due to lower price realizations and sales volumes ~~as a result of the planned triennial turnaround in E.G. and the~~partially offset by lower costs due to sale of our ~~Libya subsidiary~~U.K. business in ~~the first~~third quarter ~~2018.~~of 2019.

Critical Accounting Estimates

There have been no material changes or developments in the evaluation of the accounting estimates and the underlying assumptions or methodologies pertaining to our Critical Accounting Estimates disclosed in our Form 10-K for the year ended December 31, ~~2018~~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 Estimates - Goodwill~~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 14 1 1 to the consolidated financial statements for further information regarding ~~our annual goodwill~~the impairment ~~test.~~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.

Cash Flows

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


	Six Months Ended June 30,							Six Months Ended June 30,
(In millions)	2019			2018			(In millions)	2020		2019
Sources of cash and cash equivalents							Sources of cash and cash equivalents
Operating activities	$	1,312		$	1,416		Operating activities	$	710	$	1,312
Disposal of assets, net of cash transferred to the buyer	69			1,183			Disposal of assets, net of cash transferred to the buyer	9		69
Other	50			57			Other	11		50
Total sources of cash and cash equivalents	$	1,431		$	2,656		Total sources of cash and cash equivalents	$	730	$	1,431
Uses of cash and cash equivalents							Uses of cash and cash equivalents
Additions to property, plant and equipment	$	(1,262	)	$	(1,300	)	Additions to property, plant and equipment	$	(946)	$	(1,262)
Additions to other assets	42			(129		)	Additions to other assets	12		42
Acquisitions, net of cash acquired	—			(25		)

Purchases of common stock	(266		)	(11		)	Purchases of common stock	(92)		(266)
Dividends paid	(82		)	(85		)	Dividends paid	(40)		(82)
Other	(29		)	(2		)	Other	—		(29)
Total uses of cash and cash equivalents	$	(1,597	)	$	(1,552	)	Total uses of cash and cash equivalents	$	(1,066)	$	(1,597)

Cash flows generated from operating activities in the first six months of ~~2019~~2020 were 7%46% lower primarily as a result of lower commodity price realizations decreased while net sales volumes remained flat compared to 2018. Consolidated average crude oil and condensate price realizations, inclusive of the impacts of realized gains and losses on commodity derivatives, decreased by ~~approximately 5% dur~~i~~ng the first six months of 2019 as compared to the prior period.~~realizations.

Proceeds from the disposals of assets for the first six months of 2019 were primarily related to the final proceeds received from the sale of non-operated interest in the Atrush block in Kurdistan. Proceeds from the disposals of assets for the first six months of 2018 were primarily related to the final proceeds received from the sale of our Canadian business and sale of our non-operated interest in Libya. See ~~Note 4~~ ~~to the consolidated financial statements for further information concerning dispositions.~~

Additions to property, plant and equipment in the first six months of 2019 were consistent with expectations relative to our $2.6 billion Capital Budget, which includes approximately $2.4 billion of development capital and $200 million to fund resource play leasing and exploration (“REx”). 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)	2019			2018		(In millions)	2020		2019
United States	$	1,292		$	1,252	United States	$	698	$	1,292
International	15			22		International	—		15
Corporate	8			10		Corporate	9		8
Total capital expenditures	1,315			1,284		Total capital expenditures	707		1,315
Change in capital expenditure accrual	(53		)	16		Change in capital expenditure accrual	239		(53)
Total use of cash and cash equivalents for property, plant and equipment	$	1,262		$	1,300	Total use of cash and cash equivalents for property, plant and equipment	$	946	$	1,262

~~Additions to other assets of $42 million relates to the clearing of deposits related to~~The decline in our ~~resource play leasing and exploration program to property, plant and equipment during the first six months of 2019. During the first six months of 2019, our REx~~ capital expenditures ~~totaled $74 million, inclusive~~for the U.S. segment was caused by lower drilling and completions activities across all four of costs included within property, plant and equipment and other assets. During the first six months of 2018, additions to other assets related to REx capital expenditures, with total REx expenditures of $248 million, inclusive of costs included within property, plant and equipment, other assets and acquisitions.our shale basins.

~~The Board of Directors approved a $0.05 per share dividend for each of the fourth quarter of 2018 and~~In the first quarter of ~~2019, which were paid in the first and second quarters of 2019. See Capital Requirements below for additional information about dividends.~~

~~In the first six months of 2019,~~2020, we acquired approximately 169 million common shares at a cost of ~~$250~~$85 million, which were held as treasury stock. See Note 1618 to the consolidated financial statements for further information.

Liquidity and Capital Resources

Available Liquidity

Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, sales of non-core assets, capital market transactions, and our revolving Credit Facility. At June 30, ~~2019,~~2020, we had approximately ~~$4.4~~$3.5 billion of liquidity consisting of ~~$1.0~~$0.5 billion in cash and cash equivalents and ~~$3.4~~$3.0 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.

Our working capital requirements are supported by ~~these sources~~our cash and ~~we may issue either commercial paper backed by~~cash equivalents and our Credit ~~Facility or~~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, ~~dividend payments,~~ defined benefit plan contributions, repayment of debt maturities, and other amounts that may ultimately be paid in connection with contingencies.

General economic conditions, commodity prices, and financial, business and other factors, including the global pandemic, could affect our operations and our ability to access the capital markets. In

During the ~~second quarter 2019, we were upgraded~~first half of 2020, commodity prices significantly declined due to ~~investment grade by Moody’s Investor Services;~~the combined impacts of global crude oil oversupply and ~~were also upgraded by S&P. Our corporate~~lower demand for hydrocarbons due to the global pandemic. As a result, credit ~~ratings as of June 30, 2019 are: Standard & Poor’s Ratings Services BBB (stable); Fitch Ratings BBB (stable); and Moody’s Investor Services, Inc. Baa3 (stable).~~rating agencies reviewed many companies in the industry, including us. We ~~are now~~continue to be rated investment grade at all three primary credit rating agencies. ~~In addition, we also have the ability to borrow on our U.S. commercial paper program, which is backed by the revolving credit facility.~~ 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, ~~2018~~2019 for a discussion of how a ~~further~~ 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, ~~2019,~~2020, we had no borrowings against our Credit ~~Facility or under our U.S. commercial paper program that is backed by the Credit~~ Facility.

At June 30, ~~2019,~~2020, we had $5.5 billion of total debt outstanding, with our next significant debt maturity of ~~which~~ ~~$600 million~~ is$1.0 billion due ~~June 2020.~~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.

We continue to own $400 million of St. John the Baptist, State of Louisiana revenue refunding bonds that were originally issued in December 2017. In July, we announced that we had delivered to the trustee and remarketing agent a conditional notice of conversion of up to $400 million of the bonds to remarket them in August. Information about these bonds are available on the website of the Municipal Securities Rulemaking Board via its Electronic Municipal Market Access system at www.msrb.org. Information on that website is not incorporated by reference into this filing.

Shelf Registration

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

~~Asset Disposal~~

~~In the second quarter of 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. See~~ ~~Note 4~~ ~~to the consolidated financial statements for further information concerning dispositions.~~

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), which resulted in proceeds of approximately $95 million and reflects the assumption by RockRose Energy PLC (the buyer) of the U.K. business’ working capital and cash equivalent balances of approximately $345 million and the U.K. asset retirement obligations of $966 million.

~~The transaction has an effective date of January 1, 2019.~~

Debt-To-Capital Ratio

The Credit Facility includes a covenant requiring that our ~~ratio of~~ total debt to total capitalization ratio not exceed 65% as of the last day of the fiscal quarter. Our ~~debt-to-capital~~ ratio was 33% and 31% at June 30, ~~2019~~2020 and at December 31, ~~2018.~~2019, respectively.

Capital Requirements

Share Repurchase Program

In the ~~six months ended June 30, 2019,~~first quarter of 2020, we acquired approximately 169 million common shares at a cost of ~~$250~~$85 million under our share repurchase program. ~~The current remaining~~While the share repurchase program has $1.3 billion of remaining authorization, ~~is $1.5 billion.~~we elected to suspend additional share repurchases to preserve liquidity.

~~Other Expected~~

Contractual Cash ~~Outflows~~Obligations

On July 31, 2019, our Board of Directors approved a dividend of $0.05 per share for the second quarter of 2019 payable September 10, 2019 to stockholders of record at the close of business on August 21, 2019.

As of June 30, ~~2019, we plan~~2020, our contractual cash obligations as it relates to ~~make contributions of up to $12 million to~~ our ~~funded pension plans during the remainder of 2019.~~

~~Contractual Cash Obligations~~

~~In the first quarter of 2019, we entered into various~~ transportation and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities, which have varying terms extending as far as 2027. Future commitments remaining as of June 30, 2019 under the arrangements amount to $564decreased approximately $79 million ~~of which $10 million is expected to be incurred in the remainder of 2019, $54 million in 2020, $75~~($8 million in 2021, ~~$76~~$11 million in 2022, ~~$78~~$11 million in 2023, $11 million in 2024 and ~~$271~~$38 million ~~thereafter.~~thereafter) related to the cancellation of a transportation service agreement in the Bakken resource play.

Environmental Matters and Other Contingencies

There have been no significant changes to the environmental, health and safety matters under Item 1. Business or Item 3. Legal Proceedings in our ~~2018~~2019 Annual Report on Form 10-K. See Note 2224 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 ~~future performance, business strategy, reserve estimates, asset quality, production guidance,~~operational and financial strategies, including drilling plans and projects, planned wells, rig count, inventory, seismic, exploration plans, maintenance activities, drilling and completion improvements, cost reductions, and financial flexibility; our ability to successfully effect those strategies and the expected timing and results thereof; our 2020 Capital Budget and the planned allocation thereof; planned capital ~~plans, cost~~expenditures and ~~expense estimates, asset acquisitions~~the impact thereof; expectations regarding future economic and ~~dispositions, future~~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 ~~other plans~~capital resources, and ~~objectives for~~the benefits thereof; resource and asset potential; reserve estimates; growth expectations; and future ~~operations,~~production and sales expectations, and the drivers thereof, are forward-looking statements. Words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “guidance,” “intend,” “may,” “outlook,” “plan,” “project,” “seek,” “should,” “target,” “will,” “would” or similar words may be used to identify forward-looking statements; however, the absence of these words does not mean that the statements are not forward-looking. While we believe our assumptions concerning future events are reasonable, a number of factors could cause results to differ materially from those projected, including, but not limited to:

•conditions in the oil and gas industry, including supply and demand levels for crude oil and condensate, NGLs and natural gas and the resulting impact on price;

•changes in expected reserve or production levels;

•changes in political and economic conditions in the ~~jurisdictions in which we operate,~~U.S. and E.G., including changes in foreign currency exchange rates, interest rates, and inflation ~~rates,~~rates;

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

•risks related to our hedging activities;

•voluntary and involuntary volume curtailments;

•delays or cancellations of certain drilling activities;

•liability resulting from litigation;

•capital available for exploration and development;

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

•drilling and operating risks;

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

•well production timing;

•availability of drilling rigs, materials and labor, including the costs associated therewith;

•difficulty in obtaining necessary approvals and permits;

•non-performance by third parties of their contractual ~~obligations;~~obligations, including due to bankruptcy;

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

~~cyber-attacks;~~•shortages of key personnel, including employees, contractors and subcontractors;

•cyber-attacks;

•changes in safety, health, environmental, tax and other ~~regulations;~~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 ~~2018~~2019 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other filings with the SEC.

All forward-looking statements included in this report are based on information available to us on the date of this report. Except as required by law, we undertake no obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.

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 1315 and Note 1416 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, ~~2019,~~2020, we had various open commodity ~~derivatives related to crude oil with a net asset position of $25 million.~~derivatives. Based on the June 30, ~~2019~~2020 published ~~index~~NYMEX WTI and natural gas futures prices, a hypothetical 10% change (per bbl for crude ~~oil) increases (decreases)~~oil, per MMbtu for gas) would change the fair values of our $79 million net ~~commodity derivative open positions as follows:~~asset position to the following:


(In millions)	Hypothetical Price Increase of 10%		Hypothetical Price Decrease of 10%
Derivative asset - Crude Oil	$	57	$	93
Derivative asset (liability) - Natural Gas	(4)		5
Total	$	53	$	98

(In millions) Hypothetical Price Increase of 10% Hypothetical Price Decrease of 10%
Crude oil derivatives $ (35 ) $ 37

Interest Rate Risk

At June 30, ~~2019~~2020 our portfolio of current and long-term debt is comprised of fixed-rate instruments with an outstanding balance of $5.5 billion. Our sensitivity to interest rate movements and corresponding changes in the fair value of our fixed-rate debt portfolio affects our results of operations and cash flows only when we elect to repurchase or otherwise retire fixed-rate debt at prices different than carrying value.

At June 30, 2020, we had forward starting interest rate swap agreements with a total notional of $1.1 billion designated as cash flow 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. A hypothetical 10% change in interest rates would change the fair values of our $24 million net liability position to the following as of June 30, 2020:


(In millions)	Hypothetical Interest Rate Increase of 10%		Hypothetical Interest Rate Decrease of 10%
Interest rate cash flow hedges	$	16	$	32

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, ~~2019.~~2020.

During the first six months of ~~2019,~~2020, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II – OTHER INFORMATION

Item 1. Legal Proceedings

There have been no significant changes to Item 3. Legal Proceedings in our ~~2018~~2019 Annual Report on Form 10-K. See Note 2224 to the consolidated financial statements included in Part I, Item I for a description of such legal and administrative proceedings.

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. In addition to the other information set forth in this Quarterly Report on Form 10-Q, the reader should carefully consider the factors discussed in Item 1A. Risk Factors in our 2019 Annual Report on Form 10-K. There have been no material changes to the risk factors ~~under~~from those listed in Item 1A. Risk Factors in our ~~2018~~2019 Annual Report on Form ~~10-K.~~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.

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, ~~2019~~2020 of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities Exchange Act of 1934:


Period	Total Number of Shares Purchased^(a)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs^(b)	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs^(b)
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)
04/01/2019 – 04/30/2019
1,950,289
$ 17.56
1,939,827
$ 751,964,257
05/01/2019 – 05/31/2019
8,701,662
$ 15.48
8,699,788
$ 617,286,263
06/01/2019 – 06/30/2019
4,988,831
$ 13.43
4,988,831
$ 550,286,171
Total 15,640,782
$ 15.09
15,628,446

^(a)23,936 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.


^(a) ^(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.	~~12,336 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 for a total authorized amount of $7.2 billion.

As of June 30, ~~2019,~~2020, we have repurchased ~~174~~191 million common shares at a cost of approximately ~~$5.6~~$5.9 billion, ~~excluding transaction fees and commissions. In the second quarter of 2019, share repurchases were approximately $236 million,~~ excluding transaction fees and commissions. Purchases under the program are made at our discretion and may be in either open market transactions, including block purchases, or in privately negotiated transactions using cash on hand, cash generated from operations, proceeds from potential asset sales or cash from available borrowings to acquire shares. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. In connection with the economic downturn, during the second quarter of 2020, the Company temporarily suspended the share repurchase program. Shares repurchased as of June 30, ~~2019~~2020 were held as treasury stock.

Item 6. Exhibits

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

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 ~~8, 2019~~6, 2020		MARATHON OIL CORPORATION

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

Exhibit Index

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

Exhibit Number

Exhibit Description

Form

Exhibit

Filing Date

3.1

Restated Certificate of Incorporation of Marathon Oil Corporation

8-K

3.1

6/1/2018

3.2

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

10-Q

3.2

8/4/2016

3.3

Specimen of Common Stock Certificate

10-K

3.3

2/28/2014

4.1

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

10-K

4.2

2/28/2014

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*
Form of Marathon Oil Corporation 2019 Incentive Compensation Plan Restricted Stock Award Agreement for Section 16 Officers

10.2*
Form of Marathon Oil Corporation 2019 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Section 16 Officers

10.3*
Form of Marathon Oil Corporation 2019 Incentive Compensation Plan Restricted Stock Unit Award Agreement for Section 16 Officers

10.4*
Form of Marathon Oil Corporation 2019 Incentive Compensation Plan Restricted Stock Unit Award Agreement for Non-Employee Directors

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
* Filed herewith.



	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	2928
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4445
Item 4.	Controls and Procedures	4445

Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	4546
Item 1A.	Risk Factors	4546
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4547

Item 6.	Exhibits	4547
	Signatures	4648



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



(In millions)	June 30, 2019		January 1, 2019
Receivables from contracts with customers, included in receivables, less reserves	$	797	$	714
Contract asset (liability)	$	21	$	(1	)



	Three Months Ended June 30, 2019
						Not Allocated
(In millions)	U.S.		Int’l			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 costs	—		(1		)	(1		)		(2		)
Income tax provision (benefit)	3		17			12				32
Segment income	$	215	$	96		$	(150	)		$	161
Capital expenditures^(a)	$	686	$	10		$	5			$	701



(In millions)	Operating Lease Obligations
2019	$	61
2020	106
2021	62
2022	35
2023	5
Thereafter	1
Total undiscounted lease payments	$	270
Less: amount representing interest	15
Total operating lease liabilities	$	255
Less: current portion of long-term lease liability as of June 30, 2019	104
Long-term lease liability as of June 30, 2019	$	151