# UNITED	STATES

# SECURITIES	AND	EXCHANGE	COMMISSION

# ANNUAL	REPORT	PURSUANT	TO	SECTION	13	OR	15(d)

OF	THE	SECURITIES	EXCHANGE	ACT	OF	1934

For	the	Fiscal	Year	Ended	December	31,	2017

Commission	file	number	1-5153

mro_logoa43.jpg

# Marathon	Oil	Corporation

(Exact	name	of	registrant	as	specified	in	its	charter)

Delaware

(State	or	other	jurisdiction	of	incorporation	or	organization)

(I.R.S.	Employer	Identification	No.)

(Address	of	principal	executive	offices)

(Registrant's	telephone	number,	including	area	code)

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

Title	of	each	class

Common	Stock,	par	value	$1.00

Name	of	each	exchange	on	which	registered

New	York	Stock	Exchange

# 	Securities	registered	pursuant	to	Section	12(g)	of	the	Act:	None

Indicate	by	check	mark	if	the	registrant	is	a	well-known	seasoned	issuer,	as	defined	in	Rule	405	of	the	Securities	Act.		Yes þ	No	o

Indicate	by	check	mark	if	the	registrant	is	not	required	to	file	reports	pursuant	to	Section	13	or	Section	15(d)	of	the	Act.		Yes o	No		þ

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	and	(2)	has	been	subject	to	such filing	requirements	for	the	past	90	days.		Yes	þ	No	o

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

Indicate	by	check	mark	if	disclosure	of	delinquent	filers	pursuant	to	Item	405	of	Regulation	S-K	is	not	contained	herein,	and	will	not	be	contained,	to	the	best	of	registrant's	knowledge,	in	definitive	proxy	or	information statements	incorporated	by	reference	in	Part	III	of	this	Form	10-K	or	any	amendment	to	this	Form	10-K.		þ

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

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

Smaller	reporting	company	o Emerging	growth	company	o

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

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

The	aggregate	market	value	of	Common	Stock	held	by	non-affiliates	as	of	 June	30,	2017:	$10,050	million.	This	amount	is	based	on	the	closing	price	of	the	registrant's	Common	Stock	on	the	New	York	Stock	Exchange on	that	date.	Shares	of	Common	Stock	held	by	executive	officers	and	directors	of	the	registrant	are	not	included	in	the	computation.	The	registrant,	solely	for	the	purpose	of	this	required	presentation,	has	deemed	its directors	and	executive	officers	to	be	affiliates.

There	were	849,755,866	shares	of	Marathon	Oil	Corporation	Common	Stock	outstanding as	of	February	14,	2018.

Documents	Incorporated	By	Reference:

Portions	of	the	registrant's	proxy	statement	relating	to	its	 2018	Annual	Meeting	of	Stockholders,	to	be	filed	with	the	Securities	and	Exchange	Commission	pursuant	to	Regulation	14A	under	the	Securities	Exchange	Act of	1934,	are	incorporated	by	reference	to	the	extent	set	forth	in	Part	III,	Items	10-14	of	this	report.

Unless	the	context	otherwise	indicates,	references	to	"Marathon	Oil,"	"we,"	"our"	or	"us"	in	this	Annual	Report	on	Form	10-K	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).

# Table	of	Contents

# PART	I

| Item	1. | Business | 5 |
| :--- | :--- | :--- |
| Item\t1A. | Risk\tFactors | 16 |
| Item\t1B. | Unresolved\tStaff\tComments | 25 |
| Item\t2. | Properties | 25 |
| Item\t3. | Legal\tProceedings | 25 |
| Item\t4. | Mine\tSafety\tDisclosures | 25 |
| Item\t5. | Market\tfor\tRegistrant's\tCommon\tEquity,\tRelated\tStockholder\tMatters\tand\tIssuer\tPurchases\tof\tEquity\tSecurities | 26 |
| Item\t6. | Selected\tFinancial\tData | 27 |
| Item\t7. | Management's\tDiscussion\tand\tAnalysis\tof\tFinancial\tCondition\tand\tResults\tof\tOperations | 28 |
| Item\t7A. | Quantitative\tand\tQualitative\tDisclosures\tAbout\tMarket\tRisk | 50 |
| Item\t8. | Financial\tStatements\tand\tSupplementary\tData | 53 |
| Item\t9. | Changes\tin\tand\tDisagreements\twith\tAccountants\ton\tAccounting\tand\tFinancial\tDisclosure | 113 |
| Item\t9A. | Controls\tand\tProcedures | 113 |
| Item\t9B. | Other\tInformation | 113 |
| Item\t10. | Directors,\tExecutive\tOfficers\tand\tCorporate\tGovernance | 114 |
| Item\t11. | Executive\tCompensation | 114 |
| Item\t12. | Security\tOwnership\tof\tCertain\tBeneficial\tOwners\tand\tManagement\tand\tRelated\tStockholder\tMatters | 114 |
| Item\t13. | Certain\tRelationships\tand\tRelated\tTransactions,\tand\tDirector\tIndependence | 115 |
| Item\t14. | Principal\tAccountant\tFees\tand\tServices | 115 |
| Item\t15. | Exhibits,\tFinancial\tStatement\tSchedules | 116 |
| Item\t16. | Form\t10-K\tSummary | 116 |
|  | SIGNATURES | 117 |

# Definitions

Throughout	this	report,	the	following	company	or	industry	specific	terms	and	abbreviations	are	used.

AMPCO	–	Atlantic	Methanol	Production	Company	LLC,	a	company	located	in	Equatorial	Guinea	in	which	we	own	a	45%	equity	interest.

AOSP	–	Athabasca	Oil	Sands	Project,	an	oil	sands	mining,	transportation	and	upgrading	joint	venture	located	in	Alberta,	Canada,	in	which	we	held	a	20%	non-operated working	interest.

bbl	–	One	stock	tank	barrel,	which	is	42	United	States	gallons	liquid	volume.

bcf	–	Billion	cubic	feet.

boe	–	Barrels	of	oil	equivalent.

btu	–	British	thermal	unit,	an	energy	equivalence	measure.

Capital	Development	Program	–	Includes	capital	expenditures,	cash	investments	in	equity	method	investees	and	other	investments,	exploration	costs	that	are	expensed as	incurred	rather	than	capitalized,	such	as	geological	and	geophysical	costs	and	certain	staff	costs,	and	other	miscellaneous	investment	expenditures.

# DD&A	–	Depreciation,	depletion	and	amortization.

Development	well	–	A	well	drilled	within	the	proved	area	of	an	oil	or	natural	gas	reservoir	to	the	depth	of	a	stratigraphic	horizon	known	to	be	productive.

Dry	well	–	A	well	found	to	be	incapable	of	producing	either	oil	or	natural	gas	in	sufficient	quantities	to	justify	completion.

# E.G.	–	Equatorial	Guinea.

EGHoldings	–	Equatorial	Guinea	LNG	Holdings	Limited,	a	liquefied	natural	gas	production	company	located	in	E.G.	in	which	we	own	a	60%	equity	interest.

# EPA	–	United	States	Environmental	Protection	Agency.

# E&P	–	Exploration	and	production.

Exploratory	well	–	A	well	drilled	to	find	oil	or	natural	gas	in	an	unproved	area	or	find	a	new	reservoir	in	a	field	previously	found	to	be	productive	in	another	reservoir.

# FASB	–	Financial	Accounting	Standards	Board.

Henry	Hub	price	–	a	natural	gas	benchmark	price	quoted	at	settlement	date	average.

IRS	–	United	States	Internal	Revenue	Service.

LNG	–	Liquefied	natural	gas.

LPG	–	Liquefied	petroleum	gas.

Liquid	hydrocarbons	or	liquids	–	Collectively,	crude	oil,	condensate	and	natural	gas	liquids.

LLS	–	Louisiana	Light	Sweet	crude	oil,	an	oil	index	benchmark	price	as	per	Bloomberg	Finance	LLP:	LLS	St.	James.

Marathon	Oil	–	Marathon	Oil	Corporation	and	its	consolidated	subsidiaries:	the	company	as	it	exists	following	the	June	30,	2011	spin-off	of	the	refining,	marketing	and transportation	operations.

mbbld	–	Thousand	barrels	per	day.

mboed	–	Thousand	barrels	of	oil	equivalent	per	day.

mcf	–	Thousand	cubic	feet.

mmbbl	–	Million	barrels.

mmboe	–	Million	barrels	of	oil	equivalent.

mmbtu	–	Million	British	thermal	units.

mmcfd	–	Million	stabilized	cubic	feet	per	day.

mmta	–	Million	metric	tonnes	per	annum.

MPC	–	Marathon	Petroleum	Corporation	–	the	separate	independent	company,	which	owns	and	operates	the	refining,	marketing	and	transportation	operations.

# mt	–	metric	tonnes

mtd	–	metric	tonnes	per	day.

Net	acres	or	Net	wells	–	The	sum	of	the	fractional	working	interests	owned	by	us	in	gross	acres	or	gross	wells.

NGL	or	NGLs	–	Natural	gas	liquid	or	natural	gas	liquids,	which	are	naturally	occurring	substances	found	in	natural	gas,	including	ethane,	butane,	isobutane,	propane	and natural	gasoline,	which	can	be	collectively	removed	from	produced	natural	gas,	separated	into	these	substances	and	sold.

NYMEX	–	New	York	Mercantile	Exchange.

OECD	–	Organization	for	Economic	Cooperation	and	Development.

OPEC	–	Organization	of	Petroleum	Exporting	Countries.

Operational	availability	–	A	term	used	to	measure	the	ability	of	an	asset	to	produce	to	its	maximum	capacity	over	a	specified	period	of	time,	after	consideration	of internal	losses.

Productive	well	–	A	well	that	is	not	a	dry	well.	Productive	wells	include	producing	wells	and	wells	that	are	mechanically	capable	of	production.

Proved	developed	reserves	–	Proved	reserves	that	can	be	expected	to	be	recovered	through	existing	wells	with	existing	equipment	and	operating	methods	or	for	which the	cost	of	the	required	equipment	is	relatively	minor	compared	to	the	cost	of	a	new	well.

Proved	reserves	–	Proved	crude	oil	and	condensate,	NGLs,	natural	gas	and	our	historical	synthetic	crude	oil	reserves	are	those	quantities	of	crude	oil	and	condensate, NGLs,	natural	gas	and	synthetic	crude	oil,	which,	by	analysis	of	geoscience	and	engineering	data,	can	be	estimated	with	reasonable	certainty	to	be	economically producible	from	a	given	date	forward,	from	known	reservoirs,	and	under	existing	economic	conditions,	operating	methods,	and	government	regulations-prior	to	the	time at	which	contracts	providing	the	right	to	operate	expire,	unless	evidence	indicates	that	renewal	is	reasonably	certain,	regardless	of	whether	deterministic	or	probabilistic methods	are	used	for	the	estimation.	The	project	to	extract	the	hydrocarbons	must	have	commenced	or	the	operator	must	be	reasonably	certain	that	it	will	commence	the project	within	a	reasonable	time.

Proved	undeveloped	reserves	–	Proved	reserves	that	are	expected	to	be	recovered	from	new	wells	on	undrilled	acreage,	or	from	existing	wells	where	a	relatively	major expenditure	is	required	for	recompletion.	Undrilled	locations	can	be	classified	as	having	proved	undeveloped	reserves	if	a	development	plan	has	been	adopted	indicating that	they	are	scheduled	to	be	drilled	within	five	years,	unless	the	specific	circumstances	justify	a	longer	time.	Reserves	on	undrilled	acreage	shall	be	limited	to	those directly	offsetting	development	spacing	areas	that	are	reasonably	certain	of	production	when	drilled,	unless	evidence	using	reliable	technology	exists	that	establishes reasonable	certainty	of	economic	viability	at	greater	distances.

Reserve	replacement	ratio	–	A	ratio	which	measures	the	amount	of	proved	reserves	added	to	our	reserve	base	during	the	year	relative	to	the	amount	of	liquid hydrocarbons	and	natural	gas	produced.

Royalty	interest	–	An	interest	in	an	oil	or	natural	gas	property	entitling	the	owner	to	a	share	of	oil	or	natural	gas	production	free	of	costs	of	production.

SAR	or	SARs	–	Stock	appreciation	right	or	stock	appreciation	rights.

SCOOP	–	South	Central	Oklahoma	Oil	Province.

SEC	–	United	States	Securities	and	Exchange	Commission.

Seismic	–	An	exploration	method	of	sending	energy	waves	or	sound	waves	into	the	earth	and	recording	the	wave	reflections	to	indicate	the	type,	size,	shape	and	depth	of subsurface	rock	formation	(3-D	seismic	provides	three-dimensional	pictures	and	4-D	factors	in	changes	that	occurred	over	time).

STACK	–	Sooner	Trend,	Anadarko	(basin),	Canadian	(and)	Kingfisher	(counties).

TD	–	Total	depth	or	the	bottom	of	a	drilled	hole.

Total	proved	reserves	–	The	summation	of	proved	developed	reserves	and	proved	undeveloped	reserves.

U.K.	–	United	Kingdom.

U.S.	–	United	States	of	America.

U.S.	resource	plays	–	Consists	of	our	unconventional	properties	in	the	Oklahoma,	Eagle	Ford,	Bakken	and	Northern	Delaware.

# U.S.	GAAP	–	U.S.	Generally	Accepted	Accounting	principles

Working	interest	–	The	interest	in	a	mineral	property,	which	gives	the	owner	that	share	of	production	from	the	property.	A	working	interest	owner	bears	that	share	of	the costs	of	exploration,	development	and	production	in	return	for	a	share	of	production.	Working	interests	are	sometimes	burdened	by	overriding	royalty	interests	or	other interests.

WTI	–	West	Texas	Intermediate	crude	oil,	an	oil	index	benchmark	price	as	quoted	by	NYMEX.

# Disclosures	Regarding	Forward-Looking	Statements

This	Annual	Report	on	Form	10-K	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.	These	are	statements,	other	than	statements	of	historical	fact,	that	give	current	expectations	or	forecasts	of	future	events,	including without	limitation:	our	operational,	financial	and	growth	strategies,	including	drilling	plans	and	projects,	planned	wells,	rig	count,	inventory,	seismic,	exploration	plans, maintenance	activities,	drilling	and	completion	improvements,	cost	reductions,	non-core	asset	sales,	and	financial	flexibility;	our	ability	to	successfully	effect	those strategies	and	the	expected	timing	and	results	thereof;	our	2018	capital	development	program	and	the	planned	allocation	thereof;	planned	capital	expenditures	and	the impact	thereof;	expectations	regarding	future	economic	and	market	conditions	and	their	effects	on	us;	our	financial	and	operational	outlook,	and	ability	to	fulfill	that outlook;	our	financial	position,	balance	sheet,	liquidity	and	capital	resources,	and	the	benefits	thereof;	resource	and	asset	potential;	reserve	estimates;	growth expectations;	and	future	production	and	sales	expectations,	and	the	drivers	thereof.	In	addition,	many	forward-looking	statements	may	be	identified	by	the	use	of forward-looking	terminology	such	as	"anticipates,"	"believes,"	"estimates,"	"expects,"	"targets,"	"plans,"	"projects,"	"could,"	"may,"	"should,"	"would"	or	similar words	indicating	that	future	outcomes	are	uncertain.	While	we	believe	that	our	assumptions	concerning	future	events	are	reasonable,	these	expectations	may	not	prove	to be	correct.	A	number	of	factors	could	cause	results	to	differ	materially	from	those	indicated	by	such	forward-looking	statements	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	or	economic	conditions	in	the	jurisdictions	in	which	we	operate,	including	changes	in	foreign	currency	exchange	rates,	interest	rates, inflation	rates,	and	global	and	domestic	market	conditions;

•risks	relating	to	our	hedging

activities;

•capital	available	for	exploration	and	development;

•drilling	and	operating	risks;

•well	production

timing;

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

•difficulty	in	obtaining	necessary	approvals	and permits;

•non-performance	by	third	parties	of	their	contractual obligations;

•unforeseen	hazards	such	as	weather	conditions,	acts	of	war	or	terrorist	acts	and	the	governmental	or	military	response thereto;

•cyber-attacks;

•changes	in	safety,	health,	environmental,	tax	and	other regulations;

•other	geological,	operating	and	economic	considerations;

•other	factors	discussed	in	Item	1.	Business,	Item	1A.	Risk	Factors,	Item	7.	Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of Operations,	Item	7A.	Quantitative	and	Qualitative	Disclosures	About	Market	Risk,	and	elsewhere	in	this	report.

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	assume	no duty	to	revise	or	update	any	forward-looking	statements	whether	as	a	result	of	new	information,	future	events	or	otherwise.	All	subsequent	written	and	oral	forward- looking	statements	attributable	to	us	or	persons	acting	on	our	behalf	are	expressly	qualified	in	their	entirety	by	the	cautionary	statements	contained	throughout	this report.

# Item	1.	Business

# General

Marathon	Oil	Corporation	(NYSE:	MRO)	is	an	independent	exploration	and	production	company	based	in	Houston,	Texas,	focused	on	U.S.	unconventional resource	plays	with	operations	in	the	United	States,	Europe	and	Africa.	Our	corporate	headquarters	is	located	at	5555	San	Felipe	Street,	Houston,	Texas	77056-2723	and our	telephone	number	is	(713)	629-6600.	Each	of	our	two	reportable	operating	segments	are	organized	and	managed	based	upon	geographic	location	and	the	nature	of the	products	and	services	offered.	The	two	segments	are:

•United	States	E&P	–	explores	for,	produces	and	markets	crude	oil	and	condensate,	NGLs	and	natural	gas	in	the	United

States;

•International	E&P	–	explores	for,	produces	and	markets	crude	oil	and	condensate,	NGLs	and	natural	gas	outside	of	the	United	States	and	produces	and	markets products	manufactured	from	natural	gas,	such	as	LNG	and	methanol,	in	E.G.

# We	were	incorporated	in	2001.

Our	strategy	is	to	deliver	competitive	returns	by	focusing	on	the	lowest	cost,	highest	margin	U.S.	resource	plays	while	maintaining	a	peer-leading	balance	sheet.	See Item	7.	Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations,	for	a	more	detailed	discussion	of	our	operating	results,	cash	flows	and liquidity.

We	are	concentrated	on	our	core	operations	in	our	U.S.	unconventional	resource	plays	and	E.G.	The	map	below	shows	the	locations	of	our	core	operations:

*	Our	additional	locations	include	the	Gulf	of	Mexico,	U.K.,	Libya,	Gabon	and	the	Kurdistan	Region	of	Iraq.

# Segment	and	Geographic	Information

In	the	second	quarter	of	2017,	we	closed	on	the	sale	of	our	Canadian	business	which	includes	our	Oil	Sands	Mining	segment	and	exploration	stage	in-situ	leases. The	Canadian	business	is	reflected	as	discontinued	operations	in	all	periods	presented.	Additionally,	we	have	renamed	our	North	America	E&P	segment	to	United	States E&P	segment,	effective	June	30,	2017.	See	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	1	to	the	consolidated	financial	statements	for	further	detail.	For reportable	operating	segment	and	geographic	financial	information,	see	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	6	to	the	consolidated	financial statements.

In	the	following	discussion	regarding	our	United	States	E&P	and	International	E&P	segments,	references	to	sales	or	investment	indicate	our	ownership	interest	or share,	as	the	context	requires.

# United	States	E&P	Segment

We	are	engaged	in	oil	and	gas	exploration,	development	and	production	activities	in	the	U.S.	Our	primary	focus	in	the	United	States	E&P	segment	is	concentrated within	our	four	high	quality	unconventional	resource	plays.	See	Item	7.		Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	for further	detail	on	current	year	results.

# United	States	E&P--	Unconventional	Resource	Plays

Eagle	Ford	–	We	have	been	operating	in	the	South	Texas	Eagle	Ford	play	since	2011,	where	roughly	two	thirds	of	our	acreage	is	located	in	Karnes	County	and Atascosa	County.	We	operate	32	central	gathering	and	treating	facilities	across	the	field	that	support	more	than	1,500	producing	wells.	We	also	own	and	operate	the Sugarloaf	gathering	system,	a	42-mile	natural	gas	pipeline	through	the	heart	of	our	acreage	in	Karnes,	Atascosa	and	Bee	Counties.

Bakken	–	We	have	been	operating	in	North	Dakota	and	eastern	Montana	since	2006.	The	majority	of	our	acreage	is	in	core	prospects	within	McKenzie,	Mountrail, and	Dunn	Counties	in	North	Dakota.	We	continue	focusing	on	the	high-return	Myrmidon	area	building	on	the	successes	from	our	enhanced	completion	designs,	as	well as	delineating	our	position	in	Hector.

Oklahoma	–	Our	primary	focus	in	Oklahoma	has	been	delineation	and	leasehold	protection	in	the	Meramec	play	in	the	STACK	and	delineation	of	the	Woodford	and Springer	plays	in	the	SCOOP,	as	we	move	toward	infill	development.	We	hold	net	acreage	with	rights	to	the	Woodford,	Springer,	Meramec,	Osage,	Oswego,	Granite Wash	and	other	Pennsylvanian	and	Mississippian	plays,	with	a	majority	of	this	in	the	SCOOP	and	STACK.

Northern	Delaware	–	We	closed	on	multiple	Permian	acquisitions	during	2017,	with	a	majority	of	the	acreage	in	Northern	Delaware.	These	acquisitions	give	us	a strong	foundational	footprint	in	the	region	where	we	have	begun	developing	the	Wolfcamp	and	Bone	Spring	plays.	See	Item	8.	Financial	Statements	and	Supplementary Data	–	Note	5	to	the	consolidated	financial	statements	for	further	detail.

# Other	United	States

Our	remaining	properties	in	the	United	States	primarily	consist	of	outside	operated	assets	in	the	Gulf	of	Mexico,	including	the	Gunflint	field	where	we	hold	an	18% non-operated	working	interest.

# International	E&P	Segment

We	are	engaged	in	oil	and	gas	development	and	production	across	our	international	locations	primarily	in	E.G.,	U.K.	and	Libya.	We	include	the	results	of	our	LPG processing	plant,	gas	liquefaction	operations	and	methanol	production	operations	in	E.G.	in	our	International	E&P	segment.

# International	E&P

Equatorial	Guinea	–	We	own	a	63%	operated	working	interest	under	a	production	sharing	contract	in	the	Alba	field	and	an	80%	operated	working	interest	in	Block D,	both	of	which	are	offshore	E.G.	Block	D	was	unitized	with	the	Alba	field	in	second	quarter	2017.	Operational	availability	from	our	company-operated	facilities averaged	approximately	99%	in	2017.

Equatorial	Guinea	–	Gas	Processing	–	We	own	a	52%	interest	in	Alba	Plant	LLC,	accounted	for	as	an	equity	method	investment,	which	operates	an	onshore	LPG processing	plant	located	on	Bioko	Island.	Alba	field	natural	gas,	under	a	long-term	contract	at	a	fixed	price	per	btu,	is	processed	by	the	LPG	plant.	The	LPG	plant extracts	secondary	condensate	and	LPG	from	the	natural	gas	stream	and	uses	some	of	the	remaining	dry	natural	gas	in	its	operations.

We	also	own	60%	of	EGHoldings	and	45%	of	AMPCO,	both	accounted	for	as	equity	method	investments.	EGHoldings	operates	a	3.7	mmta	LNG	production facility	and	AMPCO	operates	a	methanol	plant,	both	located	on	Bioko	Island.	These	facilities	allow	us	to	further	monetize	natural	gas	production	from	the	Alba	field. The	LNG	production	facility	sells	LNG	under	a	3.4	mmta	sales	and	purchase	agreement.	Under	the	agreement,	which	runs	through	2023,	the	purchaser	takes	delivery	of the	LNG	on	Bioko	Island,	with	pricing	linked	principally	to	the	Henry	Hub	index.	Gross	sales	of	LNG	from	this	production	facility	totaled	approximately	3.95	mmta	in 2017.	AMPCO	had	gross	sales	totaling	approximately	1,100	mt	in	2017.	Methanol	production	is	sold	to	customers	in	Europe	and	the	U.S.

United	Kingdom	–	Our	operated	asset	in	the	U.K.	sector	of	the	North	Sea	is	the	Brae	area	complex	where	we	have	a	42%	working	interest	in	the	South,	Central, North	and	West	Brae	fields,	a	39%	working	interest	in	the	East	Brae	field,	and	a	28%	working	interest	in	the	nearby	Braemar	field.	We	own	non-operated	working interests	in	the	Foinaven	area	complex,	consisting	of	a	28%	working	interest	in	the	main	Foinaven	field,	a	47%	working	interest	in	East	Foinaven	and	a	20%	working interest	in	the	T35	and	T25	fields.

Libya	–	We	hold	a	16%	non-operated	working	interest	in	the	Waha	concessions,	which	includes	acreage	located	in	the	Sirte	Basin	of	eastern	Libya.	While	civil	and political	unrest	has	interrupted	operations	in	recent	years,	our	production	resumed	in	October	2016	at	our	Waha	concession.	During	December	2016,	liftings	resumed from	the	Es	Sider	crude	oil	terminal.	During	2017	sales	volumes	and	production	continued,	except	for	a	brief	interruption	in	March	2017	due	to	civil	unrest.

# Other	International

Kurdistan	Region	of	Iraq	–	We	have	non-operated	interests	in	two	blocks	located	north-northwest	of	Erbil:	Atrush	with	a	15%	working	interest	and	Sarsang	with	a 20%	working	interest.	In	2016,	we	relinquished	to	the	Kurdistan	Regional	Government	our	45%	operated	working	interest	in	the	Harir	block	located	northeast	of	Erbil.

Gabon	–	We	hold	a	100%	participating	interest	and	operatorship	in	the	Tchicuate	block	where	we	have	an	exploration	and	production	sharing	agreement.

In	the	third	quarter	2017,	we	entered	into	separate	agreements	to	sell	certain	non-core	properties	in	our	International	E&P	segment,	and	a	portion	of	this	transaction closed	during	the	4th	quarter	2017.	See	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	5	to	the	consolidated	financial	statements	for	information	about these	dispositions.

# Reserves

Proved	reserves	are	required	to	be	disclosed	by	continent	and	by	country	if	the	proved	reserves	related	to	any	geographic	area,	on	an	oil	equivalent	barrel	basis, represent	15%	or	more	of	our	total	proved	reserves.	A	geographic	area	can	be	an	individual	country,	group	of	countries	within	a	continent	or	a	continent.	Other International	("Other	Int'l"),	includes	the	U.K.	and	the	Kurdistan	Region	of	Iraq.	Approximately	72%	of	our	proved	reserves	are	located	in	OECD	countries,	with	70% located	within	the	U.S.

The	following	tables	set	forth	estimated	quantities	of	our	total	proved	crude	oil	and	condensate,	NGLs	and	natural	gas	reserves	based	upon	SEC	pricing	for	period ended	December	31,	2017.

| December	31,	2017 | U.S. | E.G. | Libya | Total | Other	Int'l | Total	from<br>Cont	Ops |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Proved\tDeveloped\tReserves |  |  |  |  |  |  |
| Crude\toil\tand\tcondensate\t(mmbbl) | 263 | 39 | 165 | 204 | 17 | 484 |
| Natural\tgas\tliquids\t(mmbbl) | 118 | 25 | — | 25 | — | 143 |
| Natural\tgas\t(bcf) | 726 | 833 | 94 | 927 | 2 | 1,655 |
| Total\tproved\tdeveloped\treserves\t\t(mmboe) | 502 | 203 | 181 | 384 | 17 | 903 |
| Proved\tUndeveloped\tReserves |  |  |  |  |  |  |
| Crude\toil\tand\tcondensate\t(mmbbl) | 307 | — | — | — | 9 | 316 |
| Natural\tgas\tliquids\t(mmbbl) | 111 | — | — | — | — | 111 |
| Natural\tgas\t(bcf) | 598 | — | 110 | 110 | 6 | 714 |
| Total\tproved\tundeveloped\treserves\t\t(mmboe) | 518 | — | 18 | 18 | 10 | 546 |
| Total\tProved\tReserves |  |  |  |  |  |  |
| Crude\toil\tand\tcondensate\t(mmbbl) | 570 | 39 | 165 | 204 | 26 | 800 |
| Natural\tgas\tliquids\t(mmbbl) | 229 | 25 | — | 25 | — | 254 |
| Natural\tgas\t(bcf) | 1,324 | 833 | 204 | 1,037 | 8 | 2,369 |
| Total\tproved\treserves\t(mmboe) | 1,020 | 203 | 199 | 402 | 27 | 1,449 |

Of	the	total	estimated	proved	reserves,	approximately	55%	was	crude	oil	and	condensate.	As	of	December	31,	2017,	our	estimated	proved	developed	reserves totaled	903	mmboe	or	62%	and	estimated	proved	undeveloped	reserves	totaling	546	mmboe	or	38%	of	our	total	proved	reserves.	For	additional	detail	on	reserves,	see Item	8.	Financial	Statements	and	Supplementary	Data	-	Supplementary	Information	on	Oil	and	gas	Producing	Activities.

# Productive	and	Drilling	Wells

For	our	United	States	E&P	and	International	E&P	segments,	the	following	table	sets	forth	gross	and	net	productive	wells,	service	wells	and	drilling	wells	as	of December	31	for	the	years	presented.

|  | Oil<br>Gross | Net | Natural	Gas<br>Gross | Net | Service	Wells<br>Gross | Net | Drilling	Wells<br>Gross | Net |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2017 |  |  |  |  |  |  |  |  |
| U.S. | 5,132 | 1,905 | 1,690 | 676 | 799 | 70 | 33 | 13 |
| E.G. | — | — | 19 | 12 | — | — | — | — |
| Libya | 1,071 | 175 | 7 | 2 | 94 | 16 | — | — |
| Total\tAfrica | 1,071 | 175 | 26 | 14 | 94 | 16 | — | — |
| Other\tInternational | 61 | 22 | 19 | 7 | 23 | 8 | — | — |
| Total | 6,264 | 2,102 | 1,735 | 697 | 916 | 94 | 33 | 13 |
| 2016 |  |  |  |  |  |  |  |  |
| U.S.\t(a) | 4,533 | 1,650 | 1,830 | 708 | 821 | 85 |  |  |
| E.G. | — | — | 17 | 11 | 2 | 1 |  |  |
| Libya | 1,071 | 175 | 7 | 1 | 94 | 16 |  |  |
| Total\tAfrica | 1,071 | 175 | 24 | 12 | 96 | 17 |  |  |
| Other\tInternational | 62 | 23 | 35 | 14 | 23 | 8 |  |  |
| Total | 5,666 | 1,848 | 1,889 | 734 | 940 | 110 |  |  |
| 2015 |  |  |  |  |  |  |  |  |
| U.S. | 7,198 | 2,878 | 1,796 | 750 | 2,727 | 747 |  |  |
| E.G. | — | — | 17 | 11 | 2 | 1 |  |  |
| Libya | 1,071 | 175 | 7 | 1 | 94 | 16 |  |  |
| Total\tAfrica | 1,071 | 175 | 24 | 12 | 96 | 17 |  |  |
| Other\tInternational | 59 | 21 | 39 | 16 | 24 | 8 |  |  |
| Total | 8,328 | 3,074 | 1,859 | 778 | 2,847 | 772 |  |  |

(a) Reduction	in	December	31,	2016	gross	and	net	productive	wells	and	service	wells	is	primarily	due	to	the	dispositions	of	certain	conventional	West	Texas	and	Wyoming	assets	in	2016.	See	Item 8.	Financial	Statements	and	Supplementary	Data	-	Note	5	to	the	consolidated	financial	statements	for	information	about	these	dispositions.

# Drilling	Activity

For	our	United	States	E&P	and	International	E&P	segments,	the	table	below	sets	forth,	by	geographic	area,	the	number	of	net	productive	and	dry	development	and exploratory	wells	completed	as	of	December	31	for	the	years	represented.

|  | Oil | Development<br>Natural<br>Gas | Dry | Total | Oil | Exploratory<br>Natural<br>Gas | Dry | Total | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2017 |  |  |  |  |  |  |  |  |  |
| U.S. | 107 | 27 | — | 134 | 88 | 16 | — | 104 | 238 |
| E.G. | — | — | — | — | — | — | — | — | — |
| Libya | — | — | — | — | — | — | — | — | — |
| Total\tAfrica | — | — |  | — | — | — | — | — | — |
| Other\tInternational | — | — | — | — | — | — | — | — | — |
| Total | 107 | 27 | — | 134 | 88 | 16 | — | 104 | 238 |
| 2016 |  |  |  |  |  |  |  |  |  |
| U.S. | 64 | 12 | — | 76 | 70 | 27 | — | 97 | 173 |
| E.G. | — | — | — | — | — | — | — | — | — |
| Libya | — | — | — | — | — | — | — | — | — |
| Total\tAfrica | — | — | — | — | — | — | — | — | — |
| Other\tInternational | — | — | — | — | — | — | — | — | — |
| Total | 64 | 12 | — | 76 | 70 | 27 | — | 97 | 173 |
| 2015 |  |  |  |  |  |  |  |  |  |
| U.S. | 135 | 36 | 11 | 182 | 49 | 48 | 1 | 98 | 280 |
| E.G. | — | 1 | — | 1 | — | — | 1 | 1 | 2 |
| Libya | — | — | — | — | — | — | — | — | — |
| Total\tAfrica | — | 1 | — | 1 | — | — | 1 | 1 | 2 |
| Other\tInternational | 1 | — | — | 1 | — | — | — | — | 1 |
| Total | 136 | 37 | 11 | 184 | 49 | 48 | 2 | 99 | 283 |

# Acreage

We	believe	we	have	satisfactory	title	to	our	United	States	E&P	and	International	E&P	properties	in	accordance	with	standards	generally	accepted	in	the	industry; nevertheless,	we	can	be	involved	in	title	disputes	from	time	to	time	which	may	result	in	litigation.	In	the	case	of	undeveloped	properties,	an	investigation	of	record	title	is made	at	the	time	of	acquisition.	Drilling	title	opinions	are	usually	prepared	before	commencement	of	drilling	operations.	Our	title	to	properties	may	be	subject	to	burdens such	as	royalty,	overriding	royalty,	carried,	net	profits,	working	and	other	similar	interests	and	contractual	arrangements	customary	in	the	industry.	In	addition,	our interests	may	be	subject	to	obligations	or	duties	under	applicable	laws	or	burdens	such	as	net	profits	interests,	liens	related	to	operating	agreements,	development obligations	or	capital	commitments	under	international	production	sharing	contracts	or	exploration	licenses.

The	following	table	sets	forth,	by	geographic	area,	the	gross	and	net	developed	and	undeveloped	acreage	held	in	our	United	States	E&P	and	International	E&P segments	as	of	December	31,	2017.

|  | Developed |  | Undeveloped |  | Developed	and<br>Undeveloped |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tthousands) | Gross | Net | Gross | Net | Gross | Net |
| U.S. | 1,529 | 1,008 | 388 | 322 | 1,917 | 1,330 |
| \t\tE.G. | 82 | 67 | 54 | 36 | 136 | 103 |
| \t\tLibya | 12,909 | 2,108 | — | — | 12,909 | 2,108 |
| \t\tOther\tAfrica | — | — | 277 | 277 | 277 | 277 |
| Total\tAfrica | 12,991 | 2,175 | 331 | 313 | 13,322 | 2,488 |
| Other\tInternational | 86 | 31 | 171 | 32 | 257 | 63 |
| Total | 14,606 | 3,214 | 890 | 667 | 15,496 | 3,881 |

In	the	ordinary	course	of	business,	based	on	our	evaluations	of	certain	geologic	trends	and	prospective	economics,	we	have	allowed	certain	lease	acreage	to	expire and	may	allow	additional	acreage	to	expire	in	the	future.	If	production	is	not	established	or	we	take	no	other	action	to	extend	the	terms	of	the	leases,	licenses	or concessions,	additional	undeveloped	acreage	will	expire	in	future	years.	We	plan	to	continue	the	terms	of	certain	of	these	licenses	and	concession	areas	or	retain	leases through	operational	or	administrative	actions.

# Net	Sales	Volumes

|  | U.S. | E.G. | Libya | Other	Int'l | Cont	Ops | Disc	Ops | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Year\tEnded\tDecember\t31, |  |  |  |  |  |  |  |
| 2017 |  |  |  |  |  |  |  |
| Crude\tand\tcondensate\t(mbbld)(a) | 133 | 21 | 19 | 12 | 185 | — | 185 |
| Natural\tgas\tliquids\t(mbbld) | 43 | 11 | — | 1 | 55 | — | 55 |
| Natural\tgas\t(mmcfd)(b) | 348 | 459 | 4 | 22 | 833 | — | 833 |
| Synthetic\tcrude\toil\t(mbbld)(c) | — | — | — | — | — | 18 | 18 |
| Total\tsales\tvolumes\t(mboed) | 234 | 109 | 20 | 16 | 379 | 18 | 397 |
| 2016 |  |  |  |  |  |  |  |
| Crude\tand\tcondensate\t(mbbld)(a) | 131 | 20 | 3 | 12 | 166 | — | 166 |
| Natural\tgas\tliquids\t(mbbld) | 40 | 11 | — | — | 51 | — | 51 |
| Natural\tgas\t(mmcfd)(b) | 314 | 425 | — | 28 | 767 | — | 767 |
| Synthetic\tcrude\toil\t(mbbld)(c) | — | — | — | — | — | 48 | 48 |
| Total\tsales\tvolumes\t(mboed) | 223 | 102 | 3 | 17 | 345 | 48 | 393 |
| 2015 |  |  |  |  |  |  |  |
| Crude\tand\tcondensate\t(mbbld)(a) | 171 | 19 | — | 14 | 204 | — | 204 |
| Natural\tgas\tliquids\t(mbbld) | 39 | 10 | — | — | 49 | — | 49 |
| Natural\tgas\t(mmcfd)(b) | 351 | 410 | — | 21 | 782 | — | 782 |
| Synthetic\tcrude\toil\t(mbbld)(c) | — | — | — | — | — | 45 | 45 |
| Total\tsales\tvolumes\t(mboed) | 269 | 97 | — | 18 | 384 | 45 | 429 |

(a) The	amounts	correspond	with	the	basis	for	fiscal	settlements	with	governments,	representing	equity	tanker	liftings	and	direct	deliveries	of	liquid	hydrocarbons.

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

(c) Upgraded	bitumen	excluding	blendstocks.

# Average	Production	Cost	per	Unit	 (a)

| (Dollars	per	boe) | U.S. | E.G. | Libya | Other	Int'l | Cont	Ops | Disc	Ops | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2017 | $9.49 | $2.12 | $6.08 | $26.61 | $7.90 | $29.72 | $9.23 |
| 2016 | 9.84 | 2.17 | N.M. | 23.13 | 8.41 | 29.36 | 11.02 |
| 2015 | 10.65 | 2.37 | N.M. | 27.23 | 9.54 | 38.42 | 12.62 |

(a) Production,	severance	and	property	taxes	are	excluded;	however,	shipping	and	handling	as	well	as	other	operating	expenses	are	included	in	the	production	costs	used	in	this	calculation.	See Item	8.	Financial	Statements	and	Supplementary	Data	–	Supplementary	Information	on	Oil	and	Gas	Producing	Activities	-	Results	of	Operations	for	Oil	and	Gas	Production	Activities	for	more information	regarding	production	costs.

N.M.	Not	meaningful	information	due	to	limited	sales.

# Average	Sales	Price	per	Unit(a)

| (Dollars	per	unit) | U.S. | E.G. |  | Libya | Total | Other	Int'l | Disc	Ops | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2017 |  |  |  |  |  |  |  |  |
| Crude\tand\tcondensate\t(bbl) | $49.35 | $46.02 |  | $60.72 | $53.11 | $52.66 | $— | $50.38 |
| Natural\tgas\tliquids\t(bbl) | 20.55 | 1.00 | (b) | — | 1.00 | 39.65 | — | 16.65 |
| Natural\tgas\t(mcf) | 2.84 | 0.24 | (b) | 5.03 | 0.28 | 6.28 | — | 1.51 |
| Synthetic\tcrude\toil\t(bbl) | — | — |  | — | — | — | 47.39 | 47.39 |
| 2016 |  |  |  |  |  |  |  |  |
| Crude\tand\tcondensate\t(bbl) | $38.57 | $38.85 |  | $57.69 | $40.95 | $43.21 | $— | $39.23 |
| Natural\tgas\tliquids\t(bbl) | 13.15 | 1.00 | (b) | — | 1.00 | 26.41 | — | 10.68 |
| Natural\tgas\t(mcf) | 2.38 | 0.24 | (b) | — | 0.24 | 4.80 | — | 1.26 |
| Synthetic\tcrude\toil\t(bbl) | — | — |  | — | — | — | 37.57 | 37.57 |
| 2015 |  |  |  |  |  |  |  |  |
| Crude\tand\tcondensate\t(bbl) | $43.50 | $42.83 |  | $— | $42.83 | $53.91 | $— | $44.14 |
| Natural\tgas\tliquids\t(bbl) | 13.37 | 1.00 | (b) | — | 1.00 | 32.53 | — | 11.16 |
| Natural\tgas\t(mcf) | 2.66 | 0.24 | (b) | — | 0.24 | 6.85 | — | 1.50 |
| Synthetic\tcrude\toil\t(bbl) | — | — |  | — | — | — | 40.13 | 40.13 |

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

(b) Primarily	represents	fixed	prices	under	long-term	contracts	with	Alba	Plant	LLC,	AMPCO	and/or	EGHoldings,	which	are	equity	method	investees.	We	include	our	share	of	income	from	each	of these	equity	method	investees	in	our	International	E&P	Segment.

# Marketing

Our	reportable	operating	segments	include	activities	related	to	the	marketing	and	transportation	of	substantially	all	of	our	crude	oil	and	condensate,	NGLs	and natural	gas.	These	activities	include	the	transportation	of	production	to	market	centers,	the	sale	of	commodities	to	third	parties	and	the	storage	of	production.	We	balance our	various	sales,	storage	and	transportation	positions	in	order	to	aggregate	volumes	to	satisfy	transportation	commitments	and	to	achieve	flexibility	within	product	types and	delivery	points.	Such	activities	can	include	the	purchase	of	commodities	from	third	parties	for	resale.

# Gross	Delivery	Commitments

We	have	committed	to	deliver	gross	quantities	of	crude	oil	and	condensate,	NGLs	and	natural	gas	to	customers	under	a	variety	of	contracts.	As	of	December	31, 2017,	the	contracts	for	fixed	and	determinable	quantities	were	at	variable,	market-based	pricing	and	related	primarily	to	the	following	commitments:

|  | 2018 | 2019 | 2020 | Thereafter | Through |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Eagle\tFord |  |  |  |  |  |
| Crude\tand\tcondensate\t(mbbld) | 95 | 65 | 51 | — | 2020 |
| Natural\tgas\tliquids\t(mbbld) | 1 | 1 | — | — | 2020 |
| Natural\tgas\t(mmcfd) | 168 | 168 | 168 | 46\t-\t70 | 2022 |
| Bakken |  |  |  |  |  |
| Crude\tand\tcondensate\t(mbbld) | 10 | 10 | 10 | 5\t-\t10 | 2027 |
| Natural\tgas\t(mmcfd) | 2 | 2 | 2 | 2\t-\t25 | 2027 |
| Oklahoma |  |  |  |  |  |
| Natural\tgas\t(mmcfd) |  |  |  |  |  |
|  | — | 90 | 118 | 110\t-\t148 | 2030 |

All	of	these	contracts	provide	the	options	of	delivering	third-party	volumes	or	paying	a	monetary	shortfall	penalty	if	production	is	inadequate.	In	addition	to	the contracts	discussed	above,	we	have	entered	into	numerous	agreements	for	transportation	and	processing	of	our	equity	production.	Some	of	these	contracts	have volumetric	requirements	which	could	require	monetary	shortfall	penalties	if	our	production	is	inadequate	to	meet	the	terms.

# Competition

Competition	exists	in	all	sectors	of	the	oil	and	gas	industry	and	we	compete	with	major	integrated	and	independent	oil	and	gas	companies,	as	well	as	national	oil companies.	We	compete,	in	particular,	in	the	exploration	for	and	development	of	new	reserves,	acquisition	of	oil	and	natural	gas	leases	and	other	properties,	the marketing	and	delivery	of	our	production	into	worldwide	commodity	markets	and	for	the	labor	and	equipment	required	for	exploration	and	development	of	those properties.	Principal	methods	of	competing	include	geological,	geophysical,	and	engineering	research	and	technology,	experience	and	expertise,	economic	analysis	in connection	with	portfolio	management,	and	safely	operating	oil	and	gas	producing	properties.	See	Item	1A.	Risk	Factors	for	discussion	of	specific	areas	in	which	we compete	and	related	risks.

# Environmental,	Health	and	Safety	Matters

The	Health,	Environmental,	Safety	and	Corporate	Responsibility	Committee	of	our	Board	of	Directors	is	responsible	for	overseeing	our	position	on	public	issues, including	environmental,	health	and	safety	matters.	Our	Corporate	Health,	Environment,	Safety	and	Security	organization	has	the	responsibility	to	ensure	that	our operating	organizations	maintain	environmental	compliance	systems	that	support	and	foster	our	compliance	with	applicable	laws	and	regulations.	Committees	comprised of	certain	of	our	officers	review	our	overall	performance	associated	with	various	environmental	compliance	programs.	We	also	have	a	Corporate	Emergency	Response Team	which	oversees	our	response	to	any	major	environmental	or	other	emergency	incident	involving	us	or	any	of	our	properties.

Our	businesses	are	subject	to	numerous	laws	and	regulations	relating	to	the	protection	of	the	environment,	health	and	safety	at	the	national,	state	and	local	levels. These	laws	and	their	implementing	regulations	and	other	similar	state	and	local	laws	and	rules	can	impose	certain	operational	controls	for	minimization	of	pollution	or recordkeeping,	monitoring	and	reporting	requirements	or	other	operational	or	siting	constraints	on	our	business,	result	in	costs	to	remediate	releases	of	regulated substances,	including	crude	oil,	into	the	environment,	or	require	costs	to	remediate	sites	to	which	we	sent	regulated	substances	for	disposal.	In	some	cases,	these	laws	can impose	strict	liability	for	the	entire	cost	of	clean-up	on	any	responsible	party	without	regard	to	negligence	or	fault	and	impose	liability	on	us	for	the	conduct	of	others (such	as	prior	owners	or	operators	of	our	assets)	or	conditions	others	have	caused,	or	for	our	acts	that	complied	with	all	applicable	requirements	when	we	performed them.	We	have	incurred	and	will	continue	to	incur	capital,	operating	and	maintenance,	and	remediation	expenditures	as	a	result	of	environmental	laws	and	regulations.

New	laws	have	been	enacted	and	regulations	are	being	adopted	by	various	regulatory	agencies	on	a	continuing	basis	and	the	costs	of	compliance	with	these	new laws	and	regulations	can	only	be	broadly	appraised	until	their	implementation	becomes	more	defined.

For	a	discussion	of	environmental	capital	expenditures	and	costs	of	compliance	for	air,	water,	solid	waste	and	remediation,	see	Item	3.	Legal	Proceedings	and Item	7.	Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	–	Management's	Discussion	and	Analysis	of	Environmental	Matters, Litigation	and	Contingencies.

# Air	and	Climate	Change

Environmental	advocacy	groups	and	regulatory	agencies	in	the	United	States	and	other	countries	have	focused	considerable	attention	on	the	emissions	of	carbon dioxide,	methane	and	other	greenhouse	gases	and	their	potential	role	in	climate	change.	Developments	in	greenhouse	gas	initiatives	may	affect	us	and	other	similarly situated	companies	operating	in	the	oil	and	gas	industry.	As	part	of	our	commitment	to	environmental	stewardship,	we	estimate	and	publicly	report	greenhouse	gas emissions	from	our	operations.	We	are	working	to	continuously	improve	the	accuracy	and	completeness	of	these	estimates.	In	addition,	we	continuously	strive	to improve	operational	and	energy	efficiencies	through	resource	and	energy	conservation	where	practicable	and	cost	effective.

Government	entities	have	filed	lawsuits	in	California	and	New	York	seeking	to	hold	a	wide	variety	of	companies	that	produce	fossil	fuels	liable	for	the	alleged impacts	of	the	greenhouse	gas	emissions	attributable	to	those	fuels.	The	lawsuits	allege	damages	as	a	result	of	global	warming	and	the	plaintiffs	are	seeking	unspecified damages	and	abatement	under	various	tort	theories.	Marathon	Oil	has	been	named	as	a	defendant	in	six	of	these	lawsuits	in	California,	along	with	numerous	other companies.	Similar	lawsuits	may	be	filed	in	other	jurisdictions.	While	the	ultimate	outcome	and	impact	to	us	cannot	be	predicted	with	certainty,	we	believe	that	the claims	made	against	us	are	without	merit	and	will	not	have	a	material	adverse	effect	on	our	consolidated	financial	position,	results	of	operations	or	cash	flow.

The	EPA	finalized	a	more	stringent	National	Ambient	Air	Quality	Standard	("NAAQS")	for	ozone	in	October	2015.	This	more	stringent	ozone	NAAQS	could	result in	additional	areas	being	designated	as	non-attainment,	including	areas	in	which	we	operate,	which	may	result	in	an	increase	in	costs	for	emission	controls	and requirements	for	additional	monitoring	and	testing,	as	well	as	a	more	cumbersome	permitting	process.	The	EPA	anticipates	promulgating	final	area	designations	under the	new	standard	in	the	first	half	of	2018.	Although	there	may	be	an	adverse	financial	impact	(including	compliance	costs,	potential	permitting	delays	and	increased regulatory	requirements)	associated	with	this	revised	regulation,	the	extent	and	magnitude	of

that	impact	cannot	be	reliably	or	accurately	estimated	due	to	the	present	uncertainty	regarding	any	additional	measures	and	how	they	will	be	implemented.	The	EPA's final	rule	has	been	judicially	challenged	by	both	industry	and	other	interested	parties,	and	the	outcome	of	this	litigation	may	also	impact	implementation	and	revisions	to the	rule.

In	November	2016,	the	Bureau	of	Land	Management	("BLM")	issued	a	final	rule	to	further	restrict	venting	and/or	flaring	of	gas	from	facilities	subject	to	BLM jurisdiction,	and	to	modify	certain	royalty	requirements.		BLM	issued	a	two-year	stay	of	these	requirements	in	December	2017	and	has	indicated	that	the	requirements could	be	rescinded	or	significantly	revised	in	the	future.	If	not	withdrawn	or	significantly	revised,	this	rule	is	expected	to	result	in	additional	costs	of	compliance	as	well as	increased	monitoring,	recordkeeping	and	recording	for	some	of	our	facilities.		If	we	are	unable	to	comply	with	the	terms	of	these	regulations,	we	could	be	required	to forego	certain	operations.	These	regulations	may	also	result	in	administrative,	civil	and/or	criminal	penalties	for	non-compliance.

# Hydraulic	Fracturing

Hydraulic	fracturing	is	a	commonly	used	process	that	involves	injecting	water,	sand	and	small	volumes	of	chemicals	into	the	wellbore	to	fracture	the	hydrocarbon- bearing	rock	thousands	of	feet	below	the	surface	to	facilitate	higher	flow	of	hydrocarbons	into	the	wellbore.	Our	business	uses	this	technique	extensively	throughout	our operations.	Hydraulic	fracturing	has	been	regulated	at	the	state	and	local	level	through	permitting	and	compliance	requirements.	Various	state	and	local-level	initiatives in	regions	with	substantial	shale	resources	have	been	or	may	be	proposed	or	implemented	to	further	regulate	hydraulic	fracturing	practices,	limit	water	withdrawals	and water	use,	require	disclosure	of	fracturing	fluid	constituents,	restrict	which	additives	may	be	used,	or	implement	temporary	or	permanent	bans	on	hydraulic	fracturing.

# Water

In	2014,	the	EPA	and	the	U.S.	Army	Corps	of	Engineers	published	proposed	regulations	which	expand	the	surface	waters	that	are	regulated	under	the	Clean	Water Act	("CWA")	and	its	various	programs.	While	these	regulations	were	finalized	largely	as	proposed	in	2015,	the	rule	has	been	stayed	by	the	courts	pending	a	substantive decision	on	the	merits.	If	this	rule	is	ultimately	implemented,	the	expansion	of	CWA	jurisdiction	will	result	in	additional	costs	of	compliance	as	well	as	increased monitoring,	recordkeeping	and	recording	for	some	of	our	facilities.

For	additional	information,	see	Item	1A.	Risk	Factors.

# Concentrations	of	Credit	Risk

We	are	exposed	to	credit	risk	in	the	event	of	nonpayment	by	counterparties,	a	significant	portion	of	which	are	concentrated	in	energy-related	industries.	The creditworthiness	of	customers	and	other	counterparties	is	subject	to	continuing	review,	including	the	use	of	master	netting	agreements,	where	appropriate.	In	2017,	sales to	Vitol	and	each	of	their	respective	affiliates	accounted	for	approximately	10%	of	our	total	revenues.	In	2016,	sales	to	Valero	Marketing	and	Supply,	Tesoro	Petroleum, and	Flint	Hills	Resources	and	each	of	their	respective	affiliates	accounted	for	approximately	13%,	11%	and	10%	of	our	total	revenues.	In	2015,	sales	to	Shell	Oil	and	its affiliates	accounted	for	approximately	10%	of	our	total	revenues.

# Trademarks,	Patents	and	Licenses

We	currently	hold	a	number	of	U.S.	and	foreign	patents.	Although	in	the	aggregate	our	trademarks,	patents	and	licenses	are	important	to	us,	we	do	not	regard	any single	trademark,	patent,	license	or	group	of	related	trademarks,	patents	or	licenses	as	critical	or	essential	to	our	business	as	a	whole.

# Employees

We	had	approximately	2,300	active,	full-time	employees	as	of	December	31,	2017.

# Executive	Officers	of	the	Registrant

The	executive	officers	of	Marathon	Oil	and	their	ages	as	of	February	1,	2018,	are	as	follows:

Mr.	Tillman	was	appointed	president	and	chief	executive	officer	in	August	2013.		Mr.	Tillman	is	also	a	member	of	our	Board	of	Directors.		Prior	to	this appointment,	Mr.	Tillman	served	as	vice	president	of	engineering	for	ExxonMobil	Development	Company	(a	project	design	and	execution	company),	where	he	was responsible	for	all	global	engineering	staff	engaged	in	major	project	concept	selection,	front-end	design	and	engineering.		Between	2007	and	2010,	Mr.	Tillman	served as	North	Sea	production	manager	and	lead	country	manager	for	subsidiaries	of	ExxonMobil	in	Stavanger,	Norway.		Mr.	Tillman	began	his	career	in	the	oil	and	gas industry	at	Exxon	Corporation	in	1989	as	a	research	engineer	and	has	extensive	operations	management	and	leadership	experience.

Mr.	Whitehead	was	appointed	executive	vice	president	and	chief	financial	officer	in	March	2017.	Prior	to	this	appointment,	Mr.	Whitehead	served	as	executive	vice president	and	chief	financial	officer	of	both	EP	Energy	Corp.	and	EP	Energy	LLC	(oil	and	natural	gas	producer)	since	May	2012.	Between	2009	and	2012	Mr. Whitehead	served	as	senior	vice	president	of	strategy	and	enterprise	business	development	and	a	member	of	El	Paso	Corporation's	executive	committee.	He	joined	El Paso	Exploration	&	Production	Company	as	senior	vice	president	and	chief	financial	officer	in	2006.	Before	joining	El	Paso	Mr.	Whitehead	was	vice	president, controller	and	chief	accounting	officer	of	Burlington	Resources	Inc.	(oil	and	natural	gas	producer),	and	formerly	senior	vice	president	and	CFO	of	Burlington	Resources Canada.

Mr.	Little	was	appointed	executive	vice	president	of	operations	in	August	2016	after	having	served	as	vice	president,	conventional	since	December	2015,	vice president	international	and	offshore	exploration	and	production	operations	since	September	2013,	and	as	vice	president,	international	production	operations	since September	2012.	Prior	to	that,	Mr.	Little	was	resident	manager	of	our	Norway	operations	and	served	as	general	manager,	worldwide	drilling	and	completions.	Mr.	Little joined	Marathon	Oil	in	1986	and	has	since	held	a	number	of	engineering	and	management	positions	of	increasing	responsibility.

Mr.	Hedgebeth	was	appointed	senior	vice	president,	general	counsel	and	secretary	in	April	2017.	Between	2009	and	2017	Mr.	Hedgebeth	served	as	general	counsel, corporate	secretary	and	chief	compliance	officer	for	Spectra	Energy	Corp	(oil	and	natural	gas	pipeline	company)	and	general	counsel	for	Spectra	Energy	Partners,	LP. Before	joining	Spectra	Energy	Mr.	Hedgebeth	served	as	senior	vice	president,	general	counsel	and	secretary	with	Circuit	City	Stores,	Inc.	(consumer	electronics company),	and	vice	president	of	legal	for	The	Home	Depot,	Inc.	(home	improvement	supplies	retailing	company).

Mr.	Wagner	was	appointed	executive	vice	president	of	corporate	development	and	strategy	in	November	2017	after	having	served	as	senior	vice	president	of corporate	development	and	strategy	since	March	2017,	vice	president	of	corporate	development	and	interim	chief	financial	officer	since	August	2016	and	vice	president of	corporate	development	since	April	2014.	Prior	to	this	appointment,	he	served	as	senior	vice	president,	western	business	unit,	for	QR	Energy	LP	(an	oil	and	natural	gas producer)	and	the	affiliated	Quantum	Resources	Management,	which	he	joined	in	early	2012	as	vice	president,	exploitation.	Prior	to	that,	Mr.	Wagner	was	managing director	in	Houston	for	Scotia	Waterous,	the	oil	and	gas	arm	of	Scotiabank	(an	international	banking	services	provider),	from	2010	to	2012.	Before	joining	Scotia,	Mr. Wagner	was	vice	president,	Gulf	of	Mexico,	for	Devon	Energy	Corp.	(an	oil	and	natural	gas	producer),	having	joined	Devon	in	2003	as	manager,	international exploitation.

Ms.	Krajicek	was	appointed	vice	president—conventional	assets	in	August	2016	after	having	served	as	vice	president	of	technology	and	innovation	since	December 2015.	Prior	to	that,	Ms.	Krajicek	served	as	vice	president,	health,	environment,	safety	and	security	from	January	2015	through	December	2015.	In	January	2018	Ms. Krajicek	announced	her	plans	to	retire	effective	April	1,	2018.	Ms.	Krajicek	joined	Marathon	Oil	in	2007	and	has	since	held	a	number	of	positions	of	increasing responsibility.	Prior	to	joining	the	Company,	Ms.	Krajicek	spent	22	years	with	Conoco	and	then	ConocoPhillips	(a	multinational	energy	corporation),	where	she	held	a variety	of	reservoir	engineering	and	asset	management	and	development	management	positions	for	upstream	and	mid-stream	businesses	under	development,	both	in	the U.S.	and	internationally.

Mr.	Wilson	was	appointed	vice	president,	controller	and	chief	accounting	officer	in	October	2014.	Prior	to	joining	Marathon	Oil,	he	served	in	various	finance	and accounting	positions	of	increasing	responsibility	at	Noble	Energy,	Inc.	(a	global	exploration	and	production	company)	since	2001,	including	as	director	corporate accounting	from	February	2014	through	September	2014,	director	global	operations	services	finance	from	October	2012	through	February	2014,	director	controls	and

reporting	from	April	2011	through	September	2012,	and	international	finance	manager	from	September	2009	through	March	2011.

# Available	Information

Our	website	is	www.marathonoil.com.	Our	Annual	Reports	on	Form	10-K,	Quarterly	Reports	on	Form	10-Q	and	Current	Reports	on	Form	8-K	and	other	reports and	filings	with	the	SEC	are	available	free	of	charge	on	our	website	as	soon	as	reasonably	practicable	after	the	reports	are	filed	or	furnished	with	the	SEC.	Information contained	on	our	website	is	not	incorporated	into	this	Annual	Report	on	Form	10-K	or	our	other	securities	filings.	Our	filings	are	also	available	in	hard	copy,	free	of charge,	by	contacting	our	Investor	Relations	office.

The	public	may	read	and	copy	any	materials	we	file	with	the	SEC	at	its	Public	Reference	Room	at	100	F	Street,	NE,	Washington,	DC	20549.	Information	on	the operation	of	the	Public	Reference	Room	may	be	obtained	by	calling	the	SEC	at	1-800-SEC-0330.	The	SEC	also	maintains	a	website	(www.sec.gov)	that	contains reports,	proxy	and	information	statements	and	other	information	regarding	issuers	that	file	electronically	with	the	SEC.

Additionally,	we	make	available	free	of	charge	on	our	website:

•our	Code	of	Business	Conduct	and	Code	of	Ethics	for	Senior	Financial

Officers;

•our	Corporate	Governance	Principles;	and

•the	charters	of	our	Audit	and	Finance	Committee,	Compensation	Committee,	Corporate	Governance	and	Nominating	Committee	and	Health,	Environmental, Safety	and	Corporate	Responsibility	Committee.

# Item	1A.	Risk	Factors

We	are	subject	to	various	risks	and	uncertainties	in	the	course	of	our	business.	The	following	summarizes	significant	risks	and	uncertainties	that	may	adversely affect	our	business,	financial	condition	or	results	of	operations.	When	considering	an	investment	in	our	securities,	you	should	carefully	consider	the	risk	factors	included below	as	well	as	those	matters	referenced	in	the	foregoing	pages	under	"Disclosures	Regarding	Forward-Looking	Statements"	and	other	information	included	and incorporated	by	reference	into	this	Annual	Report	on	Form	10-K.

# A	substantial	decline	in	crude	oil	and	condensate,	NGLs	and	natural	gas	prices	would	reduce	our	operating	results	and	cash	flows	and	could	adversely	impact our	future	rate	of	growth	and	the	carrying	value	of	our	assets.

The	markets	for	crude	oil	and	condensate,	NGLs	and	natural	gas	have	been	volatile	and	are	likely	to	continue	to	be	volatile	in	the	future,	causing	prices	to	fluctuate widely.	Our	revenues,	operating	results	and	future	rate	of	growth	are	highly	dependent	on	the	prices	we	receive	for	our	crude	oil	and	condensate,	NGLs	and	natural	gas. Many	of	the	factors	influencing	prices	of	crude	oil	and	condensate,	NGLs	and	natural	gas	are	beyond	our	control.	These	factors	include:

•worldwide	and	domestic	supplies	of	and	demand	for	crude	oil	and	condensate,	NGLs	and	natural	gas;

•the	cost	of	exploring	for,	developing	and	producing	crude	oil	and	condensate,	NGLs	and	natural

•the	ability	of	the	members	of	OPEC	and	certain	non-OPEC	members,	such	as	Russia,	to	agree	to	and	maintain	production controls;

•the	production	levels	of	non-OPEC	countries,	including	production	levels	in	the	shale	plays	in	the	United States;

•the	level	of	drilling,	completion	and	production	activities	by	other	exploration	and	production	companies,	and	variability	therein,	in	response	to	market conditions;

•political	instability	or	armed	conflict	in	oil	and	natural	gas	producing regions;

•changes	in	weather	patterns	and	climate;

•natural	disasters	such	as	hurricanes	and	tornadoes;

•the	price	and	availability	of	alternative	and	competing	forms	of energy;

•the	effect	of	conservation efforts;

•epidemics	or	pandemics;

•technological	advances	affecting	energy	consumption	and	energy supply;

•domestic	and	foreign	governmental	regulations	and	taxes; and

•general	economic	conditions	worldwide.

The	long-term	effects	of	these	and	other	factors	on	the	prices	of	crude	oil	and	condensate,	NGLs	and	natural	gas	are	uncertain.	Historical	declines	in	commodity prices	have	adversely	affected	our	business	by:

•reducing	the	amount	of	crude	oil	and	condensate,	NGLs	and	natural	gas	that	we	can	produce economically;

•reducing	our	revenues,	operating	income	and	cash flows;

•causing	us	to	reduce	our	capital	expenditures,	and	delay	or	postpone	some	of	our	capital projects;

•requiring	us	to	impair	the	carrying	value	of	our assets;

•reducing	the	standardized	measure	of	discounted	future	net	cash	flows	relating	to	crude	oil	and	condensate,	NGLs	and	natural	gas;

•increasing	the	costs	of	obtaining	capital,	such	as	equity	and	short-	and	long-term

debt.

Estimates	of	crude	oil	and	condensate,	NGLs	and	natural	gas	reserves	depend	on	many	factors	and	assumptions,	including	various	assumptions	that	are	based on	conditions	in	existence	as	of	the	dates	of	the	estimates.	Any	material	changes	in	those	conditions	or	other	factors	affecting	those	assumptions	could	impair the	quantity	and	value	of	our	reserves.

The	proved	reserve	information	included	in	this	Annual	Report	on	Form	10-K	has	been	derived	from	engineering	and	geoscience	estimates.	Estimates	of	crude	oil and	condensate,	NGLs,	natural	gas	and	our	historical	synthetic	crude	oil	reserves	were	prepared,	in	accordance	with	SEC	regulations,	by	our	in-house	teams	of	reservoir engineers	and	geoscience	professionals	and	were	reviewed	and	approved	by	our	Corporate	Reserves	Group	and	third-party	consultants.	Prior	to	2016,	the	synthetic

crude	oil	reserves	estimates,	included	in	discontinued	operations,	were	prepared	by	GLJ,	a	third-party	consulting	firm	experienced	in	working	with	oil	sands.	Reserves were	valued	based	on	SEC	pricing	for	the	periods	ended	December	31,	2017,	2016	and	2015,	as	well	as	other	conditions	in	existence	at	those	dates.	The	table	below provides	the	2017	SEC	pricing	for	certain	benchmark	prices:

If	commodity	prices	were	to	decrease	by	approximately	10%	below	average	prices	used	to	estimate	2017	proved	reserves	(see	table	above),	we	would	not	expect price	related	reserve	revisions	to	have	a	material	impact	on	proved	reserve	volumes.	Future	reserve	revisions	could	also	result	from	changes	in	capital	funding,	drilling plans	and	governmental	regulation,	among	other	things.

Reserve	estimation	is	a	subjective	process	that	involves	estimating	volumes	to	be	recovered	from	underground	accumulations	of	crude	oil	and	condensate,	NGLs and	natural	gas	that	cannot	be	directly	measured.	Estimates	of	economically	producible	reserves	and	of	future	net	cash	flows	depend	on	a	number	of	variable	factors	and assumptions,	including:

•location,	size	and	shape	of	the	accumulation	as	well	as	fluid,	rock	and	producing	characteristics	of	the accumulation;

•historical	production	from	the	area,	compared	with	production	from	other	analogous	producing areas;

•the	assumed	impacts	of	regulation	by	governmental agencies;

•assumptions	concerning	future	operating	costs,	taxes,	development	costs	and	workover	and	repair	costs;

•industry	economic	conditions,	levels	of	cash	flows	from	operations	and	other	operating

considerations.

As	a	result,	different	petroleum	engineers	and	geoscientists,	each	using	industry-accepted	geologic	and	engineering	practices	and	scientific	methods,	may	produce different	estimates	of	proved	reserves	and	future	net	cash	flows	based	on	the	same	available	data.	Because	of	the	subjective	nature	of	such	reserve	estimates,	each	of	the following	items	may	differ	materially	from	the	estimated	amounts:

•the	amount	and	timing	of	production;

•the	revenues	and	costs	associated	with	that	production;

•the	amount	and	timing	of	future	development	expenditures.

# If	we	are	unsuccessful	in	acquiring	or	finding	additional	reserves,	our	future	crude	oil	and	condensate,	NGLs	and	natural	gas	production	would	decline, thereby	reducing	our	cash	flows	and	results	of	operations	and	impairing	our	financial	condition.

The	rate	of	production	from	crude	oil	and	condensate,	NGLs	and	natural	gas	properties	generally	declines	as	reserves	are	depleted.	Except	to	the	extent	we	acquire interests	in	additional	properties	containing	proved	reserves,	conduct	successful	exploration	and	development	activities	or,	through	engineering	studies,	optimize production	performance	or	identify	additional	reservoirs	not	currently	producing	or	secondary	recovery	reserves,	our	proved	reserves	will	decline	materially	as	crude	oil and	condensate,	NGLs	and	natural	gas	are	produced.	Accordingly,	to	the	extent	we	are	not	successful	in	replacing	the	crude	oil	and	condensate,	NGLs	and	natural	gas	we produce,	our	future	revenues	will	decline.	Creating	and	maintaining	an	inventory	of	prospects	for	future	production	depends	on	many	factors,	including:

•obtaining	rights	to	explore	for,	develop	and	produce	crude	oil	and	condensate,	NGLs	and	natural	gas	in	promising areas;

•drilling	success;

•the	ability	to	complete	projects	timely	and	cost	effectively;

•the	ability	to	find	or	acquire	additional	proved	reserves	at	acceptable	costs;

•the	ability	to	fund	such	activity.

# Future	exploration	and	drilling	results	are	uncertain	and	involve	substantial	costs.

Drilling	for	crude	oil	and	condensate,	NGLs	and	natural	gas	involves	numerous	risks,	including	the	risk	that	we	may	not	encounter	commercially	productive reservoirs.	The	costs	of	drilling,	completing	and	operating	wells	are	often	uncertain,	and	drilling	operations	may	be	curtailed,	delayed	or	canceled	as	a	result	of	a	variety of	factors,	including:

•unexpected	drilling conditions;

•title	problems;

•pressure	or	irregularities	in formations;

•equipment	failures	or	accidents;

•inflation	in	exploration	and	drilling costs;

•fires,	explosions,	blowouts	or	surface	cratering;

•lack	of	access	to	pipelines	or	other	transportation	methods;	and

•shortages	or	delays	in	the	availability	of	services	or	delivery	of equipment.

# If	crude	oil	and	condensate,	NGLs	and	natural	gas	prices	decrease,	it	could	adversely	affect	the	abilities	of	our	counterparties	to	perform	their	obligations	to us,	including	abandonment	obligations,	which	could	negatively	impact	our	financial	results.

We	often	enter	into	arrangements	to	conduct	certain	business	operations,	such	as	oil	and	gas	exploration	and	production,	or	transportation	of	crude	oil	and condensate,	NGLs	and	natural	gas,	with	partners	and	other	counterparties	in	order	to	share	risks	associated	with	those	operations.	In	addition,	we	market	our	products	to a	variety	of	purchasers.	If	commodity	prices	decrease,	some	of	our	counterparties	may	experience	liquidity	problems	and	may	not	be	able	to	meet	their	financial	and other	obligations,	including	abandonment	obligations,	to	us.	The	inability	of	our	joint	venture	partners	to	fund	their	portion	of	the	costs	under	our	joint	venture agreements,	or	the	nonperformance	by	purchasers,	contractors	or	other	counterparties	of	their	obligations	to	us,	could	negatively	impact	our	operating	results	and	cash flows.

# If	we	are	unable	to	complete	capital	projects	at	their	expected	costs	and	in	a	timely	manner,	or	if	the	market	conditions	assumed	in	our	project	economics deteriorate,	our	business,	financial	condition,	results	of	operations	and	cash	flows	could	be	materially	and	adversely	affected.

Delays	or	cost	increases	related	to	capital	spending	programs	involving	drilling	and	completion	activities,	engineering,	procurement	and	construction	of	facilities (including	improvements	and	repairs	to	our	existing	facilities)	could	adversely	affect	our	ability	to	achieve	forecasted	internal	rates	of	return	and	operating	results. Delays	in	making	required	changes	or	upgrades	to	our	facilities	could	subject	us	to	fines	or	penalties	as	well	as	affect	our	ability	to	supply	certain	products	we	produce. Such	delays	or	cost	increases	may	arise	as	a	result	of	unpredictable	factors,	many	of	which	are	beyond	our	control,	including:

•denial	of	or	delay	in	receiving	requisite	regulatory	approvals	and/or

permits;

•unplanned	increases	in	the	cost	of	construction	materials	or labor;

•disruptions	in	transportation	of	components	or	construction	materials;

•increased	costs	or	operational	delays	resulting	from	shortages	of water;

•adverse	weather	conditions,	natural	disasters	or	other	events	(such	as	equipment	malfunctions,	explosions,	fires	or	spills)	affecting	our	facilities,	or	those	of vendors	or	suppliers;

•shortages	of	sufficiently	skilled	labor,	or	labor	disagreements	resulting	in	unplanned	work stoppages;

•market-related	increases	in	a	project's	debt	or	equity	financing	costs; and

•nonperformance	by,	or	disputes	with,	vendors,	suppliers,	contractors	or subcontractors.

Any	one	or	more	of	these	factors	could	have	a	significant	impact	on	our	capital	projects.

# Our	offshore	operations	involve	special	risks	that	could	negatively	impact	us.

Offshore	operations	present	technological	challenges	and	operating	risks	because	of	the	marine	environment.		Activities	in	deepwater	areas	may	pose	incrementally greater	risks	because	of	water	depths	that	limit	intervention	capability	and	the	physical	distance	to	oilfield	service	infrastructure	and	service	providers.		Environmental remediation	and	other	costs	resulting	from	spills	or	releases	may	result	in	substantial	liabilities.

# We	may	incur	substantial	capital	expenditures	and	operating	costs	as	a	result	of	compliance	with	and	changes	in	environmental,	health,	safety	and	security laws	and	regulations,	and,	as	a	result,	our	business,	financial	condition,	results	of	operations	and	cash	flows	could	be	materially	and	adversely	affected.

Our	businesses	are	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	venting	or	flaring	of	natural	gas,	waste	management,	pollution	prevention,	greenhouse	gas	emissions	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.	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.	To the	extent	these	expenditures,	as	with	all	costs,	are	not	ultimately	reflected	in	the	prices	of	our	products,	our	operating	results	will	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	countries where	we	operate,	including	the	U.S.	and	the	European	Union.	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.	The	EPA	has	also	finalized	regulations	targeting	new	sources	of	methane	emissions	from	the	oil	and	gas	industry.	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.

# The	potential	adoption	of	federal,	state	and	local	legislative	and	regulatory	initiatives	related	to	hydraulic	fracturing	could	result	in	increased	compliance	costs, operating	restrictions	or	delays	in	the	completion	of	oil	and	gas	wells.

Hydraulic	fracturing	is	a	commonly	used	process	that	involves	injecting	water,	sand,	and	small	volumes	of	chemicals	into	the	wellbore	to	fracture	the	hydrocarbon- bearing	rock	thousands	of	feet	below	the	surface	to	facilitate	higher	flow	of	hydrocarbons	into	the	wellbore.	Our	business	uses	this	technique	extensively	throughout	our U.S.	operations.	Hydraulic	fracturing	has	been	regulated	at	the	state	and	local	level	through	permitting	and	compliance	requirements.	Various	state	and	local-level initiatives	in	regions	with	substantial	shale	resources	have	been	or	may	be	proposed	or	implemented	to	further	regulate	hydraulic	fracturing	practices,	limit	water withdrawals	and	water	use,	require	disclosure	of	fracturing	fluid	constituents,	restrict	which	additives	may	be	used,	or	implement	temporary	or	permanent	bans	on hydraulic	fracturing.	In	2015	the	BLM	issued	a	rule	governing	certain	hydraulic	fracturing	practices	on	lands	within	their	jurisdiction;	however,	this	rule	was	rescinded	in December	2017.

Increased	regulation	and	attention	given	to	the	hydraulic	fracturing	process	could	lead	to	greater	opposition,	including	litigation,	to	oil	and	gas	activities	using hydraulic	fracturing	techniques.	Additional	legislation	or	regulation	could	also	lead	to	operational	delays	or	increased	operating	costs	in	the	production	of	crude	oil	and condensate,	NGLs	and	natural	gas,	including	from	the	shale	plays,	or	could	make	it	more	difficult	to	perform	hydraulic	fracturing.	The	adoption	of	any	federal,	state	or local	laws	or	the	implementation	of	regulations	regarding	hydraulic	fracturing	could	potentially	cause	a	decrease	in	the	completion	of	new	oil	and	gas	wells	and increased	compliance	costs	which	could	increase	costs	of	our	operations	and	cause	considerable	delays	in	acquiring	regulatory	approvals	to	drill	and	complete	wells.

The	potential	adoption	of	federal,	state	and	local	legislative	and	regulatory	initiatives	intended	to	address	potential	induced	seismic	activity	in	the	areas	in which	we	operate	could	result	in	increased	compliance	costs,	operating	restrictions	or	delays	in	the	completion	of	oil	and	gas	wells.

State	and	federal	regulatory	agencies	recently	have	focused	on	a	possible	connection	between	the	operation	of	injection	wells	used	for	oil	and	gas	waste	disposal and	seismic	activity.		When	caused	by	human	activity,	such	events	are	called	induced	seismicity.	Separate	and	apart	from	the	referenced	potential	connection	between injection	wells	and	seismicity,	concerns	have	been	raised	that	hydraulic	fracturing	activities	may	be	correlated	to	anomalous	seismic	events.	Marathon	uses	hydraulic fracturing	techniques	throughout	its	U.S.	operations.

While	the	scientific	community	and	regulatory	agencies	at	all	levels	are	continuing	to	study	the	possible	linkage	between	oil	and	gas	activity	and	induced seismicity,	some	state	regulatory	agencies	have	modified	their	regulations	or	guidance	to	mitigate	potential	causes	of	induced	seismicity.	For	example,	Oklahoma	has taken	numerous	regulatory	actions	in	response	to	concerns	related	to	the	operation	of	produced	water	disposal	wells	and	induced	seismicity,	and	has	issued	guidelines	to operators	in	certain	areas	of	the	State	curtailing	injection	of	produced	water	due	to	seismic	concerns.	Marathon	does	not	currently	own	or	operate	injection	wells	or contract	for	such	services	in	these	areas.	Further,	Oklahoma	recently	issued	guidelines	to	operators	for	management	of	anomalous	seismicity	that	may	be	related	to hydraulic	fracturing	activities	in	the	SCOOP/STACK	area.	In	addition,	a	number	of	lawsuits	have	been	filed	in	Oklahoma	alleging	damage	from	seismicity	relating	to disposal	well	operations.	Marathon	has	not	been	named	in	any	of	those	lawsuits.

Increased	seismicity	in	Oklahoma	or	other	areas	could	result	in	additional	regulation	and	restrictions	on	our	operations	and	could	lead	to	operational	delays	or increased	operating	costs.		Additional	regulation	and	attention	given	to	induced	seismicity	could	also	lead	to	greater	opposition,	including	litigation,	to	oil	and	gas activities.

# Worldwide	political	and	economic	developments	and	changes	in	law	or	policy	could	adversely	affect	our	operations	and	materially	reduce	our	profitability	and cash	flows.

Local	political	and	economic	factors	in	global	markets	could	have	a	material	adverse	effect	on	us.	A	total	of	38%	of	our	crude	oil	and	condensate,	NGLs	and	natural gas	related	to	continuing	operations	in	2017	was	derived	from	production	outside	the	U.S.	and	30%	of	our	proved	reserves	of	crude	oil	and	condensate,	NGLs	and natural	gas	as	of	December	31,	2017	were	located	outside	the	U.S.	We	are,	therefore,	subject	to	the	political,	geographic	and	economic	risks	and	possible	terrorist activities	or	other	armed	conflict	attendant	to	doing	business	within	or	outside	of	the	U.S.	There	are	many	risks	associated	with	operations	in	countries	such	as	E.G., Gabon,	the	Kurdistan	Region	of	Iraq	and	Libya,	and	in	global	markets	including:

•changes	in	governmental	policies	relating	to	crude	oil	and	condensate,	NGLs	or	natural	gas	and

taxation;

•other	political,	economic	or	diplomatic	developments	and	international	monetary	fluctuations;

•political	and	economic	instability,	war,	acts	of	terrorism,	armed	conflict	and	civil disturbances;

•the	possibility	that	a	government	may	seize	our	property	with	or	without	compensation,	may	attempt	to	renegotiate	or	revoke	existing	contractual	arrangements	or may	impose	additional	taxes	or	royalty	burdens;	and

•fluctuating	currency	values,	hard	currency	shortages	and	currency

controls.

For	the	past	several	years,	there	have	been	varying	degrees	of	political	instability	and	public	protests,	including	demonstrations	which	have	been	marked	by violence	and	numerous	incidences	of	terrorist	acts,	within	some	countries	in	the	Middle	East	and	Africa.	Some	political	regimes	in	these	countries	are	threatened	or	have changed	as	a	result	of	such	unrest.

If	such	unrest	continues	to	spread,	conflicts	could	result	in	civil	wars,	regional	conflicts,	and	regime	changes	resulting	in	governments	that	are	hostile	to	the	U.S. These	may	have	the	following	results,	among	others:

•volatility	in	global	crude	oil	prices	which	could	negatively	impact	the	global	economy,	resulting	in	slower	economic	growth	rates	and	reduced	demand	for	our products;

•negative	impact	on	the	world	crude	oil	supply	if	transportation	avenues	are disrupted;

•security	concerns	leading	to	the	prolonged	evacuation	of	our personnel;

•damage	to,	or	the	inability	to	access,	production	facilities	or	other	operating	assets;

•inability	of	our	service	and	equipment	providers	to	deliver	items	necessary	for	us	to	conduct	our

operations.

Continued	hostilities	in	the	Middle	East	and	Africa	and	the	occurrence	or	threat	of	future	terrorist	attacks,	or	other	armed	conflict,	could	adversely	affect	the economies	of	the	U.S.	and	other	developed	countries.	A	lower	level	of	economic	activity	could	result	in	a	decline	in	energy	consumption,	which	could	cause	our revenues	and	margins	to	decline	and	limit	our	future	growth	prospects.	These	risks	could	lead	to	increased	volatility	in	prices	for	crude	oil	and	condensate,	NGLs	and natural	gas.	In	addition,	these	risks	could	increase	instability	in	the	financial	and	insurance	markets	and	make	it	more	difficult	for	us	to	access	capital	and	to	obtain	the insurance	coverage	that	we	consider	adequate.

Actions	of	governments	through	tax	legislation	or	interpretations	of	tax	law,	and	other	changes	in	law,	executive	order	and	commercial	restrictions	could	reduce	our operating	profitability,	both	in	the	U.S.	and	abroad.	The	U.S.	government	can	prevent	or	restrict	us	from	doing	business	in	foreign	countries.	These	restrictions	and	those of	foreign	governments	have	in	the	past	limited	our	ability	to	operate	in,	or	gain	access	to,	opportunities	in	various	countries	and	will	continue	to	do	so	in	the	future. Changes	in	law	could	also	adversely	affect	our	results,	including	new	regulations	resulting	in	higher	costs	to	transport	our	production	by	pipeline,	rail	car,	truck	or	vessel or	the	adoption	of	government	payment	transparency	regulations	that	could	require	us	to	disclose	competitively	sensitive	commercial	information	or	that	could	cause	us to	violate	the	non-disclosure	laws	of	other	countries.

# Our	level	of	indebtedness	may	limit	our	liquidity	and	financial	flexibility.

As	of	December	31,	2017,	our	total	debt	was	$5.5	billion,	with	no	debt	due	within	the	next	24	months.	Our	indebtedness	could	have	important	consequences	to	our business,	including,	but	not	limited	to,	the	following:

•we	may	be	more	vulnerable	to	general	adverse	economic	and	industry conditions;

•a	portion	of	our	cash	flows	from	operating	activities	must	be	used	to	service	our	indebtedness	and	is	not	available	for	other purposes;

•our	flexibility	in	planning	for,	or	reacting	to,	changes	in	our	industry	may	be

limited;

•a	financial	covenant	in	our	Credit	Agreement	stipulates	that	our	total	debt	to	capitalization	ratio	will	not	exceed	65%	as	of	the	last	day	of	any	fiscal	quarter,	and if	exceeded,	may	make	additional	borrowings	more	expensive	and	affect	our	ability	to	plan	for	and	react	to	changes	in	the	economy	and	our	industry;

•we	may	be	at	a	competitive	disadvantage	as	compared	to	similar	companies	that	have	less	debt;

•additional	financing	in	the	future	for	working	capital,	capital	expenditures,	acquisitions	or	development	activities,	general	corporate	or	other	purposes	may	have higher	costs	and	more	restrictive	covenants.

We	may	incur	additional	debt	in	order	to	fund	our	capital	expenditures,	acquisitions	or	development	activities,	or	for	general	corporate	or	other	purposes.	A	higher level	of	indebtedness	increases	the	risk	that	our	financial	flexibility	may	deteriorate.	Our	ability	to	meet	our	debt	obligations	and	service	our	debt	depends	on	future performance.	General	economic	conditions,	crude	oil	and	condensate,	NGLs	and	natural	gas	prices,	and	financial,	business	and	other	factors	will	affect	our	operations and	our	future	performance.	Many	of	these	factors	are	beyond	our	control	and	we	may	not	be	able	to	generate	sufficient	cash	flow	to	pay	the	interest	on	our	debt,	and future	working	capital,	borrowings	and	equity	financing	may	not	be	available	to	pay	or	refinance	such	debt.	See	Item	8.	Financial	Statements	and	Supplementary	Data	– Note	15	to	the	consolidated	financial	statements	for	a	discussion	of	debt	obligations.

# A	downgrade	in	our	credit	rating	could	negatively	impact	our	cost	of	and	ability	to	access	capital,	which	could	adversely	affect	our	business.

We	receive	debt	ratings	from	the	major	credit	rating	agencies	in	the	United	States.	Due	to	the	decline	in	crude	oil	and	U.S.	natural	gas	prices	in	recent	years,	credit rating	agencies	reviewed	companies	in	the	energy	industry,	including	us.	At	December	31,	2017,	our	corporate	credit	ratings	were:	Standard	&	Poor's	Global	Ratings Services	BBB-	(stable);	Fitch	Ratings	BBB	(stable);	and	Moody's	Investor	Services,	Inc.	Ba1	(stable).	The	credit	rating	process	is	contingent	upon	a	number	of	factors, many	of	which	are	beyond	our	control.	A	downgrade	of	our	credit	ratings	could	negatively	impact	our	cost	of	capital	and	our	ability	to	access	the	capital	markets, increase	the	interest	rate	and	fees	we	pay	on	our	revolving	credit	facility,	and	may	limit	or	reduce	credit	lines	with	our	bank	counterparties.	We	could	also	be	required	to post	letters	of	credit	or	other	forms	of	collateral	for	certain	contractual	obligations,	which	could	increase	our	costs	and	decrease	our	liquidity	or	letter	of	credit	capacity under	our	unsecured	revolving	credit	facility.	Limitations	on	our	ability	to	access	capital	could	adversely	impact	the	level	of	our	capital	spending	program,	our	ability	to manage	our	debt	maturities,	or	our	flexibility	to	react	to	changing	economic	and	business	conditions.

# Our	commodity	price	risk	management	activities	may	prevent	us	from	fully	benefiting	from	commodity	price	increases	and	may	expose	us	to	other	risks, including	counterparty	risk.

Global	commodity	prices	are	volatile.	In	order	to	mitigate	commodity	price	volatility	and	increase	the	predictability	of	cash	flows	related	to	the	marketing	of	our crude	oil	and	natural	gas,	we,	from	time	to	time,	enter	into	crude	oil	and	natural	gas	hedging	arrangements	with	respect	to	a	portion	of	our	expected	production.	While hedging	arrangements	are	intended	to	mitigate	commodity	price	volatility,	we	may	be	prevented	from	fully	realizing	the	benefits	of	price	increases	above	the	price	levels of	the	derivative	instruments	used	to	manage	price	risk.	In	addition,	our	hedging	arrangements	may	expose	us	to	the	risk	of	financial	loss	in	certain	circumstances, including	instances	in	which	the	counterparties	to	our	hedging	contracts	fail	to	perform	under	the	contracts.	See	Item	7A.	Quantitative	and	Qualitative	Disclosures	about Market	Risk.

# Our	business	could	be	negatively	impacted	by	cyberattacks	targeting	our	computer	and	telecommunications	systems	and	infrastructure,	or	targeting	those	of our	third-party	service	providers.

Our	business,	like	other	companies	in	the	oil	and	gas	industry,	has	become	increasingly	dependent	on	digital	technologies,	including	technologies	that	are	managed by	third-party	service	providers	on	whom	we	rely	to	help	us	collect,	host	or	process	information.	Such	technologies	are	integrated	into	our	business	operations	and	used as	a	part	of	our	production	and	distribution	systems	in	the	U.S.	and	abroad,	including	those	systems	used	to	transport	production	to	market,	to	enable	communications, and	to	provide	a	host	of	other	support	services	for	our	business.	Use	of	the	internet	and	other	public	networks	for	communications,	services,	and	storage,	including "cloud"	computing,	exposes	all	users	(including	our	business)	to	cybersecurity	risks.

While	we	and	our	third-party	service	providers	commit	resources	to	the	design,	implementation,	and	monitoring	of	our	information	systems,	there	is	no	guarantee that	our	security	measures	will	provide	absolute	security.	Despite	these	security	measures,	we	may	not	be	able	to	anticipate,	detect,	or	prevent	cyberattacks,	particularly because	the	methodologies	used	by	attackers	change	frequently	or	may	not	be	recognized	until	launched,	and	because	attackers	are	increasingly	using	techniques designed	to	circumvent	controls	and	avoid	detection.	We	and	our	third-party	service	providers	may	therefore	be	vulnerable	to	security	events	that	are	beyond	our	control, and	we	may	be	the	target	of	cyber-attacks,	as	well	as	physical	attacks,	which	could	result	in	information	security	breaches	and	significant	disruption	to	our	business.	Our information	systems	and	related	infrastructure	have	experienced	attempted	and	actual	minor	breaches	of	our	cybersecurity	in	the	past,	but	we	have	not	suffered	any losses	or	breaches	which	had	a	material	effect	on	our	business,	operations	or	reputation	relating	to	such	attacks;	however,	there	is	no	assurance	that	we	will	not	suffer such	losses	or	breaches	in	the	future.

As	cyberattacks	continue	to	evolve,	we	may	be	required	to	expend	significant	additional	resources	to	respond	to	cyberattacks,	to	continue	to	modify	or	enhance	our protective	measures,	or	to	investigate	and	remediate	any	information	systems	and	related	infrastructure	security	vulnerabilities.	We	may	also	be	subject	to	regulatory investigations	or	litigation	relating	from	cybersecurity	issues.

# 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	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.	Both	the	cost	and	availability	of	pipelines, rail	cars,	trucks,	or	vessels	to	transport	our	crude	oil	could	be	adversely	impacted	by	new	and	expected	state	or	federal	regulations	relating	to	transportation	of	crude	oil.

If	we	acquire	crude	oil	and	natural	gas	properties,	our	failure	to	fully	identify	existing	and	potential	problems,	to	accurately	estimate	reserves,	production	rates or	costs,	or	to	effectively	integrate	the	acquired	properties	into	our	operations	could	materially	and	adversely	affect	our	business,	financial	condition	and results	of	operations.

We	typically	seek	the	acquisition	of	crude	oil	and	natural	gas	properties	and	leases.		Although	we	perform	reviews	of	properties	to	be	acquired	in	a	manner	that	we believe	is	diligent	and	consistent	with	industry	practices,	reviews	of	records	and	properties	may	not	necessarily	reveal	existing	or	potential	problems,	nor	may	they permit	us	to	become	sufficiently	familiar	with	the	properties	in	order	to	fully	assess	possible	deficiencies	and	potential	problems.		Even	when	problems	with	a	property are	identified,	we	often	assume	environmental	and	other	risks	and	liabilities	in	connection	with	acquired	properties	pursuant	to	the	acquisition	agreements.		Moreover, there	are	numerous	uncertainties	inherent	in	estimating	quantities	of	crude	oil	and	natural	gas	(as	previously	discussed),	actual	future	production	rates	and	associated costs	with	respect	to	acquired	properties.		Actual	reserves,	production	rates	and	costs	may	vary	substantially	from	those	assumed	in	our	estimates.		In	addition,	an acquisition	may	have	a	material	and	adverse	effect	on	our	business	and	results	of	operations,	particularly	during	the	periods	in	which	the	operations	of	the	acquired properties	are	being	integrated	into	our	ongoing	operations	or	if	we	are	unable	to	effectively	integrate	the	acquired	properties	into	our	ongoing	operations.

# We	operate	in	a	highly	competitive	industry,	and	many	of	our	competitors	are	larger	and	have	available	resources	in	excess	of	our	own.

The	oil	and	gas	industry	is	highly	competitive,	and	many	competitors,	including	major	integrated	and	independent	oil	and	gas	companies,	as	well	as	national	oil companies,	are	larger	and	have	substantially	greater	resources	at	their	disposal	than	we	do.	We	compete	with	these	companies	for	the	acquisition	of	oil	and	natural	gas leases	and	other	properties.	We	also	compete	with	these	companies	for	equipment	and	personnel,	including	petroleum	engineers,	geologists,	geophysicists	and	other specialists,	required	to	develop	and	operate	those	properties	and	in	the	marketing	of	crude	oil	and	condensate,	NGLs	and	natural	gas	to	end-users.	Such	competition	can significantly	increase	costs	and	affect	the	availability	of	resources,	which	could	provide	our	larger	competitors	a	competitive	advantage	when	acquiring	equipment, leases	and	other	properties.	They	may	also	be	able	to	use	their	greater	resources	to	attract	and	retain	experienced	personnel.

# Many	of	our	major	projects	and	operations	are	conducted	with	partners,	which	may	decrease	our	ability	to	manage	risk.

We	often	enter	into	arrangements	to	conduct	certain	business	operations,	such	as	oil	and	gas	exploration	and	production	with	partners	in	order	to	share	risks associated	with	those	operations.	However,	these	arrangements	also	may	decrease	our	ability	to	manage	risks	and	costs,	particularly	where	we	are	not	the	operator.	We could	have	limited	influence	over	and	control	of	the	behaviors	and	performance	of	these	operations.	In	addition,	misconduct,	fraud,	noncompliance	with	applicable	laws and	regulations	or	improper	activities	by	or	on	behalf	of	one	or	more	of	our	partners	could	have	a	significant	negative	impact	on	our	business	and	reputation.

# Our	operations	are	subject	to	business	interruptions	and	casualty	losses.	We	do	not	insure	against	all	potential	losses	and	therefore	we	could	be	seriously harmed	by	unexpected	liabilities	and	increased	costs.

Our	United	States	E&P	and	International	E&P	operations	are	subject	to	unplanned	occurrences,	including	blowouts,	explosions,	fires,	loss	of	well	control,	spills, tornadoes,	hurricanes	and	other	adverse	weather,	tsunamis,	earthquakes,	volcanic	eruptions	or	nuclear	or	other	disasters,	labor	disputes	and	accidents.	These	same	risks can	be	applied	to	the	third-parties	which	transport	our	products	from	our	facilities.	A	prolonged	disruption	in	the	ability	of	any	pipelines,	rail	cars,	trucks,	or	vessels	to transport	our	production	could	contribute	to	a	business	interruption	or	increase	costs.

Our	operations	are	also	subject	to	the	additional	hazards	of	pollution,	releases	of	toxic	gas	and	other	environmental	hazards	and	risks.	These	hazards	could	result	in serious	personal	injury	or	loss	of	human	life,	significant	damage	to	property	and	equipment,	environmental	pollution,	impairment	of	operations	and	substantial	losses	to us.	Various	hazards	have	adversely	affected	us	in	the	past,	and	damages	resulting	from	a	catastrophic	occurrence	in	the	future	involving	us	or	any	of	our	assets	or operations	may	result	in	our	being	named	as	a	defendant	in	one	or	more	lawsuits	asserting	potentially	large	claims	or	in	our	being	assessed	potentially	substantial	fines by	governmental	authorities.	We	maintain	insurance	against	many,	but	not	all,	potential	losses	or	liabilities	arising	from	operating	hazards	in	amounts	that	we	believe	to be	prudent.	Uninsured	losses	and	liabilities	arising	from	operating	hazards	could	reduce	the	funds	available	to	us	for	capital,	exploration	and	investment	spending	and could	have	a	material	adverse	effect	on	our	business,	financial	condition,	results	of	operations	and	cash	flows.	Historically,	we	have	maintained	insurance	coverage	for physical	damage	including	at	times	resulting	business	interruption	to	our	major	onshore	and	offshore	facilities,	with	significant	self-insured	retentions.	In	the	future,	we may	not	be	able	to	maintain	or	obtain	insurance	of	the	type	and	amount	we	desire	at	reasonable	rates.	As	a	result	of	market	conditions,	premiums	and	deductibles	for	our insurance	policies	will	change	over	time	and	could	escalate.	In	some	instances,	certain	insurance	could	become	unavailable	or	available	only	for	reduced	amounts	of coverage.	For	example,	due	to	historical	hurricane	activity,	the	availability	of	insurance	coverage	for	windstorms	has	changed	and,	in	some	instances,	it	is	uneconomical. As	a	result,	our	exposure	to	losses	from	future	windstorm	activity	has	increased.

# Litigation	by	private	plaintiffs	or	government	officials	or	entities	could	adversely	affect	our	performance.

We	currently	are	defending	litigation	and	anticipate	that	we	will	be	required	to	defend	new	litigation	in	the	future.	The	subject	matter	of	such	litigation	may	include releases	of	hazardous	substances	from	our	facilities,	privacy	laws,	contract	disputes,	royalty	disputes	or	any	other	laws	or	regulations	that	apply	to	our	operations.	In some	cases	the	plaintiff	or	plaintiffs	seek	alleged	damages	involving	large	classes	of	potential	litigants,	and	may	allege	damages	relating	to	extended	periods	of	time	or other	alleged	facts	and	circumstances.	If	we	are	not	able	to	successfully	defend	such	claims,	they	may	result	in	substantial	liability.	We	do	not	have	insurance	covering all	of	these	potential	liabilities.	In	addition	to	substantial	liability,	litigation	may	also	seek	injunctive	relief	which	could	have	an	adverse	effect	on	our	future	operations.

For	instance,	government	entities	have	filed	lawsuits	in	California	and	New	York	seeking	to	hold	a	wide	variety	of	companies	that	produce	fossil	fuels	liable	for	the alleged	impacts	of	the	greenhouse	gas	emissions	attributable	to	those	fuels.	The	lawsuits	allege	damages	as	a	result	of	global	warming	and	the	plaintiffs	are	seeking unspecified	damages	and	abatement	under	various	tort	theories.	Marathon	Oil	has	been	named	as	a	defendant	in	six	of	these	lawsuits	in	California,	along	with	numerous other	companies.	Similar	lawsuits	may	be	filed	in	other	jurisdictions.	The	ultimate	outcome	and	impact	to	us	cannot

be	predicted	with	certainty,	and	we	could	incur	substantial	legal	costs	associated	with	defending	these	and	similar	lawsuits	in	the	future.

# In	connection	with	our	separation	from	MPC,	MPC	agreed	to	indemnify	us	for	certain	liabilities.	However,	there	can	be	no	assurance	that	the	indemnity	will be	sufficient	to	protect	us	against	the	full	amount	of	such	liabilities,	or	that	MPC's	ability	to	satisfy	its	indemnification	obligations	will	not	be	impaired	in	the future.

Pursuant	to	the	Separation	and	Distribution	Agreement	and	the	Tax	Sharing	Agreement	we	entered	into	with	MPC	in	connection	with	the	spin-off,	MPC	agreed	to indemnify	us	for	certain	liabilities.	However,	third	parties	could	seek	to	hold	us	responsible	for	any	of	the	liabilities	that	MPC	agreed	to	retain	or	assume,	and	there	can be	no	assurance	that	the	indemnification	from	MPC	will	be	sufficient	to	protect	us	against	the	full	amount	of	such	liabilities,	or	that	MPC	will	be	able	to	fully	satisfy	its indemnification	obligations.	In	addition,	even	if	we	ultimately	succeed	in	recovering	from	MPC	any	amounts	for	which	we	are	held	liable,	we	may	be	temporarily required	to	bear	these	losses	ourselves.

# The	spin-off	could	result	in	substantial	tax	liability.

We	obtained	a	private	letter	ruling	from	the	IRS	substantially	to	the	effect	that	the	distribution	of	shares	of	MPC	common	stock	in	the	spin-off	qualified	as	tax	free to	MPC,	us	and	our	stockholders	for	U.S.	federal	income	tax	purposes	under	Sections	355	and	368	and	related	provisions	of	the	U.S.	Internal	Revenue	Code	of	1986,	as amended	(the	"Code").	If	the	factual	assumptions	or	representations	made	in	the	request	for	the	private	letter	ruling	prove	to	have	been	inaccurate	or	incomplete	in	any material	respect,	then	we	will	not	be	able	to	rely	on	the	ruling.	Furthermore,	the	IRS	does	not	rule	on	whether	a	distribution	such	as	the	spin-off	satisfies	certain requirements	necessary	to	obtain	tax-free	treatment	under	Section	355	of	the	Code.	Rather,	the	private	letter	ruling	was	based	on	representations	by	us	that	those requirements	were	satisfied,	and	any	inaccuracy	in	those	representations	could	invalidate	the	ruling.	In	connection	with	the	spin-off,	we	also	obtained	an	opinion	of outside	counsel,	substantially	to	the	effect	that,	the	distribution	of	shares	of	MPC	common	stock	in	the	spin-off	qualified	as	tax	free	to	MPC,	us	and	our	stockholders	for U.S.	federal	income	tax	purposes	under	Sections	355	and	368	and	related	provisions	of	the	Code.	The	opinion	relied	on,	among	other	things,	the	continuing	validity	of the	private	letter	ruling	and	various	assumptions	and	representations	as	to	factual	matters	made	by	MPC	and	us	which,	if	inaccurate	or	incomplete	in	any	material respect,	would	jeopardize	the	conclusions	reached	by	such	counsel	in	its	opinion.	The	opinion	is	not	binding	on	the	IRS	or	the	courts,	and	there	can	be	no	assurance	that the	IRS	or	the	courts	would	not	challenge	the	conclusions	stated	in	the	opinion	or	that	any	such	challenge	would	not	prevail.

If,	notwithstanding	receipt	of	the	private	letter	ruling	and	opinion	of	counsel,	the	spin-off	were	determined	not	to	qualify	under	Section	355	of	the	Code,	each	U.S. holder	of	our	common	stock	who	received	shares	of	MPC	common	stock	in	the	spin-off	would	generally	be	treated	as	receiving	a	taxable	distribution	of	property	in	an amount	equal	to	the	fair	market	value	of	the	shares	of	MPC	common	stock	received.	That	distribution	would	be	taxable	to	each	such	stockholder	as	a	dividend	to	the extent	of	our	accumulated	earnings	and	profits	as	of	the	effective	date	of	the	spin-off.	For	each	such	stockholder,	any	amount	that	exceeded	those	earnings	and	profits would	be	treated	first	as	a	non-taxable	return	of	capital	to	the	extent	of	such	stockholder's	tax	basis	in	its	shares	of	our	common	stock	with	any	remaining	amount	being taxed	as	a	capital	gain.	We	would	be	subject	to	tax	as	if	we	had	sold	all	the	outstanding	shares	of	MPC	common	stock	in	a	taxable	sale	for	their	fair	market	value	and would	recognize	taxable	gain	in	an	amount	equal	to	the	excess	of	the	fair	market	value	of	such	shares	over	our	tax	basis	in	such	shares.

Under	the	terms	of	the	Tax	Sharing	Agreement	we	entered	into	with	MPC	in	connection	with	the	spin-off,	MPC	is	generally	responsible	for	any	taxes	imposed	on MPC	or	us	and	our	subsidiaries	in	the	event	that	the	spin-off	and/or	certain	related	transactions	were	to	fail	to	qualify	for	tax-free	treatment	as	a	result	of	actions	taken,	or breaches	of	representations	and	warranties	made	in	the	Tax	Sharing	Agreement,	by	MPC	or	any	of	its	affiliates.	However,	if	the	spin-off	and/or	certain	related transactions	were	to	fail	to	qualify	for	tax-free	treatment	because	of	actions	or	failures	to	act	by	us	or	any	of	our	affiliates,	we	would	be	responsible	for	all	such	taxes.

# We	may	issue	preferred	stock	whose	terms	could	dilute	the	voting	power	or	reduce	the	value	of	Marathon	Oil	common	stock.

Our	restated	certificate	of	incorporation	authorizes	us	to	issue,	without	the	approval	of	our	stockholders,	one	or	more	classes	or	series	of	preferred	stock	having	such preferences,	powers	and	relative,	participating,	optional	and	other	rights,	including	preferences	over	Marathon	Oil	common	stock	respecting	dividends	and	distributions, as	our	Board	of	Directors	generally	may	determine.	The	terms	of	one	or	more	classes	or	series	of	preferred	stock	could	dilute	the	voting	power	or	reduce	the	value	of Marathon	Oil	common	stock.	For	example,	we	could	grant	holders	of	preferred	stock	the	right	to	elect	some	number	of	our	directors	in	all	events	or	on	the	happening	of specified	events	or	the	right	to	veto	specified	transactions.	Similarly,	the	repurchase	or	redemption	rights	or	liquidation	preferences	we	could	assign	to	holders	of preferred	stock	could	affect	the	residual	value	of	the	common	stock.

# Item	1B.	Unresolved	Staff	Comments

None.

# Item	2.	Properties

The	location	and	general	character	of	our	principal	crude	oil	and	condensate,	NGLs	and	natural	gas	properties	and	facilities,	and	other	important	physical	properties have	been	described	by	segment	under	Item	1.	Business.

Estimated	net	proved	crude	oil	and	condensate,	NGLs	and	natural	gas	reserves	are	set	forth	in	Item	8.	Financial	Statements	and	Supplementary	Data	– Supplementary	Information	on	Oil	and	Gas	Producing	Activities	–	Estimated	Quantities	of	Proved	Oil	and	Gas	Reserves.	The	basis	for	estimating	these	reserves	is discussed	in	Item	1.	Business	–	Reserves.

# Item	3.	Legal	Proceedings

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.

See	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	24	to	the	consolidated	financial	statements	for	a	description	of	such	legal	and	administrative proceedings.

# Environmental	Proceedings

The	following	is	a	summary	of	certain	proceedings	involving	us	that	were	pending	or	contemplated	as	of	December	31,	2017,	under	federal	and	state	environmental laws.

As	of	December	31,	2017,	we	have	sites	across	the	country	where	remediation	is	being	sought	under	environmental	statutes,	both	federal	and	state,	or	where	private parties	are	seeking	remediation	through	discussions	or	litigation.		Based	on	currently	available	information	the	accrued	amount	to	address	the	clean-up	and	remediation costs	connected	with	these	sites	is	not	material.

If	our	assumptions	relating	to	these	costs	prove	to	be	inaccurate,	future	expenditures	may	exceed	our	accrued	amounts.

# Item	4.	Mine	Safety	Disclosures

Not	applicable.

# PART	II

# Item	5.			Market	for	Registrant's	Common	Equity,	Related	Stockholder	Matters	and	Issuer	Purchases	of	Equity	Securities

The	principal	market	on	which	Marathon	Oil	common	stock	is	traded	is	the	New	York	Stock	Exchange	("NYSE").	As	of	January	31,	2018,	there	were	31,472 registered	holders	of	Marathon	Oil	common	stock.

The	following	table	reflects	high	and	low	sales	prices	for	Marathon	Oil	common	stock	and	the	related	dividend	per	share	by	quarter	for	the	past	two	years:

|  |  | 2017 |  |  | 2016 |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (Dollars\tper\tshare) | High\tPrice | Low\tPrice | Dividends | High\tPrice | Low\tPrice | Dividends |
| First\tQuarter | $18.18 | $14.61 | $0.05 | $12.82 | $6.73 | $0.05 |
| Second\tQuarter | $16.60 | $11.35 | $0.05 | $15.27 | $10.53 | $0.05 |
| Third\tQuarter | $13.73 | $10.77 | $0.05 | $16.80 | $12.90 | $0.05 |
| Fourth\tQuarter | $17.26 | $13.48 | $0.05 | $18.80 | $12.78 | $0.05 |
| Full\tYear | $18.18 | $10.77 | $0.20 | $18.80 | $6.73 | $0.20 |

Dividends	–	Our	Board	of	Directors	intends	to	declare	and	pay	dividends	on	Marathon	Oil	common	stock	based	on	our	financial	condition	and	results	of	operations, although	it	has	no	obligation	under	Delaware	law	or	the	Restated	Certificate	of	Incorporation	to	do	so.	In	determining	our	dividend	policy,	the	Board	will	rely	on	our consolidated	financial	statements.	Dividends	on	Marathon	Oil	common	stock	are	limited	to	our	legally	available	funds.

The	following	table	provides	information	about	purchases	by	Marathon	Oil	and	its	affiliated	purchaser,	during	the	quarter	ended	December	31,	2017,	of	equity securities	that	are	registered	by	Marathon	Oil	pursuant	to	Section	12	of	the	Securities	Exchange	Act	of	1934:

| Period | Total	Number	of<br>Shares<br>Purchased(a) | Average<br>Price	Paid<br>per	Share | Total	Number	of<br>Shares	Purchased<br>as	Part	of	Publicly<br>Announced	Plans<br>or	Programs(b) | Approximate<br>Dollar	Value	of<br>Shares	that	May<br>Yet	Be	Purchased<br>Under	the	Plans<br>or	Programs(b) |
| :--- | :--- | :--- | :--- | :--- |
| 10/01/17\t–\t10/31/17 | 49,046 | $13.38 | — | $1,500,285,529 |
| 11/01/17\t–\t11/30/17 | 2,813 | $14.62 | — | $1,500,285,529 |
| 12/01/17\t–\t12/31/17 | — | — | — | $1,500,285,529 |
| Total | 51,859 | $13.45 | — |  |

(a) 51,859	shares	of	restricted	stock	were	delivered	by	employees	to	Marathon	Oil,	upon	vesting,	to	satisfy	tax	withholding	requirements.

(b) In	January	2006,	we	announced	a	$2.0	billion	share	repurchase	program.	Our	Board	of	directors	subsequently	increased	the	authorization	for	repurchases	under	the	program	by	$500	million	in January	2007,	by	$500	million	in	May	2007,	by	$2.0	billion	in	July	2007,	and	by	$1.2	billion	in	December	2013,	for	a	total	authorized	amount	of	$6.2	billion.	The	remaining	share	repurchase authorization	as	of	December	31,	2017	is	$1.5	billion.	No	repurchases	were	made	under	the	program	in	2017.

# Item	6.			Selected	Financial	Data

|  |  | Year	Ended	December	31, | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions,\texcept\tper\tshare\tdata) | 2017 | 2016 | 2015 | 2014 | 2013 |
| Statement\tof\tIncome\tData(a)(b)(c) |  |  |  |  |  |
| Revenues | $4,373 | $3,170 | $4,635 | $9,238 | $9,731 |
| Income\t(loss)\tfrom\tcontinuing\toperations | (830) | (2,087) | (1,701) | 710 | 710 |
| Discontinued\toperations | (4,893) | (53) | (503) | 2,336 | 1,043 |
| Net\tincome\t(loss) | (5,723) | (2,140) | (2,204) | 3,046 | 1,753 |
| Per\tShare\tData(a)(b)(c) |  |  |  |  |  |
| Basic: |  |  |  |  |  |
| Income\t(loss)\tfrom\tcontinuing\toperations | $(0.97) | $(2.55) | $(2.51) | $1.04 | $1.01 |
| Discontinued\toperations | $(5.76) | $(0.06) | $(0.75) | $3.44 | $1.48 |
| Net\tincome\t(loss) | $(6.73) | $(2.61) | $(3.26) | $4.48 | $2.49 |
| Diluted: |  |  |  |  |  |
| Income\t(loss)\tfrom\tcontinuing\toperations | $(0.97) | $(2.55) | $(2.51) | $1.04 | $1.00 |
| Discontinued\toperations | $(5.76) | $(0.06) | $(0.75) | $3.42 | $1.47 |
| Net\tincome\t(loss) | $(6.73) | $(2.61) | $(3.26) | $4.46 | $2.47 |
| Statement\tof\tCash\tFlows\tData(b) |  |  |  |  |  |
| Additions\tto\tproperty,\tplant\tand\tequipment\trelated\tto\tcontinuing\toperations | $(1,974) | $(1,204) | $(3,485) | $(4,937) | $(4,170) |
| Dividends\tpaid | 170 | 162 | 460 | 543 | 508 |
| Dividends\tper\tshare | $0.20 | $0.20 | $0.68 | $0.80 | $0.72 |
| Balance\tSheet\tData\tat\tDecember\t31 |  |  |  |  |  |
| Total\tassets | $22,012 | $31,094 | $32,311 | $35,983 | $35,588 |
| Total\tlong-term\tdebt,\tincluding\tcapitalized\tleases | 5,494 | 6,581 | 7,268 | 5,285 | 6,352 |
| (a)\nIncludes\timpairments\tto\tproducing\tproperties\tof\t$229\tmillion,\t$67\tmillion,\t$381\tmillion,\t$132\tmillion\tand\t$96\tmillion\tin\t2017,\t2016,\t2015,\t2014\tand\t2013\tand\timpairments\tto\tunproved |  |  |  |  |  |
| properties\tof\t$246\tmillion,\t$195\tmillion,\t$655\tmillion,\t$306\tmillion\tand\t$572\tmillion\tin\t2017,\t2016,\t2015,\t2014\tand\t2013\t(see\tItem\t8.\tFinancial\tStatements\tand\tSupplementary\tData\t–\tNote | properties\tof\t$246\tmillion,\t$195\tmillion,\t$655\tmillion,\t$306\tmillion\tand\t$572\tmillion\tin\t2017,\t2016,\t2015,\t2014\tand\t2013\t(see\tItem\t8.\tFinancial\tStatements\tand\tSupplementary\tData\t–\tNote | properties\tof\t$246\tmillion,\t$195\tmillion,\t$655\tmillion,\t$306\tmillion\tand\t$572\tmillion\tin\t2017,\t2016,\t2015,\t2014\tand\t2013\t(see\tItem\t8.\tFinancial\tStatements\tand\tSupplementary\tData\t–\tNote | properties\tof\t$246\tmillion,\t$195\tmillion,\t$655\tmillion,\t$306\tmillion\tand\t$572\tmillion\tin\t2017,\t2016,\t2015,\t2014\tand\t2013\t(see\tItem\t8.\tFinancial\tStatements\tand\tSupplementary\tData\t–\tNote | properties\tof\t$246\tmillion,\t$195\tmillion,\t$655\tmillion,\t$306\tmillion\tand\t$572\tmillion\tin\t2017,\t2016,\t2015,\t2014\tand\t2013\t(see\tItem\t8.\tFinancial\tStatements\tand\tSupplementary\tData\t–\tNote | 10 |

(b) We	closed	on	the	sale	of	our	Canada	business	in	2017	which	resulted	in	an	after-tax	non-cash	impairment	charge	of	 $4.96	billion	and	our	Angola	assets	and	Norway	business	in	2014	(see	Item	8. Financial	Statements	and	Supplementary	Data	–	Note	5	to	the	consolidated	financial	statements).	The	applicable	periods	have	been	recast	to	reflect	as	discontinued	operations.

(c) December	31,	2016	includes	the	increase	of	a	valuation	allowance	on	certain	of	our	deferred	tax	assets	for	$1,346	million	(see	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	9	to the	consolidated	financial	statements).

# Item	7.	Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations

The	following	discussion	and	analysis	of	our	financial	condition	and	results	of	operations	should	be	read	in	conjunction	with	the	information	under	Item	8.

Financial	Statements	and	Supplementary	Data	and	the	other	financial	information	found	elsewhere	in	this	Form	10-K.	The	following	discussion	includes	forward- looking	statements	that	involve	certain	risks	and	uncertainties.	See	"Disclosures	Regarding	Forward-Looking	Statements"	(immediately	prior	to	Part	I)	and	Item	1A. Risk	Factors.

Each	of	our	segments	is	organized	and	managed	based	upon	both	geographic	location	and	the	nature	of	the	products	and	services	it	offers.

# Executive	Summary

During	2017,	we	continued	to	strengthen	our	balance	sheet,	transform	our	portfolio	and	manage	our	capital	and	operating	costs.	Through	multiple	financing transactions	in	2017,	we	have	reduced	total	debt	by	approximately	$1.75	billion	which	will	result	in	a	reduction	to	our	future	annual	interest	expense	of	approximately $115	million.	Additionally,	we	closed	on	the	sale	of	our	Canadian	business	for	approximately	$2.5	billion	and	acquired	acreage	in	the	Permian	basin,	including	over 70,000	net	acres	in	Northern	Delaware	for	approximately	$1.9	billion.

As	discussed	in	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	5	to	the	consolidated	financial	statements,	we	closed	on	the	sale	of	our	Canadian	business, which	has	been	reflected	as	discontinued	operations	and	is	excluded	from	operations	in	all	periods	presented.

# Key	highlights	include	the	following:

# Liquidity	and	corporate	financing

•Ended	2017	with	liquidity	of	$4.0	billion,	comprised	of	$563	million	in	cash	and	cash	equivalents	and	an	undrawn	$3.4	billion	revolving	credit	facility,	which was	increased	from	$3.3	billion	in	July	2017.	Remaining	proceeds	of	$750	million	from	the	sale	of	our	Canadian	business	are	scheduled	to	be	received	in	the first	quarter	of	2018.

•In	third	quarter	2017,	we	issued	$1	billion	of	4.4%	senior	unsecured	notes	due	in	2027	and	redeemed	approximately	$1.75	billion	of	debt	due	in	2017,	2018	and 2019.	This	offering	and	redemption	reduced	our	future	annual	interest	expense	by	approximately	$64	million.

•In	December	2017,	we	redeemed	$1	billion	of	5.125%	municipal	revenue	bonds	due	in	2037	in	a	refunding	transaction	that	preserved	our	ability	to	remarket	up to	$1	billion	of	tax-exempt	municipal	bonds	prior	to	2037.	This	redemption	reduced	our	future	annual	interest	expense	by	approximately	$51	million.

# Simplifying	our	portfolio

•We	closed	on	the	sale	of	our	Canadian	business	for	approximately	$2.5	billion	with	over	$1.8	billion	in	proceeds	received	to	date	and	$750	million	to	be received	in	first	quarter	2018.

•We	closed	on	multiple	Permian	basin	acquisitions	for	approximately	$1.9	billion	of	cash	on

hand.

# Financial	and	Operational	results

•Total	2017	net	sales	volumes	from	continuing	operations	are	379	mboed,	including	Libya,	which	is	10%	higher	compared	to	2016.	This	includes	a	12% increase	in	sales	volumes	from	the	U.S	resource	plays	to	217	mboed	within	our	United	States	E&P	segment.

•Due	to	improved	cost	structure	and	higher	sales	volumes,	our	production	expense	rate	in	our	United	States	E&P	segment	decreased	7%	to	$5.57	per	boe	in	2017 compared	to	last	year.	In	our	International	E&P	segment,	our	production	expense	rate	decreased	14%	to	$4.33	per	boe	in	2017	primarily	due	to	an	increase	in sales	volumes	in	E.G.	and	Libya.

•Added	proved	reserves	of	193	mmboe	for	a	reserve	replacement	ratio	from	continuing	operations	of

•Net	cash	provided	by	operating	activities	in	2017	was	$2.0	billion,	compared	to	$901	million	in	2016	primarily	as	a	result	of	improved	price	realizations, increased	sales	volumes	and	lower	unit	production	expenses.

•Our	net	loss	per	share	from	continuing	operations	was	$0.97	in	2017	as	compared	to	a	net	loss	per	share	of	$2.55	last	year.	Included	in	the	2017	net	loss are:

◦An	increase	in	sales	and	other	operating	revenues	of	over	40%	to	$4.2	billion	primarily	due	to	improved	price	realizations	and	increased	sales volumes.

◦Our	sales	volumes	from	continuing	operations	increased	10%	while	production	expense	remained	flat	during	2017	as	a	result	of	improved	cost structure.

◦Depreciation,	depletion	and	amortization	expense	increased	10%	to	$2.4	billion	due	to	our	increase	in	sales	volumes	from	continuing operations.

◦Exploration	and	impairment	expenses	increased	by	$248	million	to	$638	million,	year	over	year,	primarily	due	to	non-cash	impairment	charges	on	proved and	unproved	properties	primarily	as	a	result	of	the	anticipated	sales	of	certain	non-core	international	assets	and	due	to	lower	forecasted	long-term commodity	prices.

◦Our	provision	for	income	taxes	was	$376	million	in	2017	primarily	as	a	result	of	our	full	valuation	allowance	on	our	net	federal	deferred	tax	assets throughout	2017	and	the	effects	of	our	foreign	operations.	See	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	7	to	the	consolidated financial	statements	for	a	discussion	of	the	effects	of	U.S.	Tax	Reform	Legislation.

# Outlook

# Capital	Development	Program

Our	$2.3	billion	2018	Capital	Development	Program	will	be	over	90%	allocated	to	our	U.S.	resource	plays.	Almost	60%	of	this	development	budget	will	be allocated	to	the	high-return	Eagle	Ford	and	Bakken	assets,	which	have	demonstrated	step-change	performance	improvements	while	operating	at	scale.	Approximately one-third	of	the	development	budget	will	be	allocated	to	our	Northern	Delaware	and	Oklahoma	assets,	where	the	majority	of	drilling	activity	will	be	transitioning	to multi-well	pads,	while	continuing	strategic	delineation	and	appraisal.

Our	2018	Capital	Development	Program	is	broken	down	by	reportable	operating	segment	in	the	table	below:

| (In	millions) | Capital	Development	Program |
| :--- | :--- |
| United\tStates\tE&amp;P |  |
| \t\t\tEagle\tFord | $710 |
| \t\t\tBakken | 590 |
| \t\t\tOklahoma | 410 |
| \t\t\tNorthern\tDelaware | 380 |
| Total\tUnited\tStates\tE&amp;P | $2,090 |
| International\tE&amp;P\tand\tcorporate\tother\t(a) | 210 |
| Total\tCapital\tDevelopment\tProgram | $2,300 |

(a)	International	E&P	and	corporate	other	includes	our	International	E&P	segment	and	other	corporate	items

Our	net	sales	volumes	from	continuing	operations,	including	Libya,	averaged	379	mboed,	345	mboed	and	385	mboed	for	2017,	2016	and	2015,	respectively.	This 10%	increase	in	2017	was	primarily	due	to	new	wells	to	sales	in	our	U.S.	resource	plays,	our	acquisitions	in	Northern	Delaware	and	the	resumption	of	sales	in	Libya.

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.

| Net	Sales	Volumes | 2017 | Increase<br>(Decrease) | 2016 | Increase<br>(Decrease) | 2015 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| United\tStates\tE&amp;P\t(mboed) | 234 | 5% | 223 | (17)% | 269 |
| International\tE&amp;P\t(a)\t(mboed) | 145 | 19% | 122 | 5\t% | 116 |
| Total\tContinuing\tOperations\t(mboed) | 379 | 10% | 345 | (10)% | 385 |

# United	States	E&P

The	following	tables	provide	additional	detail	regarding	net	sales	volumes,	sales	mix	and	operational	drilling	activity	for	our	significant	operations	within	this segment:

| Net	Sales	Volumes | 2017 | Increase<br>(Decrease) | 2016 | Increase<br>(Decrease) | 2015 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| \tEquivalent\tBarrels\t(mboed) |  |  |  |  |  |
| Oklahoma | 54 | 54% | 35 | 40% | 25 |
| Eagle\tFord | 101 | (4)% | 105 | (22)% | 134 |
| Bakken | 56 | 4% | 54 | (8)% | 59 |
| Northern\tDelaware | 6 | 100% | — | —% | — |
| Other\tUnited\tStates(a) | 17 | (41)% | 29 | (43)% | 51 |
| Total\tUnited\tStates\tE&amp;P\t(mboed) | 234 | 5% | 223 | (17)% | 269 |

(a)	Year	ended	December	31,	2017	includes	decreases	of	14	mboed,	consisting	of	the	disposition	of	Wyoming	and	certain	non-operated	CO2	and	waterflood	assets	in	West	Texas	and	New	Mexico	in 2016.	Year	ended	December	31,	2016	decreases	relating	to	assets	sold	were	23	mboed,	primarily	consisting	of	Wyoming,	West	Texas,	East	Texas,	North	Louisiana	and	certain	Gulf	of	Mexico assets.	See	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	5	to	the	consolidated	financial	statements	for	information	about	these	dispositions.

•Eagle	Ford	–	Our	net	sales	volumes	were	101	mboed	in	2017,	4%	lower	compared	to	2016.	We	brought	fewer	wells	to	sales	in	2017,	while	we	increased	well productivity	through	completion	optimization	and	efficiency	gains.

•Bakken	–	Our	net	sales	volumes	were	56	mboed	in	2017	compared	to	54	mboed	in	2016.	In	2017,	we	improved	well	performance	with	continued	application	of high	intensity	completions.	During	the	year,	we	set	a	new	record	in	the	Williston	Basin	for	the	highest	30-day	initial	production	oil	rate.

•Oklahoma	–	Our	net	sales	volumes	in	2017	increased	by	54%	to	54	mboed	compared	to	year	ended	2016.	Our	activity	during	2017	was	concentrated	in	the STACK	and	was	focused	on	leasehold	capture,	delineation	drilling	and	infill	spacing	pilots.

•Northern	Delaware	–	Our	net	sales	volumes	were	6	mboed	in	2017	which	reflected	a	partial	year	of	production	following	the	second	quarter	2017	closing	of	the BC	Operating	and	Black	Mountain	assets.	During	2017	we	focused	our	activity	on	delineation	and	leasehold	capture	across	our	position	in	Eddy	and	Lea Counties,	New	Mexico.

The	following	table	provides	net	sales	volumes	from	continuing	operations	within	this	segment:

| Net	Sales	Volumes | 2017 | Increase<br>(Decrease) | 2016 | Increase<br>(Decrease) | 2015 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Equivalent\tBarrels\t(mboed) |  |  |  |  |  |
| Equatorial\tGuinea | 109 | 7% | 102 | 5% | 97 |
| United\tKingdom(a) | 14 | (18)% | 17 | (11)% | 19 |
| Libya | 20 | 567% | 3 | 100% | — |
| Other\tInternational | 2 | 100% | — | —% | — |
| Total\tInternational\tE&amp;P\t(mboed) | 145 | 19% | 122 | 5% | 116 |
| Equity\tMethod\tInvestees |  |  |  |  |  |
| LNG\t(mtd) | 6,423 | 9% | 5,874 | —% | 5,884 |
| Methanol\t(mtd) | 1,374 | 1% | 1,358 | 45% | 937 |
| Condensate\t&amp;\tLPG\t(boed) | 14,501 | 8% | 13,430 | 10% | 12,208 |

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

•Equatorial	Guinea	–	Net	sales	volumes	in	2017	were	higher	than	2016	as	a	result	of	the	completion	and	start-up	of	our	Alba	field	compression	project	in	mid- 2016	and	lower	volumes	in	first	quarter	2016	due	to	a	planned	turnaround.	Additionally,	in	April	2017	we	received	host	government	approval	to	develop	Block D	offshore	E.G.	through	unitization	with	the	Alba	field.

•United	Kingdom	–	Net	sales	volumes	in	2017	decreased	compared	to	2016	primarily	as	a	result	of	planned	turn-around	activity	at	the	Brae	and	Foinaven complexes	and	the	temporary	shut-down	of	the	outside-operated	Forties	Pipeline	System	during	fourth	quarter	2017.

•Libya	–	While	civil	and	political	unrest	has	interrupted	operations	in	recent	years,	our	production	resumed	in	October	2016.	During	December	2016,	liftings resumed	from	the	Es	Sider	crude	oil	terminal.	During	2017,	sales	volumes	and	production	continued,	except	for	a	brief	interruption	in	March	2017	due	to	civil unrest.

# Market	Conditions

Crude	oil,	natural	gas	and	NGL	benchmarks	increased	in	2017	as	compared	to	the	same	period	in	2016.	As	a	result,	we	experienced	increased	price	realizations associated	with	those	benchmarks.	We	continue	to	expect	crude	oil,	natural	gas	and	NGLs	benchmark	prices	to	remain	volatile	based	on	global	supply	and	demand, which	will	result	in	increases	or	decreases	in	our	price	realizations.	See	Item	1A.	Risk	Factors	and	Item	7.	Management's	Discussion	and	Analysis	of	Financial	Condition –	Critical	Accounting	Estimates	for	further	discussion	of	how	declines	in	commodity	prices	could	impact	us.	Additional	detail	on	market	conditions,	including	our average	price	realizations	and	benchmarks	for	crude	oil,	NGLs	and	natural	gas	relative	to	our	operating	segments,	follows.

	The	following	table	presents	our	average	price	realizations	and	the	related	benchmarks	for	crude	oil,	NGLs	and	natural	gas	for	2017,	2016	and	2015:

|  | 2017 | Increase<br>(Decrease) | 2016 | Increase<br>(Decrease) | 2015 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Average\tPrice\tRealizations\t(a) |  |  |  |  |  |
| Crude\tOil\tand\tCondensate\t(per\tbbl)\t(b) | $49.35 | 28% | $38.57 | (11)% | 43.50 |
| Natural\tGas\tLiquids\t(per\tbbl) | 20.55 | 56% | 13.15 | (2)% | 13.37 |
| Total\tLiquid\tHydrocarbons\t(per\tbbl) | 42.31 | 29% | 32.71 | (14)% | 37.85 |
| Natural\tGas\t(per\tmcf)\t(c) | 2.84 | 19% | 2.38 | (11)% | 2.66 |
| Benchmarks |  |  |  |  |  |
| WTI\tcrude\toil\taverage\tof\tdaily\tprices\t(per\tbbl) | $50.85 | 17% | $43.47 | (11)% | 48.76 |
| LLS\tcrude\toil\taverage\tof\tdaily\tprices\t(per\tbbl) | 54.04 | 20% | 45.02 | (14)% | 52.33 |
| Mont\tBelvieu\tNGLs\t(per\tbbl)\t(d) | 23.76 | 37% | 17.40 | 3\t% | 16.94 |
| Henry\tHub\tnatural\tgas\tsettlement\tdate\taverage\t(per\tmmbtu) | 3.11 | 26% | 2.46 | (8)% | 2.66 |

(b) Inclusion	of	realized	gains	on	crude	oil	derivative	instruments	would	have	increased	average	liquid	hydrocarbon	price	realizations	per	barrel	by $0.75,	$0.92,	and	$1.24	for	2017,	2016,	and 2015.

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

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

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

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

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

The	following	table	presents	our	average	price	realizations	and	the	related	benchmark	for	crude	oil	for	2017,	2016	and	2015:

|  | 2017 | Increase<br>(Decrease) | 2016 | (Decrease) | 2015 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Average\tPrice\tRealizations |  |  |  |  |  |
| Crude\tOil\tand\tCondensate\t(per\tbbl) | $53.05 | 27% | $41.70 | (12)% | $47.50 |
| Natural\tGas\tLiquids\t(per\tbbl) | 3.15 | 49% | 2.11 | (25)% | 2.81 |
| Total\tLiquid\tHydrocarbons\t(per\tbbl) | 43.36 | 35% | 32.10 | (12)% | 36.67 |
| Natural\tGas\t(per\tmcf) | 0.55 | 6% | 0.52 | (24)% | 0.68 |
| Benchmark |  |  |  |  |  |
| Brent\t(Europe)\tcrude\toil\t(per\tbbl)(a) | $54.25 | 25% | $43.55 | (17)% | $52.35 |

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

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

# Consolidated	Results	of	Operations:	2017	compared	to	2016

# Sales	and	other	operating	revenues,	including	related	party	are	summarized	by	segment	in	the	following	table:

|  | Year	Ended	December	31, | Year	Ended	December	31, |
| :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 |
| Sales\tand\tother\toperating\trevenues,\tincluding\trelated\tparty |  |  |
| United\tStates\tE&amp;P | $3,138 | $2,375 |
| International\tE&amp;P | 1,154 | 665 |
| Segment\tsales\tand\tother\toperating\trevenues,\tincluding\trelated\tparty | 4,292 | 3,040 |
| Unrealized\tgain\t(loss)\ton\tcommodity\tderivative\tinstruments | (81) | (110) |
| Sales\tand\tother\toperating\trevenues,\tincluding\trelated\tparty | $4,211 | $2,930 |

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.

|  | Year	Ended	December	31, | Increase	(Decrease)	Related	to | Increase	(Decrease)	Related	to | Year	Ended	December	31, |
| :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | 2016 | Price\tRealizations | Net\tSales\tVolumes | 2017 |
| United\tStates\tE&amp;P\tPrice-Volume\tAnalysis\t(a) |  |  |  |  |
| Liquid\thydrocarbons | $2,041 | $619 | $66 | $2,726 |
| Natural\tgas | 274 | 58 | 29 | 361 |
| Realized\tgain\ton\tcommodity |  |  |  |  |
| \t\t\t\tderivative\tinstruments | 44 |  |  | 45 |
| Other\tsales | 16 |  |  | 6 |
| Total | $2,375 |  |  | $3,138 |
| International\tE&amp;P\tPrice-Volume\tAnalysis |  |  |  |  |
| Liquid\thydrocarbons | $546 | $264 | $205 | $1,015 |
| Natural\tgas | 87 | 4 | 6 | 97 |
| Other\tsales | 32 |  |  | 42 |
| Total | $665 |  |  | $1,154 |

(a)	Year	ended	December	31,	2016	includes	sales	volumes	of	14	mboed	on	an	annualized	basis	relating	to	assets	sold	when	compared	to	2017,	primarily	consisting	of	the	disposition	of	Wyoming	and certain	non-operated	CO2	and	waterflood	assets	in	West	Texas	and	New	Mexico	in	2016.

Marketing	revenues	decreased	$78	million	in	2017	from	2016,	primarily	as	a	result	of	lower	marketed	volumes	in	the	United	States	E&P	segment	due	to	non-core asset	dispositions.	Marketing	activities	include	the	purchase	of	commodities	from	third	parties	for	resale	and	serve	to	aggregate	volumes	in	order	to	satisfy	transportation commitments	as	well	as	to	achieve	flexibility	within	product	types	and	delivery	points.	Since	the	volume	of	marketing	activity	is	based	on	market	dynamics,	it	can fluctuate	from	period	to	period.

Income	from	equity	method	investments	increased	$81	million	primarily	due	to	higher	price	realizations	from	LPG	at	our	Alba	plant	and	methanol	at	our	AMPCO methanol	facility.	Also	contributing	to	the	increase	was	improvement	in	net	sales	volumes	primarily	driven	by	the	completion	of	the	Alba	field	compression	project	in E.G.	during	the	second	half	of	2016.

Net	gain	on	disposal	of	assets	decreased	$331	million	in	2017	from	2016.	This	decrease	was	primarily	related	to	the	sale	of	non-core	assets	in	the	first	half	of	2016 in	Wyoming,	West	Texas	and	New	Mexico,	and	the	Gulf	of	Mexico.	See	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	5	to	the	consolidated	financial statements	for	information	about	these	dispositions.

Other	income	increased	$25	million	in	2017	from	2016.	This	increase	was	primarily	a	result	of	a	downward	revision	in	U.K.	estimated	asset	retirement	costs	as	well as	timing	of	abandonment	activities	in	the	U.K.	See	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	11	to	the	consolidated	financial	statements	for	detail about	our	asset	retirement	obligation.

Production	expenses	remained	nearly	flat	during	2017	while	our	sales	volumes	from	continuing	operations	increased.	During	2017,	our	production	expense	rate (expense	per	boe)	for	United	States	E&P	was	lower	primarily	due	to	the	disposition	of	higher	cost	non-core	assets	in	Wyoming.	The	International	E&P	expense	rate decreased	in	the	year	of	2017	primarily	due	to

an	increase	in	sales	volumes	in	E.G.	and	Libya,	combined	with	lower	maintenance	costs	in	E.G.

| ($	per	boe) | 2017 | 2016 |
| :--- | :--- | :--- |
| Production\tExpense\tRate |  |  |
| United\tStates\tE&amp;P | $5.57 | $5.96 |
| International\tE&amp;P | $4.33 | $5.05 |

Marketing	expenses	decreased	$77	million	in	2017	from	the	prior	year,	consistent	with	the	decrease	in	marketing	revenues	discussed	above.

Other	operating	expenses	decreased	$53	million	compared	to	2016	which	included	the	termination	payment	of	our	Gulf	of	Mexico	deepwater	drilling	commitment in	2016.

	Exploration	expenses	increased	$86	million	during	2017	versus	the	comparable	2016	period,	due	primarily	to	charges	taken	as	a	result	of	lower	forecasted	long- term	commodity	prices	and	the	anticipated	sales	of	certain	non-core	properties	in	our	International	E&P	segment.	In	2017,	we	recorded	non-cash	charges	of	$159	million comprised	of	$95	million	in	unproved	property	impairments	in	our	International	E&P	segment	and	$64	million	in	dry	well	costs	related	to	our	Diaba	License	G4-223	in the	Republic	of	Gabon.	Additionally,	our	decision	not	to	develop	the	Tchicuate	offshore	Block	in	the	Republic	of	Gabon	resulted	in	an	increase	to	exploration	expenses of	$43	million	during	2017.	Unproved	property	impairments	during	2016	primarily	consist	of	non-cash	charges	related	to	our	decision	to	not	drill	our	remaining	Gulf	of Mexico	leases.

The	following	table	summarizes	the	components	of	exploration	expenses:

|  | Year	Ended	December	31, | Year	Ended	December	31, |
| :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 |
| Exploration\tExpenses |  |  |
| Unproved\tproperty\timpairments | $246 | $195 |
| Dry\twell\tcosts | 77 | 25 |
| Geological\tand\tgeophysical | 25 | 5 |
| Other | 61 | 98 |
| Total\texploration\texpenses | $409 | $323 |

Exploration	expenses	are	also	discussed	in	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	10	to	the	consolidated	financial	statements.

Depreciation,	depletion	and	amortization	increased	$216	million	in	2017	from	the	prior	year	primarily	as	a	result	of	an	increase	of	$176	million	in	the	United States	E&P	due	to	a	5%	increase	in	net	sales	volumes,	and	an	increase	in	the	DD&A	rates	within	our	U.S.	resource	plays.	Also	contributing	to	this	higher	expense	was	an increase	of	$52	million	in	our	International	E&P	segment	resulting	from	increased	sales	volumes	due	to	the	completion	and	start-up	of	our	E.G.	Alba	field	compression project	in	mid-2016,	and	the	resumption	of	sales	volumes	and	production	in	Libya.	Our	segments	apply	the	units-of-production	method	to	the	majority	of	their	assets, including	capitalized	asset	retirement	costs;	therefore,	volumes	have	an	impact	on	DD&A	expense.

The	DD&A	rate	(expense	per	boe),	which	is	impacted	by	field-level	changes	in	sales	volumes,	reserves	and	capitalized	costs,	can	also	cause	changes	to	our	DD&A. The	DD&A	rate	for	United	States	E&P	increased	primarily	due	to	the	sales	volume	mix	between	our	U.S.	resource	plays,	and	the	outside-operated	Gunflint	field achieving	first	production	in	mid-2016.	Also	contributing	to	the	increase	was	a	reduction	to	the	Eagle	Ford	proved	developed	reserve	base	in	the	fourth	quarter	of	2016.

The	DD&A	rate	for	International	E&P	remained	relatively	consistent	with	the	2016	rate.	The	following	table	provides	DD&A	rates	for	each	segment.

	Impairments	increased	$162	million	in	2017	from	the	comparable	2016	period.	This	increase	was	primarily	consisting	of	$136	million	of	proved	property impairments	in	certain	non-core	properties	in	our	International	E&P	segment	as	a	result	of	our	anticipated	sales	and	lower	forecasted	long-term	commodity	prices. Additionally,	included	in	proved	property	impairments	was	$89	million	in	2017	and	$67	million	in	2016,	both	relating	to	lower	forecasted	commodity	prices	in conventional	properties	in	Oklahoma	and	the	Gulf	of	Mexico.

See	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	10	to	the	consolidated	financial	statement	for	additional	detail.

Taxes	other	than	income	includes	production,	severance	and	ad	valorem	taxes,	primarily	in	the	U.S.,	which	tend	to	increase	or	decrease	in	relation	to	revenue	and sales	volumes.	Taxes	other	than	income	increased	$32	million	in	the	current	year	as	a	result	of	increased	revenue	and	sales	volumes,	and	due	to	a	reserve	being established	for	non-income	tax	examinations	relating	to	open	tax	years.	The	following	table	summarizes	the	components	of	taxes	other	than	income:

|  | Year	Ended	December	31, |  |
| :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 |
| Taxes\tother\tthan\tincome |  |  |
| Production\tand\tseverance | $121 | $91 |
| Ad\tvalorem | 13 | 23 |
| Other | 49 | 37 |
| Total | $183 | $151 |

General	and	administrative	expenses	decreased	$81	million	in	2017	primarily	due	to	reduced	pension	settlement	charges	of	$32	million	in	2017	compared	to	$103 million	in	2016.

Net	interest	and	other	decreased	$62	million	during	2017	primarily	as	a	result	of	the	termination	of	our	forward	starting	interest	rate	swaps,	which	resulted	in	a	gain of	$47	million.	Additionally,	during	2017	we	reduced	total	long	term	debt	by	approximately	$1.75	billion	which	resulted	in	a	reduction	to	our	net	interest	and	other.	The components	of	net	interest	and	other	are	detailed	in	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	15	to	the	consolidated	financial	statements.

Loss	on	early	extinguishment	of	debt	increased	$51	million	in	2017	primarily	due	to	make-whole	call	provisions	of	$46	million	paid	upon	the	redemption	of approximately	$1.75	billion	in	senior	unsecured	notes.	See	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	15	to	the	consolidated	financial	statements	for further	detail.

Provision	(benefit)	for	income	taxes	reflects	an	effective	tax	rate	from	continuing	operations	of	83%	and	79%	for	2017	and	2016.	In	2017,	our	tax	expense	was primarily	a	result	of	our	full	valuation	allowance	on	our	net	federal	deferred	tax	assets	throughout	2017	and	the	effects	of	our	foreign	operations.

See	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	7	to	the	consolidated	financial	statements	for	a	discussion	of	the	effective	income	tax	rate.

Discontinued	operations	are	presented	net	of	tax.	See	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	5	to	the	consolidated	financial	statements	for financial	information	concerning	our	discontinued	operations.

# Segment	income	(loss)

Segment	income	(loss)	represents	income	(loss)	from	operations	excluding	certain	items	not	allocated	to	segments,	net	of	income	taxes,	attributable	to	the	operating segments.	A	portion	of	our	corporate	and	operations	support	general	and	administrative	costs	are	not	allocated	to	the	operating	segments.	Gains	or	losses	on	dispositions, certain	impairments,	unrealized	gains	or	losses	on	commodity	derivative	instruments,	pension	settlement	losses,	or	other	items	that	affect	comparability	also	are	not allocated	to	operating	segments.

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

|  | Year	Ended	December	31, |  |
| :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 |
| United\tStates\tE&amp;P | $(148) | $(415) |
| International\tE&amp;P | 374 | 228 |
| Segment\tincome\t(loss) | 226 | (187) |
| Items\tnot\tallocated\tto\tsegments,\tnet\tof\tincome\ttaxes\t(a) | (1,056) | (1,900) |
| \t\t\t\tIncome\t(loss)\tfrom\tcontinuing\toperations | (830) | (2,087) |
| \t\t\t\tIncome\t(loss)\tfrom\tdiscontinued\toperations\t(b) | (4,893) | (53) |
| \t\t\t\t\t\t\t\t\tNet\tincome\t(loss) | $(5,723) | $(2,140) |

(a)	See	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	6	to	the	consolidated	financial	statements	for	further	detail	about	items	not	allocated	to	segments.

(b)	We	sold	our	Canadian	business	in	the	second	quarter	of	2017.	The	Canadian	business	is	reflected	as	discontinued	operations	in	all	periods	presented.

	United	States	E&P	segment	loss	decreased	$267	million	in	2017	compared	to	2016	primarily	due	to	higher	price	realizations	and	higher	sales	volumes.	Partially offsetting	this	revenue	increase	was	an	increase	in	DD&A	and	a	decrease	in	the	income	tax	benefit,	as	we	did	not	realize	a	tax	benefit	on	any	net	federal	deferred	tax assets	generated	in	2017	due	to	the	full	valuation	allowance	on	net	federal	deferred	tax	assets	in	the	prior	year.

	International	E&P	segment	income	increased	$146	million	in	2017	compared	to	2016	primarily	due	to	higher	price	realizations,	and	an	increase	in	sales	volumes	in E.G.	and	Libya.	This	was	partially	offset	by	an	increase	in	DD&A	and	income	tax	expense	as	a	result	of	the	increase	in	sales	volumes.

|  | Year	Ended	December	31, |  |
| :--- | :--- | :--- |
| (In\tmillions) | 2016 | 2015 |
| Sales\tand\tother\toperating\trevenues,\tincluding\trelated\tparty |  |  |
| United\tStates\tE&amp;P | $2,375 | $3,358 |
| International\tE&amp;P | 665 | 728 |
| Segment\tsales\tand\tother\toperating\trevenues,\tincluding\trelated\tparty | 3,040 | 4,086 |
| Unrealized\tgain\ton\tcrude\toil\tderivative\tinstruments | (110) | 50 |
| Sales\tand\tother\toperating\trevenues,\tincluding\trelated\tparty | $2,930 | $4,136 |

|  | Year	Ended	December	31, | Increase	(Decrease)	Related	to | Increase	(Decrease)	Related	to | Year	Ended	December	31, |
| :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | 2015 | Price\tRealizations | Net\tSales\tVolumes | 2016 |
| United\tStates\tE&amp;P\tPrice-Volume\tAnalysis |  |  |  |  |
| Liquid\thydrocarbons | $2,905 | $(321) | $(543) | $2,041 |
| Natural\tgas | 341 | (32) | (35) | 274 |
| Realized\tgain\ton\tcrude\toil |  |  |  |  |
| \t\t\t\tderivative\tinstruments | 78 |  |  | 44 |
| Other\tsales | 34 |  |  | 16 |
| Total | $3,358 |  |  | $2,375 |
| International\tE&amp;P\tPrice-Volume\tAnalysis |  |  |  |  |
| Liquid\thydrocarbons | $578 | $(78) | $46 | $546 |
| Natural\tgas | 108 | (25) | 4 | 87 |
| Other\tsales | 42 |  |  | 32 |
| Total | $728 |  |  | $665 |

Marketing	revenues	decreased	$259	million	in	2016	from	2015.	Marketing	activities	include	the	purchase	of	commodities	from	third	parties	for	resale	and	serve	to aggregate	volumes	in	order	to	satisfy	transportation	commitments	as	well	as	to	achieve	flexibility	within	product	types	and	delivery	points.	Since	the	volume	of marketing	activity	is	based	on	market	dynamics,	it	can	fluctuate	from	period	to	period.	The	decreases	are	primarily	related	to	lower	marketed	volumes	in	the	United States,	which	were	further	compounded	by	a	lower	commodity	price	environment.

Income	from	equity	method	investments	increased	$30	million	primarily	due	to	higher	net	sales	volumes	in	the	second	half	of	2016	in	E.G.	as	a	result	of	the completion	of	the	Alba	field	compression	project.	Additionally,	a	partial	impairment	of	our	investment	in	an	equity	method	investee	in	2015	of	$12	million	contributed to	the	increase	in	the	current	year.

Net	gain	on	disposal	of	assets	increased	$269	million	in	2016	from	2015.	See	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	5	to	the	consolidated financial	statements	for	information	about	these	dispositions.

Production	expenses	decreased	$267	million	in	2016	from	2015.	United	States	E&P	declined	$238	million	primarily	due	to	lower	operational,	maintenance	and labor	costs,	coupled	with	lower	net	sales	volumes	resulting	from	the	impact	of	our	non-core	asset	dispositions	and	lower	activity	levels.	International	E&P	declined	$29 million	largely	due	to	lower	operational	and	maintenance	costs	as	well	as	a	more	favorable	exchange	rate	on	expenses.

The	2016	production	expense	rate	(expense	rate	per	boe)	for	United	States	E&P	declined	primarily	due	to	cost	reductions	that	occurred	at	a	rate	faster	than	our production	decline.	The	International	E&P	expense	rate	decreased	in	2016	primarily	due	to	reduced	maintenance	and	project	costs	in	the	U.K.	and	benefited	from	the favorable	exchange	rate.	The	following	table	provides	production	expense	rates	for	each	segment:

| ($	per	boe) | 2016 | 2015 |
| :--- | :--- | :--- |
| Production\tExpense\tRate |  |  |
| United\tStates\tE&amp;P | $5.96 | $7.38 |
| International\tE&amp;P | $5.05 | $5.99 |

Other	operating	expenses	increased	$74	million	primarily	as	a	result	of	the	termination	payment	of	our	Gulf	of	Mexico	deepwater	drilling	commitment.

	Exploration	expenses	decreased	$648	million	in	2016	compared	to	2015,	reflecting	our	strategic	decision	to	transition	out	of	conventional	exploration.	In	2016, unproved	property	impairments	primarily	consisted	of	non-cash	charges	related	to	our	decision	to	not	drill	our	remaining	Gulf	of	Mexico	leases	and	also	included certain	other	unproved	properties	in	the	United	States.	In	2015,	unproved	property	impairments	are	due	to	changes	in	our	conventional	exploration	strategy	(Gulf	of Mexico	and	the	Harir	block	in	the	Kurdistan	Region	of	Iraq),	and	the	sale	of	certain	properties	in	the	Gulf	of	Mexico,	as	well	as	our	unproved	property	in	Colorado.

Dry	well	costs	in	2015	included	the	operated	Solomon	exploration	well	in	the	Gulf	of	Mexico	and	our	operated	Sodalita	West	#1	exploratory	well	in	E.G.

|  | Year	Ended	December	31, | Year	Ended	December	31, |
| :--- | :--- | :--- |
| (In\tmillions) | 2016 | 2015 |
| Exploration\tExpenses |  |  |
| Unproved\tproperty\timpairments | $195 | $655 |
| Dry\twell\tcosts | 25 | 212 |
| Geological\tand\tgeophysical | 5 | 31 |
| Other | 98 | 73 |
| Total\texploration\texpenses | $323 | $971 |

Exploration	expense	are	also	discussed	in	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	10	to	the	consolidated	financial	statements.

Depreciation,	depletion	and	amortization	decreased	$565	million	in	2016	from	the	prior	year	primarily	as	a	result	of	net	sales	volume	decreases	in	the	United	States E&P	segment,	including	the	impact	of	non-core	asset	dispositions,	and	volume	declines	due	to	base	declines	and	lower	completion	activity.	Our	segments	apply	the units-of-production	method	to	the	majority	of	their	assets,	including	capitalized	asset	retirement	costs;	therefore,	volumes	have	an	impact	on	DD&A	expense.

The	DD&A	rate	(expense	per	boe),	which	is	impacted	by	field-level	changes	in	sales	volumes,	reserves	and	capitalized	costs,	can	also	cause	changes	to	our	DD&A. The	following	table	provides	DD&A	rates	for	each	segment.	The	DD&A	rate	for	United	States	E&P	decreased	primarily	due	to	a	higher	proved	reserve	base.	The DD&A	rate	for	International	E&P	declined	primarily	due	to	sales	volume	mix	changes	in	E.G.	and	the	U.K.	for	2016.

	Impairments	decreased	$654	million	in	2016	versus	2015.	Impairments	in	2016	were	primarily	the	result	of	lower	forecasted	commodity	prices	in	conventional properties	in	Oklahoma	and	the	Gulf	of	Mexico,	and	were	also	the	result	of	revisions	to	estimated	abandonment	costs.	Impairments	in	2015	included	$340	million	for	the goodwill	impairment	of	the	United	States	E&P	reporting	unit,	and	$335	million	related	to	proved	properties	(primarily	in	Colorado	and	the	Gulf	of	Mexico)	as	a	result	of lower	forecasted	commodity	prices,	and	$44	million	associated	with	our	disposition	of	natural	gas	assets	in	East	Texas,	North	Louisiana	and	Wilburton,	Oklahoma.

See	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	10	and	Note	12	to	the	consolidated	financial	statement	for	additional	detail.

	Taxes	other	than	income	includes	production,	severance	and	ad	valorem	taxes,	primarily	in	the	U.S.,	which	tend	to	increase	or	decrease	in	relation	to	revenue	and sales	volumes.	The	decline	in	revenue	and	sales	volumes	during	2016	resulted	in	a	decline	of	$65	million	compared	to	2015.	The	following	table	summarizes	the components	of	taxes	other	than	income:

|  | Year	Ended	December	31, |  |
| :--- | :--- | :--- |
| (In\tmillions) | 2016 | 2015 |
| Taxes\tother\tthan\tincome |  |  |
| Production\tand\tseverance | $91 | $131 |
| Ad\tvalorem | 23 | 39 |
| Other | 37 | 46 |
| Total\ttaxes\tother\tthan\tincome | $151 | $216 |

General	and	administrative	expenses	decreased	$107	million	primarily	due	to	cost	savings	realized	from	the	2015	workforce	reductions	including	corresponding severance	expenses.

Net	interest	and	other	increased	$46	million	primarily	due	to	an	increase	in	interest	expense	as	a	result	of	the	increase	in	long-term	debt	in	the	second	quarter	of 2015.	The	components	of	net	interest	and	other	are	detailed	in	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	20	to	the	consolidated	financial	statements.

Provision	(benefit)	for	income	taxes	reflects	an	effective	tax	rate	of	79%	and	a	benefit	of	30%	for	2016	and	2015.	The	increase	in	the	2016	effective	tax	rate	was primarily	due	to	the	valuation	allowance	increase	of	$1,346	million	related	to	our	U.S.	benefits	on	foreign	taxes	and	other	federal	deferred	taxes.

|  | Year	Ended	December	31, | Year	Ended	December	31, |
| :--- | :--- | :--- |
| (In\tmillions) | 2016 | 2015 |
| United\tStates\tE&amp;P | $(415) | $(452) |
| International\tE&amp;P | 228 | 112 |
| Segment\tincome\t(loss) | (187) | (340) |
| Items\tnot\tallocated\tto\tsegments,\tnet\tof\tincome\ttaxes\t(a) | (1,900) | (1,361) |
| \t\t\t\tIncome\t(loss)\tfrom\tcontinuing\toperations | (2,087) | (1,701) |
| \t\t\t\tIncome\t(loss)\tfrom\tdiscontinued\toperations\t(b) | (53) | (503) |
| \t\t\t\t\t\t\t\t\tNet\tincome\t(loss) | $(2,140) | $(2,204) |

	United	States	E&P	segment	loss	decreased	$37	million	in	2016	compared	to	2015	as	a	result	of	lower	DD&A	expense,	production	costs,	taxes	other	than	income, and	exploration	expense,	with	these	expense	reductions	more	than	offsetting	the	lower	revenues	as	a	result	of	decreases	in	both	price	realizations	and	net	sales	volumes.

	International	E&P	segment	income	increased	$116	million	in	2016	compared	to	2015.	The	increase	was	largely	due	to	lower	exploration	expenses	in	2016,	as	our 2015	expense	included	costs	relating	to	our	transition	out	of	our	conventional	exploration	program.	The	remainder	of	the	increase	was	due	to	lower	production	costs	and DD&A	as	a	result	of	lower	asset	retirement	costs	and	sales	mix,	and	an	increase	in	income	from	equity	method	investments,	partially	offset	by	lower	price	realizations.

# Management's	Discussion	and	Analysis	of	Financial	Condition,	Cash	Flows	and	Liquidity

Commodity	prices	are	the	most	significant	factor	impacting	our	operating	cash	flows	and	the	amount	of	capital	available	to	reinvest	into	the	business.	In	2017,	we experienced	an	increase	in	operating	cash	flows	primarily	due	to	improvements	in	the	commodity	price	environment	which	resulted	in	an	increase	to	consolidated average	liquid	hydrocarbons	price	realizations	by	over	30%	to	$42.59.	Additionally,	we	closed	on	the	sale	of	our	Canadian	business	and	other	non-core	assets	resulting	in net	proceeds	of	$1.79	billion,	which	allowed	us	to	be	opportunistic	with	our	high	quality	acquisitions	in	the	Permian	basin.	Beyond	the	proceeds	the	non-core	asset	sales generated,	the	portfolio	changes	enhanced	our	profitability	by	disposing	of	higher	unit	cost	operations	and	allowing	for	a	more	efficient	allocation	of	our	Capital Development	Program	to	the	higher	return	opportunities	in	the	U.S.	resource	plays.

Steps	taken	in	2017	to	continue	our	operating	cash	flow	growth	include	the	following	actions:

•Improved	cost	structure	by	reducing	production	expense	per	boe	in 2017.

•Total	2017	net	sales	volumes	from	continuing	operations	increased	10%	compared	to 2016.

Other	2017	cash	flow	highlights	include:

•Divested	certain	non-core	assets	resulting	in	net	proceeds	of	$1.79 billion.

•We	closed	on	multiple	Permian	basin	acquisitions	for	$1.89	billion	with	cash	on

•Through	multiple	financing	transactions	we	have	reduced	total	debt	by	approximately	$1.75	billion	which	will	result	in	a	reduction	to	our	future	annual interest	expense	of	approximately	$115	million.

•Expect	to	receive	$750	million	in	remaining	proceeds	from	the	sale	of	our	Canadian	business	by	March	1,

•Expanded	the	capacity	of	the	revolving	credit	facility	from	$3.3	billion	to	$3.4

billion.

At	December	31,	2017,	we	had	approximately	$4.0	billion	of	liquidity	consisting	of	$563	million	in	cash	and	cash	equivalents	and	$3.4	billion	available	under	our revolving	credit	facility.	As	previously	discussed	in	our	Outlook	section,	we	are	targeting	a	$2.3	billion	Capital	Development	Program	for	2018.	We	believe	our	current liquidity	level	and	balance	sheet,	along	with	our	non-core	asset	disposition	program	and	ability	to	access	the	capital	markets	provides	us	with	the	flexibility	to	fund	our business	throughout	the	different	commodity	price	cycles.	We	will	continue	to	evaluate	the	commodity	price	environment	and	our	spending	throughout	2018.

# Cash	Flows

The	following	table	presents	sources	and	uses	of	cash	and	cash	equivalents	from	continuing	operations	for	2017,	2016	and	2015:

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 | 2015 |
| Sources\tof\tcash\tand\tcash\tequivalents |  |  |  |
| Operating\tactivities\t-\tcontinuing\toperations | $1,988 | $901 | $1,537 |
| Disposals\tof\tassets,\tnet\tof\tcash\ttransferred\tto\tthe\tbuyer | 1,787 | 1,219 | 225 |
| Common\tstock\tissuance | — | 1,236 | — |
| Borrowings | 988 | — | 1,996 |
| Other | 68 | 56 | 101 |
| Total\tsources\tof\tcash\tand\tcash\tequivalents | $4,831 | $3,412 | $3,859 |
| Uses\tof\tcash\tand\tcash\tequivalents |  |  |  |
| Cash\tadditions\tto\tproperty,\tplant\tand\tequipment | $(1,974) | $(1,204) | $(3,485) |
| Acquisitions,\tnet\tof\tcash\tacquired | (1,891) | (902) | — |
| Purchases\tof\tcommon\tstock | (11) | (6) | (11) |
| Debt\trepayments | (2,764) | (1) | (1,069) |
| Debt\textinguishment\tcosts | (46) | — | — |
| Dividends\tpaid | (170) | (162) | (460) |
| Other | (30) | (4) | (8) |
| Total\tuses\tof\tcash\tand\tcash\tequivalents | $(6,886) | $(2,279) | $(5,033) |

Cash	flows	generated	from	operating	activities	in	2017	were	higher	as	commodity	prices	and	price	realizations	improved	compared	to	2016.	This	increase	in	price realization	coupled	with	our	increased	sales	volumes	and	continued	focus	on	cost	reductions	resulted	in	an	increase	to	cash	flows	generated	from	operating	activities.

Proceeds	from	the	disposals	of	assets	for	2017	are	primarily	a	result	of	the	disposal	of	our	Canadian	business,	and	proceeds	from	disposals	of	assets	in	2016	are primarily	from	the	sale	of	our	Wyoming	upstream	and	midstream	assets,	as	well	as	the	sale	of	certain	other	non-operated	CO2	and	waterflood	assets	in	West	Texas	and New	Mexico.	Disposals	of	assets	in	2015	pertain	to	the	sale	of	certain	of	our	operated	and	non-operated	producing	properties	in	the	Gulf	of	Mexico	as	well	as	natural	gas assets	in	East	Texas,	North	Louisiana	and	Wilburton,	Oklahoma.	Disposition	transactions	are	discussed	in	further	detail	in	Item	8.	Financial	Statements	and Supplementary	Data	–	Note	5	to	the	consolidated	financial	statements.

Issuance	of	common	stock	reflects	net	proceeds	received	in	March	2016	from	our	public	sale	of	common	stock.	See	Item	8.	Financial	Statements	and Supplementary	Data	-	Note	22	to	the	consolidated	financial	statements	for	additional	information.

Borrowings	in	2017	are	a	result	of	the	issuance	of	$1	billion	of	4.4%	senior	unsecured	notes	due	in	2027.	Our	2015	borrowings	reflect	net	proceeds	received	from the	issuance	of	senior	notes	in	June	2015.	Financing	transactions	are	discussed	in	further	detail	in	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	15	to	the consolidated	financial	statements	for	additional	information.

Additions	to	property,	plant	and	equipment	reflect	a	significant	use	of	cash	and	cash	equivalents.	The	following	table	shows	capital	expenditures	related	to continuing	operations	by	segment	and	reconciles	to	additions	to	property,	plant	and	equipment	as	presented	in	the	consolidated	statements	of	cash	flows	for	2017,	2016 and	2015:

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 | 2015 |
| United\tStates\tE&amp;P | $2,081 | $936 | $2,553 |
| International\tE&amp;P | 42 | 82 | 368 |
| Corporate | 27 | 18 | 25 |
| Total\tcapital\texpenditures | 2,150 | 1,036 | 2,946 |
| Change\tin\tcapital\texpenditure\taccrual | (176) | 168 | 539 |
| Additions\tto\tproperty,\tplant\tand\tequipment | $1,974 | $1,204 | $3,485 |

During	2017,	we	closed	on	multiple	Permian	basin	acquisitions	for	approximately	$1.9	billion	with	cash	on	hand.	Additionally,	during	2016,	we	closed	the Oklahoma	STACK	acquisition	for	a	purchase	price	of	$902	million,	net	of	cash

acquired;	see	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	4	to	the	consolidated	financial	statements	for	further	information	concerning	acquisitions.

In	December	2017,	we	redeemed	$1	billion	of	5.125%	municipal	revenue	bonds	due	in	2037	in	a	refunding	transaction.	Additionally,	during	the	third	quarter	of 2017,	we	used	the	net	proceeds	of	the	borrowing	disclosed	above	plus	existing	cash	on	hand	to	redeem	$1.76	billion	in	senior	unsecured	notes	resulting	in	a	recognized loss	on	early	extinguishment	of	debt	of	$46	million,	primarily	due	to	make-whole	call	provisions.	In	November	2015,	we	repaid	our	$1	billion	0.90%	senior	notes	upon maturity.	Financing	transactions	are	discussed	in	further	detail	in	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	15	to	the	consolidated	financial statements	for	additional	information.

During	2017,	the	Board	of	Directors	approved	a	$0.05	per	share	quarterly	dividend.	See	Capital	Requirements	below	for	additional	information	about	the	fourth quarter	dividend.	During	2015	we	announced	an	adjustment	to	our	quarterly	dividend	starting	in	third	quarter	2015,	with	the	full-year	impact	resulting	in	a	decrease	of dividends	paid	in	2017	and	2016.

# Liquidity	and	Capital	Resources

In	June	2017,	we	extended	the	maturity	date	of	our	Credit	Facility	from	May	28,	2020,	to	May	28,	2021.	In	July	2017,	we	increased	our	$3.3	billion	unsecured Credit	Facility	by	$93	million	to	a	total	of	$3.4	billion.	Fees	on	the	unused	commitment	of	each	lender,	as	well	as	the	borrowing	options	under	the	Credit	Facility,	remain unaffected	by	the	increase	and	term	extension.	We	have	the	ability	to	request	two	additional	one-year	extensions	and	an	option	to	increase	the	commitment	amount	by	up to	an	additional	$107	million,	subject	to	the	consent	of	any	increasing	lenders.		The	sub-facilities	for	swing-line	loans	and	letters	of	credit	remain	unchanged	allowing	up to	an	aggregate	amount	of	$100	million	and	$500	million,	respectively.

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	December	31,	2017,	we	had	approximately	$4.0	billion	of	liquidity	consisting	of	$563	million	in	cash	and	cash	equivalents	and	$3.4 billion	available	under	our	revolving	credit	facility.	During	the	first	quarter	of	2018,	we	expect	to	receive	$750	million	in	remaining	proceeds	from	the	sale	of	our Canadian	business.	Our	working	capital	requirements	are	supported	by	these	sources	and	we	may	draw	on	our	revolving	credit	facility	to	meet	short-term	cash requirements,	or	issue	debt	or	equity	securities	through	the	shelf	registration	statement	discussed	below	as	part	of	our	longer-term	liquidity	and	capital	management program.	Because	of	the	alternatives	available	to	us	as	discussed	above,	we	believe	that	our	short-term	and	long-term	liquidity	are	adequate	to	fund	not	only	our	current operations,	but	also	our	near-term	and	long-term	funding	requirements	including	our	capital	spending	programs,	dividend	payments,	defined	benefit	plan	contributions, repayment	of	debt	maturities,	and	other	amounts	that	may	ultimately	be	paid	in	connection	with	contingencies.

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

In	December	of	2017,	we	redeemed	$1	billion	of	5.125%	municipal	revenue	bonds	due	in	2037	in	a	refunding	transaction	that	preserved	our	ability	to	remarket	up	to $1	billion	of	tax-exempt	municipal	bonds	prior	to	2037.	We	may	incur	additional	debt	in	order	to	fund	our	capital	expenditures,	acquisitions	or	development	activities,	or for	general	corporate	or	other	purposes.	A	higher	level	of	indebtedness	could	increase	the	risk	that	our	liquidity	and	financial	flexibility	deteriorates.	See	Item	1A.	Risk Factors	for	a	further	discussion	of	how	our	level	of	indebtedness	could	affect	us.

# Capital	Resources

# Credit	Arrangements	and	Borrowings

At	December	31,	2017,	we	had	no	borrowings	against	our	revolving	credit	facility.

At	December	31,	2017,	we	had	$5.5	billion	in	long-term	debt	outstanding,	with	our	next	debt	maturity	in	the	amount	of	$600	million	due	in	2020.

We	do	not	have	any	triggers	on	any	of	our	corporate	debt	that	would	cause	an	event	of	default	in	the	case	of	a	downgrade	of	our	credit	ratings.

# Shelf	Registration

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

# Asset	Disposals

We	closed	on	$1.8	billion	of	non-core	asset	sales	during	2017,	with	the	largest	transaction	being	the	disposal	of	our	Canadian	business.	During	the	third	quarter	of 2017,	we	entered	into	separate	agreements	to	sell	certain	non-core	properties	in	our	International	E&P	segment	for	combined	proceeds	of	$53	million,	before	closing adjustments.	We	have	closed	on	one	of	these	agreements	in	2017,	and	we	expect	the	remainder	of	the	agreements	to	close	during	2018.

See	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	5	to	the	consolidated	financial	statements	for	additional	discussion	of	these	dispositions.

# Debt-To-Capital	Ratio

The	Credit	Facility	includes	a	covenant	requiring	that	our	ratio	of	total	debt	to	total	capitalization	not	exceed	65%	as	of	the	last	day	of	each	fiscal	quarter.	Our	debt- to-capital	ratio	was	32%	at	December	31,	2017	and	29%	at	December	31,	2016.

| (Dollars	in	millions) | 2017 | 2016 |
| :--- | :--- | :--- |
| Long-term\tdebt\tdue\twithin\tone\tyear | $— | $686 |
| Long-term\tdebt | 5,494 | 6,581 |
| Total\tdebt | $5,494 | $7,267 |
| Equity | $11,708 | $17,541 |
| Calculation |  |  |
| Total\tdebt | $5,494 | $7,267 |
| \tTotal\tdebt\tplus\tequity\t(total\tcapitalization) | $17,202 | $24,808 |
| Debt-to-capital\tratio | 32% | 29% |

# Capital	Requirements

# Capital	Spending

Our	approved	Capital	Development	Program	for	2018	is	$2.3	billion.	Additional	details	were	previously	discussed	in	Outlook.

# Share	Repurchase	Program

The	remaining	share	repurchase	authorization	as	of	December	31,	2017	is	$1.5	billion.

# Other	Expected	Cash	Outflows

On	January	30,	2018,	our	Board	of	Directors	approved	a	dividend	of	$0.05	per	share	for	the	fourth	quarter	of	2017.	The	dividend	is	payable	on	March	12,	2018	to shareholders	on	record	on	February	21,	2018.

We	plan	to	make	contributions	of	up	to	$65	million	to	our	funded	pension	plans	during	2018.	Cash	contributions	to	be	paid	from	our	general	assets	for	the	unfunded pension	and	postretirement	plans	are	expected	to	be	approximately	$6	million	and	$21	million	in	2018.

# Contractual	Cash	Obligations

The	table	below	provides	aggregated	information	on	our	consolidated	obligations	to	make	future	payments	under	existing	contracts	as	of	December	31,	2017.

| (In	millions) | Total | 2018 | 2019-<br>2020 | 2021-<br>2022 | Later<br>Years |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Short\tand\tlong-term\tdebt\t(includes\tinterest)(a) | $8,776 | $256 | $1,103 | $1,512 | $5,905 |
| Lease\tobligations | 119 | 29 | 55 | 31 | 4 |
| Purchase\tobligations: |  |  |  |  |  |
| Oil\tand\tgas\tactivities(b) | 108 | 94 | 8 | 4 | 2 |
| Service\tand\tmaterials\tcontracts(c) | 115 | 65 | 48 | 2 | — |
| Transportation\tand\trelated\tcontracts | 1,581 | 313 | 483 | 241 | 544 |
| Drilling\trigs\tand\tfracturing\tcrews(d) | 21 | 21 | — | — | — |
| Other | 42 | 13 | 24 | 5 | — |
| Total\tpurchase\tobligations | 1,867 | 506 | 563 | 252 | 546 |
| Other\tlong-term\tliabilities\treported\tin\tthe\tconsolidated\tbalance\nsheet(e) | 486 | 141 | 77 | 63 | 205 |
| Total\tcontractual\tcash\tobligations(f) | $11,248 | $932 | $1,798 | $1,858 | $6,660 |

(b) Oil	and	gas	activities	include	contracts	to	acquire	property,	plant	and	equipment	and	commitments	for	oil	and	gas	exploration	such	as	costs	related	to	contractually	obligated	exploratory	work programs	that	are	expensed	immediately.

(c) Service	and	materials	contracts	include	contracts	to	purchase	services	such	as	utilities,	supplies	and	various	other	maintenance	and	operating	services.

(d) Some	contracts	may	be	canceled	at	an	amount	less	than	the	contract	amount.	Were	we	to	elect	that	option	where	possible	at	December	31,	2017	our	minimum	commitment	would	be	$14	million.

(e) Primarily	includes	obligations	for	pension	and	other	postretirement	benefits	including	medical	and	life	insurance.	We	have	estimated	projected	funding	requirements	through	2027.	Although unrecognized	tax	benefits	are	not	a	contractual	obligation,	they	are	presented	in	this	table	because	they	represent	potential	demands	on	our	liquidity.

(f) This	table	does	not	include	the	estimated	discounted	liability	for	dismantlement,	abandonment	and	restoration	costs	of	oil	and	gas	properties	of $1,483	million.	See	Item	8.	Financial	Statements and	Supplementary	Data	–	Note	11	to	the	consolidated	financial	statements.

# Transactions	with	Related	Parties

We	own	a	63%	working	interest	in	the	Alba	field	offshore	E.G.	Onshore	E.G.,	we	own	a	52%	interest	in	an	LPG	processing	plant,	a	60%	interest	in	an	LNG production	facility	and	a	45%	interest	in	a	methanol	production	plant,	each	through	equity	method	investees.	We	sell	our	natural	gas	from	the	Alba	field	to	these	equity method	investees	as	the	feedstock	for	their	production	processes.

# Off-Balance	Sheet	Arrangements

Off-balance	sheet	arrangements	comprise	those	arrangements	that	may	potentially	impact	our	liquidity,	capital	resources	and	results	of	operations,	even	though such	arrangements	are	not	recorded	as	liabilities	under	accounting	principles	generally	accepted	in	the	U.S.	Although	off-balance	sheet	arrangements	serve	a	variety	of our	business	purposes,	we	are	not	dependent	on	these	arrangements	to	maintain	our	liquidity	and	capital	resources,	and	we	are	not	aware	of	any	circumstances	that	are reasonably	likely	to	cause	the	off-balance	sheet	arrangements	to	have	a	material	adverse	effect	on	liquidity	and	capital	resources.

We	will	issue	stand-alone	letters	of	credit	when	required	by	a	business	partner.	Such	letters	of	credit	outstanding	at	December	31,	2017,	2016	and	2015	aggregated $89	million,	$166	million	and	$53	million.	Most	of	the	letters	of	credit	are	in	support	of	obligations	recorded	in	the	consolidated	balance	sheet.	For	example,	they	are issued	to	counterparties	to	support	firm	transportation	agreements	and	future	abandonment	liabilities.

# Management's	Discussion	and	Analysis	of	Environmental	Matters,	Litigation	and	Contingencies

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

We	accrue	for	environmental	remediation	activities	when	the	responsibility	to	remediate	is	probable	and	the	amount	of	associated	costs	can	be	reasonably	estimated. As	environmental	remediation	matters	proceed	toward	ultimate	resolution	or	as	additional	remediation	obligations	arise,	charges	in	excess	of	those	previously	accrued may	be	required.

New	or	expanded	environmental	requirements,	which	could	increase	our	environmental	costs,	may	arise	in	the	future.	We	strive	to	comply	with	all	legal requirements	regarding	the	environment,	but	as	not	all	costs	are	fixed	or	presently	determinable	(even	under	existing	legislation)	and	may	be	affected	by	future legislation	or	regulations,	it	is	not	possible	to	predict	all	of	the	ultimate	costs	of	compliance,	including	remediation	costs	that	may	be	incurred	and	penalties	that	may	be imposed.

For	more	information	on	environmental	regulations	that	impact	us,	or	could	impact	us,	see	Item	1.	Business	–	Environmental,	Health	and	Safety	Matters,	Item	1A. Risk	Factors	and	Item	3.	Legal	Proceedings.

# Critical	Accounting	Estimates

The	preparation	of	financial	statements	in	accordance	with	accounting	principles	generally	accepted	in	the	U.S.	requires	us	to	make	estimates	and	assumptions	that affect	the	reported	amounts	of	assets	and	liabilities	and	the	disclosure	of	contingent	assets	and	liabilities	as	of	the	date	of	the	consolidated	financial	statements	and	the reported	amounts	of	revenues	and	expenses	during	the	respective	reporting	periods.	Accounting	estimates	are	considered	to	be	critical	if	(1)	the	nature	of	the	estimates and	assumptions	is	material	due	to	the	levels	of	subjectivity	and	judgment	necessary	to	account	for	highly	uncertain	matters	or	the	susceptibility	of	such	matters	to change,	and	(2)	the	impact	of	the	estimates	and	assumptions	on	financial	condition	or	operating	performance	is	material.	Actual	results	could	differ	from	the	estimates and	assumptions	used.

# Estimated	Quantities	of	Net	Reserves

We	use	the	successful	efforts	method	of	accounting	for	our	oil	and	gas	producing	activities.	The	successful	efforts	method	inherently	relies	on	the	estimation	of proved	crude	oil	and	condensate,	NGLs	and	natural	gas	reserves.	The	amount	of	estimated	proved	reserve	volumes	affect,	among	other	things,	whether	certain	costs	are capitalized	or	expensed,	the	amount	and	timing	of	costs	depreciated,	depleted	or	amortized	into	net	income	and	the	presentation	of	supplemental	information	on	oil	and gas	producing	activities.	In	addition,	the	expected	future	cash	flows	to	be	generated	by	producing	properties	are	used	for	testing	impairment	and	the	expected	future taxable	income	available	to	realize	deferred	tax	assets,	also	in	part,	rely	on	estimates	of	quantities	of	net	reserves.	Refer	to	the	applicable	sections	below	for	further discussion	of	these	accounting	estimates.

The	estimation	of	quantities	of	net	reserves	is	a	highly	technical	process	performed	by	our	engineers	and	geoscientists	for	crude	oil	and	condensate,	NGLs	and natural	gas,	which	is	based	upon	several	underlying	assumptions.	The	reserve	estimates	may	change	as	additional	information	becomes	available	and	as	contractual, operational,	economic	and	political	conditions	change.	We	evaluate	our	reserves	using	drilling	results,	reservoir	performance,	seismic	interpretation	and	future	plans	to develop	acreage.	Technologies	used	in	proved	reserves	estimation	includes	statistical	analysis	of	production	performance,	decline	curve	analysis,	pressure	and	rate transient	analysis,	pressure	gradient	analysis,	reservoir	simulation	and	volumetric	analysis.	The	observed	statistical	nature	of	production	performance	coupled	with highly	certain	reservoir	continuity	or	quality	within	the	reliable	technology	areas	and	sufficient	proved	developed	locations	establish	the	reasonable	certainty	criteria required	for	booking	proved	reserves.	The	data	for	a	given	reservoir	may	also	change	over	time	as	a	result	of	numerous	factors	including,	but	not	limited	to,	additional development	activity,	production	history	and	continual	reassessment	of	the	viability	of	production	under	varying	economic	conditions.

Reserve	estimates	are	based	on	an	unweighted	arithmetic	average	of	commodity	prices	during	the	12-month	period,	using	the	closing	prices	on	the	first	day	of	each month,	as	defined	by	the	SEC.	The	table	below	provides	the	2017	SEC	pricing	for	certain	benchmark	prices:

|  | SEC	Pricing	2017 |
| :--- | :--- |
| WTI\tCrude\toil\t(per\tbbl) | $51.34 |
| Henry\tHub\tnatural\tgas\t(per\tmmbtu) | $2.98 |
| Brent\tcrude\toil\t(per\tbbl) | $54.39 |
| Mont\tBelvieu\tNGLs\t(per\tbbl) | $22.03 |

When	determining	the	December	31,	2017	proved	reserves	for	each	property,	the	benchmark	prices	listed	above	were	adjusted	using	price	differentials	that	account for	property-specific	quality	and	location	differences.

Estimates	of	future	cash	flows	associated	with	proved	reserves	are	based	on	actual	costs	of	developing	and	producing	proved	reserves	at	the	end	of	the	year.	If commodity	prices	were	to	decrease	by	approximately	10%,	below	average	prices	used	to	estimate	2017	proved	reserves	(see	table	above),	we	would	not	expect	price related	reserve	revisions	to	have	a	material	impact	on	proved	reserve	volumes.	For	further	discussion	of	risks	associated	with	our	estimation	of	proved	reserves,	see	Part I.	Item	1A	Risk	Factors.

Depreciation	and	depletion	of	crude	oil	and	condensate,	NGLs	and	natural	gas	producing	properties	is	determined	by	the	units-of-production	method	and	could change	with	revisions	to	estimated	proved	reserves.	While	revisions	of	previous	reserve	estimates	have	not	historically	been	significant	to	the	depreciation	and	depletion rates	of	our	segments,	any	reduction	in	proved	reserves,	could	result	in	an	acceleration	of	future	DD&A	expense.	The	following	table	illustrates,	on	average,	the sensitivity	of	each	segment's	units-of-production	DD&A	per	boe	and	pretax	income	to	a	hypothetical	10%	change	in	2017	proved	reserves	based	on	2017	production.

|  | Impact	of	a	10%	Increase	in	Proved	Reserves | Impact	of	a	10%	Increase	in	Proved	Reserves | Impact	of	a	10%	Decrease	in	Proved	Reserves | Impact	of	a	10%	Decrease	in	Proved	Reserves |
| :--- | :--- | :--- | :--- | :--- |
| (In\tmillions,\texcept\tper\tboe) | DD&amp;A\tper\tboe | Pretax\tIncome | DD&amp;A\tper\tboe | Pretax\tIncome |
| United\tStates\tE&amp;P | $(2.14) | $183 | $2.61 | $(224) |
| International\tE&amp;P | $(0.56) | $30 | $0.69 | $(36) |

# Asset	Retirement	Obligations

We	have	material	legal,	regulatory	and	contractual	obligations	to	remove	and	dismantle	long-lived	assets	and	to	restore	land	or	seabed	at	the	end	of	oil	and	gas production	operations.	A	liability	equal	to	the	fair	value	of	such	obligations	and	a	corresponding	capitalized	asset	retirement	cost	are	recognized	on	the	balance	sheet	in the	period	in	which	the	legal	obligation	is	incurred	and	a	reasonable	estimate	of	fair	value	can	be	made.	The	capitalized	asset	retirement	cost	is	depreciated	using	the units-of-production	method	or	the	straight	line	method	(dependent	on	the	underlying	asset)	and	the	discounted	liability	is	accreted	over	the	period	until	the	obligation	is satisfied,	the	impacts	of	which	are	recognized	as	DD&A	in	the	consolidated	statements	of	income.	In	many	cases,	the	satisfaction	and	subsequent	discharge	of	these liabilities	is	projected	to	occur	many	years,	or	even	decades,	into	the	future.	Furthermore,	the	legal,	regulatory	and	contractual	requirements	often	do	not	provide	specific guidance	regarding	removal	practices	and	the	criteria	that	must	be	fulfilled	when	the	removal	and/or	restoration	event	actually	occurs.

Estimates	of	retirement	costs	are	developed	for	each	property	based	on	numerous	factors,	such	as	the	scope	of	the	dismantlement,	timing	of	settlement, interpretation	of	legal,	regulatory	and	contractual	requirements,	type	of	production	and	processing	structures,	depth	of	water	(if	applicable),	reservoir	characteristics, depth	of	the	reservoir,	market	demand	for	equipment,	currently	available	dismantlement	and	restoration	procedures	and	consultations	with	construction	and	engineering professionals.	Inflation	rates	and	credit-adjusted-risk-free	interest	rates	are	then	applied	to	estimate	the	fair	values	of	the	obligations.	To	the	extent	these	or	other assumptions	change	after	initial	recognition	of	the	liability,	the	fair	value	estimate	is	revised	and	the	recognized	liability	adjusted,	with	a	corresponding	adjustment	made to	the	related	asset	balance	or	income	statement,	as	appropriate.	Changes	in	estimated	asset	retirement	obligations	for	late	life	assets	could	result	in	future	impairment charges	or	in	the	recognition	of	income.	See	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	11	to	the	consolidated	financial	statements	for	disclosures regarding	our	asset	retirement	obligation	estimates.

An	estimate	of	the	sensitivity	to	net	income	if	other	assumptions	had	been	used	in	recording	these	liabilities	is	not	practical	because	of	the	number	of	obligations that	must	be	assessed,	the	number	of	underlying	assumptions	and	the	wide	range	of	possible	assumptions.

# Fair	Value	Estimates

Fair	value	is	the	price	that	would	be	received	to	sell	an	asset	or	paid	to	transfer	a	liability	in	an	orderly	transaction	between	market	participants	at	the	measurement date.	There	are	three	approaches	for	measuring	the	fair	value	of	assets	and	liabilities:	the	market	approach,	the	income	approach	and	the	cost	approach,	each	of	which includes	multiple	valuation	techniques.	The	market	approach	uses	prices	and	other	relevant	information	generated	by	market	transactions	involving	identical	or comparable	assets	or	liabilities.	The	income	approach	uses	valuation	techniques	to	measure	fair	value	by	converting	future	amounts,	such	as	cash	flows	or	earnings,	into a	single	present	value,	or	range	of	present	values,	using	current	market	expectations	about	those	future	amounts.	The	cost	approach	is	based	on	the	amount	that	would currently	be	required	to	replace	the	service	capacity	of	an	asset.	This	is	often	referred	to	as	current	replacement	cost.	The	cost	approach	assumes	that	the	fair	value	would not	exceed	what	it	would	cost	a	market	participant	to	acquire	or	construct	a	substitute	asset	of	comparable	utility,	adjusted	for	obsolescence.

The	fair	value	accounting	standards	do	not	prescribe	which	valuation	technique	should	be	used	when	measuring	fair	value	and	do	not	prioritize	among	the techniques.	These	standards	establish	a	fair	value	hierarchy	that	prioritizes	the	inputs	used	in	applying	the	various	valuation	techniques.	Inputs	broadly	refer	to	the assumptions	that	market	participants	use	to	make	pricing	decisions,	including	assumptions	about	risk.	Level	1	inputs	are	given	the	highest	priority	in	the	fair	value hierarchy	while	Level	3	inputs	are	given	the	lowest	priority.	The	three	levels	of	the	fair	value	hierarchy	are	as	follows:

•Level	1	–	Observable	inputs	that	reflect	unadjusted	quoted	prices	for	identical	assets	or	liabilities	in	active	markets	as	of	the	measurement	date.	Active	markets	are those	in	which	transactions	for	the	asset	or	liability	occur	in	sufficient	frequency	and	volume	to	provide	pricing	information	on	an	ongoing	basis.

•Level	2	–	Observable	market-based	inputs	or	unobservable	inputs	that	are	corroborated	by	market	data.	These	are	inputs	other	than	quoted	prices	in	active	markets included	in	Level	1,	which	are	either	directly	or	indirectly	observable	as	of	the	measurement	date.

•Level	3	–	Unobservable	inputs	that	are	not	corroborated	by	market	data	and	may	be	used	with	internally	developed	methodologies	that	result	in	management's best	estimate	of	fair	value.

Valuation	techniques	that	maximize	the	use	of	observable	inputs	are	favored.	Assets	and	liabilities	are	classified	in	their	entirety	based	on	the	lowest	priority	level	of input	that	is	significant	to	the	fair	value	measurement.	The	assessment	of	the	significance	of	a	particular	input	to	the	fair	value	measurement	requires	judgment	and	may affect	the	placement	of	assets	and	liabilities	within	the	levels	of	the	fair	value	hierarchy.	See	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	14	to	the consolidated	financial	statements	for	disclosures	regarding	our	fair	value	measurements.

Significant	uses	of	fair	value	measurements	include:

•impairment	assessments	of	long-lived

assets;

•impairment	assessments	of	goodwill;	and

•recorded	value	of	derivative	instruments.

The	need	to	test	long-lived	assets	and	goodwill	for	impairment	can	be	based	on	several	indicators,	including	a	significant	reduction	in	prices	of	crude	oil	and condensate,	NGLs	and	natural	gas,	sustained	declines	in	our	common	stock,	reductions	to	our	Capital	Development	Program,	unfavorable	adjustments	to	reserves, significant	changes	in	the	expected	timing	of	production,	other	changes	to	contracts	or	changes	in	the	regulatory	environment	in	which	the	property	is	located.

# Impairment	Assessments	of	Long-Lived	Assets

Long-lived	assets	in	use	are	assessed	for	impairment	whenever	changes	in	facts	and	circumstances	indicate	that	the	carrying	value	of	the	assets	may	not	be recoverable.	For	purposes	of	an	impairment	evaluation,	long-lived	assets	must	be	grouped	at	the	lowest	level	for	which	independent	cash	flows	can	be	identified,	which generally	is	field-by-field	or,	in	certain	instances,	by	logical	grouping	of	assets	if	there	is	significant	shared	infrastructure	or	contractual	terms	that	cause	economic interdependency	amongst	separate,	discrete	fields.	If	the	sum	of	the	undiscounted	estimated	cash	flows	from	the	use	of	the	asset	group	and	its	eventual	disposition	is	less than	the	carrying	value	of	an	asset	group,	the	carrying	value	is	written	down	to	the	estimated	fair	value.	During	2017	lower	forecasted	long-term	commodity	prices	and the	anticipated	sales	of	certain	non-core	proved	properties	in	our	International	E&P	segment	triggered	an	assessment	of	certain	of	our	long-lived	assets	related	to	oil	and gas	producing	properties	for	impairment.	We	estimated	the	fair	values	using	an	income	and	market	approach	and	recognized	impairments.	As	of	December	31,	2017	our estimated	undiscounted	cash	flows	relating	to	our	remaining	long-lived	assets	significantly	exceeded	their	carrying	values.	Long-lived	assets	most	at	risk	for	future impairment	had	estimated	undiscounted	cash	flows	that	exceeded	their	$66	million	carrying	value	by	$22	million.	See	Item	8.	Financial	Statements	and	Supplementary Data	Note	10	and	Note	14	to	the	consolidated	financial	statements	for	discussion	of	impairments	recorded	in	2017,	2016	and	2015	and	the	related	fair	value measurements.

Fair	value	calculated	for	the	purpose	of	testing	our	long-lived	assets	for	impairment	is	estimated	using	the	present	value	of	expected	future	cash	flows	method	and comparative	market	prices	when	appropriate.	Significant	judgment	is	involved	in	performing	these	fair	value	estimates	since	the	results	are	based	on	forecasted assumptions.	Significant	assumptions	include:

•Future	crude	oil	and	condensate,	NGLs	and	natural	gas	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,	governmental	policies and	vehicle	stocks.	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	crude	oil	and	condensate,	NGLs	and	natural	gas	prices	and	estimates	of	such	future	prices	are	inherently	imprecise.	See	Item	1A.	Risk Factors	for	further	discussion	on	commodity	prices.

•Estimated	quantities	of	crude	oil	and	condensate,	NGLs	and	natural	gas.	Such	quantities	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	for	further discussion	on	reserves.

•Expected	timing	of	production.	Production	forecasts	are	the	outcome	of	engineering	studies	which	estimate	reserves,	as	well	as	expected	capital	development 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	that	we	use	in	our	fair	value	estimates	is	consistent	with	that	used	in	our planning	and	capital	investment	reviews.

•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.

•Future	capital	requirements.	Our	estimates	of	future	capital	requirements	are	based	upon	a	combination	of	authorized	spending	and	internal forecasts.

We	base	our	fair	value	estimates	on	projected	financial	information	which	we	believe	to	be	reasonably	likely	to	occur.	An	estimate	of	the	sensitivity	to	changes	in assumptions	in	our	undiscounted	cash	flow	calculations	is	not	practicable,	given	the	numerous	assumptions	(e.g.	reserves,	pace	and	timing	of	development	plans, commodity	prices,	capital	expenditures,	operating	costs,	drilling	and	development	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.	For	example,	the	impact	of sustained	reduced	commodity	prices	on	future	undiscounted	cash	flows	would	likely	be	partially	offset	by	lower	costs.

# Impairment	Assessments	of	Goodwill

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.	Goodwill	is	tested	for	impairment	at	the	reporting	unit	level.	Our	reporting	units	are	the	same	as	our reporting	segments,	of	which	only	International	E&P	includes	goodwill.	We	performed	our	annual	impairment	test	in	the	second	quarter	of	2017	for	the	International E&P	reporting	unit	and	no	impairment	was	required.	As	of	the	date	of	our	last	goodwill	impairment	assessment,	our	International	E&P	reporting	unit	fair	value	exceeded its	book	value	by	over	40%.

We	estimate	the	fair	values	of	our	International	E&P	reporting	unit	using	a	combination	of	market	and	income	approaches.	Determining	the	fair	value	of	a	reporting unit	requires	judgment	and	the	use	of	significant	estimates	and	assumptions.	The	market	approach	referenced	observable	inputs	specific	to	us	and	our	industry,	such	as the	price	of	our	common	equity,	our	enterprise	value,	and	valuation	multiples	of	us	and	our	peers	from	the	investor	analyst	community.	The	income	approach	utilizes discounted	cash	flows,	which	are	based	on	forecasted	assumptions.	Key	assumptions	to	the	income	approach	are	the	same	as	those	described	above	regarding	our impairment	assessment	of	long	lived	assets	and	are	consistent	with	those	that	management	uses	to	make	business	decisions.	We	believe	the	estimates	and	assumptions used	in	our	impairment	assessments	are	reasonable	and	based	on	available	market	information,	but	variations	in	such	assumptions	could	result	in	materially	different calculations	of	fair	value	and	determinations	of	whether	or	not	an	impairment	is	indicated.	See	Item	8.	Financial	Statements	and	Supplementary	Data	Note	12	to	the consolidated	financial	statements	for	additional	discussion	of	goodwill.

# Derivatives

We	record	all	derivative	instruments	at	fair	value.	Fair	value	measurements	for	all	our	derivative	instruments	are	based	on	observable	market-based	inputs	that	are corroborated	by	market	data	and	are	discussed	in	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	13	to	the	consolidated	financial	statements.	Additional information	about	derivatives	and	their	valuation	may	be	found	in	Item	7A.	Quantitative	and	Qualitative	Disclosures	About	Market	Risk.

# Income	Taxes

We	are	subject	to	income	taxes	in	numerous	taxing	jurisdictions	worldwide.	Estimates	of	income	taxes	to	be	recorded	involve	interpretation	of	complex	tax	laws and	assessment	of	the	effects	of	foreign	taxes	on	our	U.S.	federal	income	taxes.

Uncertainty	exists	regarding	tax	positions	taken	in	previously	filed	tax	returns	which	remain	subject	to	examination,	along	with	positions	expected	to	be	taken	in future	returns.	We	provide	for	unrecognized	tax	benefits,	based	on	the	technical	merits,	when	it	is	more	likely	than	not	that	an	uncertain	tax	position	will	not	be sustained	upon	examination.	Adjustments	are	made	to	the	uncertain	tax	positions	when	facts	and	circumstances	change,	such	as	the	closing	of	a	tax	audit;	court proceedings;	changes	in	applicable	tax	laws,	including	tax	case	rulings	and	legislative	guidance;	or	expiration	of	the	applicable	statute	of	limitations.

On	December	22,	2017,	the	United	States	enacted	the	Tax	Cuts	and	Jobs	Act	("Tax	Reform	Legislation"),	which	made	significant	changes	to	U.S.	federal	income tax	law.	We	expect	that	certain	aspects	of	the	Tax	Reform	Legislation	will	positively	impact	our	future	after-tax	earnings	in	the	U.S.,	primarily	due	to	the	lower	federal statutory	tax	rate.	The	Tax	Reform	Legislation	is	a	comprehensive	bill	containing	several	other	provisions,	such	as	limitations	on	the	deductibility	of	interest	expense	and certain	executive	compensation,	that	are	not	expected	to	have	a	material	effect	on	our	results.	The	ultimate	impact	of	the	Tax	Reform	Legislation	may	differ	from	our estimates	due	to	changes	in	interpretations	and	assumptions	made	by	us,	as	well	as	additional	regulatory	guidance	that	may	be	issued.	Item	8.	Financial	Statements	and Supplementary	Data	–	Note	7	to	the	consolidated	financial	statements	for	further	disclosure	regarding	Tax	Reform	Legislation.

We	have	recorded	deferred	tax	assets	and	liabilities,	measured	at	enacted	tax	rates,	for	temporary	differences	between	book	basis	and	tax	basis,	tax	credit carryforwards	and	operating	loss	carryforwards.	In	accordance	with	U.S.	GAAP	accounting	standards,	we	routinely	assess	the	realizability	of	our	deferred	tax	assets	and reduce	such	assets,	to	the	expected	realizable	amount,	by	a	valuation	allowance	if	it	is	more	likely	than	not	that	some	portion	or	all	of	the	deferred	tax	assets	will	not	be realized.	In	assessing	the	need	for	additional	or	adjustments	to	existing	valuation	allowances,	we	consider	all	available	positive	and	negative	evidence.	Positive	evidence includes	reversals	of	temporary	differences,	forecasts	of	future	taxable	income,	assessment	of	future	business	assumptions	and	applicable	tax	planning	strategies	that	are prudent	and	feasible.	Negative	evidence	includes	losses	in	recent	years	as	well	as	the	forecasts	of	future	income	(loss)	in	the	realizable	period.	In	making	our	assessment regarding	valuation	allowances,	we	weight	the	evidence	based	on	objectivity.

We	base	our	future	taxable	income	estimates	on	projected	financial	information	which	we	believe	to	be	reasonably	likely	to	occur.	Numerous	judgments	and assumptions	are	inherent	in	the	estimation	of	future	taxable	income,	including	factors	such	as	future	operating	conditions	and	the	assessment	of	the	effects	of	foreign taxes	on	our	U.S.	federal	income	taxes.	Future	operating	conditions	can	be	affected	by	numerous	factors,	including	(i)	future	crude	oil	and	condensate,	NGLs	and	natural gas	prices,	(ii)	estimated	quantities	of	crude	oil	and	condensate,	NGLs	and	natural	gas,	(iii)	expected	timing	of	production,	and	(iv)	future	capital	requirements.	These assumptions	are	described	in	further	detail	above	regarding	our	impairment	assessment	of	long-lived	assets.	An	estimate	of	the	sensitivity	to	changes	in	assumptions resulting	in	future	taxable	income	calculations	is	not	practicable,	given	the	numerous	assumptions	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.	For	example,	the	impact	of	sustained	reduced	commodity prices	on	future	taxable	income	would	likely	be	partially	offset	by	lower	capital	expenditures.

Based	on	the	assumptions	and	judgments	described	above,	as	of	December	31,	2017,	we	reflect	a	valuation	allowance	in	our	Consolidated	Balance	Sheet	of	$926 million	against	our	gross	deferred	tax	assets	of	$2.0	billion	in	various	jurisdictions	in	which	we	operate.	Our	gross	deferred	tax	assets	consist	primarily	of	federal	U.S. operating	loss	carryforwards	of	$898	million,	which	will	expire	in	2035,	2036	and	2037.	Since	December	31,	2016,	we	have	maintained	a	full	valuation	allowance	on our	net	federal	deferred	tax	assets.	If	objective	negative	evidence	in	the	form	of	cumulative	losses	is	no	longer	present	and	additional	weight	is	given	to	subjective evidence	such	as	forecasted	projections	of	taxable	income	in	future	years,	we	would	adjust	the	amount	of	the	federal	deferred	tax	assets	considered	realizable	and	reduce the	provision	for	income	taxes	in	the	period	of	adjustment.

# Pension	and	Other	Postretirement	Benefit	Obligations

Accounting	for	pension	and	other	postretirement	benefit	obligations	involves	numerous	assumptions,	the	most	significant	of	which	relate	to	the	following:

•the	discount	rate	for	measuring	the	present	value	of	future	plan obligations;

•the	expected	long-term	return	on	plan assets;

•the	rate	of	future	increases	in	compensation	levels; and

•health	care	cost	projections.

We	develop	our	demographics	and	utilize	the	work	of	third-party	actuaries	to	assist	in	the	measurement	of	these	obligations.	We	have	selected	different	discount rates	for	our	U.S.	pension	plans	and	our	other	U.S.	postretirement	benefit	plans	due	to	the	different	projected	benefit	payment	patterns.	In	determining	the	assumed discount	rates,	our	methods	include	a

review	of	market	yields	on	high-quality	corporate	debt	and	use	of	our	third-party	actuary's	discount	rate	model.	This	model	calculates	an	equivalent	single	discount	rate for	the	projected	benefit	plan	cash	flows	using	a	yield	curve	derived	from	bond	yields.	The	yield	curve	represents	a	series	of	annualized	individual	spot	discount	rates from	0.5	to	99	years.	The	bonds	used	are	rated	AA	or	higher	by	a	recognized	rating	agency,	only	non-callable	bonds	are	included	and	outlier	bonds	(bonds	that	have	a yield	to	maturity	that	significantly	deviates	from	the	average	yield	within	each	maturity	grouping)	are	removed.	Each	issue	is	required	to	have	at	least	$250	million	par value	outstanding.	The	constructed	yield	curve	is	based	on	those	bonds	representing	the	50%	highest	yielding	issuances	within	each	defined	maturity	group.

Of	the	assumptions	used	to	measure	obligations	and	estimated	annual	net	periodic	benefit	cost	as	of	December	31,	the	discount	rate	has	the	most	significant	effect on	the	periodic	benefit	cost	reported	for	the	plans.	The	hypothetical	impacts	of	a	0.25%	change	in	the	discount	rates	of	3.55%	for	our	U.S.	pension	plans	and	3.54%	for our	other	U.S.	postretirement	benefit	plans	is	summarized	in	the	table	below:

|  | Impact	of	a	0.25%	Increase	in	Discount	Rate | Impact	of	a	0.25%	Increase	in	Discount	Rate | Impact	of	a	0.25%	Decrease	in	Discount	Rate | Impact	of	a	0.25%	Decrease	in	Discount	Rate |
| :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Obligation | Expense | Obligation | Expense |
| U.S.\tpension\tplans | $(4) | $— | $4 | $— |
| Other\tU.S.\tpostretirement\tbenefit\tplans | $(5) | $— | $5 | $— |

The	asset	rate	of	return	assumption	for	the	funded	U.S.	plan	considers	the	plan's	asset	mix	(currently	targeted	at	approximately	55%	equity	and	45%	other	fixed income	securities),	past	performance	and	other	factors.	Certain	components	of	the	asset	mix	are	modeled	with	various	assumptions	regarding	inflation,	debt	returns	and stock	yields.	Decreasing	the	6.50%	asset	rate	of	return	assumption	by	0.25%	would	not	have	a	significant	impact	on	our	defined	benefit	pension	expense.

Compensation	change	assumptions	are	based	on	historical	experience,	anticipated	future	management	actions	and	demographics	of	the	benefit	plans.	Health	care cost	trend	assumptions	are	developed	based	on	historical	cost	data,	the	near-term	outlook	and	an	assessment	of	likely	long-term	trends.

Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	17	to	the	consolidated	financial	statements	includes	detailed	information	about	the	assumptions	used to	calculate	the	components	of	our	annual	defined	benefit	pension	and	other	postretirement	plan	expense,	as	well	as	the	obligations	and	accumulated	other comprehensive	income	reported	on	the	consolidated	balance	sheets.

# Contingent	Liabilities

We	accrue	contingent	liabilities	for	environmental	remediation,	tax	deficiencies	related	to	operating	taxes,	as	well	as	tax	disputes	and	litigation	claims	when	such contingencies	are	probable	and	estimable.	Actual	costs	can	differ	from	estimates	for	many	reasons.	For	instance,	settlement	costs	for	claims	and	litigation	can	vary	from estimates	based	on	differing	interpretations	of	laws,	opinions	on	responsibility	and	assessments	of	the	amount	of	damages.	Similarly,	liabilities	for	environmental remediation	may	vary	from	estimates	because	of	changes	in	laws,	regulations	and	their	interpretation,	additional	information	on	the	extent	and	nature	of	site contamination	and	improvements	in	technology.	Our	in-house	legal	counsel	regularly	assesses	these	contingent	liabilities.	In	certain	circumstances	outside	legal	counsel is	utilized.

We	generally	record	losses	related	to	these	types	of	contingencies	as	other	operating	expense	or	general	and	administrative	expense	in	the	consolidated	statements	of income,	except	for	tax	contingencies	unrelated	to	income	taxes,	which	are	recorded	as	taxes	other	than	income.	For	additional	information	on	contingent	liabilities,	see Item	7.	Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	–	Management's	Discussion	and	Analysis	of	Environmental	Matters, Litigation	and	Contingencies.

An	estimate	of	the	sensitivity	to	net	income	if	other	assumptions	had	been	used	in	recording	these	liabilities	is	not	practical	because	of	the	number	of	contingencies that	must	be	assessed,	the	number	of	underlying	assumptions	and	the	wide	range	of	reasonably	possible	outcomes,	in	terms	of	both	the	probability	of	loss	and	the estimates	of	such	loss.

# Accounting	Standards	Not	Yet	Adopted

See	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	2	to	the	consolidated	financial	statements.

# Item	7A.	Quantitative	and	Qualitative	Disclosures	About	Market	Risk

We	are	exposed	to	market	risks	related	to	the	volatility	of	crude	oil	and	condensate,	NGLs,	and	natural	gas	prices	as	the	volatility	of	these	prices	continues	to	impact our	industry.	We	expect	commodity	prices	to	remain	volatile	and	unpredictable	in	the	future.	We	are	also	exposed	to	market	risks	related	to	changes	in	interest	rates	and foreign	currency	exchange	rates.	We	employ	various	strategies,	including	the	use	of	financial	derivative	instruments,	to	manage	the	risks	related	to	these	fluctuations. We	are	at	risk	for	changes	in	the	fair	value	of	all	of	our	derivative	instruments;	however,	such	risk	should	be	mitigated	by	price	or	rate	changes	related	to	the	underlying commodity	or	financial	transaction.	While	the	use	of	derivative	instruments	could	materially	affect	our	results	of	operations	in	particular	quarterly	or	annual	periods,	we believe	that	the	use	of	these	instruments	will	not	have	a	material	adverse	effect	on	our	financial	position	or	liquidity.

See	Item	8.	Financial	Statements	and	Supplementary	Data	–	Notes	13	and	14	to	the	consolidated	financial	statements	for	more	information	about	the	fair	value measurement	of	our	derivatives,	the	amounts	recorded	in	our	consolidated	balance	sheets	and	statements	of	income	and	the	related	notional	amounts.

# Commodity	Price	Risk

Our	strategy	is	to	obtain	competitive	prices	for	our	products	and	allow	operating	results	to	reflect	market	price	movements	dictated	by	supply	and	demand.	However, management	will	periodically	protect	prices	on	forecasted	sales	to	support	cash	flow	and	liquidity,	as	deemed	appropriate.	We	may	use	a	variety	of	commodity	derivative instruments,	including	futures,	forwards,	swaps	and	combinations	of	options,	as	part	of	an	overall	program	to	manage	commodity	price	risk	in	our	business.	Our consolidated	results	for	2017	and	2016	were	impacted	by	crude	oil	and	natural	gas	derivatives	related	to	a	portion	of	our	forecasted	United	States	E&P	sales.	The	table below	provides	a	summary	of	open	positions	as	of	December	31,	2017	and	the	weighted	average	price	for	those	contracts:

# Crude	Oil

|  | First	Quarter | Second<br>Quarter | Third<br>Quarter | Fourth<br>Quarter | First<br>Quarter | Second<br>Quarter |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Three-Way\tCollars\t(a) |  |  |  |  |  |  |
| Volume\t(Bbls/day) | 85,000 | 85,000 | 85,000 | 85,000 | 10,000 | 10,000 |
| Weighted\taverage\tprice\tper\tBbl: |  |  |  |  |  |  |
| Ceiling | $56.38 | $56.38 | $56.96 | $56.96 | $60.00 | $60.00 |
| Floor | $51.65 | $51.65 | $51.53 | $51.53 | $55.00 | $55.00 |
| Sold\tput | $45.00 | $45.00 | $44.65 | $44.65 | $47.00 | $47.00 |
| Swaps |  |  |  |  |  |  |
| Volume\t(Bbls/day) | 20,000 | 20,000 | — | — | — | — |
| Weighted\taverage\tprice\tper\tBbl | $55.12 | $55.12 | $— | $— | $— | $— |
| Basis\tSwaps\t(b) |  |  |  |  |  |  |
| Volume\t(Bbls/day) | 5,000 | 5,000 | 10,000 | 10,000 | — | — |
| Weighted\taverage\tprice\tper\tBbl | $(0.60) | $(0.60) | $(0.67) | $(0.67) | $— | $— |

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

# Natural	Gas

|  | First	Quarter | 2018<br>Second	Quarter | Third	Quarter | Fourth	Quarter |
| :--- | :--- | :--- | :--- | :--- |
| Three-Way\tCollars |  |  |  |  |
| Volume\t(MMBtu/day) | 200,000 | 160,000 | 160,000 | 160,000 |
| Weighted\taverage\tprice\tper\tMMBtu |  |  |  |  |
| Ceiling | $3.79 | $3.61 | $3.61 | $3.61 |
| Floor | $3.08 | $3.00 | $3.00 | $3.00 |
| Sold\tput | $2.55 | $2.50 | $2.50 | $2.50 |

The	following	table	provides	a	sensitivity	analysis	of	the	projected	incremental	effect	on	income	(loss)	from	operations	of	a	hypothetical	10%	change	in	NYMEX WTI	and	Henry	Hub	prices	on	our	open	commodity	derivative	instruments	as	of	December	31,	2017:

| (In	millions) | Hypothetical	Price	Increase<br>of	10% | Hypothetical	Price	Decrease<br>of	10% |
| :--- | :--- | :--- |
| Crude\toil\tderivatives | $(180) | $149 |
| Natural\tgas\tderivatives | (8) | 7 |
| \t\t\t\t\t\t\tTotal | $(188) | $156 |

# Interest	Rate	Risk

At	December	31,	2017,	our	portfolio	of	long-term	debt	was	substantially	comprised	of	fixed	rate	instruments.	Our	sensitivity	to	interest	rate	movements	and corresponding	changes	in	the	fair	value	of	our	fixed	rate	debt	portfolio	affects	our	results	of	operations	and	cash	flows	only	when	we	elect	to	repurchase	or	otherwise retire	fixed-rate	debt	at	prices	different	than	carrying	value.	Sensitivity	analysis	of	the	incremental	effect	of	a	hypothetical	10%	change	in	interest	rates	on	our	financial assets	and	liabilities	as	of	December	31,	2017,	is	provided	in	the	following	table.

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

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

(c) Excludes	capital	leases.

# Counterparty	Risk

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

# Item	8.	Financial	Statements	and	Supplementary	Data

# Index

| Management's	Responsibilities	for	Financial	Statements | 54 |
| :--- | :--- |
| Management's\tReport\ton\tInternal\tControl\tover\tFinancial\tReporting | 54 |
| Report\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm | 55 |
| Audited\tConsolidated\tFinancial\tStatements |  |
| Consolidated\tStatements\tof\tIncome | 57 |
| Consolidated\tStatements\tof\tComprehensive\tIncome | 58 |
| Consolidated\tBalance\tSheets | 59 |
| Consolidated\tStatements\tof\tCash\tFlows | 60 |
| Consolidated\tStatements\tof\tStockholders'\tEquity | 61 |
| Notes\tto\tConsolidated\tFinancial\tStatements | 62 |
| Select\tQuarterly\tFinancial\tData\t(Unaudited) | 98 |
| Supplementary\tInformation\ton\tOil\tand\tGas\tProducing\tActivities\t(Unaudited) | 99 |

# Management's	Responsibilities	for	Financial	Statements

# To	the	Stockholders	of	Marathon	Oil	Corporation:

The	accompanying	consolidated	financial	statements	of	Marathon	Oil	Corporation	and	its	consolidated	subsidiaries	("Marathon	Oil")	are	the	responsibility	of management	and	have	been	prepared	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States.	They	necessarily	include	some	amounts	that	are based	on	best	judgments	and	estimates.	The	financial	information	displayed	in	other	sections	of	this	Annual	Report	on	Form	10-K	is	consistent	with	these	consolidated financial	statements.

Marathon	Oil	seeks	to	assure	the	objectivity	and	integrity	of	its	financial	records	by	careful	selection	of	its	managers,	by	organization	arrangements	that	provide	an appropriate	division	of	responsibility	and	by	communications	programs	aimed	at	assuring	that	its	policies	and	methods	are	understood	throughout	the	organization.

The	Board	of	Directors	pursues	its	oversight	role	in	the	area	of	financial	reporting	and	internal	control	over	financial	reporting	through	its	Audit	and	Finance Committee.	This	Committee,	composed	solely	of	independent	directors,	regularly	meets	(jointly	and	separately)	with	the	independent	registered	public	accounting	firm, management	and	internal	auditors	to	monitor	the	proper	discharge	by	each	of	their	responsibilities	relative	to	internal	accounting	controls	and	the	consolidated	financial statements.

/s/	Lee	M.	Tillman

President	and	Chief	Executive	Officer

/s/	Dane	E.	Whitehead

Executive	Vice	President	and	Chief	Financial	Officer

# Management's	Report	on	Internal	Control	over	Financial	Reporting

Marathon	Oil's	management	is	responsible	for	establishing	and	maintaining	adequate	internal	control	over	financial	reporting	(as	defined	in	Rules	13(a)	–	15(f) under	the	Securities	Exchange	Act	of	1934).	Our	internal	control	over	financial	reporting	is	designed	to	provide	reasonable	assurance	regarding	the	reliability	of financial	reporting	and	the	preparation	of	the	consolidated	financial	statements.

Because	of	its	inherent	limitations,	internal	control	over	financial	reporting	may	not	prevent	or	detect	misstatements	and	even	when	determined	to	be	effective,	can only	provide	reasonable	assurance	with	respect	to	financial	statement	preparation	and	presentation.	Also,	projections	of	any	evaluation	of	effectiveness	to	future	periods are	subject	to	the	risk	that	controls	may	become	inadequate	because	of	changes	in	conditions	or	that	the	degree	of	compliance	with	the	policies	or	procedures	may deteriorate.

An	evaluation	of	the	design	and	effectiveness	of	our	internal	control	over	financial	reporting,	based	on	the	2013	framework	in	Internal	Control	–	Integrated Framework	issued	by	the	Committee	of	Sponsoring	Organizations	of	the	Treadway	Commission,	was	conducted	under	the	supervision	and	with	the	participation	of management,	including	our	Chief	Executive	Officer	and	Chief	Financial	Officer.	Based	on	the	results	of	this	evaluation,	Marathon	Oil's	management	concluded	that	its internal	control	over	financial	reporting	was	effective	as	of	December	31,	2017.

The	effectiveness	of	Marathon	Oil's	internal	control	over	financial	reporting	as	of	December	31,	2017	has	been	audited	by	PricewaterhouseCoopers	LLP,	an independent	registered	public	accounting	firm,	as	stated	in	their	report	which	is	included	herein.

# Report	of	Independent	Registered	Public	Accounting	Firm

To	the	Board	of	Directors	and	Stockholders	of	Marathon	Oil	Corporation:

# Opinions	on	the	Financial	Statements	and	Internal	Control	over	Financial	Reporting

We	have	audited	the	accompanying	consolidated	balance	sheets	of	Marathon	Oil	Corporation	and	its	subsidiaries	as	of	December	31,	2017	and	2016,	and	the related	consolidated	statements	of	income,	comprehensive	income,	cash	flows	and	stockholders'	equity	for	each	of	the	three	years	in	the	period	ended	December	31, 2017,	including	the	related	notes	(collectively	referred	to	as	the	"consolidated	financial	statements").	We	also	have	audited	the	Company's	internal	control	over	financial reporting	as	of	December	31,	2017,	based	on	criteria	established	in	Internal	Control	-	Integrated	Framework	(2013)	issued	by	the	Committee	of	Sponsoring Organizations	of	the	Treadway	Commission	(COSO).

In	our	opinion,	the	consolidated	financial	statements	referred	to	above	present	fairly,	in	all	material	respects,	the	financial	position	of	the	Company	as	of	December 31,	2017	and	2016,	and	the	results	of	their	operations	and	their	cash	flows	for	each	of	the	three	years	in	the	period	ended	December	31,	2017	in	conformity	with accounting	principles	generally	accepted	in	the	United	States	of	America.	Also	in	our	opinion,	the	Company	maintained,	in	all	material	respects,	effective	internal control	over	financial	reporting	as	of	December	31,	2017,	based	on	criteria	established	in	Internal	Control	-	Integrated	Framework	(2013)	issued	by	the	COSO.

# Basis	for	Opinions

The	Company's	management	is	responsible	for	these	consolidated	financial	statements,	for	maintaining	effective	internal	control	over	financial	reporting,	and	for	its assessment	of	the	effectiveness	of	internal	control	over	financial	reporting,	included	in	the	accompanying	Management's	Report	on	Internal	Control	over	Financial Reporting.	Our	responsibility	is	to	express	opinions	on	the	Company's	consolidated	financial	statements	and	on	the	Company's	internal	control	over	financial	reporting based	on	our	audits.	We	are	a	public	accounting	firm	registered	with	the	Public	Company	Accounting	Oversight	Board	(United	States)	("PCAOB")	and	are	required	to be	independent	with	respect	to	the	Company	in	accordance	with	the	U.S.	federal	securities	laws	and	the	applicable	rules	and	regulations	of	the	Securities	and	Exchange Commission	and	the	PCAOB.

We	conducted	our	audits	in	accordance	with	the	standards	of	the	PCAOB.	Those	standards	require	that	we	plan	and	perform	the	audits	to	obtain	reasonable assurance	about	whether	the	consolidated	financial	statements	are	free	of	material	misstatement,	whether	due	to	error	or	fraud,	and	whether	effective	internal	control over	financial	reporting	was	maintained	in	all	material	respects.

Our	audits	of	the	consolidated	financial	statements	included	performing	procedures	to	assess	the	risks	of	material	misstatement	of	the	consolidated	financial statements,	whether	due	to	error	or	fraud,	and	performing	procedures	that	respond	to	those	risks.	Such	procedures	included	examining,	on	a	test	basis,	evidence	regarding the	amounts	and	disclosures	in	the	consolidated	financial	statements.	Our	audits	also	included	evaluating	the	accounting	principles	used	and	significant	estimates	made by	management,	as	well	as	evaluating	the	overall	presentation	of	the	consolidated	financial	statements.	Our	audit	of	internal	control	over	financial	reporting	included obtaining	an	understanding	of	internal	control	over	financial	reporting,	assessing	the	risk	that	a	material	weakness	exists,	and	testing	and	evaluating	the	design	and operating	effectiveness	of	internal	control	based	on	the	assessed	risk.	Our	audits	also	included	performing	such	other	procedures	as	we	considered	necessary	in	the circumstances.	We	believe	that	our	audits	provide	a	reasonable	basis	for	our	opinions.

# Definition	and	Limitations	of	Internal	Control	over	Financial	Reporting

A	company's	internal	control	over	financial	reporting	is	a	process	designed	to	provide	reasonable	assurance	regarding	the	reliability	of	financial	reporting	and	the preparation	of	financial	statements	for	external	purposes	in	accordance	with	generally	accepted	accounting	principles.	A	company's	internal	control	over	financial reporting	includes	those	policies	and	procedures	that	(i)	pertain	to	the	maintenance	of	records	that,	in	reasonable	detail,	accurately	and	fairly	reflect	the	transactions	and dispositions	of	the	assets	of	the	company;	(ii)	provide	reasonable	assurance	that	transactions	are	recorded	as	necessary	to	permit	preparation	of	financial	statements	in accordance	with	generally	accepted	accounting	principles,	and	that	receipts	and	expenditures	of	the	company	are	being	made	only	in	accordance	with	authorizations	of management	and	directors	of	the	company;	and	(iii)	provide	reasonable	assurance	regarding	prevention	or	timely	detection	of	unauthorized	acquisition,	use,	or disposition	of	the	company's	assets	that	could	have	a	material	effect	on	the	financial	statements.

Because	of	its	inherent	limitations,	internal	control	over	financial	reporting	may	not	prevent	or	detect	misstatements.	Also,	projections	of	any	evaluation	of effectiveness	to	future	periods	are	subject	to	the	risk	that	controls	may	become	inadequate	because	of	changes	in	conditions,	or	that	the	degree	of	compliance	with	the policies	or	procedures	may	deteriorate.

# /s/	PricewaterhouseCoopers	LLP

We	have	served	as	the	Company's	auditor	since	1982.

# Consolidated	Statements	of	Income

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions,\texcept\tper\tshare\tdata) | 2017 | 2016 | 2015 |
| Revenues\tand\tother\tincome: |  |  |  |
| Sales\tand\tother\toperating\trevenues,\tincluding\trelated\tparty | $4,211 | $2,930 | $4,136 |
| Marketing\trevenues | 162 | 240 | 499 |
| Income\tfrom\tequity\tmethod\tinvestments | 256 | 175 | 145 |
| Net\tgain\t(loss)\ton\tdisposal\tof\tassets | 58 | 389 | 120 |
| Other\tincome | 78 | 53 | 53 |
| Total\trevenues\tand\tother\tincome | 4,765 | 3,787 | 4,953 |
| Costs\tand\texpenses: |  |  |  |
| Production | 706 | 712 | 979 |
| Marketing,\tincluding\tpurchases\tfrom\trelated\tparties | 168 | 245 | 500 |
| Other\toperating | 431 | 484 | 410 |
| Exploration | 409 | 323 | 971 |
| Depreciation,\tdepletion\tand\tamortization | 2,372 | 2,156 | 2,721 |
| Impairments | 229 | 67 | 721 |
| Taxes\tother\tthan\tincome | 183 | 151 | 216 |
| General\tand\tadministrative | 400 | 481 | 588 |
| Total\tcosts\tand\texpenses | 4,898 | 4,619 | 7,106 |
| Income\t(loss)\tfrom\toperations | (133) | (832) | (2,153) |
| Net\tinterest\tand\tother | (270) | (332) | (286) |
| Loss\ton\tearly\textinguishment\tof\tdebt | (51) | — | — |
| Income\t(loss)\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | (454) | (1,164) | (2,439) |
| Provision\t(benefit)\tfor\tincome\ttaxes | 376 | 923 | (738) |
| Income\t(loss)\tfrom\tcontinuing\toperations | (830) | (2,087) | (1,701) |
| Income\t(loss)\tfrom\tdiscontinued\toperations | (4,893) | (53) | (503) |
| Net\tincome\t(loss) | $(5,723) | $(2,140) | $(2,204) |
| Per\tShare\tData |  |  |  |
| Basic: |  |  |  |
| Income\t(loss)\tfrom\tcontinuing\toperations | $(0.97) | $(2.55) | $(2.51) |
| Income\t(loss)\tfrom\tdiscontinued\toperations | $(5.76) | $(0.06) | $(0.75) |
| Net\tincome\t(loss) | $(6.73) | $(2.61) | $(3.26) |
| Diluted: |  |  |  |
| Income\t(loss)\tfrom\tcontinuing\toperations | $(0.97) | $(2.55) | $(2.51) |
| Income\t(loss)\tfrom\tdiscontinued\toperations | $(5.76) | $(0.06) | $(0.75) |
| Net\tincome\t(loss) | $(6.73) | $(2.61) | $(3.26) |
| Dividends | $0.20 | $0.20 | $0.68 |
| Weighted\taverage\tshares: |  |  |  |
| Basic | 850 | 819 | 677 |
| Diluted | 850 | 819 | 677 |

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

# Consolidated	Statements	of	Comprehensive	Income

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 | 2015 |
| Net\tincome\t(loss) | $(5,723) | $(2,140) | $(2,204) |
| Other\tcomprehensive\tincome\t(loss) |  |  |  |
| Postretirement\tand\tpostemployment\tplans |  |  |  |
| Change\tin\tactuarial\tloss\tand\tother | 21 | 16 | 228 |
| Income\ttax\tprovision\t(benefit) | 7 | (4) | (86) |
| Postretirement\tand\tpostemployment\tplans,\tnet\tof\ttax | 28 | 12 | 142 |
| Derivative\thedges |  |  |  |
| Net\tunrecognized\tgain\t(loss) | (13) | 61 | — |
| Reclassification\tof\tgains\ton\tterminated\tderivative\thedges | (47) | — | — |
| Income\ttax\tprovision\t(benefit) | 21 | (22) | — |
| Derivative\thedges,\tnet\tof\ttax | (39) | 39 | — |
| Foreign\tcurrency\thedges |  |  |  |
| \t\t\tNet\trecognized\tloss\treclassified\tto\tdiscontinued\toperations | 34 | — | — |
| \t\t\tIncome\ttax\tprovision\t(benefit) | (4) | — | — |
| Foreign\tcurrency\thedges,\tnet\tof\ttax | 30 | — | — |
| Other,\tnet\tof\ttax | 2 | 1 | — |
| Other\tcomprehensive\tincome\t(loss) | 21 | 52 | 142 |
| Comprehensive\tincome\t(loss) | $(5,702) | $(2,088) | $(2,062) |

# Consolidated	Balance	Sheets

|  | December	31, |  |
| :--- | :--- | :--- |
| (In\tmillions,\texcept\tpar\tvalues\tand\tshare\tamounts) | 2017 | 2016 |
| Assets |  |  |
| Current\tassets: |  |  |
| Cash\tand\tcash\tequivalents | $563 | $2,488 |
| Receivables,\tless\treserve\tof\t$12\tand\t$6 | 1,082 | 748 |
| Notes\treceivable | 748 | — |
| Inventories | 126 | 136 |
| Other\tcurrent\tassets | 36 | 66 |
| Current\tassets\theld\tfor\tsale | 11 | 227 |
| Total\tcurrent\tassets | 2,566 | 3,665 |
| Equity\tmethod\tinvestments | 847 | 931 |
| Property,\tplant\tand\tequipment,\tless\taccumulated\tdepreciation, |  |  |
| depletion\tand\tamortization\tof\t$21,564\tand\t$20,255 | 17,665 | 16,727 |
| Goodwill | 115 | 115 |
| Other\tnoncurrent\tassets | 764 | 558 |
| Noncurrent\tassets\theld\tfor\tsale | 55 | 9,098 |
| Total\tassets | $22,012 | $31,094 |
| Liabilities |  |  |
| Current\tliabilities: |  |  |
| Accounts\tpayable | $1,395 | $967 |
| Payroll\tand\tbenefits\tpayable | 108 | 129 |
| Accrued\ttaxes | 177 | 94 |
| Other\tcurrent\tliabilities | 288 | 243 |
| Long-term\tdebt\tdue\twithin\tone\tyear | — | 686 |
| Current\tliabilities\theld\tfor\tsale | — | 121 |
| Total\tcurrent\tliabilities | 1,968 | 2,240 |
| Long-term\tdebt | 5,494 | 6,581 |
| Deferred\ttax\tliabilities | 833 | 769 |
| Defined\tbenefit\tpostretirement\tplan\tobligations | 362 | 345 |
| Asset\tretirement\tobligations | 1,428 | 1,602 |
| Deferred\tcredits\tand\tother\tliabilities | 217 | 225 |
| Noncurrent\tliabilities\theld\tfor\tsale | 2 | 1,791 |
| Total\tliabilities | 10,304 | 13,553 |
| Commitments\tand\tcontingencies |  |  |
| Stockholders'\tEquity |  |  |
| Preferred\tstock\t-\tno\tshares\tissued\tor\toutstanding\t(no\tpar\tvalue, |  |  |
| \t26\tmillion\tshares\tauthorized) | — | — |
| Common\tstock: |  |  |
|  | 937 | 937 |
| Held\tin\ttreasury,\tat\tcost\t–\t87\tmillion\tand\t90\tmillion\tshares | (3,325) | (3,431) |
| Additional\tpaid-in\tcapital | 7,379 | 7,446 |
| Retained\tearnings | 6,779 | 12,672 |
| Accumulated\tother\tcomprehensive\tloss | (62) | (83) |
| Total\tstockholders'\tequity | 11,708 | 17,541 |
| Total\tliabilities\tand\tstockholders'\tequity | $22,012 | $31,094 |

# Consolidated	Statements	of	Cash	Flows

|  | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 | 2015 |
| Increase\t(decrease)\tin\tcash\tand\tcash\tequivalents |  |  |  |
| Operating\tactivities: |  |  |  |
| Net\tincome\t(loss) | $(5,723) | $(2,140) | $(2,204) |
| Adjustments\tto\treconcile\tnet\tincome\t(loss)\tto\tnet\tcash\tprovided\tby\toperating\tactivities: |  |  |  |
| Discontinued\toperations | 4,893 | 53 | 503 |
| Depreciation,\tdepletion\tand\tamortization | 2,372 | 2,156 | 2,721 |
| Impairments | 229 | 67 | 721 |
| Exploratory\tdry\twell\tcosts\tand\tunproved\tproperty\timpairments | 323 | 220 | 867 |
| Net\t(gain)\tloss\ton\tdisposal\tof\tassets | (58) | (389) | (120) |
| Deferred\tincome\ttaxes | (61) | 828 | (804) |
| Net\t(gain)\tloss\ton\tderivative\tinstruments | (11) | 63 | (126) |
| Net\tcash\treceived\t(paid)\tin\tsettlement\tof\tderivative\tinstruments | 98 | 61 | 55 |
| Stock\tbased\tcompensation | 50 | 48 | 45 |
| Equity\tmethod\tinvestments,\tnet | 20 | 17 | 33 |
| Changes\tin: |  |  |  |
| Current\treceivables | (334) | 67 | 790 |
| Inventories | 10 | 64 | 25 |
| Current\taccounts\tpayable\tand\taccrued\tliabilities | 297 | (137) | (906) |
| All\tother\toperating,\tnet | (117) | (77) | (63) |
| Net\tcash\tprovided\tby\toperating\tactivities\tfrom\tcontinuing\toperations | 1,988 | 901 | 1,537 |
| Investing\tactivities: |  |  |  |
| Additions\tto\tproperty,\tplant\tand\tequipment | (1,974) | (1,204) | (3,485) |
| Acquisitions,\tnet\tof\tcash\tacquired | (1,891) | (902) | — |
| Disposal\tof\tassets,\tnet\tof\tcash\ttransferred\tto\tthe\tbuyer | 1,787 | 1,219 | 225 |
| Equity\tmethod\tinvestments\t-\treturn\tof\tcapital | 64 | 55 | 77 |
| Purchases\tof\tshort\tterm\tinvestments | — | — | (925) |
| Maturities\tof\tshort\tterm\tinvestments |  |  |  |
|  | — | — | 925 |
| All\tother\tinvesting,\tnet | (30) | (1) | 24 |
| Net\tcash\tused\tin\tinvesting\tactivities\tfrom\tcontinuing\toperations | (2,044) | (833) | (3,159) |
| Financing\tactivities: |  |  |  |
| Borrowings | 988 | — | 1,996 |
| Debt\trepayments | (2,764) | (1) | (1,069) |
| Debt\textinguishment\tcosts | (46) | — | — |
| Common\tstock\tissuance | — | 1,236 | — |
| Purchases\tof\tcommon\tstock | (11) | (6) | (11) |
| Dividends\tpaid | (170) | (162) | (460) |
| All\tother\tfinancing,\tnet | — | 1 | (5) |
| Net\tcash\tprovided\tby\t(used\tin)\tfinancing\tactivities | (2,003) | 1,068 | 451 |
| Cash\tFlow\tfrom\tDiscontinued\tOperations: |  |  |  |
| Operating\tactivities | 141 | 177 | 39 |
| Investing\tactivities | (13) | (41) | (43) |
| Changes\tin\tcash\tincluded\tin\tcurrent\tassets\theld\tfor\tsale | 2 | 100 | 90 |
| Net\tincrease\tin\tcash\tand\tcash\tequivalents\tof\tdiscontinued\toperations | 130 | 236 | 86 |
| Effect\tof\texchange\trate\tchanges\ton\tcash\tand\tcash\tequivalents: | 4 | (3) | (3) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (1,925) | 1,369 | (1,088) |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 2,488 | 1,119 | 2,207 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $563 | $2,488 | $1,119 |

# Consolidated	Statements	of	Stockholders'	Equity

# Total	Equity	of	Marathon	Oil	Stockholders

# Notes	to	Consolidated	Financial	Statements

# 1.	Summary	of	Principal	Accounting	Policies

We	are	a	global	energy	company	engaged	in	exploration,	production	and	marketing	of	crude	oil	and	condensate,	NGLs	and	natural	gas;	as	well	as	production	and marketing	of	products	manufactured	from	natural	gas,	such	as	LNG	and	methanol,	in	E.G.

Basis	of	presentation	and	principles	applied	in	consolidation	–	These	consolidated	financial	statements	include	the	accounts	of	our	controlled	subsidiaries. Investments	in	unincorporated	joint	ventures	and	undivided	interests	in	certain	operating	assets	are	consolidated	on	a	pro	rata	basis.

Equity	method	investments	–	Investments	in	entities	over	which	we	have	significant	influence,	but	not	control,	are	accounted	for	using	the	equity	method	of accounting.	This	includes	entities	in	which	we	hold	majority	ownership	but	the	minority	stockholders	have	substantive	participating	rights	in	the	investee.	Income	from equity	method	investments	represents	our	proportionate	share	of	net	income	generated	by	the	equity	method	investees	and	is	reflected	in	revenue	and	other	income	in our	consolidated	statements	of	income.	Equity	method	investments	are	included	as	noncurrent	assets	on	the	consolidated	balance	sheet.

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	and	is	other	than	temporary,	the	carrying	value	of	the	equity	method	investment	is	written	down	to	fair	value,	and	the	amount	of	the	write-down is	included	in	income.	Differences	in	the	basis	of	the	investments	and	the	separate	net	asset	value	of	the	investees,	if	any,	are	amortized	into	income	over	the	remaining useful	lives	of	the	underlying	assets,	except	for	the	excess	related	to	goodwill.

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

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

As	discussed	above	we	closed	on	the	sale	of	our	Canadian	business,	which	includes	our	Oil	Sands	Mining	segment	and	exploration	stage	in-situ	leases	in	the	second quarter	2017.	The	characteristics	and	composition	of	our	North	America	E&P	reporting	segment	remained	unchanged	and	there	was	no	effect	on	previously	reported segment	information.	As	all	our	remaining	properties	within	the	segment	are	located	within	the	United	States,	we	concluded	that	our	North	America	E&P	segment would	be	renamed	United	States	E&P	segment,	effective	June	30,	2017.	During	the	year,	no	changes	occurred	to	our	International	E&P	segment.	See	Note	6	for	further information	on	our	reportable	segments.

Use	of	estimates	–	The	preparation	of	financial	statements	in	accordance	with	U.S.	GAAP	requires	management	to	make	estimates	and	assumptions	that	affect	the reported	amounts	of	assets	and	liabilities	and	the	disclosure	of	contingent	assets	and	liabilities	as	of	the	date	of	the	consolidated	financial	statements	and	the	reported amounts	of	revenues	and	expenses	during	the	respective	reporting	periods.

Estimated	quantities	of	crude	oil	and	condensate,	NGLs	and	natural	gas	reserves	is	a	significant	estimate	that	requires	judgment.	All	of	the	reserve	data	included	in this	Form	10-K	are	estimates.	Reservoir	engineering	is	a	subjective	process	of	estimating	underground	accumulations	of	crude	oil	and	condensate,	NGLs	and	natural	gas. There	are	numerous	uncertainties	inherent	in	estimating	quantities	of	proved	crude	oil	and	condensate,	NGLs	and	natural	gas	reserves.	The	accuracy	of	any	reserves estimate	is	a	function	of	the	quality	of	available	data	and	of	engineering	and	geological	interpretation	and	judgment.	As	a	result,	reserve	estimates	may	be	different	from the	quantities	of	crude	oil	and	condensate,	NGLs	and	natural	gas	that	are	ultimately	recovered.	See	Supplementary	Data	-	Supplementary	Information	on	Oil	and	gas Producing	Activities	for	further	detail.

Other	items	subject	to	estimates	and	assumptions	include	the	carrying	amounts	of	property,	plant	and	equipment,	asset	retirement	obligations,	goodwill,	valuation	of derivative	instruments	and	valuation	allowances	for	deferred	income	tax	assets,	among	others.	Although	we	believe	these	estimates	are	reasonable,	actual	results	could differ	from	these	estimates.

Foreign	currency	transactions	–	The	U.S.	dollar	is	the	functional	currency	of	our	foreign	operating	subsidiaries.	Foreign	currency	transaction	gains	and	losses	are included	in	net	income.

Revenue	recognition	–	Revenues	are	recognized	when	products	are	shipped	or	services	are	provided	to	customers,	title	is	transferred,	the	sales	price	is	fixed	or determinable	and	collectability	is	reasonably	assured.	We	follow	the	sales	method	of

accounting	for	crude	oil	and	natural	gas	production	imbalances	and	would	recognize	a	liability	if	our	existing	proved	reserves	were	not	adequate	to	cover	an	imbalance. Imbalances	have	not	been	significant	in	the	periods	presented.

In	the	lower	48	states	of	the	U.S.,	production	volumes	of	crude	oil	and	condensate,	NGLs	and	natural	gas	are	generally	sold	immediately	and	transported	to	market. In	international	locations,	liquid	hydrocarbon	production	volumes	may	be	stored	as	inventory	and	sold	at	a	later	time.

Cash	and	cash	equivalents	–	Cash	and	cash	equivalents	include	cash	on	hand	and	on	deposit	and	investments	in	highly	liquid	debt	instruments	with	original maturities	of	three	months	or	less.

Short-term	Investments	-	Our	short-term	investments	are	comprised	of	bank	time	deposits	with	original	maturities	of	greater	than	three	months	but	less	than	twelve months.	They	are	classified	as	held-to-maturity	investments,	which	are	recorded	at	amortized	cost.

Accounts	receivable	–	The	majority	of	our	receivables	are	from	joint	interest	owners	in	properties	we	operate	or	from	purchasers	of	commodities,	both	of	which	are recorded	at	invoiced	amounts	and	do	not	bear	interest.	We	often	have	the	ability	to	withhold	future	revenue	disbursements	to	recover	any	non-payment	of	joint	interest billings.	We	conduct	credit	reviews	of	commodity	purchasers	prior	to	making	commodity	sales	to	new	customers	or	increasing	credit	for	existing	customers.	Based	on these	reviews,	we	may	require	a	standby	letter	of	credit	or	a	financial	guarantee.	We	routinely	assess	the	collectability	of	receivable	balances	to	determine	if	the	amount of	the	reserve	in	allowance	for	doubtful	accounts	is	sufficient.

Notes	receivable	-	We	hold	two	notes	receivable	from	the	sale	of	our	Canadian	business,	which	closed	in	the	second	quarter	of	2017.	Both	notes	receivable	were initially	recorded	at	fair	value	and	are	reported	at	amortized	cost.	The	notes	receivable	are	evaluated	for	collectability	on	an	individual	basis	each	reporting	period,	based on	the	financial	condition	of	the	debtor.	No	allowances	for	credit	losses	were	established	for	the	notes	receivable	as	of	December	31,	2017.	See	Note	5	for	additional discussion.

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.

We	may	enter	into	a	contract	to	sell	a	particular	quantity	and	quality	of	crude	oil	at	a	specified	location	and	date	to	a	particular	counterparty,	and	simultaneously agree	to	buy	a	particular	quantity	and	quality	of	the	same	commodity	at	a	specified	location	on	the	same	or	another	specified	date	from	the	same	counterparty.	We account	for	such	matching	buy/sell	arrangements	as	exchanges	of	inventory.

Derivative	instruments	–	We	may	use	derivatives	to	manage	a	portion	of	our	exposure	to	commodity	price	risk,	commodity	locational	risk,	foreign	currency	risk and	interest	rate	risk.	All	derivative	instruments	are	recorded	at	fair	value.	Commodity	derivatives	and	interest	rate	swaps	are	reflected	on	our	consolidated	balance	sheet on	a	net	basis	by	counterparty,	as	they	are	governed	by	master	netting	agreements.	Cash	flows	related	to	derivatives	used	to	manage	commodity	price	risk,	foreign currency	risk	and	interest	rate	risk	are	classified	in	operating	activities.	Our	derivative	instruments	contain	no	significant	contingent	credit	features.

Fair	value	hedges	–	We	may	use	interest	rate	swaps	to	manage	our	exposure	to	interest	rate	risk	associated	with	fixed	interest	rate	debt	in	our	portfolio.	Changes	in the	fair	values	of	both	the	hedged	item	and	the	related	derivative	are	recognized	immediately	in	net	income	with	an	offsetting	effect	included	in	the	basis	of	the	hedged item.	The	net	effect	is	to	report	in	net	income	the	extent	to	which	the	hedge	is	not	effective	in	achieving	offsetting	changes	in	fair	value.

Cash	flow	hedges	–	We	may	use	interest	rate	derivative	instruments	to	manage	the	risk	of	interest	rate	changes	during	the	period	prior	to	anticipated	borrowings	and designate	them	as	cash	flow	hedges.	Derivative	instruments	designated	as	cash	flow	hedges	are	linked	to	specific	assets	and	liabilities	or	to	specific	firm	commitments	or forecasted	transactions.	The	effective	portion	of	changes	in	the	fair	value	of	a	qualifying	cash	flow	hedge	are	recorded	in	other	comprehensive	income	until	the	hedged item	is	reclassified	to	net	income	when	the	underlying	forecasted	transaction	is	recognized	in	net	income.	Ineffective	portions	of	a	cash	flow	hedge's	change	in	fair	value are	recognized	currently	within	net	interest	and	other	on	the	consolidated	statements	of	income.	However,	if	it	is	determined	that	the	likelihood	of	the	original	forecasted transaction	occurring	is	no	longer	probable,	the	entire	accumulated	gain	or	loss	recognized	in	other	comprehensive	income	is	immediately	reclassified	into	net	income.

Derivatives	not	designated	as	hedges	–	Derivatives	that	are	not	designated	as	hedges	may	include	commodity	derivatives	used	primarily	to	manage	price	and locational	risks	on	the	forecasted	sale	of	crude	oil	and	natural	gas	that	we	produce.	Changes	in	the	fair	value	of	derivatives	not	designated	as	hedges	are	recognized immediately	in	net	income.

Concentrations	of	credit	risk	–	All	of	our	financial	instruments,	including	derivatives,	involve	elements	of	credit	and	market	risk.	The	most	significant	portion	of our	credit	risk	relates	to	nonperformance	by	counterparties.	The	counterparties	to	our	financial	instruments	consist	primarily	of	major	financial	institutions	and companies	within	the	energy	industry.	To	manage	counterparty	risk	associated	with	financial	instruments,	we	select	and	monitor	counterparties	based	on	our	assessment of	their	financial	strength	and	on	credit	ratings,	if	available.	Additionally,	we	limit	the	level	of	exposure	with	any	single	counterparty.

Fair	value	transfer	–	We	recognize	transfers	between	levels	of	the	fair	value	hierarchy	as	of	the	end	of	the	reporting	period.	If	significant	transfers	occur,	they would	be	disclosed	in	Note	14	to	the	consolidated	financial	statements.

Property,	plant	and	equipment	–	We	use	the	successful	efforts	method	of	accounting	for	oil	and	gas	producing	activities.

Property	acquisition	costs	–	Costs	to	acquire	mineral	interests	in	oil	and	natural	gas	properties,	to	drill	exploratory	wells	in	progress	and	those	that	find	proved reserves,	and	to	drill	development	wells	are	capitalized.	Costs	to	drill	exploratory	wells	that	do	not	find	proved	reserves,	geological	and	geophysical	costs	and	costs	of carrying	and	retaining	unproved	properties	are	expensed.	Costs	incurred	for	exploratory	wells	that	find	reserves	but	cannot	yet	be	classified	as	proved	are	capitalized	if (1)	the	well	has	found	a	sufficient	quantity	of	reserves	to	justify	its	completion	as	a	producing	well	and	(2)	we	are	making	sufficient	progress	assessing	the	reserves	and the	economic	and	operating	viability	of	the	project.	The	status	of	suspended	exploratory	well	costs	is	monitored	continuously	and	reviewed	at	least	quarterly.

Depreciation,	depletion	and	amortization	–	Capitalized	costs	to	acquire	oil	and	natural	gas	properties	are	depreciated	and	depleted	on	a	units-of-production	basis based	on	estimated	proved	reserves.	Capitalized	costs	of	exploratory	wells	and	development	costs	are	depreciated	and	depleted	on	a	units-of-production	basis	based	on estimated	proved	developed	reserves.	Support	equipment	and	other	property,	plant	and	equipment	related	to	oil	and	gas	producing	activities,	as	well	as	property,	plant and	equipment	unrelated	to	oil	and	gas	producing	activities,	are	recorded	at	cost	and	depreciated	on	a	straight-line	basis	over	the	estimated	useful	lives	of	the	assets	as summarized	below.

Impairments	–	We	evaluate	our	oil	and	gas	producing	properties,	including	capitalized	costs	of	exploratory	wells	and	development	costs,	for	impairment	of	value whenever	events	or	changes	in	circumstances	indicate	that	the	carrying	amount	of	an	asset	may	not	be	recoverable.	If	the	sum	of	the	expected	undiscounted	future	cash flows	from	the	use	of	the	asset	and	its	eventual	disposition	is	less	than	the	carrying	amount	of	the	asset,	an	impairment	loss	is	recognized	based	on	the	fair	value	of	the asset.	Oil	and	gas	producing	properties	are	reviewed	for	impairment	on	a	field-by-field	basis	or,	in	certain	instances,	by	logical	grouping	of	assets	if	there	is	significant shared	infrastructure	or	contractual	terms	that	cause	economic	interdependency	amongst	separate,	discrete	fields.	Oil	and	gas	producing	properties	deemed	to	be impaired	are	written	down	to	their	fair	value,	as	determined	by	discounted	future	net	cash	flows	or,	if	available,	comparable	market	value.	We	evaluate	our	unproved property	investment	and	record	impairment	based	on	time	or	geologic	factors.	Information	such	as	drilling	results,	reservoir	performance,	seismic	interpretation	or	future plans	to	develop	acreage	is	also	considered.	When	unproved	property	investments	are	deemed	to	be	impaired,	this	amount	is	reported	in	exploration	expenses	in	our consolidated	statements	of	income.

Dispositions	–	When	property,	plant	and	equipment	depreciated	on	an	individual	basis	is	sold	or	otherwise	disposed	of,	any	gains	or	losses	are	reflected	in	net	gain (loss)	on	disposal	of	assets	in	our	consolidated	statements	of	income.	Gains	on	the	disposal	of	property,	plant	and	equipment	are	recognized	when	earned,	which	is generally	at	the	time	of	closing.	If	a	loss	on	disposal	is	expected,	such	losses	are	recognized	either	when	the	assets	are	classified	as	held	for	sale,	or	are	measured	using	a probability	weighted	income	approach	based	on	both	the	anticipated	sales	price	and	a	held-for-use	model	depending	on	timing	of	the	sale.	Proceeds	from	the	disposal	of property,	plant	and	equipment	depreciated	on	a	group	basis	are	credited	to	accumulated	depreciation,	depletion	and	amortization	with	no	immediate	effect	on	net	income until	net	book	value	is	reduced	to	zero.

Goodwill	–	Goodwill	represents	the	excess	of	the	purchase	price	over	the	estimated	fair	value	of	the	net	assets	acquired	in	the	acquisition	of	a	business.	Such goodwill	is	not	amortized,	but	rather	is	tested	for	impairment	annually	and	when	events	or	changes	in	circumstances	indicate	that	the	fair	value	of	a	reporting	unit	with goodwill	has	been	reduced	below	carrying	value.	The	impairment	test	requires	allocating	goodwill	and	other	assets	and	liabilities	to	a	reporting	unit.	The	fair	value	of	a reporting	unit	is	determined	and	compared	to	the	book	value	of	the	reporting	unit.	If	the	fair	value	of	the	reporting	unit	is	less	than	the	book	value,	including	goodwill, then	the	recorded	goodwill	is	impaired	to	its	implied	fair	value	with	a	charge	to	impairments.

Major	maintenance	activities	–	Costs	for	planned	major	maintenance	are	expensed	in	the	period	incurred	and	can	include	the	costs	of	contractor	repair	services, materials	and	supplies,	equipment	rentals	and	our	labor	costs.

Environmental	costs	–	We	provide	for	remediation	costs	and	penalties	when	the	responsibility	to	remediate	is	probable	and	the	amount	of	associated	costs	can	be reasonably	estimated.	The	timing	of	remediation	accruals	coincides	with	completion	of	a	feasibility	study	or	the	commitment	to	a	formal	plan	of	action.	Remediation liabilities	are	accrued	based	on	estimates	of	known	environmental	exposure	and	are	discounted	when	the	estimated	amounts	are	reasonably	fixed	or	reliably determinable.	Environmental	expenditures	are	capitalized	only	if	the	costs	mitigate	or	prevent	future	contamination	or	if	the	costs	improve	the	environmental	safety	or efficiency	of	the	existing	assets.

Asset	retirement	obligations	–	The	fair	value	of	asset	retirement	obligations	is	recognized	in	the	period	in	which	the	obligations	are	incurred	if	a	reasonable	estimate of	fair	value	can	be	made.	Our	asset	retirement	obligations	primarily	relate	to	the	abandonment	of	oil	and	gas	producing	facilities.	Asset	retirement	obligations	for	such facilities	include	costs	to	dismantle	and	relocate	or	dispose	of	production	platforms,	gathering	systems,	wells	and	related	structures	and	restoration	costs	of	land	and seabed,	including	those	leased.	Estimates	of	these	costs	are	developed	for	each	property	based	on	the	type	of	production	facilities	and	equipment,	depth	of	water, reservoir	characteristics,	depth	of	the	reservoir,	market	demand	for	equipment,	currently	available	procedures	and	consultations	with	construction	and	engineering professionals.

Inflation	rates	and	credit-adjusted-risk-free	interest	rates	are	used	to	estimate	the	fair	value	of	asset	retirement	obligations.	Depreciation	of	capitalized	asset retirement	costs	and	accretion	of	asset	retirement	obligations	are	recorded	over	time.	Depreciation	is	generally	determined	on	a	units-of-production	basis	based	on estimated	proved	developed	reserves	for	oil	and	gas	production	facilities,	while	accretion	of	the	liability	occurs	over	the	useful	lives	of	the	assets.

Deferred	income	taxes	–	Deferred	tax	assets	and	liabilities,	measured	at	enacted	tax	rates,	are	recognized	for	the	estimated	future	tax	consequences	attributable	to differences	between	the	financial	statement	carrying	amounts	of	assets	and	liabilities	and	their	tax	bases	as	reported	in	our	filings	with	the	respective	taxing	authorities. We	routinely	assess	the	realizability	of	our	deferred	tax	assets	based	on	several	interrelated	factors	and	reduce	such	assets	by	a	valuation	allowance	if	it	is	more	likely than	not	that	some	portion	or	all	of	the	deferred	tax	assets	will	not	be	realized.	These	factors	include	whether	we	are	in	a	cumulative	loss	position	in	recent	years,	our reversal	of	temporary	differences,	and	our	expectation	to	generate	sufficient	future	taxable	income.	We	use	the	liability	method	in	determining	our	provision	and liabilities	for	our	income	taxes,	under	which	current	and	deferred	tax	liabilities	and	assets	are	recorded	in	accordance	with	enacted	tax	laws	and	rates.

Stock-based	compensation	arrangements	–	The	fair	value	of	stock	options	is	estimated	on	the	date	of	grant	using	the	Black-Scholes	option	pricing	model.	The model	employs	various	assumptions,	based	on	management's	best	estimates	at	the	time	of	grant,	which	impact	the	calculation	of	fair	value	and	ultimately,	the	amount	of expense	that	is	recognized	over	the	life	of	the	stock	option	award.	Of	the	required	assumptions,	the	expected	volatility	of	our	stock	price	and	the	stock	price	in	relation	to the	strike	price	have	the	most	significant	impact	on	the	fair	value	calculation.	We	have	utilized	historical	data	and	analyzed	current	information	which	reasonably support	these	assumptions.

The	fair	value	of	our	restricted	stock	awards	and	common	stock	units	is	determined	based	on	the	market	value	of	our	common	stock	on	the	date	of	grant.	Unearned stock-based	compensation	is	charged	to	stockholders'	equity	when	restricted	stock	awards	are	granted.

The	fair	value	of	our	stock-based	performance	units	is	estimated	using	the	Monte	Carlo	simulation	method.	Since	these	awards	are	settled	in	cash	at	the	end	of	a defined	performance	period,	they	are	classified	as	a	liability	and	are	re-measured	quarterly	until	settlement.

Our	stock-based	compensation	expense	is	recognized	based	on	management's	best	estimate	of	the	awards	that	are	expected	to	vest,	using	the	straight-line	attribution method	for	all	service-based	awards	with	a	graded	vesting	feature.	If	actual	forfeiture	results	are	different	than	expected,	adjustments	to	recognized	compensation expense	may	be	required	in	future	periods.

During	the	first	quarter	of	2017,	we	adopted	the	accounting	standards	update	issued	by	the	FASB	in	March	2016	pertaining	to	share-based	payment	transactions.	As a	result	of	this	adoption,	all	cash	payments	for	withheld	shares	made	to	taxing	authorities	on	the	employees'	behalf	are	presented	within	the	financing	activities	section instead	of	the	operating	activities	section	of	the	statement	of	cash	flows.	We	elected	the	retrospective	method	for	adoption	of	this	update	and	the	change	in	the	statement of	cash	flows	is	not	material	for	the	years	ended	December	31,	2016	or	2015.	Excess	tax	benefits	were	classified	as	an	operating	activity	within	the	statement	of	cash flows	on	a	prospective	basis	beginning	in	2017;	as	such,	prior	periods	were	not	adjusted.	See	Note	2	for	additional	discussion.

# 2.	Accounting	Standards

# Not	Yet	Adopted

In	May	2014	and	August	2015,	the	FASB	issued	an	update	that	supersedes	the	existing	revenue	recognition	requirements.	This	standard	includes	a	five-step	revenue recognition	model	to	depict	the	transfer	of	goods	or	services	to	customers	in	an	amount	that	reflects	the	consideration	to	which	the	company	expects	to	be	entitled	in exchange	for	those	goods	or	services.	Among	other	things,	the	standard	requires	enhanced	disclosures	about	revenue,	provides	guidance	for	transactions	that	were	not previously	addressed	comprehensively	and	improves	guidance	for	multiple-element	arrangements.	This	standard	is	effective	for	us	in	the	first	quarter	of	2018	and	shall be	applied	retrospectively	to	each	prior	reporting	period	presented	("full	retrospective	method")	or	with	the	cumulative	effect	of	initially	applying	the	update	recognized at	the	date	of	initial	application	("modified	retrospective	method").	We	will	adopt	this	new	standard	in	the	first	quarter	of	2018	using	the	modified	retrospective	method. The	adoption	of	this	ASU	will	not	have	a	material	impact	on	our	consolidated	results	of	operations,	financial	position	or	cash	flows.	However,	as	a	result	of	this	standard we	will	change	our	presentation	of	marketing	revenues	and	marketing	expenses	from	the	current	gross	presentation	to	a	net	presentation	for	a	portion	of	our	international contracts.	For	the	years	ended	December	31,	2017	and	2016,	we	expect	the	impact	of	this	change	to	be	a	reduction	of	approximately	$130	million	and	$100	million, respectively,	in	marketing	revenue	and	expenses	in	our	consolidated	results	of	operations.	We	will	provide	the	disclosures	required	by	this	standard,	such	as	key	sources of	revenues	from	transactions	with	customers,	disaggregated	revenue	information,	and	significant	accounting	estimates	and	judgments,	beginning	in	the	first	quarter	of 2018.

In	March	2017,	the	FASB	issued	a	new	accounting	standards	update	that	will	change	how	employers	that	sponsor	defined	pension	and/or	other	postretirement benefit	plans	present	the	net	periodic	benefit	cost	in	the	income	statement.	Employers	will	present	the	service	cost	component	of	net	periodic	benefit	cost	in	the	same income	statement	line	item(s)	as	other	employee	compensation	costs	arising	from	services	rendered	during	the	period.	Only	the	service	cost	component	will	be	eligible for	capitalization	in	assets.	We	will	adopt	this	standard	in	the	first	quarter	of	2018	on	a	retrospective	basis,	and	will	reclassify	certain	amounts	from	general	and administrative	expense	to	the	exploration,	production	and	our	new	other	net	periodic	benefit	costs	expense	categories	on	our	consolidated	statements	of	income.

In	August	2016,	the	FASB	issued	a	new	accounting	standards	update	which	seeks	to	reduce	the	existing	diversity	in	practice	in	how	certain	transactions	are classified	in	the	statement	of	cash	flows.	We	will	adopt	this	standard	during	the	first	quarter	of	2018	on	a	retrospective	basis	with	no	significant	impact	on	our consolidated	results	of	operations,	financial	position	or	cash	flows.

In	November	2016,	the	FASB	issued	a	new	accounting	standards	update	that	requires	entities	to	show	the	changes	in	the	total	of	cash,	cash	equivalents	and restricted	cash	in	the	statement	of	cash	flows.	As	a	result,	entities	will	no	longer	present	transfers	between	cash	and	cash	equivalents	and	restricted	cash	in	the	statement of	cash	flows.	When	cash,	cash	equivalents,	and	restricted	cash	are	presented	in	more	than	one	line	item	on	the	balance	sheet,	the	standard	requires	a	reconciliation	of	the totals	in	the	statement	of	cash	flows	to	the	related	captions	in	the	balance	sheet.	This	reconciliation	can	be	presented	either	on	the	face	of	the	statement	of	cash	flows	or	in the	notes	to	the	financial	statements.	We	will	adopt	this	standard	in	the	first	quarter	of	2018	on	a	retrospective	basis	and	do	not	expect	the	adoption	of	this	standard	to have	a	significant	impact	on	our	consolidated	results	of	operations,	financial	position	or	cash	flows.

In	February	2017,	the	FASB	issued	a	new	accounting	standards	update	that	clarifies	the	accounting	for	the	sale	or	transfer	of	nonfinancial	assets	and	in	substance nonfinancial	assets	to	noncustomers,	including	partial	sales.	The	standard	also	clarifies	that	the	derecognition	of	all	businesses	(except	those	related	to	conveyances	of	oil and	gas	mineral	rights	or	contracts	with	customers)	should	be	accounted	for	in	accordance	with	the	derecognition	and	deconsolidation	guidance	in	Subtopic	810-10.	We will	adopt	this	standard	in	the	first	quarter	of	2018	using	the	modified	retrospective	approach	with	no	material	impact	on	our	consolidated	results	of	operations,	financial position	or	cash	flows.

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

In	January	2016,	the	FASB	issued	an	accounting	standards	update	that	addresses	certain	aspects	of	recognition,	measurement,	presentation,	and	disclosure	of financial	instruments.	We	plan	to	adopt	this	standard	in	the	first	quarter	of	2018

and	do	not	expect	the	adoption	of	this	standard	to	have	a	significant	impact	on	our	consolidated	results	of	operations,	financial	position	or	cash	flows.

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

In	August	2017,	the	FASB	issued	a	new	accounting	standards	update	that	amends	the	hedge	accounting	model	to	enable	entities	to	hedge	certain	financial	and nonfinancial	risk	attributes	previously	not	allowed.	The	amendment	also	reduces	the	overall	complexity	of	documenting,	assessing	and	measuring	hedge	effectiveness. This	standard	is	effective	for	us	in	the	first	quarter	of	2019.	Early	adoption	is	permitted	in	any	interim	or	annual	period.	The	amendment	mandates	modified	retrospective adoption	when	accounting	for	hedge	relationships	in	effect	as	of	the	adoption	date.	We	are	evaluating	the	provisions	of	this	accounting	standards	update,	including transition	requirements,	and	are	assessing	the	impact	it	may	have	on	our	results	of	operations,	financial	position,	or	cash	flows.

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

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

# Recently	Adopted

In	March	2016,	the	FASB	issued	a	new	accounting	standards	update	that	changes	several	aspects	of	accounting	for	share-based	payment	transactions,	including	a requirement	to	recognize	all	excess	tax	benefits	and	tax	deficiencies	as	income	tax	expense	or	benefit	in	the	income	statement,	classification	of	awards	as	either	equity	or liabilities,	and	classification	on	the	statement	of	cash	flows.	This	standard	was	effective	for	us	in	the	first	quarter	of	2017.	The	new	standard	requires	a	company	to	make a	policy	election	on	how	it	accounts	for	forfeitures;	we	elected	to	continue	estimating	forfeitures	using	the	same	methodology	practiced	prior	to	adoption	of	this	standard. See	Note	1	for	the	impact	this	standard	has	on	the	presentation	of	our	financial	statements.

In	July	2015,	the	FASB	issued	an	update	that	requires	an	entity	to	measure	inventory	at	the	lower	of	cost	or	net	realizable	value.	This	excludes	inventory	measured using	LIFO	or	the	retail	inventory	method.	This	standard	was	effective	for	us	in	the	first	quarter	of	2017,	and	was	applied	prospectively.	Adoption	of	this	standard	did not	have	a	significant	impact	on	our	consolidated	results	of	operations,	financial	position	or	cash	flows.

# 3.				Income	(Loss)	per	Common	Share

Basic	income	(loss)	per	share	is	based	on	the	weighted	average	number	of	common	shares	outstanding.	Diluted	income	per	share	assumes	exercise	of	stock	options in	all	years,	provided	the	effect	is	not	antidilutive.	The	per	share	calculations	below	exclude	11	million,	13	million	and	13	million	stock	options	in	2017,	2016	and	2015 that	were	antidilutive.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions,\texcept\tper\tshare\tdata) | 2017 | 2016 | 2015 |
| Income\t(loss)\tfrom\tcontinuing\toperations | $(830) | $(2,087) | $(1,701) |
| Income\t(loss)\tfrom\tdiscontinued\toperations | (4,893) | (53) | (503) |
| Net\tincome\t(loss) | $(5,723) | $(2,140) | $(2,204) |
| Weighted\taverage\tcommon\tshares\toutstanding | 850 | 819 | 677 |
| Per\tbasic\tshare: |  |  |  |
| Income\t(loss)\tfrom\tcontinuing\toperations | $(0.97) | $(2.55) | $(2.51) |
| Income\t(loss)\tfrom\tdiscontinued\toperations | $(5.76) | $(0.06) | $(0.75) |
| Net\tincome\t(loss) | $(6.73) | $(2.61) | $(3.26) |
| Per\tdiluted\tshare: |  |  |  |
| Income\t(loss)\tfrom\tcontinuing\toperations | $(0.97) | $(2.55) | $(2.51) |
| Income\t(loss)\tfrom\tdiscontinued\toperations | $(5.76) | $(0.06) | $(0.75) |
| Net\tincome\t(loss) | $(6.73) | $(2.61) | $(3.26) |

# 4.	Acquisitions

In	the	fourth	quarter	of	2017,	we	closed	on	our	acquisition	of	additional	acreage	in	the	Northern	Delaware	basin	of	New	Mexico	from	a	private	seller	for	$63	million in	cash,	subject	to	post-closing	adjustments.	We	accounted	for	this	transaction	as	an	asset	acquisition,	allocating	the	purchase	price	to	unproved	property	within	property, plant	and	equipment.

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

On	August	1,	2016,	we	closed	on	our	acquisition	of	PayRock	Energy	Holdings,	LLC	("PayRock"),	a	portfolio	company	of	EnCap	Investments,	including approximately	61,000	net	surface	acres	in	the	oil	window	of	the	Anadarko	Basin	STACK	play	in	Oklahoma.	The	purchase	price	of	$904	million,	subject	to	closing adjustments,	was	paid	with	cash	on	hand.	We	accounted	for	this	transaction	as	an	asset	acquisition,	with	a	majority	of	the	purchase	price	allocated	to	unproved	property within	property,	plant	and	equipment.

# 5.	Dispositions

# Oil	Sands	Mining	Segment

On	May	31,	2017	we	closed	on	the	sale	of	our	Canadian	business,	which	included	our	20%	non-operated	interest	in	the	AOSP	to	Shell	and	Canadian	Natural Resources	Limited	("CNRL")	for	$2.5	billion,	excluding	closing	adjustments.	Under	the	terms	of	the	agreement,	$1.8	billion	was	paid	to	us	upon	closing	and	the remaining	proceeds	will	be	paid	in	the	first	quarter	of	2018.	At	closing	we	received	two	notes	receivable	for	the	remaining	proceeds,	each	with	a	face	value	of	$375 million.	We	recorded	these	notes	receivable	at	fair	value,	see	Note	14	for	fair	value	measurements.	Our	notes	receivable	are	with	10084751	Canada	Limited	("Canada Limited"),	an	affiliate	of	Shell	Canada	Limited,	and	CNRL.	The	Canada	Limited	note	receivable	is	guaranteed	by	Shell	Canada	Limited	and	the	CNRL	note	receivable is	guaranteed	by	Toronto	Dominion	Bank.	In	the	first	quarter	of	2017,	we	recorded	an	after-tax	non-cash	impairment	charge	of	$4.96	billion	primarily	related	to	the property,	plant	and	equipment	of	our	Canadian	business.	As	the	effective	date	of	the	transaction	was	January	1,	2017,	we	recorded	a	loss	on	sale	of	$43	million	during the	second	quarter	of	2017	due	to	second	quarter	results	of	operations	from	our	Canadian	business	that	were	recorded	in	our	financial	statements	but	transferred	to	the buyer	upon	closing.

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

|  | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 | 2015 |
| Total\tsales\tand\tother\trevenues\tand\tother\tincome | $431 | $863 | $908 |
| Net\tgain\t(loss)\ton\tdisposal\tof\tassets | (43) | — | — |
| Total\trevenues\tand\tother\tincome | 388 | 863 | 908 |
| Costs\tand\texpenses: |  |  |  |
| Production\texpenses | 254 | 601 | 715 |
| Exploration\texpenses | — | 7 | 347 |
| Depreciation,\tdepletion\tand\tamortization | 40 | 239 | 236 |
| Impairments | 6,636 | — | 31 |
| Other | 25 | 87 | 98 |
| Total\tcosts\tand\texpenses | 6,955 | 934 | 1,427 |
| Pretax\tincome\t(loss)\tfrom\tdiscontinued\toperations | (6,567) | (71) | (519) |
| Provision\t(benefit)\tfor\tincome\ttaxes | (1,674) | (18) | (16) |
| Income\t(loss)\tfrom\tdiscontinued\toperations | $(4,893) | $(53) | $(503) |

The	following	table	presents	the	carrying	value	of	the	major	categories	of	assets	and	liabilities	of	our	Canadian	business	reported	as	discontinued	operations	and other	non-core	international	assets	and	liabilities	from	continuing	operations,	that	are	reflected	as	held	for	sale	on	our	consolidated	balance	sheets	at	December	31,	2017 and	December	31,	2016:

|  | December	31, | December	31, |
| :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 |
| Assets\theld\tfor\tsale |  |  |
| Current\tassets: |  |  |
| Cash\tand\tcash\tequivalents | $— | $2 |
| Accounts\treceivables | — | 129 |
| Inventories | — | 91 |
| Other | — | 4 |
| Total\tcurrent\tassets\theld\tfor\tsale—discontinued\toperations | — | 226 |
| Total\tcurrent\tassets\theld\tfor\tsale—continuing\toperations | 11 | 1 |
| Total\tcurrent\tassets\theld\tfor\tsale | $11 | $227 |
| Noncurrent\tassets: |  |  |
| Property,\tplant\tand\tequipment,\tnet | $— | $8,991 |
| Other | — | 106 |
| Total\tnoncurrent\tassets\theld\tfor\tsale—discontinued\toperations | — | 9,097 |
| Total\tnoncurrent\tassets\theld\tfor\tsale—continuing\toperations | 55 | 1 |
| Total\tnoncurrent\tassets\theld\tfor\tsale | $55 | $9,098 |
| Liabilities\tassociated\twith\tassets\theld\tfor\tsale |  |  |
| Current\tliabilities: |  |  |
| Accounts\tpayable | $— | $111 |
| Other | — | 10 |
| Total\tcurrent\tliabilities\theld\tfor\tsale—discontinued\toperations | — | 121 |
| Total\tcurrent\tliabilities\theld\tfor\tsale—continuing\toperations | — | — |
| Total\tcurrent\tliabilities\theld\tfor\tsale | $— | $121 |
| Noncurrent\tliabilities: |  |  |
| Asset\tretirement\tobligations | $— | $95 |
| Deferred\ttax\tliabilities | — | 1,669 |
| Other | — | 20 |
| Total\tnoncurrent\tliabilities\theld\tfor\tsale—discontinued\toperations | — | 1,784 |
| Total\tnoncurrent\tliabilities\theld\tfor\tsale—continuing\toperations | 2 | 7 |
| Total\tnoncurrent\tliabilities\theld\tfor\tsale | $2 | $1,791 |

As	disclosed	above,	we	closed	on	the	sale	of	our	Canadian	business	in	May	of	2017.	This	sale	included	interests	in	our	exploration	stage	in-situ	leases	which	were included	within	our	historically	named	North	America	E&P	Segment.	See	Note	6	for	further	detail	on	our	segments.	These	interests	have	been	reflected	as	discontinued operations	and	are	included	within	the	disclosure	above.

In	July	2017,	we	entered	into	an	agreement	to	sell	certain	conventional	assets	in	Oklahoma.	We	closed	on	the	sale	in	September	2017	for	proceeds	of	$25	million, and	recognized	a	pre-tax	gain	of	$21	million.

In	September	2016,	we	entered	into	an	agreement	to	sell	certain	non-operated	CO2	and	waterflood	assets	in	West	Texas	and	New	Mexico.	The	sale	closed	in	late October	for	proceeds	of	$235	million,	and	we	recognized	a	total	pre-tax	gain	of	$63

million.	During	the	third	quarter	2016,	we	sold	certain	non-operated	assets	primarily	in	West	Texas	and	New	Mexico	to	multiple	purchasers	for	combined	proceeds	of approximately	$67	million,	and	recognized	a	total	pre-tax	gain	of	$55	million.

In	April	2016,	we	announced	the	sale	of	our	Wyoming	upstream	and	midstream	assets.	During	the	second	quarter,	we	received	proceeds	of	approximately	$690 million	and	recorded	a	pre-tax	gain	of	$266	million	with	the	remaining	asset	sales	closing	in	November	2016	for	proceeds	of	$155	million,	excluding	closing adjustments.	A	pre-tax	gain	of	$38	million	was	recognized	in	the	fourth	quarter	2016.

In	March	and	April	2016,	we	entered	into	separate	agreements	to	sell	our	10%	working	interest	in	the	outside-operated	Shenandoah	discovery	in	the	Gulf	of	Mexico, operated	natural	gas	assets	in	the	Piceance	basin	in	Colorado	and	certain	undeveloped	acreage	in	West	Texas	for	a	combined	total	of	approximately	$80	million	in proceeds.	We	closed	on	certain	of	the	asset	sales	and	recognized	a	net	pre-tax	loss	on	sale	of	$48	million	in	2016,	the	remaining	asset	closed	in	2017	with	a	net	pre-tax gain	on	sale	of	$32	million.

In	November	2015,	we	entered	into	an	agreement	to	sell	our	operated	producing	properties	in	the	greater	Ewing	Bank	area	and	non-operated	producing	interests	in the	Petronius	and	Neptune	fields	in	the	Gulf	of	Mexico.	The	transaction	closed	in	December	2015,	excluding	the	Neptune	field,	for	proceeds	of	$111	million.	A	$228 million	pretax	gain	was	recorded	in	the	fourth	quarter	of	2015.	The	Neptune	field	transaction	closed	during	the	first	quarter	of	2016	for	cash	proceeds	of	$4	million.

In	August	2015,	we	closed	the	sale	of	our	East	Texas,	North	Louisiana	and	Wilburton,	Oklahoma	natural	gas	assets	for	proceeds	of	$100	million	and	recorded	a pretax	loss	of	$1	million.	During	the	second	quarter	of	2015,	we	recorded	a	non-cash	impairment	charge	of	$44	million	related	to	these	assets	(see	Note	14).

In	the	third	quarter	of	2017,	we	entered	into	separate	agreements	to	sell	certain	non-core	properties	in	our	International	E&P	segment	for	combined	proceeds	of	$53 million,	before	closing	adjustments.	We	closed	on	one	of	the	asset	sales	in	the	second	half	of	2017	and	recognized	no	net	pre-tax	gain	or	loss	on	sale.	The	remaining	asset sale	is	expected	to	close	during	2018	and	is	classified	as	held	for	sale	in	the	consolidated	balance	sheet	as	of	December	31,	2017,	with	total	assets	of	$66	million	and total	liabilities	of	$2	million.	See	Note	10	for	further	detail	on	impairment	expenses	recognized	concurrently	with	these	agreements.

In	the	third	quarter	of	2015,	we	entered	into	agreements	to	sell	our	East	Africa	exploration	acreage	in	Ethiopia	and	Kenya.	A	pretax	loss	of	$109	million	was recorded	in	the	third	quarter	of	2015.	This	transaction	closed	during	the	first	quarter	of	2016.

# 6.	Segment	Information

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

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

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

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

As	discussed	in	Note	5,	we	closed	on	the	sale	of	our	Canadian	business,	which	includes	our	Oil	Sands	Mining	segment	and	exploration	stage	in-situ	leases,	in	the second	quarter	of	2017.	The	Canadian	business	is	reflected	as	discontinued	operations	and	is	excluded	from	segment	information	in	all	periods	presented.	Additionally, we	renamed	our	North	America	E&P	segment	to	United	States	E&P	segment	effective	June	30,	2017	in	all	periods	presented.	See	Note	1	for	further	information.

| Year	Ended	December	31,	2017 |  |  | Not	Allocated |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | U.S.\tE&amp;P | Int'l\tE&amp;P | to\tSegments |  | Total |
| Sales\tand\tother\toperating\trevenues | $3,138 | $1,154 | $(81) | (b) | $4,211 |
| Marketing\trevenues | 29 | 133 | — |  | 162 |
| Total\trevenues | 3,167 | 1,287 | (81) |  | 4,373 |
| Income\tfrom\tequity\tmethod\tinvestments | — | 256 | — |  | 256 |
| Net\tgain\ton\tdisposal\tof\tassets\tand\tother\tincome | 13 | 6 | 117 | (c) | 136 |
| Less: |  |  |  |  |  |
| Production\texpenses | 476 | 229 | 1 |  | 706 |
| Marketing\tcosts | 36 | 132 | — |  | 168 |
| Other\toperating | 354 | 77 | — |  | 431 |
| Exploration | 154 | 5 | 250 | (d) | 409 |
| Depreciation,\tdepletion\tand\tamortization | 2,011 | 328 | 33 |  | 2,372 |
| Impairments | 4 | — | 225 | (e) | 229 |
| Taxes\tother\tthan\tincome | 173 | — | 10 |  | 183 |
| General\tand\tadministrative | 119 | 32 | 249 | (f) | 400 |
| Net\tinterest\tand\tother | — | — | 270 | (g) | 270 |
| Loss\ton\tearly\textinguishment\tof\tdebt | — | — | 51 | (h) | 51 |
| Income\ttax\tprovision\t(benefit) | 1 | 372 | 3 |  | 376 |
| Segment\tincome\t(loss)\t/\tIncome\t(loss)\tfrom\tcontinuing\toperations | $(148) | $374 | $(1,056) |  | $(830) |
| Capital\texpenditures\t(a) | $2,081 | $42 | $27 |  | $2,150 |

(a) Includes	accruals.

(b) Unrealized	loss	on	commodity	derivative	instruments.

(c) Primarily	related	to	sale	of	certain	conventional	assets	in	Oklahoma	and	Colorado.	(See	Note 5).

(d)	Primarily	related	to	unproved	property	impairments	associated	with	certain	non-core	properties	within	our	International	E&P	segment.	(See	Note

(e) Primarily	related	to	proved	property	impairments	associated	with	certain	non-core	properties	within	our	International	E&P	segment.	(See	Note

(f) Includes	pension	settlement	loss	of	$32	million	(see	Note	17). (g)	Includes	a	gain	of	$47	million	resulting	from	the	termination	of	our	forward	starting	interest	rate	swaps.	(See	Note	 13.)

(h)	Primarily	related	to	the	make-whole	call	provisions	paid	upon	redemption	of	our	senior	unsecured	notes.	(See	Note 15.)

(b) Unrealized	gain	on	commodity	derivative	instruments.

(c) Partial	impairment	of	investment	in	equity	method	investee	(See	Note	 14).

(d) Primarily	related	to	gain	on	sale	of	our	properties	and	interests	in	the	Gulf	of	Mexico,	partially	offset	by	the	loss	on	sale	of	East	Africa	exploration	acreage 	(see	Note	5). (e)	Unproved	property	impairments	associated	with	lower	forecasted	commodity	prices	and	change	in	conventional	exploration	strategy	(See	Note 10).

(f) Includes	goodwill	impairment	(see	Note	12)	and	proved	property	impairments	(see	Note	 10).

(g) Includes	pension	settlement	loss	of	$119	million	(see	Note	17)	and	severance	related	expenses	associated	with	workforce	reductions	of	 $55	million.

Revenues	from	external	customers	are	attributed	to	geographic	areas	based	upon	selling	location.	The	following	summarizes	revenues	from	external	customers	by geographic	area.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 | 2015 |
| United\tStates | $3,086 | $2,400 | $3,804 |
| Equatorial\tGuinea | 530 | 444 | 444 |
| Libya | 431 | 54 | — |
| U.K. | 289 | 263 | 380 |
| Other\tinternational | 37 | 9 | 7 |
| Total\trevenues | $4,373 | $3,170 | $4,635 |

In	2017,	sales	to	Vitol	and	each	of	their	respective	affiliates	accounted	for	approximately	10%	of	our	total	revenues.	In	2016,	sales	to	Valero	Marketing	and	Supply, Tesoro	Petroleum,	and	Flint	Hills	Resources	and	each	of	their	respective	affiliates	accounted	for	approximately	13%,	11%	and	10%	of	our	total	revenues.	In	2015,	sales to	Shell	Oil	and	its	affiliates	accounted	for	approximately	10%	of	our	total	revenues.

The	following	summarizes	revenues	by	product	line.

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 | 2015 |
| Crude\toil\tand\tcondensate | $3,477 | $2,605 | $3,963 |
| Natural\tgas\tliquids | 338 | 198 | 203 |
| Natural\tgas | 510 | 356 | 464 |
| Other | 48 | 11 | 5 |
| Total\trevenues | $4,373 | $3,170 | $4,635 |

The	following	summarizes	property,	plant	and	equipment	and	equity	method	investments.

|  | December	31, | December	31, |
| :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 |
| United\tStates | $15,971 | $14,272 |
| Equatorial\tGuinea | 1,582 | 1,794 |
| Other\tinternational | 959 | 1,592 |
| Total\tlong-lived\tassets | $18,512 | $17,658 |

Income	(loss)	before	tax	expense	for	continuing	operations	was:

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 | 2015 |
| United\tStates | $(783) | $(1,449) | $(2,384) |
| Foreign | 329 | 285 | (55) |
| Total | $(454) | $(1,164) | $(2,439) |

Income	tax	provisions	(benefits)	for	continuing	operations	were:

# Year	Ended	December	31,

|  |  |  |  | Year	Ended	December	31, | Year	Ended	December	31, |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | 2017 |  |  | 2016 |  |  | 2015 |  |
| (In\tmillions) | Current | Deferred | Total | Current | Deferred | Total | Current | Deferred | Total |
| Federal | $(32) | $41 | $9 | $2 | $836 | $838 | $(41) | $(684) | $(725) |
| State\tand\tlocal | (14) | 2 | (12) | 2 | 8 | 10 | (8) | (18) | (26) |
| Foreign | 483 | (104) | 379 | 91 | (16) | 75 | 115 | (102) | 13 |
| Total | $437 | $(61) | $376 | $95 | $828 | $923 | $66 | $(804) | $(738) |

A	reconciliation	of	the	federal	statutory	income	tax	rate	applied	to	income	(loss)	from	continuing	operations	before	income	taxes	to	the	provision	(benefit)	for income	taxes	follows:

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 | 2015 |
| Total\tpre-tax\tincome\t(loss)\tfrom\tcontinuing\toperations | $(454) | $(1,164) | $(2,439) |
| Total\tincome\ttax\texpense\t(benefit) | $376 | $923 | $(738) |
| Effective\tincome\ttax\texpense\t(benefit)\trate\ton\tcontinuing\toperations | 83% | 79% | (30)% |
| Income\ttaxes\tat\tthe\tstatutory\ttax\trate\tof\t35%\t(a) | $(159) | $(407) | $(854) |
| Effects\tof\tforeign\toperations | 140 | 47 | (55) |
| Adjustments\tto\tvaluation\tallowances | 446 | 1,270 | 95 |
| State\tincome\ttaxes | (19) | 9 | (15) |
| Tax\tlaw\tchange | (35) | 6 | (3) |
| Goodwill\timpairment | — | — | 94 |
| Other\tfederal\ttax\teffects | 3 | (2) | — |
| Income\ttax\texpense\t(benefit)\ton\tcontinuing\toperations | $376 | $923 | $(738) |

(a)	Includes	income	tax	benefits	primarily	related	to	our	U.S.	federal	income	taxes	where	we	have	maintained	a	full	valuation	allowance	since	December	2016.

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	appears	in	the	"Not	Allocated	to	Segments"	column	of the	tables	in	Note	6.

Effects	of	foreign	operations	–	The	effects	of	foreign	operations	increased	our	tax	expense	in	2017,	2016,	and	2015	due	to	the	mix	of	pretax	income	between	high and	low	tax	jurisdictions.	This	increase	primarily	relates	to	increased	sales	volumes	in	Libya	during	2017	where	the	tax	rate	is	93.5%.	Excluding	Libya,	the	effective	tax rates	on	continuing	operations	would	be	an	expense	of	5%	in	2017,	an	expense	of	79%	in	2016,	and	a	benefit	of	29%	in	2015.

Adjustments	to	valuation	allowances	-	Since	December	31,	2016,	we	have	maintained	a	full	valuation	allowance	on	our	net	federal	deferred	tax	assets.	In	2017,	we recorded	a	$446	million	valuation	allowance	primarily	related	to	current	year	activity	in	the	U.S.	Included	within	the	$446	million	is	a	$41	million	out-of-period adjustment	as	a	result	of	identifying	certain	deferred	tax	assets	for	which	the	impact	should	have	been	recorded	to	other	comprehensive	income,	but	had	been	recorded to	income	from	continuing	operations	in	2016.

Change	in	tax	law	–	On	December	22,	2017,	the	U.S.	enacted	the	Tax	Cuts	and	Jobs	Act	(the	"Tax	Reform	Legislation").	Tax	Reform	Legislation,	which	is	also commonly	referred	to	as	"U.S.	tax	reform",	significantly	changes	U.S.	corporate	income	tax	laws	by,	among	other	things,	reducing	the	U.S.	corporate	income	tax	rate	to 21%	starting	in	2018,	and	repeal	of	the	corporate	alternative	minimum	tax	("AMT"),	and	a	one-time	deemed	repatriation	of	accumulated	foreign	earnings.	In	the	fourth quarter	of	2017,	we	remeasured	our	deferred	taxes	at	21%,	in	accordance	with	U.S.	GAAP	standards.	The	impact	of	the	remeasurement	on	our	federal	deferred	tax assets	and	liabilities	was	equally	offset	by	an	adjustment	to	our	valuation	allowance	with	no	material	impact	to	current	year	earnings.	We	recorded	a	net	benefit	of	$35 million,	classified	as	a	receivable	within	other	noncurrent	assets	on	the	consolidated	balance	sheet,	during	the	fourth	quarter	of	2017	related	to	the	repeal	of	the	corporate AMT.	Although	the	$35	million	net	benefit	represents	what	we	believe	is	a	reasonable	estimate	of	the	impact	of	the	income	tax	effects	of	the	Act	on	our	consolidated financial	statements	as	of	December	31,	2017,	it	should	be	considered	provisional.	We	do

not	expect	to	pay	U.S.	federal	cash	taxes	on	the	deemed	repatriation	due	to	an	accumulated	deficit	in	foreign	earnings	for	tax	purposes.

Once	we	finalize	certain	tax	positions	when	we	file	our	2017	federal	tax	return,	we	will	be	able	to	conclude	whether	any	further	adjustments	are	required	to	our	net tax	position	as	of	December	31,	2017.	Any	adjustments	to	these	provisional	amounts	will	be	reported	as	a	component	of	income	tax	expense	(benefit)	in	the	reporting period	in	which	any	such	adjustments	are	determined,	which	will	be	no	later	than	the	fourth	quarter	of	2018.

Deferred	tax	assets	and	liabilities	resulted	from	the	following:

|  | Year	Ended	December	31, |  |
| :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 |
| Deferred\ttax\tassets: |  |  |
| Employee\tbenefits | $111 | $228 |
| Operating\tloss\tcarryforwards | 1,030 | 1,065 |
| Capital\tloss\tcarryforwards | 3 | 4 |
| Foreign\ttax\tcredits | 611 | 4,430 |
| Other\tcredit\tcarryforwards | — | 35 |
| Investments\tin\tsubsidiaries\tand\taffiliates | 174 | 91 |
| Other | 69 | 86 |
| Subtotal | 1,998 | 5,939 |
| Valuation\tAllowance | (926) | (4,301) |
| Total\tdeferred\ttax\tassets | 1,072 | 1,638 |
| Deferred\ttax\tliabilities: |  |  |
| Property,\tplant\tand\tequipment | 1,332 | 3,672 |
| Accrued\trevenue | 81 | 75 |
| Other | 3 | (7) |
| Total\tdeferred\ttax\tliabilities | 1,416 | 3,740 |
| Net\tdeferred\ttax\tliabilities | $344 | $2,102 |

Foreign	Tax	Credits	-	As	a	result	of	U.S.	tax	reform,	we	have	reduced	our	foreign	tax	credits	at	December	31,	2017,	which	are	offset	by	a	corresponding	reduction in	valuation	allowance,	by	$3,819	million	due	to	the	remote	likelihood	these	credits	will	be	utilized	before	expiration.	We	have	not	elected	any	of	our	foreign	earnings	to be	permanently	reinvested	abroad.	Additionally	due	to	U.S.	tax	reform,	we	do	not	expect	future	foreign	earnings	from	operations	to	be	subject	to	tax	in	the	U.S.	The remaining	foreign	tax	credits,	which	are	offset	by	a	valuation	allowance,	expire	in	2022	through	2027.

Operating	loss	carryforwards	-	At	December	31,	2017,	our	operating	loss	carryforwards	before	valuation	allowance	includes	$898	million	from	the	U.S.	that	expire in	2035-2037.	Foreign	operating	loss	carryforwards	include	$13	million	that	begin	to	expire	in	2018.	State	operating	loss	carryforwards	of	$119	million	expire	in	2018 through	2037.

Valuation	allowances	–	At	December	31,	2017,	we	reflect	a	valuation	allowance	in	our	consolidated	balance	sheet	of	$926	million	against	our	net	deferred	tax assets	in	various	jurisdictions	in	which	we	operate.	The	reduction	primarily	related	to	the	reduction	of	foreign	tax	credits	in	the	U.S.	In	2016	and	2015,	we	increased	our valuation	allowance	by	$1,268	million	and	$99	million	respectively.

Net	deferred	tax	liabilities	were	classified	in	the	consolidated	balance	sheets	as	follows:

|  | December	31, | December	31, |
| :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 |
| Assets: |  |  |
| Other\tnoncurrent\tassets | $489 | $336 |
| Liabilities: |  |  |
| Noncurrent\tdeferred\ttax\tliabilities | 833 | 769 |
| Noncurrent\tliabilities\theld\tfor\tsale | — | 1,669 |
| Net\tdeferred\ttax\tliabilities | $344 | $2,102 |

We	are	continuously	undergoing	examination	of	our	U.S.	federal	income	tax	returns	by	the	IRS.	Such	audits	have	been	completed	through	the	2014	tax	year,	with the	exception	of	2010-11.	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 adequate	provision	has	been	made	for	federal	income	taxes	and	interest	which	may	become	payable	for	years	not	yet	settled.	See	Note	24	for	further	detail.	Further,	we are	routinely	involved	in	U.S.	state	income	tax	audits	and	foreign	jurisdiction	tax	audits.	We	believe	all	other	audits	will	be	resolved	within	the	amounts	paid	and/or provided	for	these	liabilities.

As	of	December	31,	2017,	our	income	tax	returns	remain	subject	to	examination	in	the	following	major	tax	jurisdictions	for	the	tax	years	indicated:

| (In	millions) | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
| Beginning\tbalance | $66 | $65 | $80 |
| Additions\tfor\ttax\tpositions\tof\tprior\tyears | 83 | 6 | 1 |
| Reductions\tfor\ttax\tpositions\tof\tprior\tyears | (3) | (5) | — |
| Settlements | (20) | — | (7) |
| Statute\tof\tlimitations | — | — | (9) |
| Ending\tbalance | $126 | $66 | $65 |

If	the	unrecognized	tax	benefits	as	of	December	31,	2017	were	recognized,	$10	million	would	affect	our	effective	income	tax	rate.	As	of	December	31,	2017,	there are	$83	million	uncertain	tax	positions	for	which	it	is	reasonably	possible	that	the	amount	could	significantly	change	during	the	next	twelve	months.	If	this	were	to significantly	change,	we	estimate	that	any	revisions	to	current	and	deferred	tax	liabilities	would	have	no	cumulative	adverse	earnings	impact	on	our	consolidated	results of	operations.

The	U.K.	tax	authorities	have	challenged	the	timing	of	deductibility	for	certain	Brae	area	decommissioning	costs.	In	the	fourth	quarter	of	2017,	we	received	an adverse	ruling	from	the	U.K.	first-tier	tax	tribunal.	As	a	result	of	the	adverse	ruling,	in	the	fourth	quarter	of	2017	we	established	an	uncertain	tax	position.	We	have appealed	the	ruling,	but	were	required	to	pay	the	disputed	tax	amount	and	associated	interest	in	order	to	pursue	the	appeal.	The	payment	of	the	disputed	tax	and	interest, approximately	$108	million,	is	not	considered	a	settlement	of	the	tax	dispute	with	the	U.K.	tax	authorities.	If	we	prevail	in	appeals,	we	will	be	refunded	the	tax	and interest	paid,	however,	if	we	do	not	prevail	no	further	material	cash	payments	are	expected	due	to	the	initial	payment	required	to	appeal	the	adverse	ruling.	See	Note	24 for	further	detail.

Interest	and	penalties	are	recorded	as	part	of	the	tax	provision	and	were	$2	million,	$1	million	and	$1	million	related	to	unrecognized	tax	benefits	in	2017,	2016	and 2015.	As	of	December	31,	2017	and	2016,	$25	million	and	$15	million	of	interest	and	penalties	were	accrued	related	to	income	taxes.

# 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.

|  | December	31, | December	31, |
| :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 |
| Crude\toil\tand\tnatural\tgas | $9 | $6 |
| Supplies\tand\tother\titems | 117 | 130 |
| Inventories | $126 | $136 |

# 9.	Property,	Plant	and	Equipment

|  | December	31, |  |
| :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 |
| United\tStates\tE&amp;P | $15,867 | $14,158 |
| International\tE&amp;P | 1,710 | 2,470 |
| Corporate | 88 | 99 |
| Net\tproperty,\tplant\tand\tequipment | $17,665 | $16,727 |

At	December	31,	2017,	2016	and	2015	we	had	total	deferred	exploratory	well	costs	as	follows:

(a) Includes	$64	million	in	exploratory	well	costs	being	expensed	as	a	result	of	our	agreement	to	sell	Diaba	License	G4-223	in	the	Republic	of	Gabon	in	August	of	2017.	See	Note	10	for	further detail.

(b) Includes	sale	of	GOM	assets	in	2016.

Exploratory	well	costs	capitalized	greater	than	one	year	after	completion	of	drilling	are	associated	with	one	project	in	E.G.	with	costs	of	$32	million	as	of December	31,	2017.	Management	believes	this	project	with	suspended	exploratory	drilling	costs	exhibit	sufficient	quantities	of	hydrocarbons	to	justify	potential development	based	on	current	plans.	For	this	project	in	E.G.,	drilling	was	completed	on	the	Rodo	well	in	Alba	Block	Sub	Area	B,	offshore	E.	G.	in	the	first	quarter	of 2015,	and	we	have	since	completed	a	seismic	feasibility	study.	In	2017,	we	received	approval	for	and	proceeded	to	perform	a	seismic	reprocessing	program.	After completion	of	this	program	we	will	evaluate	drilling	opportunities	within	Sub	Area	B.

# 10.	Impairments	and	Exploration	Expenses

# Impairments

As	a	result	of	our	announced	disposition	of	our	Canadian	business	in	the	first	quarter	of	2017,	we	recorded	a	pre-tax	non-cash	impairment	charge	of	$6.6	billion primarily	related	to	property,	plant	and	equipment.	This	impairment	in	our	Canadian	business	is	reflected	as	discontinued	operations	in	the	consolidated	statements	of income	and	the	consolidated	statements	of	cash	flows	for	all	periods	presented

The	following	table	summarizes	impairment	charges	of	proved	properties:

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| (in\tmillions) | 2017 | 2016 | 2015 |
| Total\timpairments | $229 | $67 | $721 |

•2017	-	Impairments	were	primarily	a	result	of	lower	forecasted	long-term	commodity	prices	and	the	anticipated	sales	of	certain	non-core	proved	properties	in our	International	E&P	segment	of	$136	million.	Additionally,	included	in	proved	property	impairments	was	$89	million	relating	to	the	Gulf	of	Mexico	and certain	conventional	Oklahoma	assets	primarily	as	a	result	of	lower	forecasted	long-term	commodity	prices.

•2016	-	Impairments	of	$67	million	consisted	primarily	of	proved	properties	in	Oklahoma	and	the	Gulf	of	Mexico	as	a	result	of	lower	forecasted	commodity prices	and	revisions	to	estimated	abandonment	costs.

•2015	-	Impairments	included	$340	million	for	the	goodwill	impairment	of	the	United	States	E&P	reporting	unit,	and	$335	million	related	to	proved	properties (primarily	in	Colorado	and	the	Gulf	of	Mexico)	as	a	result	of	lower	forecasted	commodity	prices,	and	$44	million	associated	with	our	disposition	of natural	gas	assets	in	East	Texas,	North	Louisiana	and	Wilburton,	Oklahoma.

See	Note	6	for	relevant	detail	regarding	segment	presentation,	Note	12	for	further	detail	regarding	the	goodwill	impairment	and	Note	14	for	fair	value	measurements related	to	impairments	of	proved	properties	and	long-lived	assets.

# Exploration	expense

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 | 2015 |
| Exploration\tExpenses |  |  |  |
| Unproved\tproperty\timpairments | $246 | $195 | $655 |
| Dry\twell\tcosts | 77 | 25 | 212 |
| Geological\tand\tgeophysical | 25 | 5 | 31 |
| Other | 61 | 98 | 73 |
| Total\texploration\texpenses | $409 | $323 | $971 |

# Unproved	property	impairments	and	dry	well	costs

•2017	-	As	a	result	of	lower	forecasted	long-term	commodity	prices	and	the	anticipated	sales	of	certain	non-core	properties	in	our	International	E&P	segment, we	recorded	a	non-cash	charge	of	$159	million	comprised	of	$95	million	in	unproved	property	impairments;	and	$64	million	in	dry	well	costs	related	to our	Diaba	License	G4-223	in	the	Republic	of	Gabon.	Also,	because	of	our	decision	not	to	develop	the	Tchicuate	offshore	Block	in	the	Republic	of	Gabon, we	recorded	a	non-cash	impairment	charge	of	$43	million	to	unproved	property.

•2016	-	Unproved	property	impairments	recorded	of	$195	million	were	primarily	a	result	of	our	decision	to	not	drill	any	of	our	remaining	Gulf	of	Mexico undeveloped	leases	and	also	includes	certain	other	unproved	properties	in	the	United	States.	Lower	dry	well	expense	was	a	result	of	the	strategic	decision to	transition	out	of	our	conventional	exploration	program	during	2015.

•2015	-	Primarily	due	to	changes	in	our	conventional	exploration	strategy	(Gulf	of	Mexico,	Canadian	in-situ	assets	and	Harir	block	in	the	Kurdistan	Region	of Iraq),	relinquishment	of	certain	properties	in	the	Gulf	of	Mexico,	the	operated	Solomon	exploration	well	in	the	Gulf	of	Mexico	and	our	unproved	property in	Colorado	as	a	result	of	the	proved	property	impairment	mentioned	above.	Dry	well	costs	include	the	operated	Solomon	exploration	well	in	the	Gulf	of Mexico,	and	our	operated	Sodalita	West	#1	exploratory	well	in	E.G.

See	Note	6	for	relevant	detail	regarding	segment	presentation	of	unproved	property	impairments.

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	were	as	follows:

|  | For	Year	Ended	December	31, |  |
| :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 |
| Beginning\tbalance | $1,652 | $1,544 |
| Incurred\tliabilities,\tincluding\tacquisitions | 25 | 14 |
| Settled\tliabilities,\tincluding\tdispositions | (50) | (74) |
| Accretion\texpense\t(included\tin\tdepreciation,\tdepletion\tand\tamortization) | 85 | 79 |
| Revisions\tof\testimates | (227) | 96 |
| Held\tfor\tsale | (2) | (7) |
| Ending\tbalance | $1,483 | $1,652 |

•Settled	liabilities	include	dispositions,	primarily	related	to	the	sale	of	certain	conventional	assets	in	Oklahoma	as	well	as	retirements	in	the	U.K.	and	the	Gulf	of Mexico.

•Revisions	of	estimates	were	primarily	due	to	changes	in	U.K.	estimated	costs	as	well	as	timing	of	abandonment	activities	in	the U.K.

•Ending	balance	includes	$55	million	classified	as	short-term	at	December	31,

•Settled	liabilities	include	dispositions,	primarily	related	to	the	Gulf	of	Mexico	and	Wyoming	as	well	as	retirements	in	the	Gulf	of Mexico.

•Revisions	of	estimates	were	primarily	due	to	changes	in	timing	of	abandonment	activities	as	well	as	changes	in	cost	estimated	in	the U.K.

•Ending	balance	includes	$50	million	classified	as	short-term	at	December	31,

# 12.	Goodwill

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.	Goodwill	is	tested	for	impairment	at	the	reporting	unit	level.	Our	reporting	units	are	the	same	as	our reporting	segments,	of	which	only	International	E&P	includes	goodwill.	We	estimate	the	fair	value	of	our	International	E&P	reporting	unit	using	a	combination	of market	and	income	approaches.	The	market	approach	referenced	observable	inputs	specific	to	us	and	our	industry,	such	as	the	price	of	our	common	equity,	our enterprise	value,	and	valuation	multiples	of	us	and	our	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.	We	performed	our	annual	impairment	test	in	the	second	quarter	of	2017	and	concluded	no	impairment	was	required.	As	of	the	date	of our	last	impairment	assessment,	the	fair	value	of	our	International	E&P	reporting	unit	exceeded	its	book	value	by	over	40%.	We	believe	the	estimates	and	assumptions used	in	our	impairment	assessments	are	reasonable	and	based	on	available	market	information,	but	variations	in	such	assumptions	could	result	in	materially	different calculations	of	fair	value	and	determinations	of	whether	or	not	an	impairment	is	indicated.

The	table	below	displays	the	allocated	beginning	goodwill	balances	by	segment	along	with	changes	in	the	carrying	amount	of	goodwill	for	2017	and	2016:

| (In	millions) | U.S.	E&amp;P | Int'l	E&amp;P | Total |
| :--- | :--- | :--- | :--- |
| 2016 |  |  |  |
| Beginning\tbalance,\tgross | $— | $115 | $115 |
| Less:\taccumulated\timpairments | — | — | — |
| Beginning\tbalance,\tnet | — | 115 | 115 |
| \t\tDispositions | — | — | — |
| Impairment | — | — | — |
| Ending\tbalance,\tnet | $— | $115 | $115 |
| 2017 |  |  |  |
| Beginning\tbalance,\tgross | $— | $115 | $115 |
| Less:\taccumulated\timpairments | — | — | — |
| Beginning\tbalance,\tnet | — | 115 | 115 |
| Dispositions | — | — | — |
| Impairment | — | — | — |
| Ending\tbalance,\tnet | $— | $115 | $115 |

For	further	information	regarding	the	fair	value	measurement	of	derivative	instruments	see	Note	14.	See	Note	1	for	discussion	of	the	types	of	derivatives	we	use	and the	reasons	for	them.	All	of	our	commodity	derivatives	and	historical	interest	rate	derivatives	are	subject	to	enforceable	master	netting	arrangements	or	similar agreements	under	which	we	may	report	net	amounts.	The	following	tables	present	the	gross	fair	values	of	derivative	instruments	and	the	reported	net	amounts	along	with where	they	appear	on	the	consolidated	balance	sheets.

|  |  | December	31,	2017 |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Asset | Liability | Net\tAsset | Balance\tSheet\tLocation |
| Not\tDesignated\tas\tHedges |  |  |  |  |
| \t\t\t\t\tCommodity | $— | $138 | $(138) | \t Other\tcurrent\tliabilities |
| \t\t\t\t\tCommodity | — | 2 | (2) | \t Deferred\tcredits\tand\tother\tliabilities |
| Total\tNot\tDesignated\tas\tHedges | $— | $140 | $(140) |  |
| \t\t\t\t\tTotal | $— | $140 | $(140) |  |

|  |  | December	31,	2016 |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Asset | Liability | Net\tAsset | Balance\tSheet\tLocation |
| Fair\tValue\tHedges |  |  |  |  |
| \t\t\t\t\tInterest\trate | $3 | $— | $3 | \t Other\tcurrent\tassets |
| \t\t\t\t\tInterest\trate | 1 | — | 1 | \t Other\tnoncurrent\tassets |
| Cash\tFlow\tHedges |  |  |  |  |
| \t\t\t\t\tInterest\trate | $64 | $— | $64 | \t Other\tnoncurrent\tassets |
| Total\tDesignated\tHedges | $68 | $— | $68 |  |
| Not\tDesignated\tas\tHedges |  |  |  |  |
| \t\t\t\t\tCommodity | $— | $60 | $(60) | \t Other\tcurrent\tliabilities |
| Total\tNot\tDesignated\tas\tHedges | $— | $60 | $(60) |  |
| \t\t\t\t\tTotal | $68 | $60 | $8 |  |

# Derivatives	Designated	as	Fair	Value	Hedges

During	the	third	quarter	of	2017,	we	terminated	all	of	our	interest	rate	swaps	designated	as	fair	value	hedges.	The	pretax	effects	of	derivative	instruments	designated as	hedges	of	fair	value	in	our	consolidated	statements	of	income	has	a	gross	impact	that	is	not	material	to	net	interest	and	other	in	all	periods	presented.	Additionally, there	is	no	ineffectiveness	related	to	fair	value	hedges	in	all	periods	presented.

The	following	table	presents,	by	maturity	date,	information	about	our	interest	rate	swap	agreements,	including	the	weighted	average,	London	Interbank	Offer	Rate ("LIBOR")	based,	floating	rate.

|  | December	31,	2017 |  | December	31,	2016 |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Aggregate\tNotional\nAmount | Weighted\tAverage,\nLIBOR-Based, | Aggregate\tNotional\nAmount | Weighted\tAverage,\nLIBOR-Based, |
| Maturity\tDates | (in\tmillions) | Floating\tRate | (in\tmillions) | Floating\tRate |
| October\t1,\t2017 | $— | —% | $600 | 5.10% |
| March\t15,\t2018 | $— | —% | $300 | 5.04% |

The	pretax	effect	of	derivative	instruments	designated	as	hedges	of	fair	value	in	our	consolidated	statements	of	income	is	summarized	in	the	table	below.	There	is	no ineffectiveness	related	to	the	historical	fair	value	hedges.

|  |  |  | Gain	(Loss) |  |
| :--- | :--- | :--- | :--- | :--- |
|  |  |  | Year\tEnded\tDecember\t31, |  |
| (In\tmillions) | Income\tStatement\tLocation | 2017 | 2016 | 2015 |
| Derivative |  |  |  |  |
| Interest\trate | Net\tinterest\tand\tother | $— | $(4) | $— |
| Hedged\tItem |  |  |  |  |
| Debt | Net\tinterest\tand\tother | $— | $4 | $— |

# Derivatives	Not	Designated	as	Hedges

# Interest	Rate	Swaps

During	the	third	quarter	of	2016,	we	entered	into	forward	starting	interest	rate	swaps	to	hedge	the	variations	in	cash	flows	related	to	fluctuations	in	long	term	interest rates	from	debt	that	were	probable	to	be	refinanced	by	us	in	2018,	specifically	interest	rate	risk	associated	with	future	changes	in	the	benchmark	treasury	rate.	We designated	these	derivative	instruments	as	cash	flow	hedges.	During	the	second	quarter	of	2017,	we	de-designated	the	forward	starting	interest	rate	swaps	previously designated	as	cash	flow	hedges.	In	the	third	quarter	of	2017,	the	forecasted	transaction	consummated	and	we	issued	$1	billion	in	senior	unsecured	notes.	See	Note	15	for further	detail.	As	a	result,	we	terminated	our	forward	starting	interest	rate	swaps	receiving	proceeds	of	$54	million.	We	recognized	a	gain	of	$47	million,	related	to deferred	gains	reclassified	from	accumulated	other	comprehensive	income,	in	net	interest	and	other	during	2017.

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

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

|  | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 | 2015 |
| Interest\tRate\tSwaps |  |  |  |
| \t\tBeginning\tbalance | $60 | $— | $— |
| Change\tin\tfair\tvalue\trecognized\tin\tother\tcomprehensive\tincome | (13) | 64 | — |
| Reclassification\tfrom\tother\tcomprehensive\tincome | (47) | (4) | — |
| \t\tEnding\tbalance | $— | $60 | $— |

# Commodity	Derivatives

We	have	entered	into	multiple	crude	oil	and	natural	gas	derivatives	indexed	to	NYMEX	WTI	and	Henry	Hub	related	to	a	portion	of	our	forecasted	United	States E&P	sales	through	2019.	These	commodity	derivatives	consist	of	three-way	collars,	swaps,	and	basis	swaps.	Three-way	collars	consist	of	a	sold	call	(ceiling),	a purchased	put	(floor)	and	a	sold	put.	The	ceiling	price	is	the	maximum	we	will	receive	for	the	contract	volumes,	the	floor	is	the	minimum	price	we	will	receive,	unless the	market	price	falls	below	the	sold	put	strike	price.	In	this	case,	we	receive	the	NYMEX	WTI/Henry	Hub	price	plus	the	difference	between	the	floor	and	the	sold	put price.	These	commodity	derivatives	were	not	designated	as	hedges.	The	following	table	sets	forth	outstanding	derivative	contracts	as	of	December	31,	2017	and	the weighted	average	prices	for	those	contracts:

|  | First	Quarter | 2018<br>Second	Quarter | Third	Quarter | Fourth	Quarter |
| :--- | :--- | :--- | :--- | :--- |
| Three-Way\tCollars |  |  |  |  |
| Volume\t(MMBtu/day) | 200,000 | 160,000 | 160,000 | 160,000 |
| Weighted\taverage\tprice\tper\tMMBtu |  |  |  |  |
| Ceiling | $3.79 | $3.61 | $3.61 | $3.61 |
| Floor | $3.08 | $3.00 | $3.00 | $3.00 |
| Sold\tput | $2.55 | $2.50 | $2.50 | $2.50 |

The	mark-to-market	impact	and	settlement	of	these	commodity	derivative	instruments	appears	in	sales	and	other	operating	revenues	in	our	consolidated	statements of	income	for	the	years	ended	December	31,	2017,	2016,	and	2015.	The	December	31,	2017,	2016,	and	2015	impact	was	a	net	loss	of	$36	million,	a	net	loss	of	$66 million,	and	a	net	gain	of	$128	million,	respectively.	Net	settlements	of	commodity	derivative	instruments	for	the	years	ended	December	31,	2017,	2016,	and	2015	were gains	of	$45	million,	$44	million,	and	$78	million,	respectively.

# 14.	Fair	Value	Measurements

# Fair	values	–	Recurring

The	following	tables'	present	assets	and	liabilities	accounted	for	at	fair	value	on	a	recurring	basis	by	hierarchy	level.

|  |  | December	31,	2017 |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Level\t1 | Level\t2 | Level\t3 | Total |
| Derivative\tinstruments,\tassets |  |  |  |  |
| Interest\trate | — | — | — | — |
| Derivative\tinstruments,\tassets | $— | $— | $— | $— |
| Derivative\tinstruments,\tliabilities |  |  |  |  |
| Commodity\t(a) | $(20) | $(120) | $— | $(140) |
| Derivative\tinstruments,\tliabilities | $(20) | $(120) | $— | $(140) |

|  |  | December	31,	2016 | December	31,	2016 |  |
| :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Level\t1 | Level\t2 | Level\t3 | Total |
| Derivative\tinstruments,\tassets |  |  |  |  |
| \t\t\t\t\tInterest\trate | $— | $68 | $— | $68 |
| Derivative\tinstruments,\tassets | $— | $68 | $— | $68 |
| Derivative\tinstruments,\tliabilities |  |  |  |  |
| Commodity\t(a) | $— | $60 | $— | $60 |
| Derivative\tinstruments,\tliabilities | $— | $60 | $— | $60 |

(a)	Derivative	instruments	are	recorded	on	a	net	basis	in	our	balance	sheet	(see	Note	13).

Commodity	derivatives	include	three-way	collars,	swaps,	and	basis	swaps.	These	instruments	are	measured	at	fair	value	using	either	a	Black-Scholes	or	a	modified Black-Scholes	Model.	For	swaps	and	basis	swaps,	inputs	to	the	models	include	commodity	prices	and	interest	rates	and	are	categorized	as	Level	1	because	all assumptions	and	inputs	are	observable	in	active	markets	throughout	the	term	of	the	instruments.	For	three-way	collars,	inputs	to	the	models	include	commodity	prices, interest	rates,	and	implied	volatility	and	are	categorized	as	Level	2	because	predominantly	all	assumptions	and	inputs	are	observable	in	active	markets	throughout	the term	of	the	instruments.

Historically,	both	our	interest	rate	swaps	and	forward	starting	interest	rate	swaps	are	measured	at	fair	value	with	a	market	approach	using	actionable	broker	quotes, which	are	Level	2	inputs.	See	Note	13	for	additional	discussion	of	the	types	of	derivative	instruments	we	use.

# Fair	values	–	Nonrecurring

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

|  |  | 2017 |  |  | 2016 |  | 2015 |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Fair\tValue |  | Impairment | Fair\tValue | Impairment | Fair\tValue |  | Impairment |
| Long-lived\tassets\theld\tfor\tuse | $179 |  | $229 | $15 | $67 | $56 |  | $386 |

Long-lived	assets	held	for	use	that	were	impaired	are	discussed	below.	The	fair	values,	unless	otherwise	noted,	were	measured	using	an	income	approach	based upon	internal	estimates	of	future	production	levels,	prices	and	discount	rate,	all	of	which	are	Level	3	inputs.		Inputs	to	the	fair	value	measurement	include	reserve	and production	estimates	made	by	our	reservoir	engineers,	estimated	future	commodity	prices	adjusted	for	quality	and	location	differentials	and	forecasted	operating expenses	for	the	remaining	estimated	life	of	the	reservoir.

In	the	third	quarter	of	2017,	impairments	of	$65	million	were	recorded	consisting	of	certain	proved	properties	in	the	Gulf	of	Mexico	as	a	result	of	lower	forecasted long-term	commodity	prices,	to	an	aggregate	fair	value	of	$66	million.

In	the	third	quarter	of	2016,	impairments	of	$47	million	were	recorded	consisting	primarily	of	conventional	non-core	proved	properties	in	Oklahoma	as	a	result	of lower	forecasted	long-term	commodity	prices,	to	an	aggregate	fair	value	of	$15	million.	During	the	fourth	quarter	of	2016,	we	recorded	an	impairment	of	$17	million	as a	result	of	abandonment	cost	revisions	related	to	the	Ozona	development	in	the	Gulf	of	Mexico	which	ceased	productions	in	2013.

In	the	third	quarter	of	2015,	impairments	of	$333	million	were	recorded	primarily	related	to	certain	producing	assets	in	Colorado	and	the	Gulf	of	Mexico	as	a	result of	lower	forecasted	commodity	prices,	to	an	aggregate	fair	value	of	$41	million.

During	the	second	quarter	of	2015,	we	recorded	an	impairment	charge	of	$44	million	related	to	East	Texas,	North	Louisiana	and	Wilburton,	Oklahoma	natural	gas assets	as	a	result	of	the	anticipated	sale.	The	fair	values	were	measured	using	a	probability	weighted	income	approach	based	on	both	the	anticipated	sale	price	and	held- for-use	model.

In	the	third	quarter	of	2017,	we	recorded	proved	property	impairments	of	$136	million,	to	an	aggregate	fair	value	of	$103	million,	on	certain	non-core	properties	in our	International	E&P	segment	primarily	as	a	result	of	lower	forecasted	long-term	commodity	prices	and	as	a	result	of	the	anticipated	sales	of	certain	non-core international	assets.	The	fair	values	were	measured	using	the	market	approach,	based	upon	either	anticipated	sales	proceeds	less	costs	to	sell	or	a	market	comparable	sales price	per	boe.	This	resulted	in	a	Level	2	classification.	See	Note	5	for	further	information	about	the	divestment	of	certain	non-core	properties	in	our	International	E&P segment.

In	the	third	quarter	of	2015,	a	partial	impairment	of	$12	million	was	recorded	to	an	investment	in	an	equity	method	investee	as	a	result	of	lower	forecasted commodity	prices,	to	a	fair	value	of	$604	million.	The	impairment	was	reflected	in	income	from	equity	method	investments	in	our	consolidated	statement	of	income.

# Canadian	discontinued	operations

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

# Fair	values	–	Financial	instruments

Our	current	assets	and	liabilities	include	financial	instruments,	the	most	significant	of	which	are	receivables,	long-term	debt	and	payables.	We	believe	the	carrying values	of	our	receivables	and	payables	approximate	fair	value.	Our	fair	value	assessment	incorporates	a	variety	of	considerations,	including	(1)	the	short-term	duration of	the	instruments,	(2)	our	credit	rating	and	(3)	our	historical	incurrence	of	and	expected	future	insignificance	of	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	value	by individual	balance	sheet	line	item	at	December	31,	2017	and	2016.

| (In	millions) | Fair<br>Value | Carrying<br>Amount | Fair<br>Value | Carrying<br>Amount |
| :--- | :--- | :--- | :--- | :--- |
| Financial\tassets |  |  |  |  |
| Other\tcurrent\tassets\t(a) | $762 | $761 | $7 | $7 |
| Other\tnoncurrent\tassets | 159 | 161 | 105 | 108 |
| Total\tfinancial\tassets | $921 | $922 | $112 | $115 |
| Financial\tliabilities |  |  |  |  |
| Other\tcurrent\tliabilities | $32 | $43 | $68 | $75 |
| Long-term\tdebt,\tincluding\tcurrent\tportion\t(b) | 5,976 | 5,526 | 7,449 | 7,292 |
| Deferred\tcredits\tand\tother\tliabilities | 110 | 103 | 114 | 107 |
| Total\tfinancial\tliabilities | $6,118 | $5,672 | $7,631 | $7,474 |

(a) Includes	our	two	notes	receivable	relating	to	the	sale	of	our	Canadian	business	as	of	December	31,	2017,	see	note 5	for	further	information.

(b) Excludes	capital	leases,	debt	issuance	costs	and	historical	interest	rate	swap	adjustments.

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

Most	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	such	debt.	The	fair	value	of	our	debt	that	is	not	publicly-traded	is	measured	using	an	income	approach.	The	future	debt	service payments	are	discounted	using	the	rate	at	which	we	currently	expect	to	borrow.	All	inputs	to	this	calculation	are	Level	3.

# Short-term	debt

As	of	December	31,	2017,	we	had	no	borrowings	against	our	$3.4	billion	unsecured	revolving	credit	facility	(as	amended,	the	"Credit	Facility"),	as	described	below.

# Revolving	Credit	Facility

The	Credit	Facility	includes	a	covenant	requiring	that	our	ratio	of	total	debt	to	total	capitalization	not	exceed	65%	as	of	the	last	day	of	each	fiscal	quarter.	If	an	event of	default	occurs,	the	lenders	holding	more	than	half	of	the	commitments	may	terminate	the	commitments	under	the	Credit	Facility	and	require	the	immediate	repayment of	all	outstanding	borrowings	and	the	cash	collateralization	of	all	outstanding	letters	of	credit	under	the	Credit	Facility.	As	of	December	31,	2017,	we	were	in	compliance with	this	covenant	with	a	debt-to-capitalization	ratio	of	32%.

# Long-term	debt

The	following	table	details	our	long-term	debt:

|  | December	31, |  |
| :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 |
| Senior\tunsecured\tnotes: |  |  |
| 6.000%\tnotes\tdue\t2017 | — | 682 |
| 5.900%\tnotes\tdue\t2018 | — | 854 |
| 7.500%\tnotes\tdue\t2019 | — | 228 |
| 2.700%\tnotes\tdue\t2020(a) | 600 | 600 |
| \t2.800%\tnotes\tdue\t2022(a) | 1,000 | 1,000 |
| 9.375%\tnotes\tdue\t2022\t(b) | 32 | 32 |
| Series\tA\tnotes\tdue\t2022\t(b) | 3 | 3 |
| 8.500%\tnotes\tdue\t2023\t(b) | 70 | 70 |
| 8.125%\tnotes\tdue\t2023\t(b) | 131 | 131 |
| 3.850%\tnotes\tdue\t2025(a) | 900 | 900 |
| 4.400%\tnotes\tdue\t2027(a) | 1,000 | — |
| 6.800%\tnotes\tdue\t2032(a) | 550 | 550 |
| 6.600%\tnotes\tdue\t2037(a) | 750 | 750 |
| 5.200%\tnotes\tdue\t2045(a) | 500 | 500 |
| Capital\tleases: |  |  |
| Capital\tlease\tobligation\texpiring\tin\t2018 | — | 1 |
| Other\tobligations: |  |  |
| 5.125%\tobligation\trelating\tto\trevenue\tbonds\tdue\t2037 | — | 1,000 |
| Total(b) | 5,536 | 7,301 |

| Unamortized	discount | (10) | (9) |
| :--- | :--- | :--- |
| Fair\tvalue\tadjustments(c) | — | 7 |
| Unamortized\tdebt\tissuance\tcost | (32) | (35) |
| Amounts\tdue\twithin\tone\tyear | — | (683) |
| Total\tlong-term\tdebt | $5,494 | $6,581 |

(a) These	notes	contain	a	make-whole	provision	allowing	us	to	repay	the	debt	at	a	premium	to	market	price.

(b) In	the	event	of	a	change	in	control,	as	defined	in	the	related	agreements,	debt	obligations	totaling $236	million	at	December	31,	2017	may	be	declared	immediately	due	and	payable.

(c) See	Notes	13	and	14	for	information	on	historical	interest	rate	swaps.

# Debt	Issuance

On	July	24,	2017,	we	issued	$1	billion	of	4.4%	senior	unsecured	notes	that	will	mature	on	July	15,	2027.	Interest	on	the	senior	unsecured	notes	is	payable	semi- annually	beginning	January	15,	2018.	We	may	redeem	some	or	all	of	the	senior	unsecured	notes	at	any	time	at	the	applicable	redemption	price,	plus	accrued	interest,	if any.	During	the	third	quarter	of	2017,	we	used	the	net	proceeds	of	$990	million	plus	existing	cash	on	hand	to	redeem	the	following	senior	unsecured	notes:

During	the	year	ended	2017,	as	a	result	of	the	above	redemption	of	$1.76	billion	in	senior	unsecured	notes,	we	recognized	a	loss	on	early	extinguishment	of	debt	of $46	million,	primarily	due	to	make-whole	call	provisions.	In	connection	with	the	redemption	of	the	senior	unsecured	notes,	we	terminated	our	forward	starting	interest rate	swaps,	which	resulted	in	proceeds	of	$54	million	and	a	gain	of	approximately	$47	million	into	earnings	in	2017.	See	Note	13	for	further	detail	on	our	historical forward	starting	interest	rate	swaps.

# Debt	Redemption

In	December	2017,	we	entered	into	a	transaction	to	purchase	$1	billion	of	3.75%	municipal	revenue	bonds	due	in	2037,	to	be	issued	by	the	Parish	of	St.	John	the Baptist,	State	of	Louisiana	(the	"Parish").	The	Parish	will	use	the	proceeds	to	redeem	$1	billion	of	5.125%	municipal	revenue	bonds	due	in	2037	with	cash	on	hand	in	a refunding	transaction.	We	purchased	the	$1	billion	of	3.75%	municipal	revenue	bonds	due	in	2037	on	their	date	of	issuance	to	hold	for	our	own	account	and	potential remarketing	to	the	public	at	a	future	date.

The	following	table	shows	future	debt	payments:

(In	millions)

| (In	millions) |  |
| :--- | :--- |
| 2018 | $— |
| 2019 | — |
| 2020 | 600 |
| 2021 | — |
| 2022 | 1,035 |
| Thereafter | 3,901 |
| Total\tlong-term\tdebt,\tincluding\tcurrent\tportion | $5,536 |

# 16.	Incentive	Based	Compensation

Description	of	stock-based	compensation	plans	–	The	Marathon	Oil	Corporation	2016	Incentive	Compensation	Plan	(the	"2016	Plan")	was	approved	by	our stockholders	in	May	2016	and	authorizes	the	Compensation	Committee	of	the	Board	of	Directors	to	grant	stock	options,	SARs,	stock	awards	(including	restricted	stock and	restricted	stock	unit	awards)	and	performance	unit	awards	to	employees.	The	2016	Plan	also	allows	us	to	provide	equity	compensation	to	our	non-employee directors.	No	more	than	55	million	shares	of	our	common	stock	may	be	issued	under	the	2016	Plan.	For	stock	options	and	SARs,	the	number	of	shares	available	for issuance	under	the	2016	Plan	will	be	reduced	by	one	share	for	each	share	of	our	common	stock	in	respect	of	which	the	award	is	granted.	For	stock	awards	(including restricted	stock	and	restricted	stock	unit	awards),	the	number	of	shares	available	for	issuance	under	the	2016	Plan	will	be	reduced	by	2.41	shares	for	each	share	of	our common	stock	in	respect	of	which	the	award	is	granted.

Shares	subject	to	awards	under	the	2016	Plan	that	are	forfeited,	terminated	or	expire	unexercised	become	available	for	future	grants.	In	addition,	the	number	of shares	of	our	common	stock	reserved	for	issuance	under	the	2016	Plan	will	not	be	increased	by	shares	tendered	to	satisfy	the	purchase	price	of	an	award,	exchanged	for other	awards	or	withheld	to	satisfy	tax	withholding	obligations.	Shares	issued	as	a	result	of	awards	granted	under	the	2016	Plan	are	generally	funded	out	of	common stock	held	in	treasury,	except	to	the	extent	there	are	insufficient	treasury	shares,	in	which	case	new	common	shares	are	issued.

After	approval	of	the	2016	Plan,	no	new	grants	were	or	will	be	made	from	any	prior	plans.	Any	awards	previously	granted	under	any	prior	plans	shall	continue	to	be exercisable	in	accordance	with	their	original	terms	and	conditions.

# Stock-based	awards	under	the	plans

Stock	options	–	We	grant	stock	options	under	the	2016	Plan.	Our	stock	options	represent	the	right	to	purchase	shares	of	our	common	stock	at	its	fair	market	value on	the	date	of	grant.	In	general,	our	stock	options	vest	ratably	over	a	three-year	period	and	have	a	maximum	term	of	ten	years	from	the	date	they	are	granted.

SARs	-	At	December	31,	2017,	there	are	no	SARs	outstanding.

Restricted	stock	–	We	grant	restricted	stock	under	the	2016	Plan.	The	restricted	stock	awards	granted	to	officers	generally	vest	three	years	from	the	date	of	grant, contingent	on	the	recipient's	continued	employment.	We	also	grant	restricted	stock	to	certain	non-officer	employees	based	on	their	performance	within	certain guidelines	and	for	retention	purposes.	The	restricted	stock	awards	to	non-officers	generally	vest	ratably	over	a	three-year	period,	contingent	on	the	recipient's	continued employment.	Prior	to	vesting,	all	restricted	stock	recipients	have	the	right	to	vote	such	stock	and	receive	dividends	thereon.	The	non-vested	shares	of	restricted	stock	are not	transferable	and	are	held	by	our	transfer	agent.

Stock-based	performance	units	–	We	grant	stock-based	performance	units	to	officers	under	the	2016	Plan.	At	the	grant	date,	each	unit	represents	the	value	of	one share	of	our	common	stock.	These	units	are	settled	in	cash,	and	the	amount	of	the	payment	is	based	on	(1)	the	vesting	percentage,	which	can	be	from	zero	to	200%	based on	performance	achieved	and	(2)	the	value	of	our	common	stock	on	the	date	vesting	is	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 number	of	shares	that	would	represent	the	value	of	the	units.

Restricted	stock	units	–	We	maintain	an	equity	compensation	program	for	our	non-employee	directors.		All	non-employee	directors	receive	annual	grants	of common	stock	units.		Any	units	granted	prior	to	2012	must	be	held	until	completion	of	board

service,	at	which	time	the	non-employee	director	will	receive	common	shares.		For	units	granted	between	2012	and	2016,	common	shares	will	generally	vest	following completion	of	board	service	or	three	years	from	the	date	of	grant,	whichever	is	earlier.		For	awards	issued	in	2017	and	later,	directors	may	elect	to	defer	settlement	of their	common	stock	units	until	after	they	cease	serving	on	the	Board.		Absent	such	an	election	to	defer,	common	shares	will	vest	upon	the	earlier	of	three	years	from	the date	of	grant	or	completion	of	board	service.		We	also	grant	restricted	stock	units	to	certain	non-officer	international	employees	which	generally	vest	ratably	over	a three-year	period,	contingent	on	the	recipient's	continued	employment.	Grants	of	restricted	stock	units	to	these	non-officer	international	employees	are	based	on	their performance	and	for	retention	purposes.	Common	shares	will	be	issued	for	these	restricted	stock	units	after	vesting.	Prior	to	vesting,	recipients	of	restricted	stock	units typically	receive	dividend	equivalent	payments,	but	they	may	not	vote.

Total	stock-based	compensation	expense	–	Total	employee	stock-based	compensation	expense	was	$50	million,	$51	million	and	$57	million	in	2017,	2016	and 2015,	while	the	total	related	income	tax	benefits	were	$19	million	and	$20	million	in	2016	and	2015.	Due	to	the	full	valuation	allowance	on	our	net	federal	deferred	tax assets,	we	realized	no	tax	benefit	during	2017.	During	2016	and	2015,	cash	received	upon	exercise	of	stock	option	awards	was	$1	million	and	$9	million.	There	was	no cash	received	upon	exercise	of	stock	option	awards	for	2017.	There	were	no	tax	benefits	realized	for	deductions	for	stock	awards	settled	during	2017,	2016	and	2015.

	Stock	option	awards	–	During	2017,	2016	and	2015	we	granted	stock	option	awards	to	officer	employees.	The	weighted	average	grant	date	fair	value	of	these awards	was	based	on	the	following	weighted	average	Black-Scholes	assumptions:

|  | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
| Exercise\tprice\tper\tshare | $15.80 | $7.22 | $29.06 |
| Expected\tannual\tdividend\tyield | 1.3% | 2.8% | 2.9% |
| Expected\tlife\tin\tyears | 6.4 | 6.3 | 6.2 |
| Expected\tvolatility | 42% | 36% | 32% |
| Risk-free\tinterest\trate | 2.1% | 1.4% | 1.7% |
| Weighted\taverage\tgrant\tdate\tfair\tvalue\tof\tstock\toption\tawards\tgranted | $6.07 | $1.97 | $6.84 |

The	following	is	a	summary	of	stock	option	award	activity	in	2017.

The	intrinsic	value	of	stock	option	awards	exercised	during	2017	and	2016	were	not	material.	The	intrinsic	value	of	stock	awards	exercised	during	2015	was	$6 million.

As	of	December	31,	2017,	unrecognized	compensation	cost	related	to	stock	option	awards	was	$4	million,	which	is	expected	to	be	recognized	over	a	weighted average	period	of	one	year.

	Restricted	stock	awards	and	restricted	stock	units	–	The	following	is	a	summary	of	restricted	stock	and	restricted	stock	unit	award	activity	in	2017.

|  | Awards | Weighted	Average<br>Grant	Date<br>Fair	Value |
| :--- | :--- | :--- |
| Unvested\tat\tbeginning\tof\tyear | 6,933,533 | $14.44 |
| Granted | 4,198,624 | $16.13 |
| Vested\t&amp;\tExercised | (2,472,367) | $17.67 |
| Canceled | (1,086,945) | $15.03 |
| Unvested\tat\tend\tof\tyear | 7,572,845 | $14.24 |

As	of	December	31,	2017	there	was	$67	million	of	unrecognized	compensation	cost	related	to	restricted	stock	awards	which	is	expected	to	be	recognized	over	a weighted	average	period	of	one	year.

The	key	assumptions	used	in	the	Monte	Carlo	simulation	to	determine	the	fair	value	of	stock-based	performance	units	granted	in	2017,	2016	and	2015	were:

|  | 2017 | 2016 | 2015	(a) |
| :--- | :--- | :--- | :--- |
| Valuation\tdate\tstock\tprice | $16.93 | $16.93 | $16.93 |
| Expected\tannual\tdividend\tyield | 1.2% | 1.2% | 1.2% |
| Expected\tvolatility | 54% | 34% | 33% |
| Risk-free\tinterest\trate | 1.9% | 1.7% | 1.4% |
| Fair\tvalue\tof\tstock-based\tperformance\tunits\toutstanding | $21.63 | $19.86 | $0.00 |

(a)	As	of	December	31,	2017,	there	were	no	2015	performance	unit	awards	outstanding.

# 17.	Defined	Benefit	Postretirement	Plans	and	Defined	Contribution	Plan

We	have	noncontributory	defined	benefit	pension	plans	covering	substantially	all	domestic	employees,	as	well	as	U.K.	employees	who	were	hired	before	April 2010.	Certain	employees	located	in	E.G.,	who	are	U.S.	or	U.K.	based,	also	participate	in	these	plans.	Benefits	under	these	plans	are	based	on	plan	provisions	specific	to each	plan.	For	the	U.K.	pension	plan,	the	principal	employer	and	plan	trustees	reached	a	decision	to	close	the	plan	to	future	benefit	accruals	effective	December	31, 2015.

We	also	have	defined	benefit	plans	for	other	postretirement	benefits	covering	our	U.S.	employees.	Health	care	benefits	are	provided	up	to	age	65	through comprehensive	hospital,	surgical	and	major	medical	benefit	provisions	subject	to	various	cost-sharing	features.	Post-age	65	health	care	benefits	are	provided	to	certain U.S.	employees	on	a	defined	contribution	basis.	Life	insurance	benefits	are	provided	to	certain	retiree	beneficiaries.	These	other	postretirement	benefits	are	not	funded	in advance.	Employees	hired	after	2016	are	not	eligible	for	any	postretirement	health	care	or	life	insurance	benefits.

Obligations	and	funded	status	–	The	following	summarizes	the	obligations	and	funded	status	for	our	defined	benefit	pension	and	other	postretirement	plans.

|  |  | Pension	Benefits |  |  | Other	Benefits |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2017 |  | 2016 |  | 2017 | 2016 |
| (In\tmillions) | U.S. | Int'l | U.S. | Int'l | U.S. | U.S. |
| Accumulated\tbenefit\tobligation | 378 | 599 | 386 | 583 | 221 | 227 |
| Change\tin\tbenefit\tobligations: |  |  |  |  |  |  |
| Beginning\tbalance | $397 | $583 | $525 | $579 | $227 | $260 |
| Service\tcost | 22 | — | 25 | — | 2 | 2 |
| Interest\tcost | 13 | 17 | 16 | 23 | 8 | 11 |
| Plan\tamendment | — | — | — | 1 | — | (38) |
| Actuarial\tloss\t(gain) | 42 | (7) | 78 | 139 | 5 | 11 |
| Foreign\tcurrency\texchange\trate\tchanges | — | 52 | — | (108) | — | — |
| Divestiture | — | — | — | — | — | — |
| Settlements\tpaid | (84) | (31) | (240) | (36) | — | — |
| Benefits\tpaid | (6) | (15) | (7) | (15) | (21) | (19) |
| Ending\tbalance | $384 | $599 | $397 | $583 | $221 | $227 |
| Change\tin\tfair\tvalue\tof\tplan\tassets: |  |  |  |  |  |  |
| Beginning\tbalance | $227 | $595 | $354 | $608 | $— | $— |
| Actual\treturn\ton\tplan\tassets | 27 | 47 | 25 | 129 | — | — |
| Employer\tcontributions | 52 | 17 | 95 | 18 | 21 | 20 |
| Foreign\tcurrency\texchange\trate\tchanges | — | 57 | — | (109) | — | — |
| Divestiture | — | — | — | — | — | — |
| Settlements\tpaid | (84) | (31) | (240) | (36) | — | — |
| Benefits\tpaid | (6) | (15) | (7) | (15) | (21) | (20) |
| Ending\tbalance | $216 | $670 | $227 | $595 | $— | $— |
| Funded\tstatus\tof\tplans\tat\tDecember\t31 | $(168) | $71 | $(170) | $12 | $(221) | $(227) |
| Amounts\trecognized\tin\tthe\tconsolidated\tbalance\tsheets: |  |  |  |  |  |  |
| Noncurrent\tassets | — | 71 | — | 12 | — | — |
| Current\tliabilities | (6) | — | (4) | — | (21) | (21) |
| Noncurrent\tliabilities | (162) | — | (166) | — | (200) | (206) |
| Accrued\tbenefit\tcost | $(168) | $71 | $(170) | $12 | $(221) | $(227) |
| Pretax\tamounts\tin\taccumulated\tother\tcomprehensive\tloss: |  |  |  |  |  |  |
| Net\tloss\t(gain) | $122 | $58 | $130 | $81 | $30 | $25 |
| Prior\tservice\tcost\t(credit) | (45) | 3 | (55) | 4 | (56) | (63) |

# Components	of	net	periodic	benefit	cost	from	continuing	operations	and	other	comprehensive	(income)	loss	–	The	following	summarizes	the	net	periodic	benefit

costs	and	the	amounts	recognized	as	other	comprehensive	(income)	loss	for	our	defined	benefit	pension	and	other	postretirement	plans.

|  | Pension	Benefits | Pension	Benefits | Pension	Benefits | Pension	Benefits | Pension	Benefits | Pension	Benefits | Other	Benefits | Other	Benefits | Other	Benefits |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | Year\tEnded\tDecember\t31, | Year\tEnded\tDecember\t31, |  |  | Year\tEnded\tDecember\t31, | Year\tEnded\tDecember\t31, |  |
|  | 2017 |  | 2016 |  | 2015 |  | 2017 | 2016 | 2015 |
| (In\tmillions) | U.S. | Int'l | U.S. | Int'l | U.S. | Int'l | U.S. | U.S. | U.S. |
| Components\tof\tnet\tperiodic\tbenefit\tcost: |  |  |  |  |  |  |  |  |  |
| Service\tcost | $22 | $— | $25 | $— | $29 | $14 | $2 | $2 | $3 |
| Interest\tcost | 13 | 17 | 16 | 23 | 25 | 25 | 8 | 11 | 11 |
| Expected\treturn\ton\tplan\tassets | (13) | (30) | (18) | (35) | (30) | (37) | — | — | — |
| Amortization: |  |  |  |  |  |  |  |  |  |
| -\tprior\tservice\tcost\t(credit) | (10) | — | (10) | 1 | (7) | 1 | (7) | (3) | (4) |
| -\tactuarial\tloss | 8 | 1 | 14 | — | 22 | 2 | — | — | 1 |
| \t\tNet\tcurtailment\tloss\t(gain)(a) | — | — | — | — | (5) | 4 | — | — | (7) |
| Net\tsettlement\tloss(b) | 28 | 4 | 97 | 6 | 119 | — | — | — | — |
| Net\tperiodic\tbenefit\tcost(c) | $48 | $(8) | $124 | $(5) | $153 | $9 | $3 | $10 | $4 |
| Other\tchanges\tin\tplan\tassets\tand\tbenefit\tobligations\nrecognized\tin\tother\tcomprehensive\t(income)\tloss\t(pretax): |  |  |  |  |  |  |  |  |  |
| Actuarial\tloss\t(gain) | $28 | $(26) | $70 | $41 | $30 | $(25) | $5 | $11 | $(21) |
| Amortization\tof\tactuarial\tgain\t(loss) | (36) | (4) | (111) | (6) | (134) | (2) | — | — | (1) |
| Prior\tservice\tcost\t(credit) | — | — | — | 1 | (89) | 1 | — | (38) | — |
| Amortization\tof\tprior\tservice\tcredit\t(cost) | 10 | — | 10 | (1) | 7 | (5) | 7 | 3 | 13 |
| Total\trecognized\tin\tother\tcomprehensive\t(income)\tloss | $2 | $(30) | $(31) | $35 | $(186) | $(31) | $12 | $(24) | $(9) |
| Total\trecognized\tin\tnet\tperiodic\tbenefit\tcost\tand\tother\ncomprehensive\t(income)\tloss | $50 | $(38) | $93 | $30 | $(33) | $(22) | $15 | $(14) | $(5) |

(a) Related	to	workforce	reductions,	which	reduced	the	future	expected	years	of	service	for	employees	participating	in	the	plans	and	the	impact	of	discontinuing	accruals	for	future	benefits	under the	U.K.	pension	plan	effective	December	31,	2015.

(b) Settlement	losses	are	recorded	when	lump	sum	payments	from	a	plan	in	a	period	exceed	the	plan's	total	service	and	interest	costs	for	the	period.

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

The	estimated	net	loss	and	prior	service	credit	for	our	defined	benefit	pension	plans	that	will	be	amortized	from	accumulated	other	comprehensive	loss	into	net periodic	benefit	cost	in	2018	are	$13	million	and	$10	million.	The	estimated	net	loss	and	prior	service	credit	for	our	other	defined	benefit	postretirement	plans	that	will be	amortized	from	accumulated	other	comprehensive	loss	into	net	periodic	benefit	cost	in	2018	are	$1	million	and	$7	million.

Plan	assumptions	–	The	following	summarizes	the	assumptions	used	to	determine	the	benefit	obligations	at	December	31,	and	net	periodic	benefit	cost	for	the defined	benefit	pension	and	other	postretirement	plans	for	2017,	2016	and	2015.

|  |  |  | Pension	Benefits | Pension	Benefits |  |  |  | Other	Benefits |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2017 |  | 2016 |  | 2015 |  | 2017 | 2016 | 2015 |
| (In\tmillions) | U.S. | Int'l | U.S. | Int'l | U.S. | Int'l | U.S. | U.S. | U.S. |
| Weighted\taverage\tassumptions\tused\tto\tdetermine\nbenefit\tobligation: |  |  |  |  |  |  |  |  |  |
| Discount\trate | 3.55% | 2.50% | 4.02% | 2.70% | 4.04% | 3.90% | 3.54% | 3.98% | 4.36% |
| Rate\tof\tcompensation\tincrease\t(a) | 4.00% | — | 4.00% | — | 4.00% | — | 4.00% | 4.00% | 4.00% |
| Weighted\taverage\tassumptions\tused\tto\tdetermine\nnet\tperiodic\tbenefit\tcost: |  |  |  |  |  |  |  |  |  |
| Discount\trate | 3.86% | 2.70% | 3.66% | 3.90% | 3.79% | 3.70% | 3.98% | 4.36% | 3.93% |
| Expected\tlong-term\treturn\ton\tplan\tassets | 6.50% | 4.50% | 6.75% | 5.50% | 6.75% | 5.70% | — | — | — |
| Rate\tof\tcompensation\tincrease\t(a) | 4.00% | — | 4.00% | —% | 4.00% | 3.60% | 4.00% | 4.00% | 4.00% |

(a) No	future	benefits	will	be	incurred	for	the	U.K.	plan	after	December	31,	2015.	Therefore,	rate	of	compensation	increase	is	no	longer	applicable	to	this	plan.

Expected	long-term	return	on	plan	assets	–	The	expected	long-term	return	on	plan	assets	assumption	for	our	U.S.	funded	plan	is	determined	based	on	an	asset	rate- of-return	modeling	tool	developed	by	a	third-party	investment	group	which	utilizes	underlying	assumptions	based	on	actual	returns	by	asset	category	and	inflation	and takes	into	account	our	U.S.	pension	plan's	asset	allocation.	To	determine	the	expected	long-term	return	on	plan	assets	assumption	for	our	international	plans,	we	consider the	current	level	of	expected	returns	on	risk-free	investments	(primarily	government	bonds),	the	historical	levels	of	the	risk	premiums	associated	with	the	other applicable	asset	categories	and	the	expectations	for	future	returns	of	each	asset	class.	The	expected	return	for	each	asset	category	is	then	weighted	based	on	the	actual asset	allocation	to	develop	the	overall	expected	long-term	return	on	plan	assets	assumption.

# Assumed	weighted	average	health	care	cost	trend	rates

Employer	provided	subsidies	for	post-65	retiree	health	care	coverage	were	frozen	effective	January	1,	2017	at	January	1,	2016	established	amount	levels.	Company contributions	are	funded	to	a	Health	Reimbursement	Account	on	the	retiree's	behalf	to	subsidize	the	retiree's	cost	of	obtaining	health	care	benefits	through	a	private exchange.	Therefore,	a	1%	change	in	health	care	cost	trend	rates	would	not	have	a	material	impact	on	either	the	service	and	interest	cost	components	and	the postretirement	benefit	obligations.

Plan	investment	policies	and	strategies	–	The	investment	policies	for	our	U.S.	and	international	pension	plan	assets	reflect	the	funded	status	of	the	plans	and expectations	regarding	our	future	ability	to	make	further	contributions.	Long-term	investment	goals	are	to:	(1)	manage	the	assets	in	accordance	with	applicable	legal requirements;	(2)	produce	investment	returns	which	meet	or	exceed	the	rates	of	return	achievable	in	the	capital	markets	while	maintaining	the	risk	parameters	set	by	the plan's	investment	committees	and	protecting	the	assets	from	any	erosion	of	purchasing	power;	and	(3)	position	the	portfolios	with	a	long-term	risk/return	orientation. Investment	performance	and	risk	is	measured	and	monitored	on	an	ongoing	basis	through	quarterly	investment	meetings	and	periodic	asset	and	liability	studies.

U.S.	plan	–	The	plan's	current	targeted	asset	allocation	is	comprised	of	55%	equity	securities	and	45%	other	fixed	income	securities.	Over	time,	as	the	plan's	funded ratio	(as	defined	by	the	investment	policy)	improves,	in	order	to	reduce	volatility	in	returns	and	to	better	match	the	plan's	liabilities,	the	allocation	to	equity	securities	will decrease	while	the	amount	allocated	to	fixed	income	securities	will	increase.	The	plan's	assets	are	managed	by	a	third-party	investment	manager.

International	plan	–	Our	international	plan's	target	asset	allocation	is	comprised	of	55%	equity	securities	and	45%	fixed	income	securities.	The	plan	assets	are invested	in	ten	separate	portfolios,	mainly	pooled	fund	vehicles,	managed	by	several	professional	investment	managers	whose	performance	is	measured	independently by	a	third-party	asset	servicing	consulting	firm.

Fair	value	measurements	–	Plan	assets	are	measured	at	fair	value.	The	following	provides	a	description	of	the	valuation	techniques	employed	for	each	major	plan asset	class	at	December	31,	2017	and	2016.

Cash	and	cash	equivalents	–	Cash	and	cash	equivalents	are	valued	using	a	market	approach	and	are	considered	Level	1.	This	investment	also	includes	a	cash	reserve account	(a	collective	short-term	investment	fund)	that	is	valued	using	an	income	approach	and	is	considered	Level	2.

Equity	securities	-	Investments	in	common	stock	and	preferred	stock	are	valued	using	a	market	approach	at	the	closing	price	reported	in	an	active	market	and	are therefore	considered	Level	1.	Private	equity	investments	include	interests	in	limited	partnerships	which	are	valued	based	on	the	sum	of	the	estimated	fair	values	of	the investments	held	by	each	partnership.	These	private	equity	investments	are	considered	Level	3.	Investments	in	pooled	funds	are	valued	using	a	market	approach	at	the net	asset	value	("NAV")	of	units	held.	The	various	funds	consist	of	either	an	equity	or	fixed	income	investment	portfolio	with	underlying	investments	held	in	U.S.	and non-U.S.	securities.	Nearly	all	of	the	underlying	investments	are	publicly-traded.	The	majority	of	the	pooled	funds	are	benchmarked	against	a	relative	public	index. These	are	considered	Level	2.

Fixed	income	securities	-	Fixed	income	securities	are	valued	using	a	market	approach.	U.S.	treasury	notes	and	exchange	traded	funds	("ETFs")	are	valued	at	the closing	price	reported	in	an	active	market	and	are	considered	Level	1.	Corporate	bonds,	non-U.S.	government	bonds,	private	placements,	taxable	municipals, GNMA/FNMA	pools,	and	Yankee	bonds	are	valued	using	calculated	yield	curves	created	by	models	that	incorporate	various	market	factors.	Primarily	investments	are held	in	U.S.	and	non-U.S.	corporate	bonds	in	diverse	industries	and	are	considered	Level	2.	Other	fixed	income	investments	include	futures	contracts,	real	estate investment	trusts,	credit	default,	zero	coupon,	and	interest	rate	swaps.	The	investment	in	the	commingled

funds	is	valued	using	the	NAV	of	units	held	as	a	practical	expedient.	The	commingled	funds	consist	of	equity	and	fixed	income	portfolios	with	underlying	investments held	in	U.S.	and	non-U.S.	securities.	Pooled	funds	primarily	have	investments	held	in	U.S.	and	non-U.S.	publicly	traded	investment	grade	government	and	corporate bonds	and	are	considered	Level	2.

Other	–	Other	investments	are	comprised	of	an	unallocated	annuity	contract,	two	limited	liability	companies,	real	estate	and	U.S.	treasury	futures.	All	are considered	Level	3,	as	significant	inputs	to	determine	fair	value	are	unobservable.

The	following	tables	present	the	fair	values	of	our	defined	benefit	pension	plan's	assets,	by	level	within	the	fair	value	hierarchy,	as	of	December	31,	2017	and	2016.

| (In	millions) | Level	1 |  | Level	2 |  | Level	3 |  |  | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | U.S. | Int'l | U.S. | Int'l | U.S. | Int'l | U.S. | Int'l |
| Cash\tand\tcash\tequivalents | $6 | $1 | $— | $— | $— | $— | $6 | $1 |
| Equity\tsecurities: |  |  |  |  |  |  |  |  |
| Common\tstock | 81 | — | — | — | — | — | 81 | — |
| Private\tequity | — | — | — | — | 16 | — | 16 | — |
| Mutual\tand\tpooled\tfunds | — | 151 | — | 115 | — | — | — | 266 |
| Fixed\tincome\tsecurities: |  |  |  |  |  |  |  |  |
| Corporate | — | — | 6 | — | — | — | 6 | — |
| Exchange\ttraded\tfunds | 5 | — | — | — | — | — | 5 | — |
| Government | 19 | — | 2 | — | 3 | — | 24 | — |
| \t\t\tPooled\tfunds | — | — | — | 403 | — | — | — | 403 |
| Other | — | — | — | — | 19 | — | 19 | — |
| Total\tinvestments,\tat\tfair\tvalue | 111 | 152 | 8 | 518 | 38 | — | 157 | 670 |
| \t\t\tCommingled\tfunds\t(a) | — | — | — | — | — | — | 59 | — |
| Total\tinvestments | $111 | $152 | $8 | $518 | $38 | $— | $216 | $670 |

| (In	millions) | Level	1 |  | Level	2 |  | Level	3 |  |  | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | U.S. | Int'l | U.S. | Int'l | U.S. | Int'l | U.S. | Int'l |
| Cash\tand\tcash\tequivalents | $8 | $5 | $— | $— | $— | $— | $8 | $5 |
| Equity\tsecurities: |  |  |  |  |  |  |  |  |
| \t\t\tCommon\tstock | 82 | — | — | — | — | — | 82 | — |
| \t\t\tPrivate\tequity | — | — | — | — | 20 | — | 20 | — |
| Mutual\tand\tpooled\tfunds | — | 201 | — | 159 | — | — | — | 360 |
| Fixed\tincome\tsecurities: |  |  |  |  |  |  |  |  |
| \tCorporate | — | — | 52 | — | — | — | 52 | — |
| \tExchange\ttraded\tfunds | 5 | — | — | — | — | — | 5 | — |
| \tGovernment | 6 | — | 19 | — | — | — | 25 | — |
| \t\t\t\tPooled\tfunds | — | — | — | 230 | — | — | — | 230 |
| Other | — | — | — | — | 21 | — | 21 | — |
| Total\tinvestments,\tat\tfair\tvalue | 101 | 206 | 71 | 389 | 41 | — | 213 | 595 |
| \t\t\tCommingled\tfunds\t(a) | — | — | — | — | — | — | 14 | — |
| Total\tinvestments | $101 | $206 | $71 | $389 | $41 | $— | $227 | $595 |

(a) After	the	adoption	of	the	FASB	update	for	the	fair	value	hierarchy,	we	separately	report	the	investments	for	which	fair	value	was	measured	using	the	net	asset	value	per	share	as	a	practical expedient.	Amounts	presented	in	this	table	are	intended	to	reconcile	the	fair	value	hierarchy	to	the	pension	plan	assets.	See	Note	2	for	further	information	on	the	FASB	update.

The	activity	during	the	year	ended	December	31,	2017	and	2016,	for	the	assets	using	Level	3	fair	value	measurements	was	immaterial.

Estimated	future	benefit	payments	–	The	following	gross	benefit	payments,	which	were	estimated	based	on	actuarial	assumptions	applied	at	December	31,	2017	and reflect	expected	future	services,	as	appropriate,	are	to	be	paid	in	the	years	indicated.

|  | Pension	Benefits |  | Other	Benefits |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | U.S. | Int'l | U.S. |
| 2018 | $43 | $17 | $21 |
| 2019 | 40 | 18 | 20 |
| 2020 | 37 | 17 | 20 |
| 2021 | 33 | 19 | 19 |
| 2022 | 30 | 21 | 18 |
| 2023\tthrough\t2027 | 123 | 118 | 74 |

Contributions	to	defined	benefit	plans	–	We	expect	to	make	contributions	to	the	funded	pension	plans	of	up	to	$65	million	in	2018.	Cash	contributions	to	be	paid from	our	general	assets	for	the	unfunded	pension	and	postretirement	plans	are	expected	to	be	approximately	$6	million	and	$21	million	in	2018.

Contributions	to	defined	contribution	plans	–	We	contribute	to	several	defined	contribution	plans	for	eligible	employees.	Contributions	to	these	plans	totaled	$20 million,	$20	million	and	$20	million	in	2017,	2016	and	2015.

# 18.		Reclassifications	Out	of	Accumulated	Other	Comprehensive	Loss

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

|  | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 | Income\tStatement\tLine |
| Postretirement\tand\tpostemployment\tplans |  |  |  |
| Amortization\tof\tactuarial\tloss | $(9) | $(14) | General\tand\tadministrative |
| Net\tsettlement\tloss | (32) | (103) | General\tand\tadministrative |
| Derivative\thedges |  |  |  |
| Recognized\tgain\ton\tterminated\tderivative\thedge | 46 | — | Net\tinterest\tand\tother |
| \t\t\t\t\tIneffective\tportion\tof\tderivative\thedge | 1 | 4 | Net\tinterest\tand\tother |
|  | 6 | (113) | Income\t(loss)\tfrom\toperations |
|  | (40) | 41 | (Provision)\tbenefit\tfor\tincome\ttaxes |
| Total\treclassifications\tto\texpense,\tnet\tof\ttax | $(34) | $(72) | Income\t(loss)\tfrom\tcontinuing\toperations |
| Foreign\tcurrency\thedges |  |  |  |
| Net\trecognized\tloss\tin\tdiscontinued\toperations,\tnet\tof\ttax | (30) | — | Income\t(loss)\tfrom\tdiscontinued\toperations |
| Total\treclassifications\tto\texpense | $(64) | $(72) |  |

# 19.	Supplemental	Cash	Flow	Information

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 | 2015 |
| Net\tcash\tused\tin\toperating\tactivities: |  |  |  |
| Interest\tpaid\t(net\tof\tamounts\tcapitalized) | $(379) | $(375) | $(325) |
| Income\ttaxes\tpaid\tto\ttaxing\tauthorities\t\t(a) | (391) | (84) | (171) |
| Noncash\tinvesting\tactivities,\trelated\tto\tcontinuing\toperations: |  |  |  |
| Changes\tin\tasset\tretirement\tcosts | $(202) | $110 | $(95) |
| Asset\tretirement\tobligations\tassumed\tby\tbuyer | 14 | 40 | 251 |
| Increase\tin\tcapital\texpenditure\taccrual | 176 | — | — |
| Notes\treceivable\tfor\tdisposition\tof\tassets | 748 | — | — |

(a)	Includes	a	payment	of	$108	million	made	to	U.K.	taxing	authorities	to	preserve	our	appeal	rights,	see	Note	 7	-	Income	Taxes	for	additional	discussion.

# 20.	Other	Items

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 | 2015 |
| Interest: |  |  |  |
| Interest\tincome | $34 | $14 | $9 |
| Interest\texpense | (380) | (398) | (350) |
| Income\ton\tinterest\trate\tswaps | 53 | 13 | 11 |
| Interest\tcapitalized | 3 | 18 | 19 |
| Total\tinterest | (290) | (353) | (311) |
| Other: |  |  |  |
| Net\tforeign\tcurrency\tgain\t(loss) | 8 | 6 | 4 |
| Other | 12 | 15 | 21 |

| Total	other | 20 | 21 | 25 |
| :--- | :--- | :--- | :--- |
| Net\tinterest\tand\tother | $(270) | $(332) | $(286) |

Foreign	currency	–	Aggregate	foreign	currency	gains	(losses)	were	included	in	the	consolidated	statements	of	income	as	follows:

|  |  | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 | 2015 |
| Net\tinterest\tand\tother | $8 | $6 | $4 |
| Provision\tfor\tincome\ttaxes | 57 | (32) | (11) |
| Aggregate\tforeign\tcurrency\tgains\t(losses) | $65 | $(26) | $(7) |

# 21.	Equity	Method	Investments	and	Related	Party	Transactions

During	2017,	2016	and	2015	only	our	equity	method	investees	were	considered	related	parties	and	they	included:

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

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

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

activity.

Our	equity	method	investments	are	summarized	in	the	following	table:

|  | Ownership	as	of | December	31, | December	31, |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | December\t31,\t2017 | 2017 | 2016 |
| EGHoldings | 60% | $456 | $550 |
| Alba\tPlant\tLLC | 52% | 214 | 215 |
| AMPCO | 45% | 177 | 165 |
| Other\tinvestments |  | — | 1 |
| Total |  | $847 | $931 |

Dividends	and	partnership	distributions	received	from	equity	method	investees	(excluding	distributions	that	represented	a	return	of	capital	previously	contributed) were	$276	million	in	2017,	$192	million	in	2016	and	$178	million	in	2015.

Summarized	financial	information	for	equity	method	investees	is	as	follows:

| (In	millions) | 2017 | 2016 | 2015 |
| :--- | :--- | :--- | :--- |
| Income\tdata\t–\tyear\t(a): |  |  |  |
| Revenues\tand\tother\tincome | $1,294 | $770 | $769 |
| Income\tfrom\toperations | 631 | 346 | 313 |
| Net\tincome | 508 | 313 | 280 |
| Balance\tsheet\tdata\t–\tDecember\t31: |  |  |  |
| Current\tassets | $586 | $525 |  |
| Noncurrent\tassets | 1,044 | 1,173 |  |
| Current\tliabilities | 221 | 218 |  |
| Noncurrent\tliabilities | 94 | 47 |  |

(a)	See	Item	15	Exhibits,	Financial	Statement	Schedules	which	contains	the	Alba	Plant	LLC	audited	financial	statements,	which	have	been	included	pursuant	to	Rule	3-09	of	Regulation	S-X.

Revenues	from	related	parties	were	$60	million,	$54	million	and	$51	million	in	2017,	2016	and	2015,	with	the	majority	related	to	EGHoldings	in	all	years. Purchases	from	related	parties	were	$132	million,	$103	million	and	$207	million	in	2017,	2016	and	2015	with	the	majority	related	to	Alba	Plant	LLC	in	all	years.

Current	receivables	from	related	parties	at	December	31,	2017	and	2016,	were	$24	million,	and	$23	million.	Payables	to	related	parties	were	$14	million	and	$11 million	at	December	31,	2017	and	2016,	with	the	majority	related	to	Alba	Plant	LLC.

# 22.	Stockholders'	Equity

In	March	2016,	we	issued	166,750,000	shares	of	our	common	stock,	par	value	$1	per	share,	at	a	price	of	$7.65	per	share,	excluding	underwriting	discounts	and commissions,	for	net	proceeds	of	$1,236	million.	The	proceeds	were	used	to	strengthen	our	balance	sheet	and	for	general	corporate	purposes,	including	funding	a	portion of	our	Capital	Development	Program.

There	were	no	share	repurchases	during	2017	or	2016	under	our	publicly	announced	plans	or	programs.	As	of	December	31,	2017	the	total	remaining	share repurchase	authorization	was	$1.5	billion.	Purchases	under	the	program	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.	The	repurchase	program	does	not include	specific	price	targets	or	timetables.

We	lease	a	wide	variety	of	facilities	and	equipment	under	operating	leases,	including	land,	building	space,	equipment	and	vehicles.	Most	long-term	leases	include renewal	options	and,	in	certain	leases,	purchase	options.	Future	minimum	commitments	for	operating	lease	obligations	having	noncancellable	lease	terms	in	excess	of one	year	are	as	follows:

| (In	millions) | Operating	Lease<br>Obligations |
| :--- | :--- |
| 2018 | $29 |
| 2019 | 28 |
| 2020 | 27 |
| 2021 | 26 |
| 2022 | 5 |
| Later\tyears | 4 |
| Sublease\trentals | — |
| Total\tminimum\tlease\tpayments | $119 |

*	Future	minimum	commitments	for	capital	lease	obligations	are	nil	as	of	December	31,	2017.

Operating	lease	rental	expense	related	to	continuing	operations	was	$87	million,	$87	million	and	$99	million	in	2017,	2016	and	2015.

# 24.	Commitments	and	Contingencies

The	U.K.	tax	authorities	have	challenged	the	timing	of	deductibility	for	certain	Brae	area	decommissioning	costs,	which	we	claimed	for	U.K.	corporation	tax purposes.		The	dispute	relates	to	the	timing	of	the	deduction	and	does	not	dispute	the	general	deductibility	of	decommissioning	costs.	In	the	third	quarter	of	2017,	a hearing	took	place	at	the	U.K.'s	First-tier	Tribunal	with	respect	to	this	tax	deduction.		In	the	fourth	quarter	of	2017,	we	received	notification	from	the	U.K.'s	First-tier Tribunal	that	the	judge	sided	with	the	U.K.	tax	authorities	with	respect	to	the	timing	of	the	decommissioning	cost	deductions.		We	intend	to	appeal	this	decision	and estimate	that	any	revisions	to	current	and	deferred	tax	liabilities,	if	we	do	not	prevail	in	the	appeals	process,	would	have	no	cumulative	adverse	earnings	impact	on	our consolidated	results	of	operations.		In	accordance	with	U.K.	regulations,	we	have	paid	the	amount	of	tax	and	interest	in	question,	approximately	$108	million,	prior	to our	appeal.		As	a	result	of	the	negative	ruling	we	no	longer	consider	this	position	to	be	more-likely-than-not	to	be	sustained	and	have	created	an	uncertain	tax	position related	to	the	Brae	area	decommissioning	costs.		The	payment	of	the	tax	and	interest	to	the	U.K.	tax	authorities	is	not	to	settle	the	position,	but	a	regulatory	requirement to	appeal	in	the	U.K.		If	we	ultimately	prevail	in	appeals,	the	U.K.	tax	authorities	will	refund	the	tax	and	interest,	however,	if	we	ultimately	lose	in	appeals	no	material future	payments	related	to	this	issue	will	be	required.		See	Note	7	for	further	detail.

We	are	continuously	undergoing	examination	of	our	U.S.	federal	income	tax	returns	by	the	IRS.		These	audits	have	been	completed	through	the	2014	tax	year, except	for	tax	years	2010	and	2011.	During	the	third	quarter	of	2017,	we	received	a	partnership	adjustment	notification	related	to	the	2010	and	2011	tax	years,	for	which we	have	filed	a	Tax	Court	Petition	in	the	fourth	quarter	of	2017.		We	believe	that	it	is	more	likely	than	not	that	we	will	prevail.

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

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

At	December	31,	2017	and	2016,	accrued	liabilities	for	remediation	were	not	material.	It	is	not	presently	possible	to	estimate	the	ultimate	amount	of	all	remediation costs	that	might	be	incurred	or	the	penalties	that	may	be	imposed.

Guarantees	–	We	have	entered	into	a	performance	guarantee	related	to	asset	retirement	obligations	with	aggregate	maximum	potential	undiscounted	payments totaling	$35	million	as	of	December	31,	2017.	Under	the	terms	of	this	guarantee	arrangement,	we	would	be	required	to	perform	should	the	guaranteed	party	fail	to	fulfill its	obligations	under	the	specified	arrangements.

Over	the	years,	we	have	sold	various	assets	in	the	normal	course	of	our	business.	Certain	of	the	related	agreements	contain	performance	and	general	guarantees, including	guarantees	regarding	inaccuracies	in	representations,	warranties,	covenants	and	agreements,	and	environmental	and	general	indemnifications	that	require	us	to perform	upon	the	occurrence	of	a	triggering	event	or	condition.	These	guarantees	and	indemnifications	are	part	of	the	normal	course	of	selling	assets.	We	are	typically not	able	to	calculate	the	maximum	potential	amount	of	future	payments	that	could	be	made	under	such	contractual	provisions	because	of	the	variability	inherent	in	the guarantees	and	indemnities.	Most	often,	the	nature	of	the	guarantees	and	indemnities	is	such	that	there	is	no	appropriate	method	for	quantifying	the	exposure	because	the underlying	triggering	event	has	little	or	no	past	experience	upon	which	a	reasonable	prediction	of	the	outcome	can	be	based.

Contract	commitments	–	At	December	31,	2017	and	2016,	contractual	commitments	to	acquire	property,	plant	and	equipment	totaled	$102	million	and	$144 million.

In	connection	with	the	sale	of	our	operated	producing	properties	in	the	greater	Ewing	Bank	area	and	non-operated	producing	interests	in	the	Petronius	and	Neptune fields	in	the	Gulf	of	Mexico,	we	retained	an	overriding	royalty	interest	in	the	properties.	As	part	of	the	sale	agreement,	proceeds	associated	with	the	production	of	our override,	up	to	$70	million,	are	dedicated	solely	to	the	satisfaction	of	the	corresponding	future	abandonment	obligations	of	the	properties.	The	term	of	our	override	ends once	sales	proceeds	equal	$70	million.

# Select	Quarterly	Financial	Data	(Unaudited)

| (In	millions,	except	per	share	data) | 1st	Qtr. | 2nd	Qtr. | 3rd	Qtr. | 4th	Qtr. | 1st	Qtr. | 2nd	Qtr. | 3rd	Qtr. | 4th	Qtr. |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Revenues | $988 | $993 | $1,162 | $1,230 | $612 | $761 | $861 | $936 |
| Income\t(loss)\tfrom\tcontinuing\toperations\tbefore\nincome\ttaxes\t(a) | (16) | (112) | (458) | 132 | (613) | (192) | (313) | (46) |
| Income\t(loss)\tfrom\tcontinuing\toperations | (50) | (153) | (599) | (28) | (360) | (138) | (206) | (1,383) |
| Discontinued\toperations\t(b) | (4,907) | 14 | — | — | (47) | (32) | 14 | 12 |
| Net\tincome\t(loss)\t(c) | $(4,957) | $(139) | $(599) | $(28) | $(407) | $(170) | $(192) | $(1,371) |
| Income\t(loss)\tper\tshare: |  |  |  |  |  |  |  |  |
| Continuing\toperations | $(0.06) | $(0.18) | $(0.70) | $(0.03) | $(0.49) | $(0.16) | $(0.24) | $(1.63) |
| Discontinued\toperations\t(b) | $(5.78) | $0.02 | $— | $— | $(0.07) | $(0.04) | $0.01 | $0.01 |
| Basic\tnet\tincome\t(loss) | $(5.84) | $(0.16) | $(0.70) | $(0.03) | $(0.56) | $(0.20) | $(0.23) | $(1.62) |
| Dividends\tpaid\tper\tshare | $0.05 | $0.05 | $0.05 | $0.05 | $0.05 | $0.05 | $0.05 | $0.05 |

(a) Includes	impairments	to	proved	properties	of	$24	million	and	$201	million	in	the	fourth	and	third	quarter	of	2017	and	$47	million	in	the	third	quarter	of	2016.	Also	includes	unproved	property impairments	and	exploratory	dry	well	costs	of	$215	million	in	the	third	quarter	of	2017	and	$118	million	in	the	second	quarter	of	2016.	(See	Item	8.	Financial	Statements	and	Supplementary	Data –	Note	13	to	the	consolidated	financial	statements).

(b) We	closed	on	the	sale	of	our	Canadian	business	in	the	second	quarter	of	2017.	The	Canadian	business	is	reflected	as	discontinued	operations	in	all	periods	presented.	Included	in	the	first	quarter	of 2017	is	an	after-tax	non-cash	impairment	charge	of	$4.96	billion,	primarily	related	to	the	property,	plant,	and	equipment.

(c) Includes	the	increase	of	a	valuation	allowance	on	certain	of	our	deferred	tax	assets	for	$1,346	million	in	the	fourth	quarter	of	2016	(see	Item	8.	Financial	Statements	and	Supplementary	Data	– Note	9	to	the	consolidated	financial	statements).

# Supplementary	Information	on	Oil	and	Gas	Producing	Activities	(Unaudited)

The	supplementary	information	is	disclosed	by	the	following	geographic	areas:	the	U.S.;	E.G.;	Libya;	Other	Africa,	which	includes	Gabon;	and	Other	International ("Other	Int'l"),	which	includes	the	U.K.	and	the	Kurdistan	Region	of	Iraq.	We	closed	the	sale	of	our	Canada	business	in	2017	and	have	reflected	this	business	as discontinued	operations	("Disc	Ops")	in	all	periods	presented.	See	Note	5	for	further	details	on	our	Canadian	disposition.

# Preparation	of	Reserve	Estimates

All	estimates	of	reserves	are	made	in	compliance	with	SEC	Rule	4-10	of	Regulation	S-X.	Crude	oil	and	condensate,	NGL,	natural	gas	and	our	historical	synthetic crude	oil	reserve	estimates	are	reviewed	and	approved	by	our	Corporate	Reserves	Group	("CRG"),	which	includes	our	Director	of	Corporate	Reserves	and	his	staff	of Reserve	Coordinators.	Crude	oil	and	condensate,	NGLs	and	natural	gas	reserve	estimates	are	developed	or	reviewed	by	Qualified	Reserves	Estimators	("QREs").	QREs are	petro-technical	professionals	located	throughout	our	organization	who	meet	the	qualifications	we	have	established	for	employees	engaged	in	estimating	reserves	and resources.	QREs	have	the	education,	experience,	and	training	necessary	to	estimate	reserves	and	resources	in	a	manner	consistent	with	all	external	reserve	estimation regulations	and	internal	resource	estimation	directives	and	practices.	QREs	generally	hold	at	least	a	Bachelor	of	Science	degree	in	the	appropriate	technical	field,	have	a minimum	of	three	years	of	industry	experience	with	at	least	one	year	in	reserve	estimation	and	have	completed	our	QRE	training	course.	All	reserves	changes	(including proved)	must	be	approved	by	the	CRG.	Additionally,	any	change	to	proved	reserve	estimates	in	excess	of	5	mmboe	on	a	total	field	basis,	within	a	single	month,	must	be approved	by	the	Director	of	Corporate	Reserves.

The	Director	of	Corporate	Reserves,	who	reports	to	our	Chief	Financial	Officer,	has	a	Bachelor	of	Science	degree	in	petroleum	engineering	and	is	a	registered Professional	Engineer	in	the	State	of	New	Mexico.	In	his	31	years	with	Marathon	Oil,	he	has	held	numerous	engineering	and	management	positions,	including	more recently	managing	reservoir	engineering	and	geoscience	for	our	Eagle	Ford	development	in	South	Texas.	He	is	a	25	year	member	of	the	Society	of	Petroleum	Engineers ("SPE").

Technologies	used	in	proved	reserves	estimation	includes	statistical	analysis	of	production	performance,	decline	curve	analysis,	pressure	and	rate	transient	analysis, pressure	gradient	analysis,	reservoir	simulation	and	volumetric	analysis.	The	observed	statistical	nature	of	production	performance	coupled	with	highly	certain	reservoir continuity	or	quality	within	the	reliable	technology	areas	and	sufficient	proved	developed	locations	establish	the	reasonable	certainty	criteria	required	for	booking	proved reserves.

Historical	estimates	of	synthetic	crude	oil	reserves	were	prepared	by	GLJ	Petroleum	Consultants	of	Calgary,	Alberta,	Canada,	third-party	consultants	for	2015. Their	report	was	filed	as	an	exhibit	to	the	prior	year	Annual	Report	on	Form	10-K.	The	individual	responsible	for	the	estimates	of	our	synthetic	crude	oil	reserves	had	15 years	of	experience	in	petroleum	engineering,	has	conducted	surface	mineable	oil	sands	evaluations	since	2009	and	is	a	registered	Practicing	Professional	Engineer	in	the Province	of	Alberta.

# Audits	of	Estimates

We	engage	third-party	consultants	to	provide,	at	a	minimum,	independent	estimates	for	fields	that	comprise	80%	of	our	total	proved	reserves	over	a	rolling	four- year	period.	We	exceeded	this	percentage	for	the	four-year	period	ended	December	31,	2017,	with	84%	of	our	total	proved	reserves	independently	audited.	An	audit tolerance	at	a	field	level	of	+/-	10%	to	our	internal	estimates	has	been	established.	Should	the	third-party	consultants'	initial	analysis	fall	outside	our	tolerance	band, both	parties	will	re-examine	the	information	provided,	request	additional	data	and	refine	their	analysis,	if	appropriate.	In	the	very	limited	instances	where	differences outside	the	10%	tolerance	cannot	be	resolved	by	year	end,	a	plan	to	resolve	the	difference	is	developed	and	executive	management	consent	is	obtained.	The	audit process	did	not	result	in	any	significant	changes	to	our	reserve	estimates	for	2017,	2016	or	2015.

During	2017,	2016	and	2015,	Netherland,	Sewell	&	Associates,	Inc.	prepared	a	reserves	certification	for	the	Alba	field	in	E.G.	The	NSAI	summary	reports	are	filed as	an	exhibit	to	this	Annual	Report	on	Form	10-K.	Members	of	the	NSAI	team	have	multiple	years	of	industry	experience,	having	worked	for	large,	international	oil	and gas	companies	before	joining	NSAI.	NSAI's	technical	team	members	meet	or	exceed	the	education,	training,	and	experience	requirements	set	forth	in	the	Standards Pertaining	to	the	Estimating	and	Auditing	of	Oil	and	Gas	Reserves	Information	promulgated	by	the	Society	of	Petroleum	Engineers.	The	senior	technical	advisor	has over	13	years	of	practical	experience	in	petroleum	engineering	and	the	estimation	and	evaluation	of	reserves	and	is	a	registered	Professional	Engineer	in	the	State	of Texas.	The	second	team	member	has	over	11	years	of	practical	experience	in	petroleum	geosciences	and	is	a	licensed	Professional	Geoscientist	in	the	State	of	Texas.

Ryder	Scott	Company	also	performed	audits	of	the	prior	years'	reserves	for	several	of	our	fields	in	2017,	2016	and	2015.	Their	summary	reports	are	filed	as	exhibits to	this	Annual	Report	on	Form	10-K.	The	team	lead	for	Ryder	Scott	has	over	35	years	of	industry	experience,	having	worked	for	a	major	financial	advisory	services group	before	joining	Ryder	Scott.	He	is	a	26	year	member	of	SPE	and	is	a	registered	Professional	Engineer	in	the	State	of	Texas.

# Estimated	Quantities	of	Proved	Oil	and	Gas	Reserves

The	estimation	of	net	recoverable	quantities	of	crude	oil	and	condensate,	natural	gas	liquids,	natural	gas	and	our	historical	synthetic	crude	oil	is	a	highly	technical process	which	is	based	upon	several	underlying	assumptions	that	are	subject	to	change.	Proved	reserves	are	determined	using	"SEC	Pricing",	calculated	as	an unweighted	arithmetic	average	of	the	first-day-of-the-month	closing	price	for	each	month.	See	Item	1A.	Risk	Factors	and	Item	7.	Management's	Discussion	and Analysis	of	Financial	Condition,	Cash	Flows	and	Liquidity	–	Critical	Accounting	Estimates	–	Estimated	Quantities	of	Net	Reserves	for	the	table	providing	our	2017 SEC	pricing	of	benchmark	prices	and	the	underlying	assumptions	used.

    The	table	below	provides	the	2017	SEC	pricing	for	certain	benchmark	prices:

| (mmbbl) | U.S. | E.G.(a) | Libya | Other	Int'l | Cont	Ops | Disc	Ops | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Crude\toil\tand\tcondensate |  |  |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2015 | 634 | 57 | 208 | 29 | 928 | — | 928 |
| Revisions\tof\tprevious\testimates | (57) | 2 | (7) | (2) | (64) | — | (64) |
| Improved\trecovery | 1 | — | — | — | 1 | — | 1 |
| Purchases\tof\treserves\tin\tplace | — | — | — | — | — | — | — |
| Extensions,\tdiscoveries\tand |  |  |  |  |  |  |  |
| other\tadditions | 70 | — | — | — | 70 | — | 70 |
| Production | (62) | (7) | — | (5) | (74) | — | (74) |
| Sales\tof\treserves\tin\tplace | (6) | — | — | — | (6) | — | (6) |
| End\tof\tyear\t-\t2015 | 580 | 52 | 201 | 22 | 855 | — | 855 |
| Revisions\tof\tprevious\testimates | 55 | 1 | (28) | 3 | 31 | — | 31 |
| Improved\trecovery | 4 | — | — | — | 4 | — | 4 |
| Purchases\tof\treserves\tin\tplace | 12 | — | — | — | 12 | — | 12 |
| Extensions,\tdiscoveries\tand |  |  |  |  |  |  |  |
| other\tadditions | 37 | — | — | 1 | 38 | — | 38 |
| Production | (48) | (8) | (1) | (4) | (61) | — | (61) |
| Sales\tof\treserves\tin\tplace | (77) | — | — | — | (77) | — | (77) |
| End\tof\tyear\t-\t2016 | 563 | 45 | 172 | 22 | 802 | — | 802 |
| Revisions\tof\tprevious\testimates | 9 | (2) | — | 8 | 15 | — | 15 |
| Improved\trecovery | — | — | — | — | — | — | — |
| Purchases\tof\treserves\tin\tplace | 18 | — | — | — | 18 | — | 18 |
| Extensions,\tdiscoveries\tand |  |  |  |  |  |  |  |
| other\tadditions | 30 | 4 | — | — | 34 | — | 34 |
| Production | (49) | (8) | (7) | (4) | (68) | — | (68) |
| Sales\tof\treserves\tin\tplace | (1) | — | — | — | (1) | — | (1) |
| End\tof\tyear\t-\t2017 | 570 | 39 | 165 | 26 | 800 | — | 800 |
| Proved\tdeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2015 | 294 | 30 | 175 | 19 | 518 | — | 518 |
| End\tof\tyear\t-\t2015 | 327 | 25 | 173 | 16 | 541 | — | 541 |
| End\tof\tyear\t-\t2016 | 238 | 45 | 172 | 13 | 468 | — | 468 |
| End\tof\tyear\t-\t2017 | 263 | 39 | 165 | 17 | 484 | — | 484 |
| Proved\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2015 | 340 | 27 | 33 | 10 | 410 | — | 410 |
| End\tof\tyear\t-\t2015 | 253 | 27 | 28 | 6 | 314 | — | 314 |
| End\tof\tyear\t-\t2016 | 325 | — | — | 9 | 334 | — | 334 |
| End\tof\tyear\t-\t2017 | 307 | — | — | 9 | 316 | — | 316 |

# Estimated	Quantities	of	Proved	Oil	and	Gas	Reserves	(continued)

| (mmbbl) | U.S. | E.G.(a) | Libya | Other	Int'l | Cont	Ops | Disc	Ops | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Natural\tgas\tliquids |  |  |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2015 | 161 | 30 | — | 1 | 192 | — | 192 |
| Revisions\tof\tprevious\testimates | (7) | 2 | — | (1) | (6) | — | (6) |
| Improved\trecovery | — | — | — | — | — | — | — |
| Purchases\tof\treserves\tin\tplace | — | — | — | — | — | — | — |
| Extensions,\tdiscoveries\tand |  |  |  |  |  |  |  |
| other\tadditions | 33 | — | — | — | 33 | — | 33 |
| Production | (14) | (4) | — | — | (18) | — | (18) |
| Sales\tof\treserves\tin\tplace | (1) | — | — | — | (1) | — | (1) |
| End\tof\tyear\t-\t2015 | 172 | 28 | — | — | 200 | — | 200 |
| Revisions\tof\tprevious\testimates | (8) | — | — | — | (8) | — | (8) |
| Improved\trecovery | — | — | — | — | — | — | — |
| Purchases\tof\treserves\tin\tplace | 12 | — | — | — | 12 | — | 12 |
| Extensions,\tdiscoveries\tand |  |  |  |  |  |  |  |
| other\tadditions | 11 | — | — | — | 11 | — | 11 |
| Production | (14) | (4) | — | — | (18) | — | (18) |
| Sales\tof\treserves\tin\tplace | (3) | — | — | — | (3) | — | (3) |
| End\tof\tyear\t-\t2016 | 170 | 24 | — | — | 194 | — | 194 |
| Revisions\tof\tprevious\testimates | 37 | 3 | — | — | 40 | — | 40 |
| Improved\trecovery | — | — | — | — | — | — | — |
| Purchases\tof\treserves\tin\tplace | 5 | — | — | — | 5 | — | 5 |
| Extensions,\tdiscoveries\tand |  |  |  |  |  |  |  |
| other\tadditions | 34 | 2 | — | — | 36 | — | 36 |
| Production | (16) | (4) | — | — | (20) | — | (20) |
| Sales\tof\treserves\tin\tplace | (1) | — | — | — | (1) | — | (1) |
| End\tof\tyear\t-\t2017 | 229 | 25 | — | — | 254 | — | 254 |
| Proved\tdeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2015 | 68 | 15 | — | — | 83 | — | 83 |
| End\tof\tyear\t-\t2015 | 92 | 12 | — | — | 104 | — | 104 |
| End\tof\tyear\t-\t2016 |  |  |  |  |  |  |  |
|  | 78 | 24 | — | — | 102 | — | 102 |
| End\tof\tyear\t-\t2017 | 118 | 25 | — | — | 143 | — | 143 |
| Proved\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2015 | 93 | 15 | — | 1 | 109 | — | 109 |
| End\tof\tyear\t-\t2015 | 80 | 16 | — | — | 96 | — | 96 |
| End\tof\tyear\t-\t2016 | 92 | — | — | — | 92 | — | 92 |
| End\tof\tyear\t-\t2017 | 111 | — | — | — | 111 | — | 111 |

| (bcf) | U.S. | E.G.(a) | Libya | Other	Int'l | Cont	Ops | Disc	Ops | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Natural\tgas |  |  |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2015 | 1,144 | 1,205 | 209 | 22 | 2,580 | — | 2,580 |
| Revisions\tof\tprevious\testimates | (22) | 35 | (3) | 1 | 11 | — | 11 |
| Improved\trecovery | — | — | — | — | — | — | — |
| Purchases\tof\treserves\tin\tplace | 1 | — | — | — | 1 | — | 1 |
| Extensions,\tdiscoveries\tand |  |  |  |  |  |  |  |
| other\tadditions | 225 | — | — | — | 225 | — | 225 |
| Production\t(b) | (128) | (150) | — | (8) | (286) | — | (286) |
| Sales\tof\treserves\tin\tplace | (69) | — | — | — | (69) | — | (69) |
| End\tof\tyear\t-\t2015 | 1,151 | 1,090 | 206 | 15 | 2,462 | — | 2,462 |
| Revisions\tof\tprevious\testimates | 145 | 8 | (1) | 3 | 155 | — | 155 |
| Improved\trecovery | — | — | — | — | — | — | — |
| Purchases\tof\treserves\tin\tplace | 61 | — | — | — | 61 | — | 61 |
| Extensions,\tdiscoveries\tand |  |  |  |  |  |  |  |
| other\tadditions | 71 | — | — | — | 71 | — | 71 |
| Production\t(b) | (115) | (155) | — | (8) | (278) | — | (278) |
| Sales\tof\treserves\tin\tplace | (25) | — | — | — | (25) | — | (25) |
| End\tof\tyear\t-\t2016 | 1,288 | 943 | 205 | 10 | 2,446 | — | 2,446 |
| Revisions\tof\tprevious\testimates | (33) | (18) | — | 4 | (47) | — | (47) |
| Improved\trecovery | — | — | — | — | — | — | — |
| Purchases\tof\treserves\tin\tplace | 36 | — | — | — | 36 | — | 36 |
| Extensions,\tdiscoveries\tand |  |  |  |  |  |  |  |
| other\tadditions | 204 | 76 | — | — | 280 | — | 280 |
| Production\t(b) | (127) | (168) | (1) | (6) | (302) | — | (302) |
| Sales\tof\treserves\tin\tplace | (44) | — | — | — | (44) | — | (44) |
| End\tof\tyear\t-\t2017 | 1,324 | 833 | 204 | 8 | 2,369 | — | 2,369 |
| Proved\tdeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2015 | 575 | 664 | 94 | 17 | 1,350 | — | 1,350 |
| End\tof\tyear\t-\t2015 |  |  |  |  |  |  |  |
|  | 640 | 552 | 94 | 11 | 1,297 | — | 1,297 |
| End\tof\tyear\t-\t2016 | 648 | 943 | 95 | 5 | 1,691 | — | 1,691 |
| End\tof\tyear\t-\t2017 | 726 | 833 | 94 | 2 | 1,655 | — | 1,655 |
| Proved\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2015 | 569 | 541 | 115 | 5 | 1,230 | — | 1,230 |
| End\tof\tyear\t-\t2015 | 511 | 538 | 112 | 4 | 1,165 | — | 1,165 |
| End\tof\tyear\t-\t2016 | 640 | — | 110 | 5 | 755 | — | 755 |
| End\tof\tyear\t-\t2017 | 598 | — | 110 | 6 | 714 | — | 714 |

| (mmbbl) | U.S. | E.G.(a) | Libya | Other	Int'l | Cont	Ops | Disc	Ops | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Synthetic\tcrude\toil |  |  |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2015 | — | — | — | — | — | 648 | 648 |
| Revisions\tof\tprevious\testimates | — | — | — | — | — | 67 | 67 |
| Improved\trecovery | — | — | — | — | — | — | — |
| Purchases\tof\treserves\tin\tplace | — | — | — | — | — | — | — |
| Extensions,\tdiscoveries\tand |  |  |  |  |  |  |  |
| other\tadditions | — | — | — | — | — | — | — |
| Production | — | — | — | — | — | (17) | (17) |
| Sales\tof\treserves\tin\tplace | — | — | — | — | — | — | — |
| End\tof\tyear\t-\t2015 | — | — | — | — | — | 698 | 698 |
| Revisions\tof\tprevious\testimates | — | — | — | — | — | 12 | 12 |
| Improved\trecovery | — | — | — | — | — | — | — |
| Purchases\tof\treserves\tin\tplace | — | — | — | — | — | — | — |
| Extensions,\tdiscoveries\tand |  |  |  |  |  |  |  |
| other\tadditions | — | — | — | — | — | — | — |
| Production | — | — | — | — | — | (18) | (18) |
| Sales\tof\treserves\tin\tplace | — | — | — | — | — | — | — |
| End\tof\tyear\t-\t2016 | — | — | — | — | — | 692 | 692 |
| Revisions\tof\tprevious\testimates | — | — | — | — | — | — | — |
| Improved\trecovery | — | — | — | — | — | — | — |
| Purchases\tof\treserves\tin\tplace | — | — | — | — | — | — | — |
| Extensions,\tdiscoveries\tand |  |  |  |  |  |  |  |
| other\tadditions | — | — | — | — | — | — | — |
| Production | — | — | — | — | — | (7) | (7) |
| Sales\tof\treserves\tin\tplace | — | — | — | — | — | (685) | (685) |
| End\tof\tyear\t-\t2017 | — | — | — | — | — | — | — |
| Proved\tdeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2015 | — | — | — | — | — | 644 | 644 |
| End\tof\tyear\t-\t2015 | — | — | — | — | — | 698 | 698 |
| End\tof\tyear\t-\t2016 | — | — | — | — | — | 692 | 692 |
| End\tof\tyear\t-\t2017 | — | — | — | — | — | — | — |
| Proved\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2015 | — | — | — | — | — | 4 | 4 |
| End\tof\tyear\t-\t2015 | — | — | — | — | — | — | — |
| End\tof\tyear\t-\t2016 | — | — | — | — | — | — | — |
| End\tof\tyear\t-\t2017 | — | — | — | — | — | — | — |

| (mmboe) | U.S. | E.G.(a) | Libya | Other	Int'l | Cont	Ops | Disc	Ops | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Total\tProved\tReserves |  |  |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2015 | 986 | 288 | 243 | 33 | 1,550 | 648 | 2,198 |
| Revisions\tof\tprevious\testimates | (67) | 8 | (8) | (2) | (69) | 67 | (2) |
| Improved\trecovery | 1 | — | — | — | 1 | — | 1 |
| Purchases\tof\treserves\tin\tplace | 1 | — | — | — | 1 | — | 1 |
| Extensions,\tdiscoveries\tand |  |  |  |  |  |  |  |
| other\tadditions | 139 | 1 | — | — | 140 | — | 140 |
| Production\t(b) | (98) | (36) | — | (6) | (140) | (17) | (157) |
| Sales\tof\treserves\tin\tplace | (18) | — | — | — | (18) | — | (18) |
| End\tof\tyear\t-\t2015 | 944 | 261 | 235 | 25 | 1,465 | 698 | 2,163 |
| Revisions\tof\tprevious\testimates | 73 | 2 | (28) | 4 | 51 | 12 | 63 |
| Improved\trecovery | 4 | — | — | — | 4 | — | 4 |
| Purchases\tof\treserves\tin\tplace | 34 | — | — | — | 34 | — | 34 |
| Extensions,\tdiscoveries\tand |  |  |  |  |  |  |  |
| other\tadditions | 59 | — | — | 1 | 60 | — | 60 |
| Production\t(b) | (82) | (37) | (1) | (6) | (126) | (18) | (144) |
| Sales\tof\treserves\tin\tplace | (84) | — | — | — | (84) | — | (84) |
| End\tof\tyear\t-\t2016 | 948 | 226 | 206 | 24 | 1,404 | 692 | 2,096 |
| Revisions\tof\tprevious\testimates | 42 | (1) | — | 8 | 49 | — | 49 |
| Improved\trecovery | — | — | — | — | — | — | — |
| Purchases\tof\treserves\tin\tplace | 28 | — | — | — | 28 | — | 28 |
| Extensions,\tdiscoveries\tand |  |  |  |  |  |  |  |
| other\tadditions | 98 | 18 | — | — | 116 | — | 116 |
| Production\t(b) | (86) | (40) | (7) | (5) | (138) | (7) | (145) |
| Sales\tof\treserves\tin\tplace | (10) | — | — | — | (10) | (685) | (695) |
| End\tof\tyear\t-\t2017 | 1,020 | 203 | 199 | 27 | 1,449 | — | 1,449 |
| Proved\tdeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2015 | 458 | 155 | 191 | 22 | 826 | 644 | 1,470 |
| End\tof\tyear\t-\t2015 | 526 | 129 | 189 | 18 | 862 | 698 | 1,560 |
| End\tof\tyear\t-\t2016 | 424 | 226 | 188 | 14 | 852 | 692 | 1,544 |
| End\tof\tyear\t-\t2017 | 502 | 203 | 181 | 17 | 903 | — | 903 |
| Proved\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2015 | 528 | 133 | 52 | 11 | 724 | 4 | 728 |
| End\tof\tyear\t-\t2015 | 418 | 132 | 46 | 7 | 603 | — | 603 |
| End\tof\tyear\t-\t2016 | 524 | — | 18 | 10 | 552 | — | 552 |
| End\tof\tyear\t-\t2017 | 518 | — | 18 | 10 | 546 | — | 546 |

(a) Consists	of	estimated	reserves	from	properties	governed	by	production	sharing	contracts.

(b) Excludes	the	resale	of	purchased	natural	gas	used	in	reservoir	management.

2017	proved	reserves	decreased	by	647	mmboe	primarily	due	to	the	following:

•Revisions	of	previous	estimates:	Increased	by	49	mmboe	primarily	due	to	the	acceleration	of	higher	economic	wells	in	the	Bakken	into	the	5-year	plan	resulting	in an	increase	of	44	mmboe,	with	the	remainder	being	due	to	revisions	across	the	business.

•Extensions,	discoveries,	and	other	additions:	Increased	by	116	mmboe	primarily	due	to	an	increase	of	97	mmboe	associated	with	the	expansion	of	proved	areas	and wells	to	sales	from	unproved	categories	in	Oklahoma.

•Purchases	of	reserves	in	place:	Increased	by	28	mmboe	from	acquisitions	of	assets	in	the	Northern	Delaware	Basin	in	New

Mexico.

•Production:	Decreased	by	145	mmboe.

•Sales	of	reserves	in	place:	Decreased	by	695	mmboe	including	685	mmboe	associated	with	the	sale	of	our	Canadian	business	and	10	mmboe	associated	with divestitures	of	certain	conventional	assets	in	Oklahoma	and	Colorado.	See	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	5	to	the	consolidated financial	statements	for	information	regarding	these	dispositions.

•Revisions	of	previous	estimates:	Increased	by	63	mmboe	primarily	due	to	an	increase	of	151	mmboe	associated	with	the	acceleration	of	higher	economic	wells	in the	U.S.	resource	plays	into	the	5-year	plan	and	a	decrease	of	64	mmboe	due	to	U.S.	technical	revisions.

•Extensions,	discoveries,	and	other	additions:	Increased	by	60	mmboe	primarily	associated	with	the	expansion	of	proved	areas	and	new	wells	to	sales	from	unproven categories	in	Oklahoma.

•Purchases	of	reserves	in	place:	Increased	by	34	mmboe	from	acquisition	of	STACK	assets	in

Oklahoma.

•Sales	of	reserves	in	place:	Decreased	by	84	mmboe	associated	with	the	divestitures	of	certain	Wyoming	and	Gulf	of	Mexico assets.

•Revisions	of	previous	estimates:	Decreased	by	2	mmboe	primarily	resulting	from	an	increase	of	105	mmboe	associated	with	drilling	programs	in	U.S.	resource plays	and	an	increase	of	67	mmboe	in	discontinued	operations	due	to	technical	reevaluation	and	lower	royalty	percentages	related	to	lower	realized	prices,	offset	by a	decrease	of	173	mmboe	which	was	largely	due	to	reductions	to	our	capital	development	program	and	adherence	to	the	SEC	5-year	rule.

•Extensions,	discoveries,	and	other	additions:	Increased	by140	mmboe	as	a	result	of	drilling	programs	in	our	U.S.	resource

plays.

•Sales	of	reserves	in	place:	U.S.	conventional	assets	sales	contributed	to	a	decrease	of	18

mmboe.

# Changes	in	Proved	Undeveloped	Reserves

As	of	December	31,	2017,	546	mmboe	of	proved	undeveloped	reserves	were	reported,	a	decrease	of	6	mmboe	from	December	31,	2016.	The	following	table	shows changes	in	proved	undeveloped	reserves	for	2017:

| (mmboe) |  |
| :--- | :--- |
| Beginning\tof\tyear | 552 |
| Revisions\tof\tprevious\testimates | 5 |
| Improved\trecovery | — |
| Purchases\tof\treserves\tin\tplace | 15 |
| Extensions,\tdiscoveries,\tand\tother\tadditions | 57 |
| Dispositions | — |
| Transfers\tto\tproved\tdeveloped | (83) |
| End\tof\tyear | 546 |

Revisions	of	prior	estimates.	Revisions	of	prior	estimates	increased	5	mmboe	during	2017,	primarily	due	to	a	44	mmboe	increase	in	the	Bakken	from	an	acceleration	of higher	economic	wells	into	the	5-year	plan,	offset	by	a	decrease	of	40	mmboe	in	Oklahoma	due	to	the	removal	of	less	economic	wells	from	the	5-year	plan.

Extensions,	discoveries	and	other	additions.	Increased	57	mmboe	through	expansion	of	proved	areas	in	Oklahoma.

Transfers	to	proved	developed.	83	mmboe	of	PUD	reserves	were	converted	to	proved	developed	status	during	2017,	primarily	from	assets	in	our	U.S.	resource	plays. This	2017	transfer	equates	to	a	15%	PUD	conversion	rate	and	a	5-year	average	annual	PUD	conversion	rate	during	the	2013-2017	period	of	18%.	All	proved undeveloped	reserve	drilling	locations	are	scheduled	to	be	drilled	prior	to	the	end	of	2022.

A	total	of	25	mmboe	of	proved	undeveloped	reserves,	or	less	than	2%	of	the	company's	total	proved	reserves,	have	been	on	the	books	beyond	5	years	as	of	year-end 2017.

As	of	year-end	2017,	there	were	18	mmboe	of	proved	undeveloped	reserves,	initially	disclosed	in	2012,	associated	with	the	Faregh	Phase	II	project	in	Libya.	Drilling operations	and	construction	of	the	associated	gas	plant	were	completed	in	2010.	Final	commissioning	was	halted	in	2011	and	again	in	2013	due	to	civil	unrest	and subsequent	declaration	of	Force	Majeure.		In	2017,	teams	conducted	an	assessment	of	the	facilities	to	determine	the	state	of	the	equipment	and	developed	a	plan	to recommission	the	plant	and	initiate	production	in	2018,	at	which	time,	all	associated	proved	undeveloped	reserves	will	be	transferred	to	proved	developed.

As	of	year-end	2017,	there	were	7	mmboe	of	proved	undeveloped	reserves,	initially	disclosed	in	2011,	associated	with	the	Fuel	Gas	Deficiency	project	in	the	U.K.	The project	includes	the	design,	procurement	and	installation	of	the	Brae	Bravo	gas	by-pass,	which	will	ensure	continued	operations	at	the	existing	Brae	Alpha	and	East	Brae platforms.	The	project	has	been	approved	and	work	is	underway	with	completion	expected	in	2018,	at	which	time,	all	associated	proved	undeveloped	reserves	will	be transferred	to	proved	developed.

# Costs	Incurred	&	Future	Costs	to	Develop

Costs	incurred	in	2017,	2016	and	2015	relating	to	the	development	of	proved	undeveloped	reserves	were	$842	million,	$359	million	and	$1,415	million.	As	of December	31,	2017,	future	development	costs	estimated	to	be	required	for	the	development	of	proved	undeveloped	crude	oil	and	condensate,	NGLs	and	natural	gas reserves	for	the	years	2018	through	2022	are	projected	to	be	$1,425	million,	$1,348	million,	$1,409	million,	$1,458	million	and	$1,028	million.

# Capitalized	Costs	and	Accumulated	Depreciation,	Depletion	and	Amortization

|  |  |  | Year	Ended	December	31, | Year	Ended	December	31, |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | U.S. | E.G. | Libya | Other\tAfrica | Other\tAfrica | Other\tInt'l | Total |
| 2017\tCapitalized\tCosts: |  |  |  |  |  |  |  |
| Proved\tproperties | $27,477 | $1,990 | 830 | $— | $— | $5,050 | $35,347 |
| Unproved\tproperties | 2,755 | 110 | 217 | 217 | 43 | 33 | 3,158 |
| Total | 30,232 | 2,100 | 1,047 | 43 | 43 | 5,083 | 38,505 |
| Accumulated\tdepreciation, |  |  |  |  |  |  |  |
| depletion\tand\tamortization: |  |  |  |  |  |  |  |
| Proved\tproperties | 14,254 | 1,348 | 289 | 289 | — | 4,850 | 20,741 |
| Unproved\tproperties\t(a) | 206 | — | — | 43 | 43 | 33 | 282 |
| Total | 14,460 | 1,348 | 289 | 289 | 43 | 4,883 | 21,023 |
| Net\tcapitalized\tcosts | $15,772 | $752 | $758 | $— | $— | $200 | $17,482 |
| 2016\tCapitalized\tCosts: |  |  |  |  |  |  |  |
| Proved\tproperties | $25,497 | $1,978 | $756 | $— | $— | $5,864 | $34,095 |
| Unproved\tproperties | 1,473 | 119 | 281 | 136 | 136 | 183 | 2,192 |
| Total | 26,970 | 2,097 | 1,037 | 136 | 136 | 6,047 | 36,287 |
| Accumulated\tdepreciation, |  |  |  |  |  |  |  |
| depletion\tand\tamortization: |  |  |  |  |  |  |  |
| Proved\tproperties | 12,526 | 1,216 | 268 | 268 | 1 | 5,246 | 19,257 |
| Unproved\tproperties\t(a) | 382 | 2 | — | — | — | 113 | 497 |
| Total | 12,908 | 1,218 | 268 | 1 | 1 | 5,359 | 19,754 |
| Net\tcapitalized\tcosts | $14,062 | $879 | $769 | $135 | $135 | $688 | $16,533 |

(a)	Includes	unproved	property	impairments	(see	Note	10).

# Costs	Incurred	for	Property	Acquisition,	Exploration	and	Development	 (a)

| (In	millions) | U.S. | E.G. | Libya | Other<br>Africa | Other	Int'l |  | Cont	Ops | Disc	Ops | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| December\t31,\t2017 |  |  |  |  |  |  |  |  |  |
| Property\tacquisition: |  |  |  |  |  |  |  |  |  |
| Proved | $191 | $1 | $— | $— | $— |  | $192 | $— | $192 |
| Unproved | 1,746 | — | — | 1 | — |  | 1,747 | — | 1,747 |
| Exploration | 882 | 1 | — | 37 | 3 |  | 923 | — | 923 |
| Development | 1,122 | 5 | 10 | — | (144) | (b) | 993 | 6 | 999 |
| Total | $3,941 | $7 | $10 | $38 | $(141) |  | $3,855 | $6 | $3,861 |
| December\t31,\t2016 |  |  |  |  |  |  |  |  |  |
| Property\tacquisition: |  |  |  |  |  |  |  |  |  |
| Proved | $276 | $— | $— | $— | $— |  | $276 | $— | $276 |
| Unproved | 642 | — | — | 1 | (11) |  | 632 | — | 632 |
| Exploration | 525 | 1 | — | 10 | 3 |  | 539 | — | 539 |
| Development | 456 | 55 | 3 | — | 121 | (b) | 635 | 31 | 666 |
| Total | $1,899 | $56 | $3 | $11 | $113 |  | $2,082 | $31 | $2,113 |
| December\t31,\t2015 |  |  |  |  |  |  |  |  |  |
| Property\tacquisition: |  |  |  |  |  |  |  |  |  |
| Proved | $4 | $— | $— | $— | $— |  | $4 | $— | $4 |
| Unproved | 61 | — | — | 1 | — |  | 62 | — | 62 |
| Exploration | 959 | 60 | 1 | 37 | 50 |  | 1,107 | 1 | 1,108 |
| Development | 1,477 | 150 | 13 | — | 31 |  | 1,671 | — | 1,671 |
| Total | $2,501 | $210 | $14 | $38 | $81 |  | $2,844 | $1 | $2,845 |

(a) Includes	costs	incurred	whether	capitalized	or	expensed.

(b) Includes	revisions	to	asset	retirement	costs	primarily	due	to	changes	in	U.K.	estimated	costs	as	well	as	timing	of	abandonment	activities	in	the	U.K.

# Results	of	Operations	for	Oil	and	Gas	Producing	Activities

|  | U.S. | E.G. | Libya | Other<br>Africa | Other	Int'l | Cont	Ops | Disc	Ops | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Year\tEnded\tDecember\t31,\t2017 |  |  |  |  |  |  |  |  |
| Revenues\tand\tother\tincome: |  |  |  |  |  |  |  |  |
| Sales | $3,050 | $45 | $431 | $— | $282 | $3,808 | $423 | $4,231 |
| Transfers | — | 344 | — | — | — | 344 | — | 344 |
| Other\tincome(a) | 74 | — | — | — | 38 | 112 | (43) | 69 |
| Total\trevenues\tand\tother\tincome | 3,124 | 389 | 431 | — | 320 | 4,264 | 380 | 4,644 |
| Expenses: |  |  |  |  |  |  |  |  |
| Production\tcosts | (985) | (84) | (44) | — | (152) | (1,265) | (272) | (1,537) |
| Exploration\texpenses(b) | (153) | — | — | (171) | (83) | (407) | — | (407) |
| Depreciation,\tdepletion\tand |  |  |  |  |  |  |  |  |
| amortization(c) | (2,105) | (134) | (21) | — | (273) | (2,533) | (6,676) | (9,209) |
| Technical\tsupport\tand\tother | (28) | (4) | (4) | (7) | (18) | (61) | — | (61) |
| Total\texpenses | (3,271) | (222) | (69) | (178) | (526) | (4,266) | (6,948) | (11,214) |
| Results\tbefore\tincome\ttaxes | (147) | 167 | 362 | (178) | (206) | (2) | (6,568) | (6,570) |
| Income\ttax\tprovision | (1) | (50) | (333) | — | 13 | (371) | 1,674 | 1,303 |
| Results\tof\toperations | $(148) | $117 | $29 | $(178) | $(193) | $(373) | $(4,894) | $(5,267) |
| Year\tEnded\tDecember\t31,\t2016 |  |  |  |  |  |  |  |  |
| Revenues\tand\tother\tincome: |  |  |  |  |  |  |  |  |
| Sales | $2,249 | $42 | $54 | $— | $237 | $2,582 | $724 | $3,306 |
| Transfers | — | 291 | — | — | — | 291 | — | 291 |
| Other\tincome(a) | 387 | — | — | — | 2 | 389 | — | 389 |
| Total\trevenues\tand\tother\tincome | 2,636 | 333 | 54 | — | 239 | 3,262 | 724 | 3,986 |
| Expenses: |  |  |  |  |  |  |  |  |
| Production\tcosts | (952) | (81) | (36) | — | (140) | (1,209) | (544) | (1,753) |
| Exploration\texpenses(b) | (306) | (1) | (6) | (8) | (2) | (323) | (7) | (330) |
| Depreciation,\tdepletion\tand |  |  |  |  |  |  |  |  |
| amortization(c) | (1,901) | (114) | (7) | — | (132) | (2,154) | (239) | (2,393) |
| Technical\tsupport\tand\tother | (21) | (4) | — | (3) | (2) | (30) | (1) | (31) |
| Total\texpenses | (3,180) | (200) | (49) | (11) | (276) | (3,716) | (791) | (4,507) |
| Results\tbefore\tincome\ttaxes | (544) | 133 | 5 | (11) | (37) | (454) | (67) | (521) |
| Income\ttax\tprovision\t(d) | 195 | (26) | (2) | — | 57 | 224 | 15 | 239 |
| Results\tof\toperations | $(349) | $107 | $3 | $(11) | $20 | $(230) | $(52) | $(282) |
| Year\tEnded\tDecember\t31,\t2015 |  |  |  |  |  |  |  |  |
| Revenues\tand\tother\tincome: |  |  |  |  |  |  |  |  |
| Sales | $3,374 | $40 | $— | $— | $329 | $3,743 | $700 | $4,443 |
| Transfers | — | 296 | — | — | — | 296 | — | 296 |
| Other\tincome(a) | 230 | — | — | (109) | 1 | 122 | — | 122 |
| Total\trevenues\tand\tother\tincome | 3,604 | 336 | — | (109) | 330 | 4,161 | 700 | 4,861 |
| Expenses: |  |  |  |  |  |  |  |  |
| Production\tcosts | (1,259) | (84) | (31) | — | (177) | (1,551) | (660) | (2,211) |
| Exploration\texpenses(b) | (750) | (41) | — | (36) | (143) | (970) | (348) | (1,318) |
| Depreciation,\tdepletion\tand |  |  |  |  |  |  |  |  |
| amortization(c) | (2,758) | (92) | (5) | — | (163) | (3,018) | (266) | (3,284) |
| Technical\tsupport\tand\tother | (47) | (6) | (1) | (1) | (3) | (58) | (2) | (60) |
| Total\texpenses | (4,814) | (223) | (37) | (37) | (486) | (5,597) | (1,276) | (6,873) |
| Results\tbefore\tincome\ttaxes | (1,210) | 113 | (37) | (146) | (156) | (1,436) | (576) | (2,012) |
| Income\ttax\tprovision | 437 | (33) | 37 | 50 | 86 | 577 | 31 | 608 |
| Results\tof\toperations | $(773) | $80 | $— | $(96) | $(70) | $(859) | $(545) | $(1,404) |

(a) Includes	net	gain	(loss)	on	dispositions	(see	Note	5)	and	revisions	to	asset	retirement	costs	primarily	due	to	changes	in	U.K.	estimated	costs	as	well	as	timing	of	abandonment	activities	in	the U.K.

(b) Includes	exploratory	dry	well	costs,	unproved	property	impairments,	and	other	(see	Note 10).

(c) Includes	long-lived	asset	impairments	(see	Note	10).

(d)				Discontinued	operations	activity	includes	$135	million	of	deferred	tax	expense	related	to	Alberta	provincial	corporate	tax	rate	increase.

The	following	reconciles	results	of	operations	for	oil	and	gas	producing	activities	to	segment	income:

|  | Year	Ended	December	31, | Year	Ended	December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 | 2015 |
| Results\tof\toperations | $(5,267) | $(282) | $(1,404) |
| Discontinued\toperations | 4,894 | 52 | 545 |
| Results\tof\tcontinuing\toperations | (373) | (230) | (859) |
| Items\tnot\tincluded\tin\tresults\tof\toil\tand\tgas\toperations,\tnet\tof\ttax: |  |  |  |
| Marketing\tincome\tand\tother\tnon-oil\tand\tgas\tproducing\trelated\tactivities | (107) | (39) | (102) |
| Income\tfrom\tequity\tmethod\tinvestments | 229 | 142 | 127 |
| Items\tnot\tallocated\tto\tsegment\tincome,\tnet\tof\ttax: |  |  |  |
| Loss\t(gain)\ton\tasset\tdispositions\tand\tother\tincome | (79) | (248) | (76) |
| Long-lived\tasset\timpairments | 475 | 148 | 602 |
| Unrealized\tloss\t(gain)\ton\tderivatives | 81 | 72 | (32) |
| Deferred\ttax\tvaluation\tallowance\tincrease | — | (32) | — |
| Segment\tincome | $226 | $(187) | $(340) |

# Standardized	Measure	of	Discounted	Future	Net	Cash	Flows	Relating	to	Proved	Reserves

U.S.	GAAP	prescribes	guidelines	for	computing	the	standardized	measure	of	future	net	cash	flows	and	changes	therein	relating	to	estimated	proved	reserves,	giving very	specific	assumptions	to	be	made	such	as	the	use	of	a	10%	discount	rate	and	an	unweighted	average	of	commodity	prices	in	the	prior	12-month	period	using	the closing	prices	on	the	first	day	of	each	month	as	well	as	current	costs	applicable	at	the	date	of	the	estimate.	These	and	other	required	assumptions	have	not	always	proved accurate	in	the	past,	and	other	valid	assumptions	would	give	rise	to	substantially	different	results.	In	addition,	the	10%	discount	rate	required	to	be	used	is	not	necessarily the	most	appropriate	discount	factor	based	on	our	cost	of	capital	and	the	risks	associated	with	our	business	and	the	oil	and	natural	gas	industry	in	general.	This information	is	not	the	fair	value	nor	does	it	represent	the	expected	present	value	of	future	cash	flows	of	our	crude	oil	and	condensate,	natural	gas	liquid,	and	natural	gas reserves.

| (In	millions) | U.S. | E.G. | Libya | Other	Int'l |  | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Year\tEnded\tDecember\t31,\t2017 |  |  |  |  |  |  |
| Future\tcash\tinflows | $36,480 | $1,966 | $10,303 | $1,403 |  | $50,152 |
| Future\tproduction\tand\tsupport\tcosts | (14,796) | (748) | (931) | (821) |  | (17,296) |
| Future\tdevelopment\tcosts | (6,987) | (7) | (501) | (1,247) |  | (8,742) |
| Future\tincome\ttax\texpenses | (786) | (274) | (8,387) | 496 |  | (8,951) |
| Future\tnet\tcash\tflows | $13,911 | $937 | $484 | $(169) | (a) | $15,163 |
| 10%\tannual\tdiscount\tfor\ttiming\tof\tcash\tflows | (7,009) | (235) | (224) | 168 |  | (7,300) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows-\nrelated\tto\tcontinuing\toperations | $6,902 | $702 | $260 | $(1) |  | $7,863 |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows-\nrelated\tto\tdiscontinued\toperations |  |  |  |  |  | — |
| Year\tEnded\tDecember\t31,\t2016 |  |  |  |  |  |  |
| Future\tcash\tinflows | $27,610 | $1,977 | $8,511 | $921 |  | $39,019 |
| Future\tproduction\tand\tsupport\tcosts | (12,758) | (824) | (930) | (673) |  | (15,185) |
| Future\tdevelopment\tcosts | (7,233) | (13) | (296) | (1,345) |  | (8,887) |
| Future\tincome\ttax\texpenses | — | (251) | (6,884) | 514 |  | (6,621) |
| Future\tnet\tcash\tflows | $7,619 | $889 | $401 | $(583) | (a) | $8,326 |
| 10%\tannual\tdiscount\tfor\ttiming\tof\tcash\tflows | (4,355) | (264) | (143) | 313 |  | (4,449) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows-\nrelated\tto\tcontinuing\toperations | $3,264 | $625 | $258 | $(270) |  | $3,877 |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows-\nrelated\tto\tdiscontinued\toperations |  |  |  |  |  | $1,076 |
| Year\tEnded\tDecember\t31,\t2015 |  |  |  |  |  |  |
| Future\tcash\tinflows | $31,026 | $2,671 | $12,157 | $1,281 |  | $47,135 |
| Future\tproduction\tand\tsupport\tcosts | (12,270) | (1,095) | (901) | (902) |  | (15,168) |
| Future\tdevelopment\tcosts | (6,637) | (94) | (689) | (1,537) |  | (8,957) |
| Future\tincome\ttax\texpenses | (778) | (369) | (9,857) | 602 |  | (10,402) |
| Future\tnet\tcash\tflows | $11,341 | $1,113 | $710 | $(556) | (a) | $12,608 |
| 10%\tannual\tdiscount\tfor\ttiming\tof\tcash\tflows | (6,082) | (380) | (441) | 352 |  | (6,551) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows-\nrelated\tto\tcontinuing\toperations | $5,259 | $733 | $269 | $(204) |  | $6,057 |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows-\nrelated\tto\tdiscontinued\toperations |  |  |  |  |  | $165 |

# Changes	in	the	Standardized	Measure	of	Discounted	Future	Net	Cash	Flows

|  |  | Year	Ended	December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | 2017 | 2016 | 2015 |  |
| Sales\tand\ttransfers\tof\toil\tand\tgas\tproduced,\tnet\tof\tproduction\tand\tsupport\tcosts | $(2,853) | $(1,634) | $(2,422) |  |
| Net\tchanges\tin\tprices\tand\tproduction\tand\tsupport\tcosts\trelated\tto\tfuture\tproduction | 4,916 | (3,621)\n(b) | (21,309) | (b) |
| Extensions,\tdiscoveries\tand\timproved\trecovery,\tless\trelated\tcosts | 661 | (2,174) | 6 |  |
| Development\tcosts\tincurred\tduring\tthe\tperiod | 1,027 | 669 | 1,693 |  |
| Changes\tin\testimated\tfuture\tdevelopment\tcosts | 183 | 2,534 | 7,247 |  |
| Revisions\tof\tprevious\tquantity\testimates(a) | 497 | 654 | (5,682) |  |
| Net\tchanges\tin\tpurchases\tand\tsales\tof\tminerals\tin\tplace | 102 | (651) | (460) |  |
| Accretion\tof\tdiscount | 698 | 1,005 | 2,719 |  |
| Net\tchange\tin\tincome\ttaxes | (1,245) | 1,038 | 9,989 |  |
| Net\tchange\tfor\tthe\tyear | 3,986 | (2,180) | (8,219) |  |
| Beginning\tof\tthe\tyear\trelated\tto\tcontinuing\toperations | 3,877 | 6,057 | 14,276 |  |
| End\tof\tthe\tyear\trelated\tto\tcontinuing\toperations | $7,863 | $3,877 | $6,057 |  |
| Net\tchange\tfor\tthe\tyear\trelated\tto\tdiscontinued\toperations | $— | $911 | $(2,115) |  |

(a)	Includes	amounts	resulting	from	changes	in	the	timing	of	production.

(b) Decrease	primarily	due	to	lower	realized	prices.

# Item	9.	Changes	in	and	Disagreements	with	Accountants	on	Accounting	and	Financial	Disclosure

# Item	9A.	Controls	and	Procedures

# Disclosure	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 Securities	Exchange	Act	of	1934)	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	December	31,	2017.

# Management's	Annual	Report	on	Internal	Control	Over	Financial	Reporting

See	"Management's	Report	on	Internal	Control	over	Financial	Reporting"	under	Item	8	of	this	Form	10-K.

# Attestation	Report	of	the	Registered	Public	Accounting	Firm

See	"Report	of	Independent	Registered	Public	Accounting	Firm"	under	Item	8	of	this	Form	10-K.

# Changes	in	Internal	Control	Over	Financial	Reporting

During	the	fourth	quarter	of	2017,	there	were	no	changes	in	our	internal	control	over	financial	reporting	that	have	materially	affected,	or	were	reasonably	likely	to materially	affect,	our	internal	control	over	financial	reporting.

# Item	9B.	Other	Information

# PART	III

# Item	10.	Directors,	Executive	Officers	and	Corporate	Governance

Information	required	by	this	item	is	incorporated	by	reference	to	"Proposal	1:	Election	of	Directors,"	"Corporate	Governance—Committees	of	the	Board"	and "Section	16(a)	Beneficial	Ownership	Reporting	Compliance"	in	our	Proxy	Statement	for	the	2018	Annual	Meeting	of	Stockholders,	to	be	filed	with	the	SEC	within	120 days	of	December	31,	2017	(the	"2018	Proxy	Statement").

See	"Executive	Officers	of	the	Registrant"	under	Item	1	of	this	Form	10-K	for	information	about	our	executive	officers.

Our	Code	of	Ethics	for	Senior	Financial	Officers,	which	applies	to	the	Company's	principal	executive	officer,	principal	financial	officer,	principal	accounting	officer or	controller,	or	persons	performing	similar	functions,	is	available	on	our	website	at	www.marathonoil.com	under	Investors—Corporate	Governance.	You	may	request	a printed	copy	free	of	charge	by	sending	a	request	to	the	Corporate	Secretary.	We	intend	to	disclose	any	amendments	and	any	waivers	to	our	Code	of	Ethics	for	Senior Financial	Officers	on	our	website	at	www.marathonoil.com	under	Investors	—Corporate	Governance	within	four	business	days.	The	waiver	information	will	remain	on the	website	for	at	least	12	months	after	the	initial	disclosure	of	such	waiver.

# Item	11.	Executive	Compensation

Information	required	by	this	item	is	incorporated	by	reference	to	"Corporate	Governance—Compensation	Committee	Interlocks	and	Insider	Participation," "Compensation	Committee	Report,"	"Director	Compensation,"	"Compensation	Discussion	and	Analysis"	and	"Executive	Compensation"	in	the	2018	Proxy	Statement.

# Item	12.	Security	Ownership	of	Certain	Beneficial	Owners	and	Management	and	Related	Stockholder	Matters

Portions	of	information	required	by	this	item	are	incorporated	by	reference	to	"Security	Ownership	of	Certain	Beneficial	Owners	and	Management"	in	the	2018 Proxy	Statement.

# Securities	Authorized	for	Issuance	Under	Equity	Compensation	Plans

The	following	table	provides	information	as	of	December	31,	2017	with	respect	to	shares	of	Marathon	Oil	common	stock	that	may	be	issued	under	our	existing equity	compensation	plans:

•Marathon	Oil	Corporation	2016	Incentive	Compensation	Plan	(the	"2016

Plan")

•Marathon	Oil	Corporation	2012	Incentive	Compensation	Plan	(the	"2012	Plan")	–	No	additional	awards	will	be	granted	under	this

•Marathon	Oil	Corporation	2007	Incentive	Compensation	Plan	(the	"2007	Plan")	–	No	additional	awards	will	be	granted	under	this

•Deferred	Compensation	Plan	for	Non-Employee	Directors	–	No	additional	awards	will	be	granted	under	this

| Plan	category | Number	of	securities	to<br>be	issued	upon<br>exercise	of	outstanding<br>options,	warrants	and<br>rights |  | Weighted-average<br>exercise	price	of<br>outstanding	options,<br>warrants	and	rights(c) | Number	of	securities<br>remaining	available	for<br>future	issuance<br>under	equity<br>compensation	plans |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Equity\tcompensation\tplans\tapproved\tby\tstockholders | 11,915,472 | (a) | $25.52 | 43,840,884 | (d) |
| Equity\tcompensation\tplans\tnot\tapproved\tby\tstockholders | 12,291 | (b) | N/A | — |  |
| Total | 11,927,763 |  | N/A | 43,840,884 |  |

(a) Includes	the	following:

•399,114	common	stock	units	that	have	been	credited	to	non-employee	directors	pursuant	to	the	non-employee	director	deferred	compensation	program	and	the	annual	director	stock	award program	established	under	the	2016	Plan,	2012	Plan,	2007	Plan	and	2003	Plan.	Common	stock	units	credited	under	the	2016	Plan,	2012	Plan,	2007	Plan	and	2003	Plan	were	69,556,	142,724, 152,839	and	33,995,	respectively;

•In	addition	to	the	awards	reported	above,	2,850,798	and	3,525,501	shares	of	restricted	stock	were	issued	and	outstanding	as	of	December	31,	2017,	but	subject	to	forfeiture	restrictions	under the	2012	and	2016	Plans,	respectively.

(b) Reflects	awards	of	common	stock	units	made	to	non-employee	directors	under	the	Deferred	Compensation	Plan	for	Non-Employee	Directors	prior	to	April	30,	2003.	When	a	non-employee director	leaves	the	Board,	he	or	she	will	be	issued	actual	shares	of	Marathon	Oil	common	stock	in	place	of	the	common	stock	units.

(c) The	weighted-average	exercise	prices	do	not	take	the	restricted	stock	units	or	common	stock	units	into	account	as	these	awards	have	no	exercise	price.

(d) Reflects	the	shares	available	for	issuance	under	the	2016	Plan.	No	more	than	18,496,714	of	these	shares	may	be	issued	for	awards	other	than	stock	options	or	stock	appreciation	rights.	In addition,	shares	related	to	grants	that	are	forfeited,	terminated,	canceled	or	expire	unexercised	shall	again	immediately	become	available	for	issuance.

The	Deferred	Compensation	Plan	for	Non-Employee	Directors	is	our	only	equity	compensation	plan	that	has	not	been	approved	by	our	stockholders.	Our	authority to	make	equity	grants	under	this	plan	was	terminated	effective	April	30,	2003.	Under	the	Deferred	Compensation	Plan	for	Non-Employee	Directors,	all	non-employee directors	were	required	to	defer	half	of	their	annual	retainers	in	the	form	of	common	stock	units.	On	the	date	the	retainer	would	have	otherwise	been	payable	to	the	non- employee	director,	we	credited	an	unfunded	bookkeeping	account	for	each	non-employee	director	with	a	number	of	common	stock	units	equal	to	half	of	his	or	her annual	retainer	divided	by	the	fair	market	value	of	our	common	stock	on	that	date.	The	ongoing	value	of	each	common	stock	unit	equals	the	market	price	of	a	share	of our	common	stock.	When	the	non-employee	director	leaves	the	Board,	he	or	she	is	issued	actual	shares	of	our	common	stock	equal	to	the	number	of	common	stock units	in	his	or	her	account	at	that	time.

# Item	13.	Certain	Relationships	and	Related	Transactions,	and	Director	Independence

Information	required	by	this	item	is	incorporated	by	reference	to	"Transactions	with	Related	Persons,"	and	"Proposal	1:	Election	of	Directors—Director Independence"	in	the	2018	Proxy	Statement.

# Item	14.	Principal	Accountant	Fees	and	Services

Information	required	by	this	item	is	incorporated	by	reference	to	"Proposal	2:	Ratification	of	Independent	Auditor	for	2018"	in	the	2018	Proxy	Statement.

# PART	IV

# Item	15.	Exhibits,	Financial	Statement	Schedules

# A.	Documents	Filed	as	Part	of	the	Report

1.	Financial	Statements	–	See	Part	II,	Item	8.	of	this	Annual	Report	on	Form	10-K.

2.	Financial	Statement	Schedules	–	The	audited	financial	statements	and	related	footnotes	of	Alba	Plant	LLC,	our	equity	method	investment,	are	being	filed	within Exhibit	99.9	in	accordance	with	Rule	3-09	of	Regulation	S-X.	All	other	financial	statement	schedules	required	under	SEC	rules	but	not	included	in	this	Annual Report	on	Form	10-K	are	omitted	because	they	are	not	applicable	or	the	required	information	is	contained	in	the	consolidated	financial	statements	or	notes thereto.

3.	Exhibits	–	The	information	required	by	this	Item	15	is	incorporated	by	reference	to	the	Exhibit	Index	accompanying	this	Annual	Report	on	Form	10-K.

# SIGNATURES

Pursuant	to	the	requirements	of	Section	13	or	15(d)	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.

Gary	E.	Wilson

Vice	President,	Controller	and	Chief	Accounting	Officer

# POWER	OF	ATTORNEY

Each	person	whose	signature	appears	below	appoints	Lee	M.	Tillman,	Dane	E.	Whitehead,	and	Gary	E.	Wilson,	and	each	of	them,	as	his	or	her	true	and	lawful attorneys-in-fact	and	agents,	with	full	power	of	substitution	and	resubstitution,	for	him	or	her	and	in	his	or	her	name,	place	and	stead,	in	any	and	all	capacities,	to	sign any	and	all	amendments	to	this	Annual	Report	on	Form	10-K,	and	to	file	the	same,	with	all	exhibits	thereto,	and	other	documents	in	connection	therewith,	with	the Securities	and	Exchange	Commission,	with	full	power	and	authority	to	each	of	said	attorneys-in-fact	and	agents	to	do	and	perform	each	and	every	act	whatsoever	that	is necessary,	appropriate	or	advisable	in	connection	with	any	or	all	of	the	above-described	matters	and	to	all	intents	and	purposes	as	he	or	she	might	or	could	do	in	person, hereby	ratifying	and	confirming	all	that	said	attorneys-in-fact	and	agents	or	any	of	them	or	their	substitutes,	may	lawfully	do	or	cause	to	be	done	by	virtue	hereof.

Pursuant	to	the	requirements	of	the	Securities	Exchange	Act	of	1934,	this	report	has	been	signed	below	by	the	following	persons	on	February	22,	2018	on	behalf	of	the registrant	and	in	the	capacities	indicated.

# Exhibit	Index

| Exhibit |  | Incorporated	by	Reference	(File	No.	001-05153,	unless | otherwise	indicated) |  |
| :--- | :--- | :--- | :--- | :--- |
| Number | Exhibit\tDescription | Form | Exhibit | Filing\tDate |
| 1 | \t Underwriting\tAgreement |  |  |  |
| 1.1* | Bond\tPurchase\tAgreement,\tdated\tas\tof\tNovember\t28,\t2017,\tbetween\tMarathon\tOil |  |  |  |
|  | Stanley\t&amp;\tCo.\tLLC. |  |  |  |
| 2 | Plan\tof\tAcquisition,\tReorganization,\tArrangement,\tLiquidation\tor\tSuccession |  |  |  |
| 2.1 | Share\tPurchase\tAgreement,\tdated\tas\tof\tMarch\t8,\t2017,\tby\tand\tamong\tMarathon\tOil | 10-Q | 10.1 | 5/5/2017 |
|  | Canadian\tNatural\tResources\tLimited,\tas\ta\tBuyer,\tin\trespect\tof\tMarathon\tOil |  |  |  |
|  | Canada\tCorporation. |  |  |  |
| 3 | \t Articles\tof\tIncorporation\tand\tBy-laws |  |  |  |
| 3.1 | Restated\tCertificate\tof\tIncorporation\tof\tMarathon\tOil\tCorporation | 10-Q | 3.1 | 8/8/2013 |
| 3.2 | Marathon\tOil\tCorporation\tBy-laws\t(Amended\tand\trestated\tas\tof\tFebruary\t24, | 8-K | 3.1 | 3/1/2016 |
|  | 2016) |  |  |  |
| 3.3 | Specimen\tof\tCommon\tStock\tCertificate | 10-K | 3.3 | 2/28/2014 |
| 4 | Instruments\tDefining\tthe\tRights\tof\tSecurity\tHolders,\tIncluding\tIndentures |  |  |  |
| 4.1 | Indenture,\tdated\tas\tof\tFebruary\t26,\t2002,\tbetween\tMarathon\tOil\tCorporation\tand | 10-K | 4.2 | 2/28/2014 |
|  | Chase\tBank\tas\tTrustee,\trelating\tto\tsenior\tdebt\tsecurities\tof\tMarathon\tOil |  |  |  |
|  | Corporation.\tPursuant\tto\tCFR\t229.601(b)(4)(iii),\tinstruments\twith\trespect\tto\tlong- |  |  |  |
|  | term\tdebt\tissues\thave\tbeen\tomitted\twhere\tthe\tamount\tof\tsecurities\tauthorized\tunder |  |  |  |
|  | such\tinstruments\tdoes\tnot\texceed\t10%\tof\tthe\ttotal\tconsolidated\tassets\tof\tMarathon |  |  |  |
|  | Securities\tand\tExchange\tCommission\tupon\tits\trequest |  |  |  |
| 10 | \t Material\tContracts |  |  |  |
| 10.1 | Amended\tand\tRestated\tCredit\tAgreement,\tdated\tas\tof\tMay\t28,\t2014,\tamong | 8-K | 4.1 | 6/2/2014 |
|  | Marathon\tOil\tCorporation,\tas\tborrower,\tThe\tRoyal\tBank\tof\tScotland\tplc,\tas |  |  |  |
|  | administrative\tagent,\tand\tcertain\tother\tfinancial\tinstitutions\tnamed\ttherein |  |  |  |
| 10.2 | First\tAmendment,\tdated\tas\tof\tMay\t5,\t2015,\tto\tthe\tAmended\tand\tRestated\tCredit | 10-Q | 10.1 | 5/7/2015 |
|  | Agreement\tdated\tas\tof\tMay\t28,\t2014,\tby\tand\tamong\tMarathon\tOil\tCorporation,\tas |  |  |  |
|  | financial\tinstitutions\tnamed\ttherein |  |  |  |
| 10.3 | Incremental\tCommitments\tSupplement,\tdated\tas\tof\tMarch\t4,\t2016,\tto\tthe\tAmended | 8-K | 99.1 | 3/8/2016 |

| Number | Exhibit	Description | Form | Exhibit | Filing	Date |
| :--- | :--- | :--- | :--- | :--- |
| 10.19† | Form\tof\tMarathon\tOil\tCorporation\t2012\tIncentive\tCompensation\tPlan | 10-K | 10.5 | 2/22/2013 |
|  | Nonqualified\tStock\tOption\tAward\tAgreement\tfor\tSection\t16\tOfficers\t(3-year |  |  |  |
|  | prorata\tvesting) |  |  |  |
| 10.20† | Form\tof\tMarathon\tOil\tCorporation\t2012\tIncentive\tCompensation\tPlan | 10-K | 10.6 | 2/22/2013 |
|  | Nonqualified\tStock\tOption\tAward\tAgreement\tfor\tOfficers\t(3-year\tprorata\tvesting) |  |  |  |
| 10.21† | Form\tof\tMarathon\tOil\tCorporation\t2012\tIncentive\tCompensation\tPlan\tRestricted | 10-K | 10.7 | 2/22/2013 |
|  | Stock\tAward\tAgreement\tfor\tSection\t16\tOfficers\t(3-year\tcliff\tvesting) |  |  |  |
| 10.22† | Form\tof\tMarathon\tOil\tCorporation\t2012\tIncentive\tCompensation\tPlan\tRestricted | 10-K | 10.8 | 2/22/2013 |
|  | Stock\tAward\tAgreement\tfor\tOfficers\t(3-year\tcliff\tvesting) |  |  |  |
| 10.23† | Form\tof\tMarathon\tOil\tCorporation\t2012\tIncentive\tCompensation\tPlan\tRestricted | 10-K | 10.9 | 2/22/2013 |
|  | Stock\tAward\tAgreement\tfor\tSection\t16\tOfficers\t(3-year\tprorata\tvesting) |  |  |  |
| 10.24† | Form\tof\tMarathon\tOil\tCorporation\t2012\tIncentive\tCompensation\tPlan\tRestricted | 10-K | 10.10 | 2/22/2013 |
|  | Stock\tAward\tAgreement\tfor\tOfficers\t(3-year\tprorata\tvesting) |  |  |  |
| 10.25† | \t Marathon\tOil\tCorporation\t2007\tIncentive\tCompensation\tPlan | 10-K | 10.5 | 2/29/2012 |
| 10.26† | Form\tof\tMarathon\tOil\tCorporation\t2007\tIncentive\tCompensation\tPlan | 10-K | 10.6 | 2/29/2012 |
|  | Nonqualified\tStock\tOption\tAward\tAgreement\tfor\tOfficers |  |  |  |
| 10.27† | Form\tof\tMarathon\tOil\tCorporation\t2007\tIncentive\tCompensation\tPlan | 10-K | 10.5 | 2/28/2011 |
|  | Nonqualified\tStock\tOption\tAward\tAgreement\tfor\tSection\t16\tOfficers |  |  |  |
| 10.28† | Form\tof\tMarathon\tOil\tCorporation\t2007\tIncentive\tCompensation\tPlan | 10-K | 10.26 | 2/26/2010 |
|  | Nonqualified\tStock\tOption\tAward\tAgreement\tfor\tSection\t16\tOfficers |  |  |  |
| 10.29† | \t Marathon\tOil\tCorporation\t2003\tIncentive\tCompensation\tPlan | 10-K | 10.9 | 2/26/2010 |
| 10.30† | Marathon\tOil\tCorporation\tDeferred\tCompensation\tPlan\tfor\tNon-Employee | 10-K | 10.29 | 2/24/2017 |
|  | Directors\t(Amended\tand\tRestated\tas\tof\tDecember\t20,\t2016) |  |  |  |
| 10.31† | Marathon\tOil\tCompany\tDeferred\tCompensation\tPlan\tAmended\tand\tRestated | 10-K | 10.32 | 2/29/2012 |
|  | Effective\tJune\t30,\t2011 |  |  |  |
| 10.32† | \t Marathon\tOil\tCompany\tExcess\tBenefit\tPlan\tAmended\tand\tRestated | 10-K | 10.31 | 2/29/2012 |
| 10.33†* | Marathon\tOil\tCorporation\tOfficer\tChange\tin\tControl\tSeverance\tBenefits\tPlan\t(as |  |  |  |
|  | amended,\teffective\tJanuary\t1,\t2018) |  |  |  |
| 10.34† | \t Marathon\tOil\tCorporation\tPolicy\tfor\tRepayment\tof\tAnnual\tCash\tBonus\tAmounts | 10-K | 10.10 | 2/28/2011 |
| 10.35† | Marathon\tOil\tCorporation\tExecutive\tTax,\tEstate,\tand\tFinancial\tPlanning\tProgram, | 10-K | 10.32 | 2/27/2009 |
|  | Amended\tand\tRestated,\tEffective\tJanuary\t1,\t2009 |  |  |  |
| 10.36 | Tax\tSharing\tAgreement\tdated\tas\tof\tMay\t25,\t2011\tamong\tMarathon\tOil | 8-K | 10.1 | 5/26/2011 |



Question: what was the greatest ultimate trend rate for health care costs ? 4.70% ( 4.70 % ) 4.50% ( 4.50 % ) 4.50% ( 4.50 % )
Calculation:    table_row = [4.70, 4.50, 4.50] # row labeled ultimate trend rate
 a = max(table_row) 
Answer: 4.7%