# 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,	2013

Commission	file	number	1-5153

# 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 R	No	£

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 £	No		R

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	R	No	£

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	R	No	£

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.		R

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

Large	accelerated	filer		R				Accelerated	filer		£	Non-accelerated	filer		£	Smaller	reporting	company		£

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

The	aggregate	market	value	of	Common	Stock	held	by	non-affiliates	as	of	June	28,	2013:	 $24,462	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	696,944,638	shares	of	Marathon	Oil	Corporation	Common	Stock	outstanding	as	of	January	31,	2014.

Documents	Incorporated	By	Reference:

Portions	of	the	registrant's	proxy	statement	relating	to	its	2014	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

# Definitions

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

# AECO	–	Alberta	Energy	Company,	a	Canadian	natural	gas	benchmark	price.

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

AOSP	–	Athabasca	Oil	Sands	Project,	an	oil	sands	mining,	transportation	and	upgrading	joint	venture	located	in	Alberta,	Canada,	in	which	we	hold	a	20	percent	interest.

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

bbld	–	Barrels	per	day.

bboe	–	Billion	barrels	of	oil	equivalent.	Natural	gas	is	converted	to	a	barrel	of	oil	equivalent	based	on	the	energy	equivalent,	which	on	a	dry	gas	basis	is	six	thousand cubic	feet	of	gas	per	one	barrel	of	oil	equivalent.

bcf	–	Billion	cubic	feet.

boe	–	Barrels	of	oil	equivalent.

boed	–	Barrels	of	oil	equivalent	per	day.

BOEMRE	–	United	States	Bureau	of	Ocean	Energy	Management,	Regulation	and	Enforcement.

btu	–	British	thermal	unit,	an	energy	equivalence	measure.

# DD&A	–	Depreciation,	depletion	and	amortization.

Developed	acreage	–	The	number	of	acres	which	are	allocated	or	assignable	to	producing	wells	or	wells	capable	of	production.

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.

Downstream	business	–	The	refining,	marketing	and	transportation	("RM&T")	operations,	spun-off	on	June	30,	2011	and	now	treated	as	discontinued	operations.

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	percent	equity	interest.

# EPA	–	Environmental	Protection	Agency.

Exit	rate	–	The	average	daily	rate	of	production	from	a	well	or	group	of	wells	in	the	last	month	of	the	period	stated.

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.

FPSO	–	Floating	production,	storage	and	offloading	vessel.

IFRS	–	International	Financial	Reporting	Standards.

Internal	Losses	–	Production	losses	attributed	to	factors	that	are	within	our	control	which	can	be	either	planned,	such	as	a	planned	turnaround,	or	unplanned,	such	as equipment	failure.

International	E&P	–	Our	International	Exploration	and	Production	("Int'l	E&P")	segment	which	explores	for,	produces	and	markets	liquid	hydrocarbons	and	natural	gas outside	of	North	America	and	produces	and	markets	products	manufactured	from	natural	gas,	such	as	liquefied	natural	gas	and	methanol,	in	E.G.

IRS	–	United	States	Internal	Revenue	Service.

KRG	–	Kurdistan	Regional	Government.

LNG	–	Liquefied	natural	gas.

LPG	–	Liquefied	petroleum	gas.

Light	sweet	crude	-	A	crude	oil	with	an	American	Petroleum	Institute	("API")	gravity	of	38	degrees	or	more	and	a	sulfur	content	of	less	than	0.5	percent.

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

Marathon	–	The	consolidated	company	prior	to	the	June	30,	2011	spin-off	of	the	downstream	business.

Marathon	Oil	–	The	company	as	it	exists	following	the	June	30,	2011	spin-off	of	the	downstream	business.

Marathon	Petroleum	Corporation	("MPC")	–	The	separate	independent	company	which	now	owns	and	operates	the	downstream	business.

# mbbl	–	Thousand	barrels.

mbbld	–	Thousand	barrels	per	day.

mboe	–	Thousand	barrels	of	oil	equivalent.

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	cubic	feet	per	day.

mmt	–	Million	metric	tonnes.

mmta	–	Million	metric	tonnes	per	annum.

mtd	–	Thousand	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,	that	can	be	collectively	removed	from	produced	natural	gas,	separated	into	these	substances	and	sold.

North	America	E&P	("N.A.	E&P")	–	Our	North	America	Exploration	and	Production	segment	which	explores	for,	produces	and	markets	liquid	hydrocarbons	and	natural gas	in	North	America.

OECD	–	Organization	for	Economic	Cooperation	and	Development.

OPEC	–	Organization	of	Petroleum	Exporting	Countries.

OSM	–	Our	Oil	Sands	Mining	segment	which	mines,	extracts	and	transports	bitumen	from	oil	sands	deposits	in	Alberta,	Canada,	and	upgrades	the	bitumen	to	produce and	market	synthetic	crude	oil	and	vacuum	gas	oil.

Operational	Availability	–	A	term	used	to	measure	the	ability	of	an	asset	to	produce	to	its	maximum	capacity	over	a	specified	period	of	time.		This	measurement considers	Internal	Losses	that	are	within	our	control.

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

Proved	reserves	–	Proved	liquid	hydrocarbon,	natural	gas	and	synthetic	crude	oil	reserves	are	those	quantities	of	liquid	hydrocarbons,	natural	gas	and	synthetic	crude oil,	which,	by	analysis	of	geoscience	and	engineering	data,	can	be	estimated	with	reasonable	certainty	to	be	economically	producible.

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	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.

# PSC	–	Production	sharing	contract.

Quest	CCS	–	Quest	Carbon	Capture	and	Storage	project	at	the	AOSP	in	Alberta,	Canada.

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,	natural	gas	and	synthetic	crude	oil	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.

SAGE	–	United	Kingdom	Scottish	Area	Gas	Evacuation	system	composed	of	a	pipeline	and	processing	terminal.

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).

Total	depth	("TD")	–	The	bottom	of	a	drilled	hole,	where	drilling	is	stopped,	logs	are	run	and	casing	is	cemented.

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

# U.K.	–	United	Kingdom.

Undeveloped	acreage	–	Acreage	on	which	wells	have	not	been	drilled	or	completed	to	a	point	that	would	permit	the	production	of	economic	quantities	of	oil	and	natural gas	regardless	of	whether	such	acreage	contains	proved	reserves.

# U.S.	–	United	States	of	America.

U.S.	GAAP	–	Accounting	principles	generally	accepted	in	the	U.S.

WCS	–	Western	Canadian	Select,	an	oil	index	benchmark	price.

Working	interest	("WI")	–	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	interest	or other	interests.

WTI	–	West	Texas	Intermediate	crude	oil,	an	oil	index	benchmark	price.

# Disclosures	Regarding	Forward-Looking	Statements

This	Annual	Report	on	Form	10-K,	particularly	Item	1.	Business,	Item	1A.	Risk	Factors,	Item	3.	Legal	Proceedings,	Item	7.	Management's	Discussion	and	Analysis of	Financial	Condition	and	Results	of	Operations	and	Item	7A.	Quantitative	and	Qualitative	Disclosures	About	Market	Risk,	includes	forward-looking	statements	within the	meaning	of	Section	27A	of	the	Securities	Act	of	1933,	as	amended,	and	Section	21E	of	the	Securities	Exchange	Act	of	1934,	as	amended.	These	statements	typically contain	words	such	as	"anticipate,"	"believe,"	"estimate,"	"expect,"	"forecast,"	"plan,"	"predict,"	"target,"	"project,"	"could,"	"may,"	"should,"	"would"	or	similar	words, indicating	that	future	outcomes	are	uncertain.	In	accordance	with	"safe	harbor"	provisions	of	the	Private	Securities	Litigation	Reform	Act	of	1995,	these	statements	are accompanied	by	cautionary	language	identifying	important	factors,	though	not	necessarily	all	such	factors,	that	could	cause	future	outcomes	to	differ	materially	from those	set	forth	in	the	forward-looking	statements.

Forward-looking	statements	in	this	Annual	Report	on	Form	10-K	may	include,	but	are	not	limited	to	statements	that	relate	to	(or	statements	that	are	subject	to	risks, contingencies	or	uncertainties	that	relate	to):	levels	of	revenues,	income	from	operations,	net	income	or	earnings	per	share;	levels	of	liquidity	and	the	availability	of financing	options;	budgets	or	levels	of	capital,	exploration,	environmental,	construction	or	maintenance	expenditures;	the	success	or	timing	of	completion	of	ongoing	or anticipated	capital,	exploration,	construction	or	maintenance	projects;	volumes	of	production	or	sales	of	liquid	hydrocarbons,	natural	gas,	and	synthetic	crude	oil;	levels of	worldwide	prices	of	liquid	hydrocarbons	and	natural	gas;	levels	of	liquid	hydrocarbon,	natural	gas	and	synthetic	crude	oil	reserves;	the	acquisition	or	divestiture	of assets;	 the	 effect	 of	 restructuring	 or	 reorganization	 of	 business	 components;	 quantitative	 or	 qualitative	 factors	 about	 market	 risk;	 the	 potential	 effect	 of	 judicial proceedings	on	our	business	and	financial	condition;	levels	of	common	share	repurchases;	the	impact	of	government	legislation	and	budgetary	and	tax	measures;	and	the anticipated	effects	of	actions	of	third	parties	such	as	competitors,	or	federal,	foreign,	state	or	local	governments	and	regulatory	authorities.

# Item	1.	Business

# General

Marathon	Oil	Corporation	was	incorporated	in	2001	and	is	an	international	energy	company	engaged	in	the	exploration,	production	and	marketing	of	liquid hydrocarbons	and	natural	gas,	production	and	marketing	of	products	manufactured	from	natural	gas	and	oil	sands	mining	with	operations	in	the	U.S.,	Angola,	Canada, E.G.,	Ethiopia,	Gabon,	Kenya,	the	Kurdistan	Region	of	Iraq,	Libya,	Norway	and	the	U.K.	We	are	based	in	Houston,	Texas	with	our	corporate	headquarters	at	5555	San Felipe	Street,	Houston,	Texas	77056-2723	and	a	telephone	number	of	(713)	629-6600.

		On	June	30,	2011,	the	spin-off	of	Marathon's	downstream	business	was	completed,	creating	two	independent	energy	companies:	Marathon	Oil	and	MPC.	Marathon stockholders	at	the	close	of	business	on	the	record	date	of	June	27,	2011	received	one	share	of	MPC	common	stock	for	every	two	shares	of	Marathon	common	stock held.	A	private	letter	ruling	received	in	June	2011	from	the	IRS	affirmed	the	tax-free	nature	of	the	spin-off.	Activities	related	to	the	downstream	business	have	been treated	as	discontinued	operations	for	all	periods	prior	to	the	spin-off	with	additional	information	in	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	3	to	the consolidated	financial	statements.

# Strategy	and	Results	Summary

Our	strategic	imperatives	are:

•Uncompromising	focus	on	core	values	to	protect	our	license	to	operate	and	drive	business	performance

•Investment	in	our	people	to	grow	and	maintain	our	capabilities	and	competencies	to	ensure	shareholders	access	to	the	full	global	opportunity

•Relentless	pursuit	of	operational	and	capital	efficiency	and	recognition	as	the	partner	/	operator	of

choice

•Acceleration	of	resource	development	to	optimize	value,	grow	profitable	volumes	and	replace reserves

•Rigorous	portfolio	management	integrated	with	robust	capital allocation

•Quality	resource	capture	through	a	focused	exploration	program	and	opportunistic	business development

•Competitive	shareholder	value	through	disciplined	long-term

focus

We	continue	to	focus	on	liquid	hydrocarbon	reserves	and	production	worldwide,	realizing	significant	increases	in	our	three	key	unconventional	liquids-rich	plays	in 2013:	the	Eagle	Ford,	Bakken	and	Oklahoma	resource	basins.	In	2014,	approximately	60	percent	of	our	capital,	investment	and	exploration	spending	budget	is	allocated to	these	areas	and	includes	co-development	of	adjacent	formations	in	parallel	with	the	main	horizons.	Our	exploration	program	includes	prospects	in	E.G.,	Ethiopia, Gabon,	the	Gulf	of	Mexico,	Kenya	and	the	Kurdistan	Region	of	Iraq.

We	 ended	2013	 with	 proved reserves	 of	 approximately	2.2	 bboe,	 an	 8	 percent increase	 over	2012.	Proved reserve replacement	 was	 194	 percent,	 excluding dispositions.

During	2013,	our	cash	additions	to	property,	plant	and	equipment	were	$5.0	billion,	including	those	related	to	discontinued	operations,	and	we	made	acquisitions	of $74	million.	We	expect	continued	spending,	primarily	funded	with	cash	flow	from	operations	or	portfolio	optimization,	in	exploration	and	development	activities	in order	to	realize	continued	reserve	and	sales	volume	growth.	See	Item	7.	Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	- Outlook,	for	discussion	of	our	$5.9	billion	capital,	investment	and	exploration	spending	budget	for	2014.

We	continually	evaluate	ways	to	optimize	our	portfolio	through	acquisitions	and	divestitures	and	have	exceeded	our	previously	stated	goal	of	divesting	between $1.5	billion	and	$3.0	billion	of	assets	over	the	period	of	2011	through	2013,	by	closing	or	entering	into	agreements	for	approximately	$3.5	billion	in	divestitures,	of which	$2.1	billion	is	from	the	sales	of	our	Angola	assets.	The	sale	of	our	interest	in	Angola	Block	31	closed	in	February	2014	and	the	sale	of	our	interest	in	Angola Block	32	is	expected	to	close	in	the	first	quarter	of	2014.	Additionally,	in	December	2013,	we	commenced	efforts	to	market	our	assets	in	the	North	Sea,	both	in	the	U.K. and	Norway,	which	would	simplify	and	concentrate	our	portfolio	to	higher	margin	growth	opportunities	and	increase	our	production	growth	rate.

The	above	discussion	of	strategy	and	results	includes	forward-looking	statements	with	respect	to	the	sale	of	our	interest	in	Angola	Block	32,	the	possible	sale	of	our U.K.	and	Norway	assets	and	projected	spending	and	expected	investment	in	exploration	and	development	activities	under	the	2014	capital,	investment	and	exploration budget.	Some	factors	that	could	potentially	affect	the	expected	investment	in	exploration	and	development	activities	include	changes	in	prices	of	and	demand	for	liquid hydrocarbons,	natural	gas	and	synthetic	crude	oil,	actions	of	competitors,	occurrence	of	acquisitions	or	dispositions	of	oil	and	natural	gas	properties,	future	financial conditions,	operating	results	and	economic	and/or	regulatory	factors	affecting	our	businesses.	The	timing	of	closing

the	sale	of	our	interest	in	Angola	Block	32	is	subject	to	customary	closing	conditions.	The	possible	sale	of	our	U.K.	and	Norway	assets	is	subject	to	the	identification	of one	or	more	buyers,	successful	negotiations,	board	approval	and	execution	of	definitive	agreements.	The	projected	spending	under	the	2014	capital,	investment	and exploration	spending	budget	is	a	good	faith	estimate,	and	therefore,	subject	to	change.	The	foregoing	factors	(among	others)	could	cause	actual	results	to	differ	materially from	those	set	forth	in	the	forward-looking	statements.

The	map	below	illustrates	the	locations	of	our	worldwide	operations.

# Segment	and	Geographic	Information

For	operating	segment	and	geographic	financial	information,	see	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	8	to	the	consolidated	financial statements.

In	the	discussion	that	follows	regarding	our	North	America	E&P,	International	E&P	and	Oil	Sands	Mining	segments,	references	to	net	wells,	acres,	sales	or investment	indicate	our	ownership	interest	or	share,	as	the	context	requires.

# North	America	E&P	Segment

We	are	engaged	in	oil	and	gas	exploration,	development	and/or	production	activities	in	the	U.S.	and	Canada.

# Unconventional	Resource	Plays

Eagle	Ford	-	As	of	December	31,	2013,	we	had	approximately	211,000	net	acres	in	the	Eagle	Ford	in	south	Texas	and	655	gross	(493	net)	operated	producing	wells in	 the	 Eagle	 Ford,	Austin	 Chalk	 and	 Pearsall	 formations.	With	approximately	90	percent	pad	drilling	 in	2013,	we	continued	 to	 improve	efficiencies	and	reduce development	costs	per	well.	The	average	spud-to-TD	time	per	well	decreased	to	13	days	during	the	last	quarter	of	the	year	compared	to	15	days	in	the	same	period	of 2012.	We	reached	TD	on	299	gross	operated	wells	and	brought	307	gross	operated	wells	to	sales	in	2013.

Throughout	2013,	we	evaluated	the	potential	of	downspacing	to	40-acre	and	60-acre	spacing	with	several	pilot	programs.	Overall,	wells	drilled	in	these	programs	at closer	spacing	showed	improved	completion	efficiency	which	helped	offset	impacts	due	to	tighter	well	spacing.	Continued	focus	on	stimulation	design	contributed	to incremental	improvements	in	well	performance	across	our	area	of	activity.	Approximately	39	percent	of	our	2014	capital,	investment	and	exploration	budget	is	dedicated to	the	Eagle	Ford.	Our	accelerated	drilling	plans	include	drilling	250	-	260	net	wells	(385	-	405	gross,	of	which	we	will	operate	340	-	355)	in	2014,	an	increase	of	almost 20	percent	over	2013.

Eagle	Ford	average	net	sales	for	2013	 were	81	mboed,	composed	of	51	mbbld	of	crude	oil	and	condensate,	14	mbbld	of	NGLs	and	94	mmcfd	of	natural	gas, compared	to	34	mboed	in	2012,	a	136	percent	increase.	Our	2013	exit	rate	was	over	98	mboed,	a	50	percent	increase	over	December	2012.	In	2013,	we	were	able	to transport	approximately	70	percent	of	our	Eagle	Ford	production	by	pipeline.	We	anticipate	the	volume	of	oil	sold	into	pipelines	will	remain	high,	with	the	actual	volume fluctuating	from	quarter	to	quarter	as	additional	infrastructure	to	service	the	area	is	constructed	and	commensurate	commitments	for	transportation	are	executed.	The ability	to	transport	more	barrels	by	pipeline	enables	us	to	reduce	costs,	improve	reliability	and	lessen	our	environmental	footprint.

Evaluation	of	the	Austin	Chalk	and	Pearsall	formations	across	our	Eagle	Ford	acreage	position	in	south	Texas	included	four	Austin	Chalk	wells	and	one	well	in	the Pearsall	formation	in	2013.	Early	Austin	Chalk	production	results	suggest	that	the	mix	of	crude	oil	and	condensate,	NGLs	and	natural	gas	is	similar	to	Eagle	Ford condensate	wells.	We	plan	to	drill	5	to	12	additional	gross	wells	in	the	Austin	Chalk	and	Pearsall	formations	in	2014.	We	will	continue	to	evaluate	the	Pearsall	formation in	 2014.	Ongoing	Austin	Chalk	and	Eagle	Ford	co-development	is	planned,	pending	results	from	our	early	wells.	Co-development	will	leverage	the	infrastructure investments	we	have	made	to	support	production	growth	across	the	Eagle	Ford	operating	area.

Approximately	193	miles	of	gathering	lines	were	installed	in	2013	for	a	total	of	over	700	miles	of	operated	gathering	pipeline	in	the	area.	We	now	have	24	central gathering	and	treating	facilities,	with	aggregate	capacity	of	over	275	mboed.	We	also	own	and	operate	the	Sugarloaf	gathering	system,	a	37-mile	natural	gas	pipeline through	the	heart	of	our	acreage	in	Karnes,	Atascosa,	and	Bee	Counties	of	south	Texas.

Bakken	–	We	hold	approximately	370,000	net	acres	in	the	Bakken	shale	oil	play	in	North	Dakota	and	eastern	Montana,	where	we	have	been	operating	since	2006. Since	inception,	we	have	continuously	sought	improvement	in	efficiency	and	well	performance	through	optimizing	completion	techniques.	Our	average	time	to	drill	a well	continued	to	improve,	averaging	15	days	spud-to-TD	in	the	last	quarter	of	2013,	compared	to	18	days	in	the	same	period	of	2012.	We	have	identified	additional improvements	to	the	30-stage	hydraulic	fracturing	designs	put	in	place	in	2012,	which	are	expected	to	further	increase	both	production	rates	and	estimated	ultimate recovery	from	our	Bakken	shale	wells	beyond	the	increases	that	were	attained	in	2012	and	2013.	We	reached	TD	on	76	gross	operated	wells	and	brought	to	sales	77 gross	operated	wells	in	2013.		Our	Bakken	shale	program	includes	plans	to	drill	80	-	90	net	wells	(200	-	220	gross,	of	which	we	will	operate	75	-	85)	in	2014.	In	addition, we	plan	to	recomplete	22	-	26	gross	wells	to	the	stage	design	optimized	in	2013.

Our	net	sales	from	the	Bakken	shale	averaged	39	mboed	in	2013,	composed	of	35	mbbld	of	crude	oil	and	condensate,	2	mbbld	of	NGLs	and	13	mmcfd	of	natural gas,	a	34	percent	increase	over	29	mboed	in	2012.	Our	production	exit	rate	for	2013	was	approximately	38	mboed.	We	sell	our	Bakken	production	primarily	into	local North	Dakota	markets	via	truck	or	pipeline	in	efforts	to	optimize	price	realizations	and	such	production	could	be	transported	to	other	areas	of	the	U.S.	by	the	purchaser.

Oklahoma	resource	basins	–	We	hold	209,000	net	acres	 in	unconventional	Oklahoma	resource	basins,	namely	 the	Anadarko	Woodford	shale	(including	 the SCOOP),	the	Southern	Mississippi	Trend,	and	the	Granite	Wash,	of	which	approximately	147,000	net	acres	are	held	by	production.	We	continued	to	add	incremental acres	to	our	SCOOP	position	in	2013.	In	the	Anadarko	Woodford	shale,	we	reached	TD	on	10	gross	operated	wells	and	brought	nine	gross	operated	wells	to	sales	in 2013.	An	additional	four	net	non-operated	Woodford	wells	were	brought	to	sales.	We	spud	three	additional	operated	Woodford	wells	in	the	SCOOP	near	the	end	of	the year.		We	drilled	two	gross	operated	wells	in	the	Southern	Mississippi	Trend	and	brought	both	wells	to	sales	in	the	fourth	quarter	of	2013.	 We	also	participated	in	two gross	non-operated	Southern	Mississippi	Trend	wells	in	2013.	Lastly,	we	spud	our	first	operated	well	in	the	unconventional	Granite	Wash	play	near	the	end	of	2013.

Sales	from	our	Oklahoma	resource	basin	plays	in	2013	were	primarily	from	the	Anadarko	Woodford	shale	and	averaged	14	mboed,	composed	of	2	mbbld	of	crude oil	and	condensate,	4	mbbld	of	NGLs	and	48	mmcfd	of	natural	gas,	for	an	increase	of	68	percent	over	2012	net	sales	of	8	mboed.	Our	accelerated	drilling	plans	for	the Oklahoma	resource	basins	include	drilling	and	completing	14	-	20	net	(21	-	27	gross)	operated	wells	in	2014,	approximately	double	our	2013	program.	Approximately six	net	non-operated	wells	are	also	expected	to	be	completed.

See	below	for	discussion	of	our	conventional,	primarily	natural	gas,	production	operations	in	Oklahoma.

# Other	United	States

Gulf	of	Mexico	–	Production	–	On	December	31,	2013,	we	held	significant	interests	in	11	producing	fields,	4	of	which	are	company-operated.	Average	net	sales	for 2013	from	the	Gulf	of	Mexico	were	17	mbbld	of	liquid	hydrocarbons	and	14	mmcfd	of	natural	gas.	Operational	availability	for	our	operated	properties	was	strong	at	97 percent,	with	internal	unplanned	losses	of	three	percent.

We	have	a	65	percent	operated	working	interest	in	the	Ewing	Bank	Block	873	platform	which	is	located	130	miles	south	of	New	Orleans,	Louisiana.	The	platform serves	as	a	production	hub	for	the	Lobster,	Oyster	and	Arnold	fields	on	Ewing	Bank	Blocks	873,	917	and	963.	The	facility	also	processes	third-party	production	via subsea	tie-backs.

We	have	a	100	percent	operated	working	interest	in	the	Droshky	development	located	on	Green	Canyon	Block	244	and	a	68	percent	operated	working	interest	in Ozona	which	is	located	on	Garden	Banks	Block	515.	The	Ozona	development	ceased	production	in	the	first	quarter	of	2013	and	is	scheduled	for	abandonment	in	2014.

We	have	a	50	percent	working	interest	in	the	non-operated	Petronius	field	on	Viosca	Knoll	Blocks	786	and	830,	located	130	miles	southeast	of	New	Orleans,	which includes	14	producing	wells.	The	Petronius	platform	is	also	capable	of	providing	processing	and	transportation	services	to	nearby	third-party	fields.	A	well	side	track project	was	successfully	completed	in	2013	and	a	similar	project	is	planned	for	2014.

We	hold	a	30	percent	working	 interest	 in	 the	non-operated	Neptune	field	 located	on	Atwater	Valley	Block	575,	120	miles	off the	coast	of	Louisiana.	 The development	includes	seven	subsea	wells	tied	back	to	a	stand-alone	platform.	A	well	side	track	project	is	planned	for	2014.

We	have	an	18	percent	working	interest	in	the	non-operated	Gunflint	field	development	located	on	Mississippi	Canyon	Blocks	948,	949,	992(N/2)	and	993(N/2). The	discovery	well	was	drilled	in	2008	and	encountered	pay	in	the	Middle	Miocene	reservoirs.	Two	subsequent	appraisal	wells	were	drilled	and	evaluated	in	2012	and 2013.	First	oil	from	this	subsea	tie-back	development	project	is	expected	in	2016.

Gulf	of	Mexico	–	Exploration	–	We	have	a	portfolio	of	over	17	prospects	with	multiple	drilling	opportunities in the	Gulf	of	Mexico.	As	we	evaluate these opportunities	for	drilling,	we	plan	to	seek	partners	to	reduce	our	exploration	risk	on	individual	projects.

We	have	a	60	percent	operated	working	interest	in	the	Key	Largo	prospect	located	on	Walker	Ridge	Block	578.	The	Key	Largo	prospect	will	be	the	first	well	drilled with	a	new	ultra	deep-water	drillship	for	which	we	and	another	operator	have	recently	secured	a	three-year	contract.	Drilling	is	expected	to	commence	in	the	third quarter	of	2014.

Prior	to	commencing	drilling	in	September	2013,	we	reduced	our	working	interest	in	the	Madagascar	prospect,	located	on	De	Soto	Canyon	Block	757,	from	100 percent	to	40	percent	as	a	result	of	two	farm-outs,	which	included	drilling	cost	carries.	Our	operated	exploration	well	on	the	Madagascar	prospect	did	not	encounter commercial	hydrocarbons	and	the	well	costs	and	related	unproved	property	were	charged	to	exploration	expense	in	2013.

A	deepwater	oil	discovery	on	the	Shenandoah	prospect,	located	on	Walker	Ridge	Block	52,	was	drilled	in	2009.	We	own	a	10	percent	non-operated	working	interest in	this	prospect.	The	first	appraisal	well	on	the	Shenandoah	prospect	reached	total	depth	in	2013.	This	appraisal	well	encountered	more	than	1,000	net	feet	of	oil	pay	in multiple	high-quality	Lower	Tertiary-aged	reservoirs.	Additional	appraisal	drilling	is	anticipated	to	begin	in	2014.

In	2013,	we	were	awarded	100	percent	working	interest	leases	in	two	Gulf	of	Mexico	blocks:	Keathley	Canyon	Block	153,	an	extension	to	the	Meteor	prospect	on our	existing	Keathley	Canyon	Block	196	lease,	and	Keathley	Canyon	Block	340	on	the	Colonial	prospect.	Both	of	these	blocks	are	inboard-Paleogene	prospects.

Colorado	–	We	hold	leases	with	natural	gas	production	in	the	Piceance	Basin	of	Colorado,	located	in	the	Greater	Grand	Valley	field	complex,	and	held	154,000	net acres	in	the	Niobrara	shale	located	in	the	DJ	Basin	that	were	sold	in	June	2013.	Net	sales	from	Colorado	averaged	2	mboed	in	2013.	We	have	no	plans	for	operated drilling	in	Colorado	in	2014.

Oklahoma	–	We	have	long-established	operated	and	non-operated	conventional	production	in	several	Oklahoma	fields	from	which	2013	sales	averaged	1	mbbld	of liquid	hydrocarbons	and	43	mmcfd	of	natural	gas.	In	2013,	we	participated	in	seven	gross	non-operated	wells	in	the	state.

Texas/North	Louisiana/New	Mexico	–	We	hold	268,000	net	acres	in	these	areas	of	which	approximately	20,000	of	the	acres	are	in	the	Haynesville	and	Bossier natural	gas	shale	plays.	Most	of	the	acreage	in	these	shale	plays	is	held	by	production.	We	participated	in	three	gross	non-operated	wells	in	the	Haynesville	shale	play during	2013.	Conventional	production	was	primarily	from	the	Mimms	Creek,	Pearwood	and	Oletha	fields	in	2013,	with	net	sales	averaging	5	mboed.

We	also	participate	in	several	non-operated	Permian	Basin	fields	in	west	Texas	and	New	Mexico.	Net	sales	from	this	area	averaged	7	mboed	in	2013.	We	plan continued	carbon	dioxide	flood	programs	in	the	Seminole	and	Vacuum	fields	during	2014.

Wyoming	–	We	have	ongoing	enhanced	oil	recovery	waterflood	projects	at	the	mature	Bighorn	Basin	and	Wind	River	Basin	fields	and	at	our	100	percent	owned and	operated	Pitchfork	field.	We	have	conventional	natural	gas	operations	in	the	Greater	Green	River	Basin	and	unconventional	coal	bed	natural	gas	operations	in	the Powder	River	Basin.	As	of	December	31,	2013,	we	had	plugged	and	abandoned	376	of	the	total	600	wells	in	the	Powder	River	Basin	and	expect	production	to	cease	in March	2014	as	we	wind	down	those	operations.

Our	Wyoming	net	sales	averaged	16	mbbld	of	liquid	hydrocarbons	and	48	mmcfd	of	natural	gas	during	2013.	We	drilled	2	gross	operated	development	wells	in Wyoming	in	2013	and	plan	to	drill	10	gross	operated	wells	in	2014.	In	addition,	we	own

and	operate	the	420-mile	Red	Butte	Pipeline.	This	crude	oil	pipeline	connects	Silvertip	Station	on	the	Montana/Wyoming	state	line	to	Casper,	Wyoming.

# Canada

We	hold	interests	in	both	operated	and	non-operated	exploration	stage	oil	sand	leases	in	Alberta,	Canada,	which	would	be	developed	using	in-situ	methods	of extraction.	These	leases	cover	approximately	142,000	gross	(54,000	net)	acres	in	four	project	areas:	Namur,	in	which	we	hold	a	70	percent	operated	interest;	Birchwood, in	which	we	hold	a	100	percent	operated	interest;	Ells	River,	in	which	we	hold	a	20	percent	non-operated	interest;	and	Saleski	in	which	we	hold	a	33	percent	non- operated	interest.

During	the	first	quarter	of	2012,	we	submitted	a	regulatory	application	relating	to	our	Canada	in-situ	assets	at	Birchwood,	for	a	proposed	12	mbbld	steam	assisted gravity	drainage	("SAGD")	demonstration	project.	We	expect	to	receive	regulatory	approval	for	this	project	by	the	end	of	2014.		Upon	receiving	this	approval,	we	will further	evaluate	our	development	plans.

# Acquisitions	and	Dispositions

In	July	2013,	we	acquired	4,800	net	undeveloped	acres	in	the	core	of	the	Eagle	Ford	shale	in	a	transaction	valued	at	$97	million,	including	carried	interest	of	$23 million.

In	June	2013,	we	closed	the	sale	of	our	interests	in	the	DJ	Basin	for	proceeds	of	$19	million.	A	pretax	loss	of	$114	million	was	recorded	in	the	second	quarter	of 2013.

In	February	2013,	we	closed	the	sale	of	our	interest	in	the	Neptune	gas	plant,	located	onshore	Louisiana,	for	proceeds	of	$166	million.	A	$98	million	pretax	gain	was recorded	in	the	first	quarter	of	2013.

In	February	2013,	we	conveyed	our	interests	in	the	Marcellus	natural	gas	shale	play	to	the	operator.	A	$43	million	pretax	loss	on	this	transaction	was	recorded	in	the first	quarter	of	2013.

In	January	2013,	we	closed	the	sale	of	our	remaining	assets	in	Alaska,	for	proceeds	of	$195	million.	A	pretax	gain	of	$55	million	was	recorded	in	2013.

The	above	discussions	include	forward-looking	statements	with	respect	to	accelerated	rig	and	drilling	activity	in	the	Eagle	Ford,	Bakken,	and	Oklahoma	resource basins,	 possible	 increased	 recoverable	 resources	 from	 improvements	 to	 the	 30-stage	 hydraulic	 fracturing	 designs	 in	 the	 Bakken	 resource	 play,	 infrastructure improvements	in	the	Eagle	Ford	resource	play,	potential	development	plans	for	the	Austin	Chalk	and	Pearsall	formations	in	the	Eagle	Ford	resource	play	and	for	the Petronius	and	Neptune	fields	 in	 the	Gulf	of	Mexico,	anticipated	future	exploratory	and	development	drilling	activity,	projected	spending	under	 the	2014	capital, investment	and	exploration	spending	budget,	planned	use	of	carbon	dioxide	flood	programs,	the	abandonment	of	the	Powder	River	Basin	in	Wyoming,	the	abandonment of	the	Ozona	development	in	the	Gulf	of	Mexico,	the	timing	of	first	oil	from	the	Gunflint	development	in	the	Gulf	of	Mexico,	and	the	timing	of	project	sanction	for	the the	SAGD	project.	The	average	times	to	drill	a	well	may	not	be	indicative	of	future	drilling	times.	Current	production	rates	may	not	be	indicative	of	future	production rates.	Some	factors	which	could	possibly	affect	these	forward-looking	statements	include	pricing,	supply	and	demand	for	liquid	hydrocarbons	and	natural	gas,	the amount	 of	 capital	 available	 for	 exploration	 and	 development,	 regulatory	 constraints,	 timing	 of	 commencing	 production	 from	 new	 wells,	 drilling	 rig	 availability, availability	of	materials	and	labor,	other	risks	associated	with	construction	projects,	the	inability	to	obtain	or	delay	in	obtaining	necessary	government	and	third-party approvals	and	permits,	unforeseen	hazards	such	as	weather	conditions,	natural	disasters,	acts	of	war	or	terrorist	acts	and	the	governmental	or	military	response,	and	other geological,	operating	and	economic	considerations.	The	projected	spending	under	the	2014	capital,	investment	and	exploration	spending	budget	is	a	good	faith	estimate, and	therefore,	subject	to	change.	The	SAGD	project	may	further	be	affected	by	board	approval	and	transportation	logistics.	Actual	results	may	differ	materially	from these	expectations,	estimates	and	projections	and	are	subject	to	certain	risks,	uncertainties	and	other	factors,	some	of	which	are	beyond	our	control	and	difficult	to predict.	The	foregoing	factors	(among	others)	could	cause	actual	results	to	differ	materially	from	those	set	forth	in	the	forward-looking	statements.

# International	E&P	Segment

We	are	engaged	in	oil	and	gas	exploration,	development	and/or	production	activities	in	Angola,	E.G.,	Ethiopia,	Gabon,	Kenya,	the	Kurdistan	Region	of	Iraq,	Libya, Norway,	and	 the	U.K.	We	also	include	the	results	of	our	natural	gas	liquefaction	operations	and	methanol	production	operations	in	E.G.	in	our	International	E&P segment.

# Africa

Equatorial	Guinea	–	Production	–	We	own	a	63	percent	operated	working	interest	under	a	PSC	in	the	Alba	field	which	is	offshore	E.G.	During	2013,	E.G.	net liquid	hydrocarbon	sales	averaged	34	mbbld	and	net	natural	gas	sales	averaged	442	mmcfd.	Operational	availability	from	our	company-operated	facilities	continues	to	be excellent	and	averaged	99	percent	in	2013,	with	internal	unplanned	losses	of	one	percent.	A	compression	project	designed	to	maintain	the	production	plateau	two additional	years	and	extend	field	life	up	to	six	years	is	underway	and	is	expected	to	be	operational	in	mid-2016.

Dry	natural	gas	from	the	Alba	field,	which	remains	after	the	condensate	and	LPG	are	removed	by	Alba	Plant	LLC,	as	discussed	below,	is	supplied	to	AMPCO	and EGHoldings	under	long-term	contracts	at	fixed	prices.	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.	Any	dry	gas	not	sold	is	returned	offshore	and	reinjected	into	the	Alba	field	for	later	production.

Equatorial	Guinea	–	Exploration	–	We	hold	a	63	percent	operated	working	interest	in	the	Deep	Luba	discovery	on	the	Alba	Block	and	an	80	percent	operated working	interest	in	the	Corona	well	on	Block	D.	We	plan	to	develop	Block	D	through	a	unitization	with	the	Alba	field,	which	is	currently	being	negotiated.	We	also	have an	80	percent	operated	working	interest	in	exploratory	Block	A-12	offshore	Bioko	Island,	located	immediately	west	of	our	operated	Alba	Field.	We	have	secured	a	rig	to drill	at	least	two	exploration	prospects	and	one	Alba	field	infill	well	in	2014.

Equatorial	Guinea	–	Gas	Processing	–	We	own	a	52	percent	interest	in	Alba	Plant	LLC,	an	equity	method	investee,	that	operates	an	onshore	LPG	processing	plant located	on	Bioko	Island.	Alba	field	natural	gas	is	processed	by	the	LPG	plant.	Under	a	long-term	contract	at	a	fixed	price	per	btu,	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.	During	2013,	the	gross	quantity	of	natural	gas supplied	to	the	LPG	production	facility	was	866	mmcfd,	from	which	6	mbbld	of	secondary	condensate	and	21	mbbld	of	LPG	were	produced	by	Alba	Plant	LLC.

We	also	own	60	percent	of	EGHoldings	and	45	percent	of	AMPCO,	both	of	which	are	accounted	for	as	equity	method	investments.	EGHoldings	operates	an	LNG production	facility	and	AMPCO	operates	a	methanol	plant,	both	located	on	Bioko	Island.	These	facilities	allow	us	to	monetize	natural	gas	reserves	from	the	Alba	field.

EGHoldings'	3.7	mmta	LNG	production	facility	sells	LNG	under	a	3.4	mmta,	or	460	mmcfd,	sales	and	purchase	agreement	through	2023.	The	purchaser	under	the agreement	takes	delivery	of	the	LNG	on	Bioko	Island,	with	pricing	linked	principally	to	the	Henry	Hub	index,	regardless	of	destination.	Gross	sales	of	LNG	from	this production	facility	totaled	3.98	mmta	in	2013.	Operational	availability	was	97	percent	in	2013,	including	a	planned	turnaround,	while	internal	unplanned	losses	were	less than	one	percent.

AMPCO	had	gross	sales	totaling	1.01	mmt	in	2013.	Operational	availability	for	this	methanol	plant	was	90	percent	in	2013	and	internal	unplanned	losses	were	10 percent.	Production	from	the	plant	is	used	to	supply	customers	in	Europe	and	the	U.S.

	Libya	–	We	hold	a	16	percent	non-operated	working	interest	in	the	Waha	concessions,	which	encompass	almost	13	million	acres	located	in	the	Sirte	Basin	of eastern	Libya.	Beginning	in	the	third	quarter	of	2013,	our	Libya	production	operations	were	impacted	by	third-party	labor	strikes	at	the	Es	Sider	oil	terminal.	We	have had	no	oil	liftings	since	July	2013.	Uncertainty	around	production	and	sales	levels	from	Libya	have	existed	since	the	first	quarter	of	2011	when	production	operations were	suspended	until	the	fourth	quarter	of	that	year.	We	and	our	partners	in	the	Waha	concessions	continue	to	assess	the	situation	and	the	condition	of	our	assets	in Libya.

Angola	–	During	2013,	we	entered	into	agreements	to	sell	our	Angola	assets.	See	discussion	of	the	transactions	in	the	Acquisitions	and	Dispositions	section	below.

Gabon	–	We	hold	a	21.25	percent	non-operated	working	interest	in	the	Diaba	License	G4-223	and	its	related	permit	offshore	Gabon,	which	covers	2.2	million	gross (476,000	net)	acres.	The	Diaman-1B	well	reached	total	depth	in	the	third	quarter	of	2013,	encountering	160-180	net	feet	of	hydrocarbon	pay	in	the	deepwater	pre-salt play.	Preliminary	analysis	suggests	that	the	hydrocarbons	are	natural	gas	with	condensate	content,	pending	results	of	ongoing	analysis	of	well	data.	Multiple	additional pre-salt	prospects	have	been	identified	on	this	License.

In	late	October	2013,	we	were	the	high	bidder	as	operator	of	two	deepwater	blocks	in	the	pre-salt	play	offshore	Gabon.	One	of	the	blocks	has	since	been	withdrawn by	the	government.	Award	of	the	other	block	is	subject	to	government	approval	and	negotiation	of	an	exploration	and	production	sharing	contract.

Kenya	–	We	hold	a	50	percent	non-operated	working	interest	in	Block	9,	consisting	of	3.9	million	gross	(1.9	million	net)	acres	 in	northwest	Kenya.	The	first exploratory	well	on	Block	9,	the	Bahasi-1,	completed	drilling	in	the	fourth	quarter	of	2013	and	was	plugged	and	abandoned.	The	Sala-1	exploration	well	is	expected	to spud	in	February	2014	on	the	eastern	side	of	Block	9,	where	previous	wells	drilled	in	the	sub-basin	confirmed	a	working	petroleum	system.	We	have	the	right	to	assume the	role	of	operator	on	Block	9	if	a	commercial	discovery	is	made.

We	also	hold	a	15	percent	non-operated	working	interest	in	Block	12A,	covering	5	million	gross	(750,000	net)	acres,	which	is	also	located	in	northwest	Kenya. Seismic	acquisition	on	Block	12A	began	in	2013	and	will	be	completed	in	the	first	quarter	of	2014.

Ethiopia	–	We	hold	a	20	percent	non-operated	interest	in	the	onshore	South	Omo	Block	in	Ethiopia.	The	concession	has	an	area	of	approximately	5.4	million	gross (1.1	million	net)	acres.	The	Sabisa-1	exploration	well	encountered	reservoir	quality	sands,	oil	and	heavy	gas	shows	and	a	thick	shale	section.	The	presence	of	oil	prone source	rocks,	reservoir	sands	and	good	seals	is	encouraging	for	the	numerous	fault	bounded	traps	identified	in	the	basin.	Because	of	mechanical	issues,	the	well	was abandoned	before	a	full	evaluation	could	be	completed.	The	Tultule-1	exploration	well	was	also	drilled	in	2013,	approximately	two	miles	from	the	Sabisa-1	well	in	a frontier	rift	basin	and	was	plugged	and	abandoned.	At	least	two	additional	exploration	wells	are	planned	for	the	eastern	side	of	the	block	in	2014	to	test	multiple	sub- basins.	The	first	of	those	wells,	Shimela-1,	is	expected	to	spud	in	March	2014.

# Europe

As	discussed	above,	we	commenced	efforts	in	December	2013	to	market	our	assets	in	the	North	Sea,	including	Norway	and	the	U.K.

Norway	–	Production	–	At	the	end	of	2013,	we	operated	9	licenses	and	held	interests	in	6	non-operated	licenses,	which	encompass	approximately	286,000	net	acres offshore	on	the	Norwegian	continental	shelf.	In	2013,	net	sales	from	Norway	averaged	71	mbbld	of	liquid	hydrocarbons	and	51	mmcfd	of	natural	gas.

Our	production	operations	in	Norway	are	centered	around	the	Alvheim	complex	which	consists	of	an	FPSO	with	subsea	infrastructure	tied	to	several	producing developments.	Produced	oil	is	transported	by	shuttle	tanker	and	produced	natural	gas	is	transported	to	the	SAGE	system	by	pipeline.	Production	in	2013	continued	to benefit	from	slower	than	expected	decline	as	a	result	of	infill	well	success,	reservoir	management	techniques,	extended	drilling	capability	and	technology	application. We	safely	completed	a	planned	turnaround	in	nine	days	in	2013	on	time	and	on	budget.	Operational	availability	continued	to	be	a	strong	factor	in	2013	performance	with a	rate	of	96	percent	and	internal	unplanned	losses	of	one	percent.

The	Alvheim	development	is	comprised	of	the	Kameleon,	East	Kameleon	and	Kneler	fields	(PL	036C,	PL	088BS	and	PL	203),	in	each	of	which	we	have	a	65 percent	operated	working	interest,	and	the	Boa	field,	in	which	we	have	a	58	percent	operated	working	interest.	At	the	end	of	2013,	the	Alvheim	development	included	12 producing,	3	temporarily	shut-in	and	2	water	disposal	wells.	One	infill	well	is	planned	for	2014	along	with	several	well	workovers.

The	Vilje	field	(PL	036D),	in	which	we	own	a	47	percent	operated	working	interest,	began	producing	through	the	Alvheim	complex	in	August	2008.	 Vilje	has	two subsea	templates	and	two	production	wells,	and	is	tied	back	through	a	12-mile	pipeline	to	the	Alvheim	FPSO.	A	third	production	well,	Vilje	Sor,	will	be	developed	as	a subsea	tieback	to	the	Vilje	field.	Production	start-up	is	expected	in	the	first	half	of	2014.

The	Volund	field	(PL	150	and	PL	150B),	located	five	miles	south	of	the	Alvheim	complex	consists	of	four	production	wells	and	one	water	injection	well	at December	31,	2013.	We	own	a	65	percent	operated	working	interest	in	Volund.

The	Viper	oil	discovery,	in	the	immediate	vicinity	of	the	Volund	Field,	was	announced	in	November	2009.	Along	with	our	partners,	we	are	evaluating	a	possible	tie- back	to	the	Alvheim	complex	of	the	Viper	discovery	as	a	combined	development	with	the	1997	Kobra	discovery.	Both	discoveries	are	within	PL203	where	we	hold	a	65 percent	operated	working	interest.

Norway	–	Exploration	–	The	Boyla	field	(PL	340),	formerly	the	Marihone	discovery,	is	located	approximately	17	miles	south	of	the	Alvheim	complex.	In	October 2012,	the	Norwegian	Ministry	of	Petroleum	and	Energy	approved	the	plan	for	the	development	and	operation	of	the	Boyla	field	in	which	we	hold	a	65	percent	operated working	interest.	Further	development	drilling	is	planned	in	the	Boyla	field	in	2014,	with	first	production	expected	in	early	2015.	Near	Boyla,	the	Caterpillar	discovery (PL	340BS)	made	in	2011	continues	to	be	evaluated	as	a	tie-back	to	the	Alvheim	complex	through	Boyla.

The	Darwin	(formerly	Veslemoy)	exploration	well	was	drilled	in	the	first	quarter	of	2013	on	PL	531,	in	which	we	hold	a	10	percent	non-operated	fully-carried working	interest,	and	was	plugged	and	abandoned.	The	30	percent	non-operated	Sverdrup	exploration	well	on	PL	330	offshore	Norway	was	drilled	in	the	third	quarter	of 2013	and	has	been	plugged	and	abandoned.

In	January	2013,	we	were	awarded	a	20	percent	non-operated	working	interest	in	PL	694,	which	consists	of	three	blocks,	south	of	the	Sverdrup	prospect	area.	We were	also	awarded	additional	acreage	in	the	North	Sea,	north	of	the	Alvheim	area	in	PL	203B.	Our	65	percent	working	interest	and	role	as	operator	are	the	same	as	PL 203.	In	addition,	in	2013	we	withdrew	from	three	licenses	(PL505,	PL505BS	and	PL570).

United	Kingdom	–	Net	sales	from	the	U.K.	averaged	15	mbbld	of	liquid	hydrocarbons	and	32	mmcfd	of	natural	gas	in	2013.	Our	largest	asset	in	the	U.K.	sector	of the	North	Sea	is	the	Brae	area	complex	where	we	are	the	operator	and	have	a	42	percent	working	interest	in	the	South,	Central,	North	and	West	Brae	fields	and	a	39 percent	working	interest	in	the	East	Brae	field.	The	Brae	Alpha	platform	and	facilities	host	the	South,	Central	and	West	Brae	fields.	The	North	Brae	and	East	Brae	fields are	natural	gas	condensate	fields	which	are	produced	via	the	Brae	Bravo	and	the	East	Brae	platforms,	respectively.	The	East	Brae	platform	also	hosts	the	nearby Braemar	field	in	which	we	have	a	28	percent	working	interest.	Two	development	wells	are	in	the	West	Brae	program,	with	the	first	to	be	spud	in	2014.	Operational availability	was	92	percent	and	internal	unplanned	losses	were	eight	percent.

The	strategic	location	of	the	Brae	platforms,	along	with	pipeline	and	onshore	infrastructure,	has	generated	third-party	processing	and	transportation	business	since 1986.	Currently,	the	operators	of	30	third-party	fields	are	contracted	to	use	the	Brae	system	and	62	mboed	are	being	processed	or	transported	through	the	Brae infrastructure.	In	addition	to	generating	processing	and	pipeline	tariff	revenue,	this	third-party	business	optimizes	infrastructure	usage.

The	working	interest	owners	of	the	Brae	area	producing	assets	collectively	own	a	50	percent	interest	in	the	non-operated	SAGE	system.	The	SAGE	pipeline transports	natural	gas	from	the	Brae	area,	and	the	third-party	Beryl	area,	and	has	a	total	wet	natural	gas	capacity	of	1.1	bcf	per	day.	The	SAGE	terminal	at	St.	Fergus	in northeast	Scotland	processes	natural	gas	from	the	SAGE	pipeline	as	well	as	approximately	1	bcf	per	day	of	third-party	natural	gas.

We	own	working	interests	in	the	non-operated	Foinaven	area	complex,	consisting	of	a	28	percent	working	interest	in	the	main	Foinaven	field,	a	47	percent	working interest	in	East	Foinaven	and	a	20	percent	working	interest	in	the	T35	and	T25	fields.	The	export	of	Foinaven	liquid	hydrocarbons	is	via	shuttle	tanker	from	the	FPSO	to market.	All	natural	gas	sales	are	to	the	non-operated	Magnus	platform	for	use	as	injection	gas.

Poland	–	After	an	extensive	evaluation	of	our	exploration	activities	in	Poland	and	unsuccessful	attempts	to	find	commercial	levels	of	hydrocarbons,	we	have	elected to	conclude	operations	in	the	country.	During	2013,	we	relinquished	7	of	our	11	operated	concessions	to	the	government	and	are	in	the	process	of	relinquishing	the remainder.

# Other	International

Kurdistan	Region	of	Iraq	–	In	aggregate,	we	have	access	to	approximately	145,000	net	acres	in	the	Kurdistan	Region	of	Iraq.	We	have	interests	in	two	non-operated blocks	located	north-northwest	of	Erbil:	Atrush	with	15	percent	working	interest	and	Sarsang	with	25	percent	working	interest.	We	also	have	a	45	percent	operated working	interest	in	the	Harir	block	located	northeast	of	Erbil.

On	the	non-operated	Atrush	block,	following	the	successful	appraisal	program	and	a	declaration	of	commerciality,	a	plan	for	field	development	was	approved	by	the Kurdistan	Ministry	of	Natural	Resources	 in	September	2013.	 	The	development	project	will	consist	of	drilling	 three	production	wells	and	constructing	a	central processing	 facility.	We	expect	first	production	by	early	2015	with	estimated	initial	gross	production	of	approximately	30	mbbld	of	oil.	The	approval	of	the	field development	plan	for	Phase	1	provides	for	a	25-year	production	period.	Subject	to	further	drilling	and	testing	results,	and	partner	and	government	approvals,	a	potential Phase	2	development	could	add	an	additional	gross	30	mbbld	facility.	Within	the	potential	Phase	2	development	area,	the	Atrush-3	appraisal	well,	located	approximately four	miles	east	of	existing	wells,	confirmed	the	extension	of	the	oil	bearing	reservoirs	and	has	been	suspended	as	a	potential	future	producer.	Testing	has	commenced	on the	Atrush-4	development	well,	spud	in	October	2013,	with	anticipated	completion	in	the	first	quarter	of	2014.	The	Atrush-5	development	well	is	expected	to	spud	in	the second	quarter	of	2014.

On	the	non-operated	Sarsang	block,	tests	have	been	completed	on	the	Gara	well.	All	zones	were	water-wet	and	the	well	was	plugged	and	abandoned	in	August 2013.	On	the	Mangesh	well,	five	drill	stem	tests	have	been	completed	and	further	testing	is	planned.	The	East	Swara	Tika	exploration	well,	which	began	in	July	2013, has	been	drilled	to	a	depth	of	5,300	feet	toward	a	planned	total	depth	of	11,000	feet.	This	well	will	test	additional	resource	potential	to	the	northeast	of	the	Swara	Tika discovery.

On	the	operated	Harir	block,	we	announced	the	Mirawa-1	discovery	in	October	2013.	The	Mirawa-1	was	drilled	to	a	total	depth	of	approximately	14,000	feet	and encountered	multiple	stacked	oil	and	natural	gas	producing	zones	with	equipment	constrained	test	flow	rates	of	more	than	11	mbbld	of	oil,	72	mmcfd	of	non-associated natural	gas	and	1,700	bbld	of	condensate.	We	have	suspended	the	well	for	potential	future	use	as	a	producing	well.	The	Jisik-1	prospect,	located	nine	miles	to	the northwest	of	the	Mirawa-1	discovery,	will	test	a	similar	structure.	Drilling	on	the	Jisik-1	prospect	commenced	in	December	2013	and	is	expected	to	reach	total	depth	in the	second	quarter	of	2014.	The	Mirawa-2	appraisal	well	is	expected	to	spud	in	the	third	quarter	of	2014,	subject	to	government	approval	of	the	Mirawa	appraisal	plan.

In	June	and	December	2013,	we	entered	into	agreements,	valued	in	total	at	$2.1	billion	before	closing	adjustments,	to	sell	our	non-operated	10	percent	working	interests in	the	Production	Sharing	Contracts	and	Joint	Operating	Agreements	for	Angola	Blocks	31	and	32.	The	sale	of	our	interest	in	Block	31	closed	in	February	2014	and	the sale	of	our	interest	in	Block	32	is	expected	to	close	in	the	first	quarter	of	2014.	Our	Angola	operations	are	reported	as	discontinued	operations	for	all	periods	presented.

In	October	of	2013,	we	transfered	our	45	percent	working	interest	and	operatorship	in	the	Safen	Block	in	the	Kurdistan	Region	of	Iraq	at	a	pretax	loss	of	$17 million.

In	January	2013,	government	approval	was	received	for	our	acquisition	of	a	20	percent	non-operated	interest	in	the	onshore	South	Omo	concession	in	Ethiopia.

The	above	discussions	include	forward-looking	statements	with	respect	to	anticipated	future	exploratory	and	development	drilling	activity	in	the	Kurdistan	Region of	Iraq,	Ethiopia,	Kenya,	Norway,	the	U.K.,	and	E.G.,	the	anticipated	start-up	date	of	the

compression	project	in	E.G.,	the	unitization	of	Block	D	and	the	Alba	field	in	E.G.,	the	award	of	one	block	in	Gabon,	plans	to	exit	Poland,	the	possible	sale	of	our	U.K. and	Norway	assets,	the	timing	of	first	production	from	the	Boyla	field,	the	timing	of	first	production	from	the	Atrush	development,	a	potential	Phase	2	development	in the	Atrush	block,	other	potential	development	projects	and	the	sale	of	our	interest	in	Angola	Block	32.	Some	factors	which	could	possibly	affect	these	forward-looking statements	include	pricing,	supply	and	demand	for	liquid	hydrocarbons	and	natural	gas,	the	amount	of	capital	available	for	exploration	and	development,	regulatory constraints,	timing	of	commencing	production	from	new	wells,	drilling	rig	availability,	the	inability	to	obtain	or	delay	in	obtaining	necessary	government	and	third-party approvals	and	permits,	unforeseen	hazards	such	as	weather	conditions,	natural	disasters,	acts	of	war	or	terrorist	acts	and	the	governmental	or	military	response,	and	other geological,	operating	and	economic	considerations.	The	award	of	the	block	in	Gabon	is	subject	to	government	approval	and	negotiation	of	an	exploration	and	production sharing	contract.	The	possible	sale	of	our	U.K.	and	Norway	assets	is	subject	to	the	identification	of	one	or	more	buyers,	successful	negotiations,	board	approval	and execution	of	definitive	agreements.	The	timing	of	closing	the	sale	of	our	interest	in	Block	32	is	subject	to	customary	closing	conditions.	Actual	results	may	differ materially	from	these	expectations,	estimates	and	projections	and	are	subject	to	certain	risks,	uncertainties	and	other	factors,	some	of	which	are	beyond	our	control	and difficult	to	predict.	The	foregoing	factors	(among	others)	could	cause	actual	results	to	differ	materially	from	those	set	forth	in	the	forward-looking	statements.

# Productive	and	Drilling	Wells

For	our	North	America	E&P	and	International	E&P	segments	and	discontinued	operations	combined,	the	following	tables	set	forth	gross	and	net	productive	wells and	service	wells	as	of	December	31,	2013,	2012	and	2011	and	drilling	wells	as	of	December	31,	2013.

# Productive	Wells(a)

|  | Oil<br>Gross | Net | Natural	Gas<br>Gross | Net | Service	Wells<br>Gross | Net | Drilling	Wells<br>Gross | Net |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2013 |  |  |  |  |  |  |  |  |
| U.S. | 6,632 | 2,568 | 2,763 | 1,482 | 2,349 | 744 | 58 | 28 |
| E.G. | — | — | 16 | 11 | 2 | 1 | — | — |
| Other\tAfrica | 1,072 | 175 | 7 | 1 | 99 | 16 | 8 | 1 |
| Total\tAfrica | 1,072 | 175 | 23 | 12 | 101 | 17 | 8 | 1 |
| Total\tEurope | 77 | 34 | 40 | 16 | 28 | 11 | — | — |
| Total\tOther\tInternational | — | — | — | — | — | — | 2 | 1 |
| Worldwide | 7,781 | 2,777 | 2,826 | 1,510 | 2,478 | 772 | 68 | 30 |
| 2012 |  |  |  |  |  |  |  |  |
| U.S. | 6,191 | 2,315 | 3,208 | 1,906 | 2,328 | 736 |  |  |
| E.G. | — | — | 14 | 9 | 4 | 3 |  |  |
| Other\tAfrica | 1,050 | 171 | 6 | 1 | 101 | 16 |  |  |
| Total\tAfrica | 1,050 | 171 | 20 | 10 | 105 | 19 |  |  |
| Total\tEurope | 77 | 34 | 40 | 16 | 28 | 11 |  |  |
| Worldwide | 7,318 | 2,520 | 3,268 | 1,932 | 2,461 | 766 |  |  |
| 2011 |  |  |  |  |  |  |  |  |
| U.S. | 5,809 | 2,058 | 3,121 | 1,876 | 2,313 | 734 |  |  |
| E.G. | — | — | 14 | 9 | 4 | 3 |  |  |
| Other\tAfrica(b) | — | — | — | — | 1 | — |  |  |
| Total\tAfrica | — | — | 14 | 9 | 5 | 3 |  |  |
| Total\tEurope | 73 | 31 | 40 | 16 | 28 | 10 |  |  |
| Worldwide | 5,882 | 2,089 | 3,175 | 1,901 | 2,346 | 747 |  |  |

(a) Of	the	gross	productive	wells,	wells	with	multiple	completions	operated	by	us	totaled 204,	188	 and	168	 as	 of	December	31,	2013,	2012 and	2011. Information	on	wells	with	multiple completions	operated	by	others	is	unavailable	to	us.

(b) As	operations	were	resuming	in	Libya	at	December	31,	2011,	an	accurate	count	of	productive	wells	was	not	possible;	therefore	no	Libyan	wells	are	included	in	this	number.

# Drilling	Activity

For	our	North	America	E&P	and	International	E&P	segments	and	discontinued	operations	combined,	the	following	table	sets	forth,	by	geographic	area,	the	number of	net	productive	and	dry	development	and	exploratory	wells	completed	in	each	of	the	last	three	years.

|  | Oil | Development<br>Natural<br>Gas | Dry | Total | Oil | Exploratory<br>Natural<br>Gas | Dry | Total | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2013 |  |  |  |  |  |  |  |  |  |
| U.S. | 237 | 20 | — | 257 | 73 | 13 | 3 | 89 | 346 |
| Total\tAfrica | 4 | — | — | 4 | 1 | — | 2 | 3 | 7 |
| Total\tEurope | — | — | — | — | — | — | 2 | 2 | 2 |
| Total\tOther\tInternational | — | — | — | — | — | — | 1 | 1 | 1 |
| Worldwide | 241 | 20 | — | 261 | 74 | 13 | 8 | 95 | 356 |
| 2012 |  |  |  |  |  |  |  |  |  |
| U.S. | 172 | 21 | 2 | 195 | 117 | 13 | 9 | 139 | 334 |
| Total\tAfrica | 4 | — | — | 4 | 1 | — | — | 1 | 5 |
| Total\tEurope | 3 | — | — | 3 | — | — | — | — | 3 |
| Worldwide | 179 | 21 | 2 | 202 | 118 | 13 | 9 | 140 | 342 |
| 2011 |  |  |  |  |  |  |  |  |  |
| U.S. | 46 | 17 | 3 | 66 | 37 | 4 | 1 | 42 | 108 |
| Total\tAfrica(a) | 2 | — | — | 2 | — | — | — | — | 2 |
| Total\tEurope | 2 | — | — | 2 | — | — | — | — | 2 |
| Total\tOther\tInternational | — | — | — | — | — | — | 1 | 1 | 1 |
| Worldwide | 50 | 17 | 3 | 70 | 37 | 4 | 2 | 43 | 113 |

(a) Activity	in	Libya	through	February	2011.

# Acreage

We	believe	we	have	satisfactory	title	to	our	North	America	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	PSCs	or	exploration	licenses.

The	following	table	sets	forth,	by	geographic	area,	the	gross	and	net	developed	and	undeveloped	acreage	held	in	our	North	America	E&P	and	International	E&P segments	and	discontinued	operations	combined	as	of	December	31,	2013.

|  | Developed | Developed | Undeveloped | Undeveloped | Developed	and<br>Undeveloped | Developed	and<br>Undeveloped |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tthousands) | Gross | Net | Gross | Net | Gross | Net |
| U.S. | 1,720 | 1,289 | 695 | 523 | 2,415 | 1,812 |
| Canada | — | — | 142 | 54 | 142 | 54 |
| Total\tNorth\tAmerica | 1,720 | 1,289 | 837 | 577 | 2,557 | 1,866 |
| E.G. | 45 | 29 | 183 | 164 | 228 | 193 |
| Other\tAfrica | 12,921 | 2,109 | 18,549 | 4,463 | 31,470 | 6,572 |
| Total\tAfrica | 12,966 | 2,138 | 18,732 | 4,627 | 31,698 | 6,765 |
| Total\tEurope | 179 | 88 | 2,030 | 748 | 2,209 | 836 |
| Other\tInternational | — | — | 466 | 145 | 466 | 145 |
| Worldwide | 14,865 | 3,515 | 22,065 | 6,097 | 36,930 | 9,612 |

	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,	undeveloped	acreage	listed	in	the	table	below	will	expire	over	the	next	three	years.	We	plan	to	continue	the	terms	of	many	of	these	licenses	and	concession areas	or	retain	leases	through	operational	or	administrative	actions.	For	leases	expiring	in	2014	that	we	do	not	intend	to	extend	or	retain,	unproved	property	impairments were	recorded	in	2013.

|  | Net	Undeveloped	Acres	Expiring | Net	Undeveloped	Acres	Expiring |  |
| :--- | :--- | :--- | :--- |
| (In\tthousands) | 2014 | 2015 | 2016 |
| U.S. | 145 | 60 | 46 |
| E.G.\t(a) | 36 | — | — |
| Other\tAfrica | 189 | 2,605 | 189 |
| Total\tAfrica | 225 | 2,605 | 189 |
| Total\tEurope | 216 | 372 | 1 |
| Other\tInternational | — | 20 | — |
| Worldwide | 586 | 3,057 | 236 |

(a)	An	exploratory	well	is	planned	on	this	acreage	in	2014.

# Oil	Sands	Mining	Segment

We	hold	a	20	percent	non-operated	interest	in	the	AOSP,	an	oil	sands	mining	and	upgrading	joint	venture	located	in	Alberta,	Canada.	 The	joint	venture	produces bitumen	from	oil	sands	deposits	in	the	Athabasca	region	utilizing	mining	techniques	and	upgrades	the	bitumen	to	synthetic	crude	oils	and	vacuum	gas	oil.

The	AOSP's	mining	and	extraction	assets	are	located	near	Fort	McMurray,	Alberta	and	include	the	Muskeg	River	and	the	Jackpine	mines.	 Gross	design	capacity	of the	combined	mines	is	255,000	(51,000	net	to	our	interest)	barrels	of	bitumen	per	day.	The	AOSP	operations	use	established	processes	to	mine	oil	sands	deposits	from an	open-pit	mine,	extract	the	bitumen	and	upgrade	it	into	synthetic	crude	oils.	Ore	is	mined	using	traditional	truck	and	shovel	mining	techniques.	The	mined	ore	passes through	primary	crushers	to	reduce	the	ore	chunks	in	size	and	is	then	sent	to	rotary	breakers	where	the	ore	chunks	are	further	reduced	to	smaller	particles.	The	particles are	combined	with	hot	water	to	create	slurry.	The	slurry	moves	through	the	extraction	process	where	it	separates	into	sand,	clay	and	bitumen-rich	froth.	A	solvent	is added	to	the	bitumen	froth	to	separate	out	the	remaining	solids,	water	and	heavy	asphaltenes.	The	solvent	washes	the	sand	and	produces	clean	bitumen	that	is	required for	the	upgrader	to	run	efficiently.	The	process	yields	a	mixture	of	solvent	and	bitumen	which	is	then	transported	from	the	mine	to	the	Scotford	upgrader	via	the approximately	300-mile	Corridor	Pipeline.

The	AOSP's	Scotford	upgrader	is	at	Fort	Saskatchewan,	northeast	of	Edmonton,	Alberta.		The	bitumen	is	upgraded	at	Scotford	using	both	hydrotreating	and hydroconversion	processes	to	remove	sulfur	and	break	the	heavy	bitumen	molecules	into	lighter	products.	Blendstocks	acquired	from	outside	sources	are	utilized	in	the production	of	our	saleable	products.	The	upgrader	produces	synthetic	crude	oils	and	vacuum	gas	oil.	The	vacuum	gas	oil	is	sold	to	an	affiliate	of	the	operator	under	a long-term	contract	at	market-related	prices,	and	the	other	products	are	sold	in	the	marketplace.

As	of	December	31,	2013,	we	own	or	have	rights	to	participate	in	developed	and	undeveloped	leases	totaling	approximately	159,000	gross	(32,000	net)	acres.	The underlying	developed	leases	are	held	for	the	duration	of	the	project,	with	royalties	payable	to	the	province	of	Alberta.	Synthetic	crude	oil	sales	volumes	for	2013	were	48 mbbld	and	net-of-royalty	production	was	42	mbbld.

In	December	2013,	a	Jackpine	mine	expansion	project	received	conditional	approval	from	the	Canadian	government.	The	project	includes	additional	mining	areas, associated	processing	facilities	and	infrastructure.	The	government	conditions	relate	to	wildlife,	the	environment	and	aboriginal	health	issues.	We	will	begin	evaluating the	potential	expansion	project	and	government	conditions	after	current	debottlenecking	activities	are	complete	and	reliability	improves.

The	governments	of	Alberta	and	Canada	have	agreed	to	partially	fund	Quest	CCS	for	865	million	Canadian	dollars.		In	the	third	quarter	of	2012,	the	Energy	and Resources	 Conservation	 Board	 ("ERCB"),	Alberta's	 primary	 energy	 regulator	 at	 that	 time,	 conditionally	 approved	 the	 project	 and	 the	AOSP	 partners	 approved proceeding	to	construct	and	operate	Quest	CCS.			Government	funding	has	commenced	and	will	continue	to	be	paid	as	milestones	are	achieved	during	the	development, construction	and	operating	phases.		Failure	of	the	AOSP	to	meet	certain	timing,	performance	and	operating	objectives	may	result	in	repaying	some	of	the	government funding.		Construction	and	commissioning	of	Quest	CCS	is	expected	to	be	completed	by	late	2015.

In	May	2013,	we	announced	that	we	terminated	our	discussions	with	respect	to	a	potential	sale	of	a	portion	of	our	20	percent	outside-operated	interest	in	the	AOSP.

The	above	discussion	contains	forward-looking	statements	with	regard	to	the	Jackpine	mine	expansion	and	Quest	CCS.	Some	factors	that	could	affect	the	Jackpine mine	expansion	include	the	inability	to	obtain	or	delay	in	obtaining	third-party	approvals	and	permits.	The	Quest	CCS	is	subject	to	the	inability	to	obtain	or	delay	in obtaining	government	funds,	the	availability	of	materials	and	labor,	unforeseen	hazards	such	as	weather	conditions	and	other	risks	customarily	associated	with	these types	of	projects.	Actual	results	may	differ	materially	from	these	expectations,	estimates	and	projections	and	are	subject	to	certain	risks,	uncertainties	and	other	factors, some	of	which	are	beyond	our	control	and	difficult	to	predict.	The	foregoing	factors	(among	others)	could	cause	actual	results	to	differ	materially	from	those	set	forth	in the	forward-looking	statements.

# Reserves

# Estimated	Reserve	Quantities

The	following	table	sets	forth	estimated	quantities	of	our	proved	liquid	hydrocarbon,	natural	gas	and	synthetic	crude	oil	reserves	based	upon	an	unweighted	average of	closing	prices	for	the	first	day	of	each	month	in	the	12-month	periods	ended	December	31,	2013,	2012	and	2011.	Included	in	our	liquid	hydrocarbon	reserves	are NGLs	which	represent	approximately	7	percent,	6	percent	and	5	percent	of	our	total	proved	reserves	on	an	oil	equivalent	barrel	basis	as	of	December	2013,	2012	and 2011.	Approximately	72	percent,	63	percent	and	40	percent	of	those	NGL	reserves	are	associated	with	our	U.S.	unconventional	resource	plays	as	of	December	31,	2013, 2012	and	2011.

Reserves	are	disclosed	by	continent	and	by	country	if	the	proved	reserves	related	to	any	geographic	area,	on	an	oil	equivalent	barrel	basis,	represent	15	percent	or more	of	our	total	proved	reserves.	A	geographic	area	can	be	an	individual	country,	group	of	countries	within	a	continent,	or	a	continent.	Due	to	the	agreements	entered	in 2013	to	sell	our	Angola	assets,	estimated	proved	reserves	for	Angola	are	reported	as	discontinued	operations	("Disc	Ops")	for	all	presented	periods.	Approximately	73 percent	of	our	December	31,	2013	proved	reserves	are	located	in	OECD	countries.

|  |  | North	America |  |  | Africa |  | Europe |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| December\t31,\t2013 | \t\tU.S. | Canada | Total | E.G. | Other | Total | Total | Disc\tOps | Grand\nTotal |
| Proved\tDeveloped\tReserves |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mmbbl) | 292 | — | 292 | 55 | 176 | 231 | 78 | 19 | 620 |
| Natural\tgas\t(bcf) | 540 | — | 540 | 823 | 95 | 918 | 41 | — | 1,499 |
| Synthetic\tcrude\toil\t(mmbbl) | — | 674 | 674 | — | — | — | — | — | 674 |
| Total\tproved\tdeveloped\treserves\t\t(mmboe) | 382 | 674 | 1,056 | 193 | 192 | 385 | 84 | 19 | 1,544 |
| Proved\tUndeveloped\tReserves |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mmbbl) | 324 | — | 324 | 43 | 39 | 82 | 11 | 9 | 426 |
| Natural\tgas\t(bcf) | 485 | — | 485 | 497 | 110 | 607 | 80 | — | 1,172 |
| Synthetic\tcrude\toil\t(mmbbl) | — | 6 | 6 | — | — | — | — | — | 6 |
| Total\tproved\tundeveloped\treserves\t\t(mmboe) | 405 | 6 | 411 | 125 | 57 | 182 | 25 | 9 | 627 |
| Total\tProved\tReserves |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mmbbl) | 616 | — | 616 | 98 | 215 | 313 | 89 | 28 | 1,046 |
| Natural\tgas\t(bcf) | 1,025 | — | 1,025 | 1,320 | 205 | 1,525 | 121 | — | 2,671 |
| Synthetic\tcrude\toil\t(mmbbl) | — | 680 | 680 | — | — | — | — | — | 680 |
| Total\tproved\treserves\t(mmboe) | 787 | 680 | 1,467 | 318 | 249 | 567 | 109 | 28 | 2,171 |

|  |  | North	America |  |  | Africa |  | Europe |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| December\t31,\t2012 | \t\tU.S. | Canada | Total | E.G. | Other | Total | Total | Disc\tOps | Grand\nTotal |
| Proved\tDeveloped\tReserves |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mmbbl) | 198 | — | 198 | 68 | 168 | 236 | 84 | — | 518 |
| Natural\tgas\t(bcf) | 546 | — | 546 | 980 | 99 | 1,079 | 28 | — | 1,653 |
| Synthetic\tcrude\toil\t(mmbbl) | — | 653 | 653 | — | — | — | — | — | 653 |
| Total\tproved\tdeveloped\treserves\t\t(mmboe) | 289 | 653 | 942 | 231 | 185 | 416 | 88 | — | 1,446 |
| Proved\tUndeveloped\tReserves |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mmbbl) | 277 | — | 277 | 42 | 41 | 83 | 5 | 18 | 383 |
| Natural\tgas\t(bcf) | 497 | — | 497 | 444 | 110 | 554 | 75 | — | 1,126 |
| Total\tproved\tundeveloped\treserves\t\t(mmboe) | 360 | — | 360 | 116 | 59 | 175 | 18 | 18 | 571 |
| Total\tProved\tReserves |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mmbbl) | 475 | — | 475 | 110 | 209 | 319 | 89 | 18 | 901 |
| Natural\tgas\t(bcf) | 1,043 | — | 1,043 | 1,424 | 209 | 1,633 | 103 | — | 2,779 |
| Synthetic\tcrude\toil\t(mmbbl) | — | 653 | 653 | — | — | — | — | — | 653 |
| Total\tproved\treserves\t(mmboe) | 649 | 653 | 1,302 | 347 | 244 | 591 | 106 | 18 | 2,017 |

|  |  | North	America |  |  | Africa |  | Europe |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| December\t31,\t2011 | \t\tU.S. | Canada | Total | E.G. | Other | Total | Total | Disc\tOps | Grand\nTotal |
| Proved\tDeveloped\tReserves |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mmbbl) | 141 | — | 141 | 78 | 179 | 257 | 84 | — | 482 |
| Natural\tgas\t(bcf) | 551 | — | 551 | 1,104 | 104 | 1,208 | 40 | — | 1,799 |
| Synthetic\tcrude\toil\t(mmbbl) | — | 623 | 623 | — | — | — | — | — | 623 |
| Total\tproved\tdeveloped\treserves\t\t(mmboe) | 233 | 623 | 856 | 262 | 196 | 458 | 91 | — | 1,405 |
| Proved\tUndeveloped\tReserves |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mmbbl) | 138 | — | 138 | 39 | 43 | 82 | 13 | 18 | 251 |
| Natural\tgas\t(bcf) | 321 | — | 321 | 467 | — | 467 | 79 | — | 867 |
| Total\tproved\tundeveloped\treserves\t\t(mmboe) | 191 | — | 191 | 117 | 43 | 160 | 26 | 18 | 395 |
| Total\tProved\tReserves |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mmbbl) | 279 | — | 279 | 117 | 222 | 339 | 97 | 18 | 733 |
| Natural\tgas\t(bcf) | 872 | — | 872 | 1,571 | 104 | 1,675 | 119 | — | 2,666 |
| Synthetic\tcrude\toil\t(mmbbl) | — | 623 | 623 | — | — | — | — | — | 623 |
| Total\tproved\treserves\t(mmboe) | 424 | 623 | 1,047 | 379 | 239 | 618 | 117 | 18 | 1,800 |

The	increase	in	proved	reserves	from	2012	to	2013	was	primarily	due	to	drilling	programs	in	our	U.S.	unconventional	shale	plays	and	better	than	expected performance	in	Norway.	Synthetic	crude	oil	reserves	also	increased	due	to	approval	of	an	improved	recovery	project	and	price	and	cost	changes.

The	above	estimated	quantities	of	proved	liquid	hydrocarbon	and	natural	gas	reserves	are	forward-looking	statements	and	are	based	on	a	number	of	assumptions, including	(among	others)	commodity	prices,	presently	known	physical	data	concerning	size	and	character	of	 the	reservoirs,	economic	recoverability,	 technology developments,	future	drilling	success,	industry	economic	conditions,	levels	of	cash	flow	from	operations,	production	experience	and	other	operating	considerations.	The above	 estimated	 quantities	 of	 proved	 synthetic	 crude	 oil	 reserves	 are	 forward-looking	 statements	 and	 are	 based	 on	 presently	 known	 physical	 data,	 economic recoverability	and	operating	conditions.	To	the	extent	these	assumptions	prove	inaccurate,	actual	recoveries	and	development	costs	could	be	different	than	current estimates.	For	additional	details	of	the	estimated	quantities	of	proved	reserves

at	the	end	of	each	of	the	last	three	years,	see	Item	8.	Financial	Statements	and	Supplementary	Data	–	Supplementary	Information	on	Oil	and	Gas	Producing	Activities.

# Preparation	of	Reserve	Estimates

All	estimates	of	reserves	are	made	in	compliance	with	SEC	Rule	4-10	of	Regulation	S-X.	Liquid	hydrocarbon,	natural	gas	and	synthetic	crude	oil	reserve	estimates are	reviewed	and	approved	by	our	Corporate	Reserves	Group,	which	 includes	our	Director	of	Corporate	Reserves	and	his	staff	of	Reserve	Coordinators.	Liquid hydrocarbon	and	natural	gas	reserve	estimates	are	developed	or	reviewed	by	Qualified	Reserves	Estimators	("QREs").	QREs	are	engineers	or	geoscientists	with	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	Marathon	Oil's	QRE	training	course.	Reserve	Coordinators	screen	all	fields	with	proved	reserves	of	20	mmboe	or	greater,	every	year,	to	determine	if	a field	review	will	be	performed.	Any	change	to	proved	reserve	estimates	in	excess	of	1	mmboe	on	a	total	field	basis,	within	a	single	month,	must	be	approved	by	a Reserve	Coordinator.

Our	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	Texas.	In	his	26	years	with	Marathon	Oil,	he	has	held	numerous	engineering	and	management	positions,	most	recently	managing our	OSM	segment.	He	is	a	member	of	the	Society	of	Petroleum	Engineers	("SPE")	and	a	former	member	of	the	Petroleum	Engineering	Advisory	Council	for	the University	of	Texas	at	Austin.

Estimates	of	synthetic	crude	oil	reserves	are	prepared	by	GLJ	Petroleum	Consultants	("GLJ")	of	Calgary,	Canada,	third-party	consultants.	Their	reports	for	all	years are	filed	as	exhibits	to	this	Annual	Report	on	Form	10-K.	The	team	lead	responsible	for	the	estimates	of	our	synthetic	crude	oil	reserves	has	over	35	years	of	experience in	petroleum	engineering	and	has	conducted	surface	mineable	oil	sands	evaluations	since	1986.	He	is	a	member	of	SPE	and	served	as	regional	director	from	1998 through	2001.	The	second	GLJ	team	member	has	13	years	of	experience	in	petroleum	engineering	and	has	conducted	surface	mineable	oil	sands	evaluations	since	2009. Both	are	registered	Practicing	Professional	Engineers	in	the	Province	of	Alberta.

# Audits	of	Estimates

Third-party	consultants	are	engaged	to	provide	independent	estimates	for	fields	that	comprise	80	percent	of	our	total	proved	reserves	over	a	rolling	four-year	period for	the	purpose	of	auditing	and	validating	our	internal	reserve	estimates.	We	exceeded	this	percentage	for	the	four-year	period	ended	December	31,	2013.	We	have established	a	tolerance	level	of	10	percent	such	that	initial	estimates	by	the	third-party	consultants	are	accepted	if	they	are	within	10	percent	of	our	internal	estimates. Should	the	third-party	consultants'	initial	analysis	fail	to	reach	our	tolerance	level,	both	parties	re-examine	the	information	provided,	request	additional	data	and	refine their	analysis	if	appropriate.	This	resolution	process	is	continued	until	both	estimates	are	within	10	percent.	In	the	very	limited	instances	where	differences	outside	the	10 percent	tolerance	cannot	be	resolved	by	year	end,	a	plan	to	resolve	the	difference	is	developed	and	senior	management	consent	is	obtained.	The	audit	process	did	not result	in	any	significant	changes	to	our	reserve	estimates	for	2013,	2012	or	2011.

During	2013,	2012	and	2011,	Netherland,	Sewell	&	Associates,	Inc.	("NSAI")	prepared	a	certification	of	the	prior	year's	reserves	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	many	years	of	industry	experience,	having	worked for	large,	international	oil	and	gas	companies	before	joining	NSAI.	The	senior	technical	advisor	has	over	35	years	of	practical	experience	in	petroleum	geosciences,	with over	16	years	experience	in	the	estimation	and	evaluation	of	reserves.	The	second	team	member	has	over	9	years	of	practical	experience	in	petroleum	engineering,	with over	4	years	experience	in	the	estimation	and	evaluation	of	reserves.	Both	are	registered	Professional	Engineers	in	the	State	of	Texas.

Ryder	Scott	Company	("Ryder	Scott")	also	performed	audits	of	several	of	our	fields	in	2013,	2012	and	2011.	Their	summary	reports	are	filed	as	exhibits	to	this Annual	Report	on	Form	10-K.	The	team	lead	for	Ryder	Scott	has	over	22	years	of	industry	experience,	having	worked	for	a	major	international	oil	and	gas	company before	joining	Ryder	Scott.	He	is	a	member	of	SPE,	where	he	served	on	the	Oil	and	Gas	Reserves	Committee,	and	is	a	registered	Professional	Engineer	in	the	State	of Texas.

# Changes	in	Proved	Undeveloped	Reserves

As	of	December	31,	2013,	627	mmboe	of	proved	undeveloped	reserves	were	reported,	an	increase	of	56	mmboe	from	December	31,	2012.	The	following	table shows	changes	in	total	proved	undeveloped	reserves	for	2013:

| (mmboe) |  |
| :--- | :--- |
| Beginning\tof\tyear | 571 |
| Revisions\tof\tprevious\testimates | 4 |
| Improved\trecovery | 7 |
| Purchases\tof\treserves\tin\tplace | 16 |
| Extensions,\tdiscoveries,\tand\tother\tadditions | 142 |
| Dispositions | (4) |
| Transfer\tto\tProved\tDeveloped | (109) |
| End\tof\tyear | 627 |

Significant	 additions	 to	 proved	 undeveloped	 reserves	 during	2013	 included	 72	 mmboe	 in	 the	 Eagle	 Ford	 and	 49	 mmboe	 in	 the	 Bakken	 shale	 plays	 due	 to development	drilling.	Transfers	from	proved	undeveloped	to	proved	developed	reserves	included	57	mmboe	in	the	Eagle	Ford,	18	mmboe	in	the	Bakken	and	7	mmboe	in the	Oklahoma	resource	basins	due	to	producing	wells.	Costs	incurred	in	2013,	2012	and	2011	relating	to	the	development	of	proved	undeveloped	reserves,	were	$2,536 million,	$1,995	million	and	$1,107	million.

A	total	of	59	mmboe	was	booked	as	a	result	of	reliable	technology.	Technologies	included	statistical	analysis	of	production	performance,	decline	curve	analysis,	rate transient	analysis,	reservoir	simulation	and	volumetric	analysis.	The	statistical	nature	of	production	performance	coupled	with	highly	certain	reservoir	continuity	or quality	within	the	reliable	technology	areas	and	sufficient	proved	undeveloped	locations	establish	the	reasonable	certainty	criteria	required	for	booking	reserves.

Projects	can	remain	in	proved	undeveloped	reserves	for	extended	periods	in	certain	situations	such	as	large	development	projects	which	take	more	than	five	years	to complete,	or	the	timing	of	when	additional	gas	compression	is	needed.	Of	the	627	mmboe	of	proved	undeveloped	reserves	at	December	31,	2013,	24	percent	of	the volume	is	associated	with	projects	that	have	been	included	in	proved	reserves	for	more	than	five	years.	The	majority	of	this	volume	is	related	to	a	compression	project	in E.G.	that	was	sanctioned	by	our	Board	of	Directors	in	2004.	The	timing	of	the	installation	of	compression	is	being	driven	by	the	reservoir	performance	with	this	project intended	to	maintain	maximum	production	levels.	Performance	of	this	field	since	the	Board	sanctioned	the	project	has	far	exceeded	expectations.	Estimates	of	initial	dry gas	in	place	increased	by	roughly	10	percent	between	2004	and	2010.	During	2012,	the	compression	project	received	the	approval	of	the	E.G.	government,	allowing design	and	planning	work	to	progress	towards	implementation,	with	completion	expected	by	mid-2016.	The	other	component	of	Alba	proved	undeveloped	reserves	is	an infill	well	approved	in	2013	and	to	be	drilled	late	2014.

	Proved	undeveloped	reserves	for	the	North	Gialo	development,	located	in	the	Libyan	Sahara	desert,	were	booked	for	the	first	time	as	proved	undeveloped	reserves in	2010.	This	development,	which	is	anticipated	to	take	more	than	five	years	to	be	developed,	is	being	executed	by	the	operator	and	encompasses	a	continuous	drilling program	including	the	design,	fabrication	and	installation	of	extensive	liquid	handling	and	gas	recycling	facilities.	Anecdotal	evidence	from	similar	development	projects in	the	region	led	to	an	expected	project	execution	of	more	than	five	years	from	the	time	the	reserves	were	initially	booked.	Interruptions	associated	with	the	civil	unrest in	2011	and	third-party	labor	strikes	in	2013	have	extended	the	project	duration.	There	are	no	other	significant	undeveloped	reserves	expected	to	be	developed	more	than five	years	after	their	original	booking.

As	 of	December	31,	2013,	future	development	costs	estimated	to	be	required	for	the	development	of	proved	undeveloped	liquid	hydrocarbon,	natural	gas	and synthetic	crude	oil	reserves	related	to	continuing	operations	for	the	years	2014	through	2018	are	projected	to	be	$2,894	million,	$2,567	million,	$2,020	million,	$1,452 million	and	$575	million.

The	timing	of	future	projects	and	estimated	future	development	costs	relating	to	the	development	of	proved	undeveloped	liquid	hydrocarbon,	natural	gas	and synthetic	crude	oil	reserves	are	forward-looking	statements	and	are	based	on	a	number	of	assumptions,	including	(among	others)	commodity	prices,	presently	known physical	data	concerning	size	and	character	of	the	reservoirs,	economic	recoverability,	technology	developments,	future	drilling	success,	industry	economic	conditions, levels	of	cash	flow	from	operations,	production	experience	and	other	operating	considerations.	To	the	extent	these	assumptions	prove	inaccurate,	actual	recoveries, timing	and	development	costs	could	be	different	than	current	estimates.

# Net	Production	Sold

|  | U.S. | North	America<br>	 Canada | Total | E.G. | Africa<br>Other | Total | Europe<br>Total | Disc<br>Ops | Grand<br>Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2013 |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mbbld)(a) | 149 | — | 149 | 34 | 24 | 58 | 86 | 10 | 303 |
| Natural\tgas\t(mmcfd)(b)(c) | 312 | — | 312 | 442 | 22 | 464 | 76 | — | 852 |
| Synthetic\tcrude\toil\t(mbbld)(d) | — | 42 | 42 | — | — | — | — | — | 42 |
| Total\tproduction\tsold\t(mboed) | 201 | 42 | 243 | 107 | 27 | 134 | 99 | 10 | 486 |
| 2012 |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mbbld)(a) | 107 | — | 107 | 36 | 42 | 78 | 97 | — | 282 |
| Natural\tgas\t(mmcfd)(b)(c) | 358 | — | 358 | 428 | 15 | 443 | 86 | — | 887 |
| Synthetic\tcrude\toil\t(mbbld)(d) | — | 41 | 41 | — | — | — | — | — | 41 |
| Total\tproduction\tsold\t(mboed) | 166 | 41 | 207 | 108 | 44 | 152 | 111 | — | 470 |
| 2011 |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mbbld)(a) | 75 | — | 75 | 38 | 5 | 43 | 101 | — | 219 |
| Natural\tgas\t(mmcfd)(b)(c) | 326 | — | 326 | 443 | — | 443 | 81 | — | 850 |
| Synthetic\tcrude\toil\t(mbbld)(d) | — | 38 | 38 | — | — | — | — | — | 38 |
| Total\tproduction\tsold\t(mboed) | 129 | 38 | 167 | 112 | 5 | 117 | 115 | — | 399 |

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

(b) U.S.	natural	gas	volumes	exclude	volumes	produced	in	Alaska	prior	to	our	disposal	of	those	assets	in	2013	that	were	stored	for	later	sale	in	response	to	seasonal	demand,	although	our	reserves had	been	reduced	by	those	volumes.

(c) Excludes	volumes	acquired	from	third	parties	for	injection	and	subsequent	resale.

(d) Upgraded	bitumen	excluding	blendstocks.

# Average	Sales	Price	per	Unit

|  |  | North	America |  |  |  | Africa |  | Europe |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (Dollars\tper\tunit) | \t\tU.S. | Canada | Total | E.G. |  | Other | Total | Total | Disc\tOps | Grand\nTotal |
| 2013 |  |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(bbl) | $85.20 | $— | $85.20 | $60.34 |  | $122.92 | $86.29 | $112.60 | $104.77 | $93.83 |
| Natural\tgas\t(mcf) | 3.84 | — | 3.84 | 0.24 | (a) | 5.44 | 0.49 | 12.13 | — | 2.75 |
| Synthetic\tcrude\toil\t(bbl) | — | 87.51 | 87.51 | — |  | — | — | — | — | 87.51 |
| 2012 |  |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(bbl) | $85.80 | $— | $85.80 | $64.33 |  | $127.31 | $98.52 | $115.16 | $— | $99.46 |
| Natural\tgas\t(mcf) | 3.92 | — | 3.92 | 0.24 | (a) | 5.76 | 0.43 | 10.45 | — | 2.80 |
| Synthetic\tcrude\toil\t(bbl) | — | 81.72 | 81.72 | — |  | — | — | — | — | 81.72 |
| 2011 |  |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(bbl) | $92.55 | $— | $92.55 | $67.70 |  | $112.56 | $73.21 | $115.55 | $— | $99.37 |
| Natural\tgas\t(mcf) | 4.95 | — | 4.95 | 0.24 | (a) | 0.70 | 0.24 | 9.75 | — | 2.96 |
| Synthetic\tcrude\toil\t(bbl) | — | 91.65 | 91.65 | — |  | — | — | — | — | 91.65 |

(a) Primarily	represents	fixed	prices	under	long-term	contracts	with	Alba	Plant	LLC,	AMPCO	and	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.

# Average	Production	Cost	per	Unit(a)

|  |  | North	America |  |  | Africa |  | Europe |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (Dollars\tper\tboe) | \t\tU.S. | \t Canada(b) | Total | E.G. | \t Other(c) | Total | Total | Disc\tOps | Grand\nTotal |
| 2013 | $13.60 | $55.42 | $20.79 | $2.88 | $7.40 | $3.80 | $13.68 | $11.89 | $14.47 |
| 2012 | 13.61 | 53.61 | 21.51 | 3.59 | 3.57 | 3.59 | 9.62 | — | 12.91 |
| 2011 | 16.51 | 59.04 | 25.97 | 2.92 | 12.22 | 3.34 | 8.85 | — | 14.42 |

(a) Production,	severance	and	property	taxes	are	excluded	from	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	cost.

(b) Production	costs	in	2011	include	a	$64	million	water	abatement	accrual.

(c) Production	operations	ceased	in	Libya	in	February	2011,	resuming	in	2012,	but	ceased	again	in	the	third	quarter	of	2013.	Fixed	costs	continue	to	be	incurred	in	these	periods	of	downtime.

# Marketing	and	Midstream

Our	operating	segments	include	activities	related	to	the	marketing	and	transportation	of	substantially	all	of	our	liquid	hydrocarbon,	synthetic	crude	oil	and	natural gas	production.	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.

As	discussed	previously,	we	currently	own	and	operate	gathering	systems	and	other	midstream	assets	in	some	of	our	production	areas.	We	continue	to	evaluate midstream	infrastructure	investments	in	connection	with	our	development	plans.

# Delivery	Commitments

We	have	committed	to	deliver	quantities	of	crude	oil	and	synthetic	crude	oil	to	customers	under	a	variety	of	contracts.	As	of	December	31,	2013,	those	contracts	for fixed	and	determinable	quantities	were	at	variable,	market-based	pricing	and	related	primarily	to	Eagle	Ford	and	Bakken	liquid	hydrocarbon	production	and	OSM synthetic	crude	oil	production.	A	minimum	of	54	mbbld	of	Eagle	Ford	liquid	hydrocarbon	production	is	to	be	delivered	through	mid-2017	under	two	contracts.	Under	a 6-year	contract	ending	May	2016,	15	mbbld	of	Bakken	liquid	hydrocarbon	production	is	to	be	delivered.	Under	a	3-year	contract	expected	to	commence	mid-2014,	14 mbbld	of	synthetic	crude	oil	production	is	to	be	delivered.	Our	current	production	rates	and	proved	reserves	are	sufficient	to	meet	these	commitments.	The	Eagle	Ford and	OSM	contracts	also	provide	the	options	of	delivering	third-party	volumes	or	paying	a	monetary	shortfall	penalty	if	production	is	inadequate.	The	Bakken	contract carries	no	penalty	for	shortfalls.

# Competition	and	Market	Conditions

Strong	competition	exists	in	all	sectors	of	the	oil	and	gas	industry	and,	in	particular,	in	the	exploration	for	and	development	of	new	reserves.	We	compete	with	major integrated	and	independent	oil	and	gas	companies,	as	well	as	national	oil	companies,	for	the	acquisition	of	oil	and	natural	gas	leases	and	other	properties.	Based	upon statistics	compiled	in	the	"2013	Global	Upstream	Performance	Review"	published	by	IHS	Herold	Inc.,	we	rank	ninth	among	U.S.-based	petroleum	companies	on	the basis	of	2012	worldwide	liquid	hydrocarbon	and	natural	gas	production.	See	Item	1A.	Risk	Factors	for	discussion	of	specific	areas	in	which	we	compete	and	related risks.

We	also	compete	with	other	producers	of	synthetic	and	conventional	crude	oil	for	the	sale	of	our	synthetic	crude	oil	to	refineries	primarily	in	North	America. Additional	synthetic	crude	oil	projects	are	being	contemplated	by	various	competitors	and,	if	undertaken	and	completed,	these	projects	may	result	in	a	significant increase	in	the	supply	of	synthetic	crude	oil	to	the	market.	Since	not	all	refineries	are	able	to	process	or	refine	synthetic	crude	oil	in	significant	volumes,	there	can	be	no assurance	that	sufficient	market	demand	will	exist	at	all	times	to	absorb	our	share	of	the	synthetic	crude	oil	production	from	the	AOSP	at	economically	viable	prices.

Our	operating	results	are	affected	by	price	changes	for	liquid	hydrocarbons,	synthetic	crude	oil	and	natural	gas,	as	well	as	changes	in	competitive	conditions	in	the markets	we	serve.	Generally,	results	from	oil	and	gas	production	and	OSM	operations	benefit	from	higher	crude	oil	prices.	Market	conditions	in	the	oil	and	gas	industry are	cyclical	and	subject	to	global	economic	and	political	events	and	new	and	changing	governmental	regulations.	See	Item	7.	Management's	Discussion	and	Analysis	of Financial	Condition	and	Results	of	Operations,	Overview	–	Market	Conditions	for	additional	discussion	of	the	impact	of	prices	on	our	operations.

# 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.	These	laws	and	regulations	include	the Occupational	Safety	and	Health	Act	("OSHA")	with	respect	to	the	protection	of	the	health	and	safety	of	employees,	the	Clean	Air	Act	("CAA")	with	respect	to	air emissions,	the	Federal	Water	Pollution	Control	Act	(also	known	as	the	Clean	Water	Act	("CWA"))	with	respect	to	water	discharges,	the	Comprehensive	Environmental Response,	Compensation,	and	Liability	Act	("CERCLA")	with	respect	to	releases	and	remediation	of	hazardous	substances,	the	Oil	Pollution	Act	of	1990	("OPA-90") with	respect	to	oil	pollution	and	response,	the	National	Environmental	Policy	Act	with	respect	to	evaluation	of	environmental	impacts,	the	Endangered	Species	Act	with respect	to	the	protection	of	endangered	or	threatened	species,	the	Resource	Conservation	and	Recovery	Act	("RCRA")	with	respect	to	solid	and	hazardous	waste treatment,	storage	and	disposal	and	the	U.S.	Emergency	Planning	and	Community	Right-to-Know	Act	with	respect	to	the	dissemination	of	information	relating	to	certain chemical	inventories.	In	addition,	many	other	states	and	countries	in	which	we	operate	have	their	own	laws	dealing	with	similar	matters.

These	laws	and	regulations	could	result	in	costs	to	remediate	releases	of	regulated	substances,	including	crude	oil,	into	the	environment,	or	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.	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	rules	can	only	be	broadly	appraised	until	their	implementation	becomes	more	defined.	Based on	regulatory	trends,	particularly	with	respect	to	the	CAA	and	its	implementing	regulations,	we	have	incurred	and	will	continue	to	incur	substantial	capital,	operating	and maintenance,	and	remediation	expenditures	as	a	result	of	environmental	laws	and	regulations.	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.

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.

In	August	2012,	the	U.S.	EPA	published	final	New	Source	Performance	Standards	("NSPS")	and	National	Emissions	Standards	for	Hazardous	Air	Pollutants ("NESHAP")	that	amended	existing	NSPS	and	NESHAP	standards	for	oil	and	gas	facilities	as	well	as	created	a	new	NSPS	for	oil	and	gas	production,	transmission	and distribution	facilities.	These	rules,	which	were	updated	in	August	2013,	have	been	challenged,	and	negotiations	with	the	U.S.	EPA	over	proposed	changes	to	the	rules continue.	Compliance	with	these	new	rules	will	result	in	an	increase	in	the	costs	of	control	equipment	and	labor	and	require	additional	notification,	monitoring,	reporting and	recordkeeping	for	some	of	our	facilities.	The	U.S.	EPA	was	also	notified	in	December	2012	that	seven	northeastern	states	intend	to	sue	the	U.S.	EPA	for	failure	to include	methane	standards	in	these	rules.	If	successfully	challenged,	the	addition	of	methane	standards	could	further	increase	our	costs	to	comply	with	these	rules.

In	July	2011,	the	U.S.	EPA	finalized	a	Federal	Implementation	Plan	under	the	CAA	that	includes	New	Source	Review	("NSR")	regulations	which	apply	to	air emissions	sources	on	Tribal	Lands.	This	rule	became	effective	on	August	30,	2011,	and	requires	the	registration	and/or	pre-construction	permitting	of	most	of	our facilities	on	Tribal	Lands	in	Wyoming,	Oklahoma	and	North	Dakota.	Rather	than	issuing	pre-construction	permits	for	our	facilities	on	Tribal	Lands	in	North	Dakota,	in August	of	2012,	the	U.S.	EPA	finalized	an	Interim	Final	Rule	under	the	CAA	that	requires	certain	control	equipment,	recordkeeping,	monitoring,	and	reporting	with respect	to	these	facilities.	Compliance	with	this	new	rule	will	result	in	an	increase	in	the	costs	of	control,	equipment	and	labor	and	will	require	additional	notification, monitoring,	reporting	and	recordkeeping	for	our	facilities	on	Tribal	Lands	in	North	Dakota.

The	U.S.	EPA	is	expected	to	propose	the	results	of	its	5-year	review	of	the	2008	ozone	National	Ambient	Air	Quality	Standards	("NAAQS")	in	2014,	which	are expected	to	encompass	a	proposal	for	a	lower	ozone	NAAQS.	A	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.	Although	 there	may	be	an	adverse	financial	 impact	(including	compliance	costs,	potential	permitting	delays	and	 increased regulatory	requirements)	associated	with	any	regulation	or	other	action	by	the	U.S.	EPA	that	lowers	the	ozone

NAAQS,	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.

At	the	end	of	2013,	the	U.S.	EPA	indicated	that,	in	addition	to	sources	already	regulated	under	the	current	NSPS	subpart	OOOO,	the	U.S.	EPA	is	considering petitions	from	members	of	the	public	to	address	other	sources	of	emissions	from	oil	and	gas	operations	such	as	pneumatics,	equipment	leaks,	liquids	unloading,	and associated	gas.	At	this	time,	it	is	uncertain	how	the	U.S.	EPA	may	address	these	sources	(e.g.,	additional	regulations	or	voluntary	programs),	what	the	scope	may	be, what	emission	control	levels	or	technology	are	being	considered	or	the	U.S.	EPA's	timing.	 Although	there	may	be	an	adverse	financial	impact	associated	with	any	such regulation	or	other	action	by	the	U.S.	EPA,	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.

# Climate	Change

In	2010,	the	U.S.	EPA	promulgated	rules	that	require	us	to	monitor	and	submit	an	annual	report	on	our	greenhouse	gas	emissions.	Further,	state,	national	and international	requirements	to	reduce	greenhouse	emissions	are	being	proposed	and	in	some	cases	promulgated.	These	requirements	apply	or	could	apply	in	countries	in which	we	operate.	Potential	legislation	and	regulations	pertaining	to	climate	change	could	also	affect	our	operations.	The	cost	to	comply	with	these	laws	and	regulations cannot	be	estimated	at	this	time.	For	additional	information,	see	Item	1A.	Risk	Factors.	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.

# 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.	Hydraulic	fracturing	has	been	regulated	at	the	state	level through	permitting	and	compliance	requirements.	State	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	addition,	the	U.S.	Congress	has	considered	legislation	that	would	require	additional regulation	affecting	the	hydraulic	fracturing	process,	including	subjecting	the	process	to	regulation	under	the	Safe	Drinking	Water	Act.	In	the	first	quarter	of	2010,	the U.S.	EPA	announced	its	intention	to	conduct	a	comprehensive	research	study	on	the	potential	effects	that	hydraulic	fracturing	may	have	on	water	quality	and	public health.	The	U.S.	EPA	issued	a	progress	report	in	late	2012,	and	expects	to	issue	a	draft	report	for	public	comment	and	peer	review	in	2014,	with	a	final	report	expected	in 2016.

Increased	regulation	and	attention	given	to	the	hydraulic	fracturing	process	could	lead	to	greater	opposition	to	oil	and	gas	production	activities	using	hydraulic fracturing	techniques.	Additional	legislation	or	regulation	could	also	lead	to	operational	delays	or	increased	operating	costs	in	the	production	of	oil	and	natural	gas	from the	developing	shale	plays,	or	could	make	it	more	difficult	to	perform	hydraulic	fracturing.	The	adoption	of	any	federal	or	state	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.

# Remediation

The	AOSP	operations	use	established	processes	to	mine	deposits	of	bitumen	from	open-pit	mines,	extract	the	bitumen	and	upgrade	it	into	synthetic	crude	oils. Tailings	are	waste	products	created	from	the	oil	sands	extraction	process	which	are	placed	in	ponds.	The	AOSP	is	required	to	reclaim	its	tailings	ponds	as	part	of	its ongoing	reclamation	work.	The	reclamation	process	uses	developing	technology	and	there	is	an	inherent	risk	that	the	current	process	may	not	be	as	effective	or	perform as	required	in	order	to	meet	the	approved	closure	and	reclamation	plan.	The	AOSP	continues	to	develop	its	current	reclamation	technology	and	continues	to	investigate alternate	tailings	management	technologies.	In	February	2009,	the	ERCB	issued	a	directive	which	more	clearly	defines	criteria	for	managing	oil	sands	tailings.	We believe	that	we	are	substantially	in	compliance	with	the	directive	at	this	time.	We	could	incur	additional	costs	if	further	new	regulations	are	issued	or	if	we	fail	to	comply in	a	timely	manner.

# 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.	For	2013, sales	to	British	Petroleum	and	its	affiliates	accounted	for	more	than	10	percent	of	our	annual	revenues.	For	2012,	sales	to	Statoil	and	to	Shell	Oil	and	its	affiliates	each accounted	for	more	than	10	percent	of	our	annual	revenues.	For	2011,	transactions	with	MPC	accounted	for	more	than	10	percent	of	our	annual	revenues.	The	majority of	those	transactions	occurred	while	MPC	was	a	wholly-owned	subsidiary.

# Trademarks,	Patents	and	Licenses

We	currently	hold	a	number	of	U.S.	and	foreign	patents	and	have	various	pending	patent	applications.	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	3,359	active,	full-time	employees	as	of	December	31,	2013.	We	consider	labor	relations	with	our	employees	to	be	satisfactory.	We	have	not	had	any	work stoppages	or	strikes	pertaining	to	our	employees.

# Executive	Officers	of	the	Registrant

The	executive	officers	of	Marathon	Oil	and	their	ages	as	of	February	1,	2014,	are	as	follows:

With	the	exception	of	Mr.	Tillman,	Mr.	Sult	and	Mr.	Robertson,	all	of	the	executive	officers	have	held	responsible	management	or	professional	positions	with Marathon	Oil	or	its	subsidiaries	for	more	than	the	past	five	years.

•Mr.	Tillman	was	appointed	president	and	chief	executive	officer	effective	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.	 Between	2007	and	2010,	Mr.	Tillman	served	as	North Sea	production	manager	and	lead	country	manager	for	subsidiaries	of	ExxonMobil,	located	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.	Sult	was	appointed	executive	vice	president	and	chief	financial	officer	effective	September	2013.	Prior	to	this	appointment,	Mr.	Sult	served	as	executive	vice president	and	chief	financial	officer	of	El	Paso	Corporation	from	2010	to	2012,	senior	vice	president	and	chief	financial	officer	from	2009	until	2010,	and	senior vice	president,	chief	accounting	officer	and	controller	from	2005	until	2009.

•Ms.	Kerrigan	was	appointed	executive	vice	president,	general	counsel	and	secretary	effective	October	2012,	and	was	appointed	general	counsel	and	secretary effective	November	2009.	Prior	to	these	appointments,	Ms.	Kerrigan	was	assistant	general	counsel	since	January	2003.

•Ms.	 Bay	 was	 appointed	 vice	 president,	 global	 exploration	 effective	 July	 2011.	Ms.	 Bay joined	 Marathon	 Oil in	 June	 2008	 as	 senior	 vice	 president, exploration.

•Mr.	Little	was	appointed	vice	president,	international	and	offshore	production	operations	in	September	2013	and	served	as	vice	president,	international	production operations	effective	September	2012.	Prior	to	this	appointment,	Mr.	Little	was	resident	manager	for	our	Norway	operations	and	served	as	general	manager, worldwide	drilling	and	completions.	Mr.	Little	joined	Marathon	Oil	in	1986	and	has	held	a	number	of	engineering	and	management	positions	of	increasing responsibility.

•Mr.	Robertson	was	appointed	vice	president,	North	America	production	operations	in	September	2013	and	served	as	vice	president,	Eagle	Ford	production operations	since	October	2012.	Mr.	Robertson	joined	Marathon	Oil	in	October	2011	as	regional	vice	president,	South	Texas/Eagle	Ford.	Between	2004	and	2011, Mr.	Robertson	held	a	number	of	senior	engineering	and	operations	management	roles	of	increasing	responsibility	with	Pioneer	Natural	Resources	in	the	U.S.	and Canada.

•Mr.	Thill	was	appointed	vice	president,	corporate,	government	and	investor	relations	effective	January	2014,	and	vice	president,	investor	relations	and	public affairs	effective	January	2008.	Mr.	Thill	was	previously	director	of	investor	relations	from	April	2003	to	December	2007.

# Available	Information

General	 information	about	Marathon	Oil,	 including	 the	Corporate	Governance	Principles	and	Charters	for	 the	Audit	and	Finance	Committee,	Compensation Committee,	 Corporate	 Governance	 and	 Nominating	 Committee	 and	 Health,	 Environmental,	 Safety	 and	 Corporate	 Responsibility	 Committee,	 can	 be	 found	 at www.marathonoil.com.	In	 addition,	 our	 Code	 of	 Business	 Conduct	 and	 Code of Ethics for Senior Financial Officers are available at http://marathonoil.com/Investor_Center/Corporate_Governance/.

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

# 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,	extended	decline	in	liquid	hydrocarbon	or	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.

Prices	for	liquid	hydrocarbons	and	natural	gas	fluctuate	widely.	Our	revenues,	operating	results	and	future	rate	of	growth	are	highly	dependent	on	the	prices	we receive	for	our	liquid	hydrocarbons	and	natural	gas.	Historically,	the	markets	for	liquid	hydrocarbons	and	natural	gas	have	been	volatile	and	may	continue	to	be	volatile in	the	future.	Many	of	the	factors	influencing	prices	of	liquid	hydrocarbons	and	natural	gas	are	beyond	our	control.	These	factors	include:

•worldwide	and	domestic	supplies	of	and	demand	for	liquid	hydrocarbons	and	natural

•the	cost	of	exploring	for,	developing	and	producing	liquid	hydrocarbons	and	natural gas;

•the	 ability	 of the	 members	 of	 OPEC to agree to and	 maintain	 production controls;

•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;

•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	liquid	hydrocarbons	and	natural	gas	are	uncertain.

Lower	liquid	hydrocarbon	and	natural	gas	prices	may	cause	us	to	reduce	the	amount	of	these	commodities	that	we	produce,	which	may	reduce	our	revenues, operating	income	and	cash	flows.	Significant	reductions	in	liquid	hydrocarbon	and	natural	gas	prices	could	require	us	to	reduce	our	capital	expenditures	or	impair	the carrying	value	of	our	assets.

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

Offshore	exploration	and	development	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.

Estimates	of	liquid	hydrocarbon,	natural	gas	and	synthetic	crude	oil	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	liquid	hydrocarbon,	natural	gas	and	synthetic	crude	oil	reserves.

The	proved	reserve	information	included	in	this	Annual	Report	on	Form	10-K	has	been	derived	from	engineering	estimates.	Estimates	of	liquid	hydrocarbon	and natural	gas	reserves	were	prepared	by	our	in-house	teams	of	reservoir	engineers	and	geoscience	professionals	and	were	reviewed	and	approved	by	our	Corporate Reserves	Group.	The	synthetic	crude	oil	reserves	estimates	were	prepared	by	GLJ	Petroleum	Consultants,	a	third-party	consulting	firm	experienced	in	working	with	oil sands.	Reserves	were	valued	based	on	the	unweighted	average	of	closing	prices	for	the	first	day	of	each	month	in	the	12-month	periods	ended	December	31,	2013,	2012 and	2011,	as	well	as	other	conditions	in	existence	at	those	dates.	Any	significant	future	price	change	will	have	a	material	effect	on	the	quantity	and	present	value	of	our proved	reserves.	Future	reserve	revisions	could	also	result	from	changes	in	governmental	regulation,	among	other	things.

Reserve	estimation	is	a	subjective	process	that	involves	estimating	volumes	to	be	recovered	from	underground	accumulations	of	liquid	hydrocarbons,	natural	gas and	bitumen	that	cannot	be	directly	measured.	(Bitumen	is	mined	and	then	upgraded	into	synthetic	crude	oil.)	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	 comparable	 producing areas;

•volumes	of	bitumen	in-place	and	various	factors	affecting	the	recoverability	of	bitumen	and	its	conversion	into	synthetic	crude	oil	such	as	historical	upgrader performance;

•the	 assumed effects of regulation by governmental agencies;

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

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

As	a	result,	different	petroleum	engineers,	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	amounts	or	other	factors	estimated:

•the	amount	and	timing	of	production;

•the revenues	 and	 costs	 associated	 with that	 production; and

•the	amount	and	timing	of	future	development	expenditures.

The	discounted	future	cash	flows	from	our	proved	liquid	hydrocarbon,	natural	gas	and	synthetic	crude	oil	reserves	reflected	in	this	Annual	Report	on	Form	10-K should	not	be	considered	as	the	market	value	of	the	reserves	attributable	to	our	properties.	As	required	by	SEC	Rule	4-10	of	Regulation	S-X,	the	estimated	discounted future	cash	flows	from	our	proved	liquid	hydrocarbon,	natural	gas	and	synthetic	crude	oil	reserves	are	based	on	an	unweighted	average	of	closing	prices	for	the	first	day of	each	month	in	the	12-month	periods	ended	December	31,	2013,	2012	and	2011,	and	costs	applicable	at	the	date	of	the	estimate,	while	actual	future	prices	and	costs may	be	materially	higher	or	lower.

In	addition,	the	10	percent	discount	factor	required	by	the	applicable	rules	of	the	SEC	to	be	used	to	calculate	discounted	future	cash	flows	for	reporting	purposes	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.

If	we	are	unsuccessful	in	acquiring	or	finding	additional	reserves,	our	future	liquid	hydrocarbon	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	liquid	hydrocarbon	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	liquid	hydrocarbons and	natural	gas	are	produced.	Accordingly,	to	the	extent	we	are	not	successful	in	replacing	the	liquid	hydrocarbons	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	liquid	hydrocarbons	and	natural	gas	in	promising areas;

•drilling	success;

•the	ability	to	complete	long	lead-time,	capital-intensive	projects	timely	and	on	budget;

•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	liquid	hydrocarbons	and	natural	gas	involves	numerous	risks,	including	the	risk	that	we	may	not	encounter	commercially	productive	liquid	hydrocarbon and	natural	gas	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;

•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	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	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.

We	may	incur	substantial	capital	expenditures	and	operating	costs	as	a	result	of	compliance	with,	and/or	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	substantial	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.	Currently,	various	legislative	and	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.,	Canada, and	Norway,	and	the	European	Union.	Our	operations	result	in	these	greenhouse	gas	emissions.	Through	2013,	domestic	legislative	and	regulatory	efforts	included proposed	federal	legislation	and	state	actions	to	develop	statewide	or	regional	programs,	each	of	which	could	impose	reductions	in	greenhouse	gas	emissions.	Further,	in December	2012	at	the	Doha	Climate	Change	Conference,

countries	agreed	to	extend	the	Kyoto	Protocol	to	2020.	However,	the	U.S.	Senate	has	not	ratified	the	Kyoto	Protocol,	nor	is	it	clear	whether	the	U.S.	Senate	plans	to ratify	 this	 agreement	 in	 the	 future.	If	 the	U.S.	does	ratify	 the	Kyoto	Protocol	 in	 the	future	or	signs	a	new	 international	agreement,	such	actions	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	liquid	hydrocarbons	and	natural	gas,	and	create	delays	in	our	obtaining	air	pollution	permits	for	new	or	modified facilities.

Although	there	may	be	adverse	financial	impact	(including	compliance	costs,	potential	permitting	delays	and	potential	reduced	demand	for	liquid	hydrocarbons	or natural	gas)	associated	with	any	legislation,	regulation,	or	other	action	by	the	U.S.	EPA,	the	extent	and	magnitude	of	that	impact	cannot	be	reliably	or	accurately estimated	due	to	the	fact	that	requirements	have	only	recently	been	adopted	and	the	present	uncertainty	regarding	any	additional	measures	and	how	they	will	be implemented.	Private	party	litigation	has	also	been	brought	against	some	emitters	of	greenhouse	gas	emissions.

# The	potential	adoption	of	federal	and	state	legislative	and	regulatory	initiatives	related	to	hydraulic	fracturing	could	result	in	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.	The	U.S.	Congress	has	considered	legislation	that	would require	additional	regulation	affecting	the	hydraulic	fracturing	process.	Consideration	of	new	federal	regulation	and	increased	state	oversight	continues	to	arise.	The	U.S. EPA	is	conducting	a	comprehensive	research	study	on	the	potential	effects	that	hydraulic	fracturing	may	have	on	water	quality	and	public	health,	issued	a	progress report	in	late	2012,	and	expects	to	issue	a	draft	report	for	public	comment	and	peer	review	in	2014,	with	a	final	report	expected	in	2016.	In	addition,	various	state-level initiatives	in	regions	with	substantial	shale	gas	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.

Increased	regulation	and	attention	given	to	the	hydraulic	fracturing	process	could	lead	to	greater	opposition,	including	litigation,	to	oil	and	gas	production	activities using	hydraulic	fracturing	techniques.	Additional	legislation	or	regulation	could	also	lead	to	operational	delays	or	increased	operating	costs	in	the	production	of	liquid hydrocarbons	and	natural	gas,	including	from	the	shale	plays,	or	could	make	it	more	difficult	to	perform	hydraulic	fracturing.	The	adoption	of	any	federal	or	state	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.

# Worldwide	political	and	economic	developments	and	changes	in	law	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	55	percent	of	our	liquid	hydrocarbon	and	natural	gas sales	volumes	in	2013	was	derived	from	production	outside	the	U.S.	and	47	percent	of	our	proved	liquid	hydrocarbon	and	natural	gas	reserves	as	of	December	31,	2013 were	located	outside	the	U.S.	All	of	our	synthetic	crude	oil	production	and	proved	reserves	are	located	in	Canada.	We	are,	therefore,	subject	to	the	political,	geographic and	economic	risks	and	possible	terrorist	activities	attendant	to	doing	business	within	or	outside	of	the	U.S.	There	are	many	risks	associated	with	operations	in	countries such	as	E.G.,	Angola,	Ethiopia,	Gabon,	Kenya,	the	Kurdistan	Region	of	Iraq	and	Libya,	and	in	global	markets	including:

•changes in	 governmental	 policies relating to liquid	 hydrocarbon	 or	 natural	 gas and taxation;

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

•political	and	economic	instability,	war,	acts	of	terrorism	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.

Since	January	2010,	there	have	been	varying	degrees	of	political	instability	and	public	protests,	including	demonstrations	which	have	been	marked	by	violence, within	some	countries	in	the	Middle	East	including	Bahrain,	Egypt,	Iraq,	Libya,	Syria,	Tunisia	and	Yemen.	 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; and

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

Continued	hostilities	in	the	Middle	East	and	the	occurrence	or	threat	of	future	terrorist	attacks	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	liquid	hydrocarbons	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	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	commodity	price	risk	management	and	trading	activities	may	prevent	us	from	fully	benefiting	from	commodity	price	increases	and	may	expose	us	to other	risks,	including	counterparty	risk.

To	the	extent	that	we	engage	in	price	risk	management	activities	to	protect	ourselves	against	commodity	price	declines,	we	may	be	prevented	from	fully	realizing the	benefits	of	price	increases	above	the	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	cyber-attacks	targeting	our	computer	and	telecommunications	systems	and	infrastructure.

Our	business,	like	other	companies	in	the	oil	and	gas	industry,	has	become	increasingly	dependent	on	digital	technologies.	Such	technologies	are	integrated	into	our business	operations	and	used	as	a	part	of	our	liquid	hydrocarbon	and	natural	gas	production	and	distribution	systems	in	the	U.S.	and	abroad,	including	those	systems used	to	transport	production	to	market.	Use	of	the	internet	and	other	public	networks	for	communications,	services,	and	storage,	including	"cloud"	computing,	exposes users	(including	our	business)	to	cybersecurity	risks.	While	our	information	systems	and	related	infrastructure	experienced	attempted	and	actual	minor	breaches	of	our cybersecurity	in	the	past,	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	cyber-attacks	continue	to	evolve,	we	may	be	required	to	expend significant	 additional	 resources	 to	 continue	 to	 modify	 or	 enhance	 our	 protective	 measures	 or	 to	 investigate	 and	 remediate	 any	 information	 systems	 and	 related infrastructure	security	vulnerabilities.

# 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	liquid	hydrocarbons	and	natural gas,	which	could	increase	the	costs	and/or	reduce	the	revenues	we	might	obtain	from	the	sale	of	our	production.

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.		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	reserves	(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	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,	oil	sands	mining	or	pipeline	transportation, 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	North	America	E&P	and	International	E&P	operations	are	subject	to	unplanned	occurrences,	including	blowouts,	explosions,	fires,	loss	of	well	control,	spills, hurricanes	and	other	adverse	weather,	tsunamis,	earthquakes,	volcanic	eruptions	or	nuclear	or	other	disasters,	labor	disputes	and	accidents.	Our	OSM	operations	are subject	 to	 business	 interruptions	 due	 to	 breakdown	 or	 failure	 of	 equipment	 or	 processes	 and	 unplanned	 events	 such	 as	 fires,	 earthquakes,	 explosions	 or	 other interruptions.	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	and	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	certain	of	our insurance	policies	have	increased	substantially	and	could	escalate	further.	In	some	instances,	certain	insurance	could	become	unavailable	or	available	only	for	reduced amounts	of	coverage.	For	example,	due	to	hurricane	activity	in	recent	years,	the	availability	of	insurance	coverage	for	our	offshore	facilities	for	windstorms	in	the	Gulf of	Mexico	region	has	been	reduced	or,	in	many	instances,	it	is	prohibitively	expensive.	As	a	result,	our	exposure	to	losses	from	future	windstorm	activity	in	the	Gulf	of Mexico	region	has	increased.

# Litigation	by	private	plaintiffs	or	government	officials	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,	antitrust	laws	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.

# 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	liquid	hydrocarbon	and	natural	gas	properties,	oil	sands	mining	properties	and	facilities,	and	other	important physical	properties	have	been	described	by	segment	under	Item	1.	Business.

Net	liquid	hydrocarbon,	natural	gas,	and	synthetic	crude	oil	sales	volumes	are	set	forth	in	Item	8.	Financial	Statements	and	Supplementary	Data	–	Supplemental Statistics.	Estimated	net	proved	liquid	hydrocarbon,	natural	gas	and	synthetic	crude	oil	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	defendant	in	a	number	of	lawsuits	arising	in	the	ordinary	course	of	business,	including,	but	not	limited	to,	royalty	claims,	contract	claims	and	environmental claims.	While	the	ultimate	outcome	and	impact	to	us	cannot	be	predicted	with	certainty,	we	believe	that	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.

# Litigation

In	March	2011,	Noble	Drilling	(U.S.)	LLC	("Noble")	filed	a	lawsuit	against	us	in	the	District	Court	of	Harris	County,	Texas,	alleging,	among	other	things,	breach of	contract,	breach	of	the	duty	of	good	faith	and	fair	dealing,	and	negligent	misrepresentation,	relating	to	a	multi-year	drilling	contract	for	a	newly	constructed	drilling rig	to	be	deployed	in	the	U.S.	Gulf	of	Mexico.		We	filed	an	answer	in	April	2011,	contending,	among	other	things,	failure	to	perform,	failure	to	comply	with	material obligations,	failure	to	mitigate	alleged	damages	and	that	Noble	failed	to	provide	the	rig	according	to	the	operating,	performance	and	safety	requirements	specified	in	the drilling	contract.	In	April	2013,	we	filed	a	counterclaim	against	Noble	alleging,	among	other	things,	breach	of	contract	and	breach	of	the	duty	of	good	faith	relating	to	the multi-year	drilling	contract.	The	counterclaim	also	included	a	breach	of	contract	claim	for	reimbursement	for	the	value	of	fuel	used	by	Noble	under	an	offshore	daywork drilling	contract.	The	parties	settled	this	litigation	in	the	fourth	quarter	of	2013,	and	the	settlement	did	not	have	a	material	adverse	effect	on	our	consolidated	results	of operations,	financial	position	or	cash	flows.

# Environmental	Proceedings

The	following	is	a	summary	of	proceedings	involving	us	that	were	pending	or	contemplated	as	of	December	31,	2013	under	federal	and	state	environmental	laws. Except	as	described	herein,	it	is	not	possible	to	predict	accurately	the	ultimate	outcome	of	these	matters;	however,	management's	belief	set	forth	in	the	first	paragraph under	Legal	Proceedings	above	takes	such	matters	into	account.

As	of	December	31,	2013,	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,	which	is	in	many	cases	preliminary	and	incomplete,	we believe	that	total	clean-up	and	remediation	costs	connected	with	these	sites	will	be	less	than	$24	million,	the	majority	of	which	have	already	been	incurred.

The	projected	liability	for	clean-up	and	remediation	provided	in	the	preceding	paragraph	is	a	forward-looking	statement.	To	the	extent	that	our	assumptions	prove	to be	inaccurate,	future	expenditures	may	differ	materially	from	those	stated	in	the	forward-looking	statement.

# 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,	2014,	there	were	41,356 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:

|  |  | 2013 |  |  | 2012 |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (Dollars\tper\tshare) | High\tPrice | Low\tPrice | Dividends | High\tPrice | Low\tPrice | Dividends |
| Quarter\t1 | $35.71 | $31.59 | $0.17 | $35.06 | $30.47 | $0.17 |
| Quarter\t2 | $36.38 | $29.85 | $0.17 | $32.23 | $23.32 | $0.17 |
| Quarter\t3 | $37.83 | $32.61 | $0.19 | $31.09 | $24.09 | $0.17 |
| Quarter\t4 | $37.93 | $34.06 | $0.19 | $31.93 | $29.30 | $0.17 |
| Full\tYear | $37.93 | $29.85 | $0.72 | $35.06 | $23.32 | $0.68 |

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

Issuer	Purchases	of	Equity	Securities	–	The	following	table	provides	information	about	purchases	by	Marathon	Oil	and	its	affiliated	purchaser,	during	the	quarter ended	December	31,	2013,	of	equity	securities	that	are	registered	by	Marathon	Oil	pursuant	to	Section	12	of	the	Securities	Exchange	Act	of	1934:

|  | Column	(a) |  | Column	(b) | Column	(c) | Column	(d) |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Period | Total\tNumber\tof\nShares\nPurchased(a) |  | Average\nPrice\tPaid\nper\tShare | Total\tNumber\tof\nShares\tPurchased\nas\tPart\tof\nPublicly\nAnnounced\tPlans\nor\tPrograms(c) | Approximate\nDollar\tValue\tof\nShares\tthat\tMay\nYet\tBe\tPurchased\nUnder\tthe\tPlans\nor\tPrograms(c) |
| 10/01/13\t–\t10/31/13 | 9,404 |  | $35.07 | — | $1,280,820,541 |
| 11/01/13\t–\t11/30/13 | 5,381 |  | $35.18 | — | $1,280,820,541 |
| 12/01/13\t–\t12/31/13 | 33,682 | (b) | $35.84 | — | $2,500,000,000 |
| Total | 48,467 |  | $35.62 | — |  |

(a) 21,898	shares	of	restricted	stock	were	delivered	by	employees	to	Marathon	Oil,	upon	vesting,	to	satisfy	tax	withholding	requirements.

(b) In	 December	 2013,	26,569	 shares	 were	 repurchased	 in	 open-market	 transactions	 to	 satisfy	 the	 requirements	 for	 dividend	 reinvestment	 under	 the	 Marathon	 Oil	 Corporation	 Dividend Reinvestment	and	Direct	Stock	Purchase	Plan	(the	"Dividend	Reinvestment	Plan")	by	the	administrator	of	the	Dividend	Reinvestment	Plan.	Shares	needed	to	meet	the	requirements	of	the Dividend	Reinvestment	Plan	are	either	purchased	in	the	open	market	or	issued	directly	by	Marathon	Oil.

(c) In	December	2013,	our	Board	of	Directors	increased	the	authorization	for	repurchases	of	our	common	stock	by	$1.2	billion,	bringing	the	remaining	share	repurchase	authorization	to	$2.5 billion.	As	of	December	31,	2013,	we	had	repurchased	92	million	common	shares	at	a	cost	of	$3,722	million,	which	includes	transaction	fees	and	commissions	that	are	not	reported	in	the	table above.	Of	this	total,	14	million	shares	were	acquired	at	a	cost	of	$500	million	during	the	third	quarter	of	2013,	12	million	shares	at	a	cost	of	$300	million	in	the	third	quarter	of	2011	and 66	million	shares	for	$2,922	million	prior	to	the	spin-off	of	our	downstream	business.

# Item	6.			Selected	Financial	Data

| (In	millions,	except	per	share	data) | 2013(a)(b) | 2012(a)(b) | 2011(a)(b) | 2010(a)(b) | 2009(b) |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Statement\tof\tIncome\tData |  |  |  |  |  |
| Revenues | $14,501 | \t $15,692 | \t $14,669 | \t $11,690 | \t $8,524 |
| Income\tfrom\tcontinuing\toperations | 1,593 | 1,613 | 1,718 | 1,448 | 756 |
| Net\tincome | 1,753 | 1,582 | 2,946 | 2,568 | 1,463 |
| Per\tShare\tData |  |  |  |  |  |
| Basic: |  |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $2.26 | $2.28 | $2.42 | $2.04 | $1.06 |
| Net\tincome | $2.49 | $2.24 | $4.15 | $3.62 | $2.06 |
| Diluted: |  |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $2.24 | $2.27 | $2.41 | $2.03 | $1.06 |
| Net\tincome | $2.47 | $2.23 | $4.13 | $3.61 | $2.06 |
| Statement\tof\tCash\tFlows\tData (b) |  |  |  |  |  |
| Additions\tto\tproperty,\tplant\tand\tequipment\trelated\tto\ncontinuing\toperations | $4,766 | \t $4,593 | \t $2,986 | \t $3,269 | \t $3,056 |
| Dividends\tpaid | 508 | 480 | 567 | 704 | 679 |
| Dividends\tper\tshare | $0.72 | $0.68 | $0.80 | $0.99 | $0.96 |
| Balance\tSheet\tData\tas\tof\tDecember\t31: |  |  |  |  |  |
| Total\tassets | $35,620 | \t $35,306 | \t $31,371 | \t $50,014 | \t $47,052 |
| Total\tlong-term\tdebt,\tincluding\tcapitalized\tleases | 6,394 | 6,512 | 4,674 | 7,601 | 8,436 |

(b) We	entered	into	agreements	to	sell	our	Angola	assets	in	2013	(see	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	6	to	the	consolidated	financial	statements);	our	downstream business	was	spun-off	on	June	30,	2011	(see	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	3	to	the	consolidated	financial	statements);	and	our	Ireland	and	previous	Gabon businesses	were	sold	in	2009.	The	applicable	periods	have	been	recast	to	reflect	these	businesses	in	discontinued	operations.

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

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

•North	America	 E&P	 –	 explores for,	 produces	 and	 markets liquid	 hydrocarbons	 and	 natural	 gas in	 North America;

•International	E&P	–	explores	for,	produces	and	markets	liquid	hydrocarbons	and	natural	gas	outside	of	North	America	and	produces	and	markets	products manufactured	from	natural	gas,	such	as	LNG	and	methanol,	in	E.G.;	and

•Oil	Sands	Mining	–	mines,	extracts	and	transports	bitumen	from	oil	sands	deposits	in	Alberta,	Canada,	and	upgrades	the	bitumen	to	produce	and	market synthetic	crude	oil	and	vacuum	gas	oil.

Certain	sections	of	Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	include	forward-looking	statements	concerning	trends or	 events	 potentially	 affecting	 our	 business.	These	statements	 typically	contain	words	such	as	"anticipates,"	"believes,"	"estimates,"	"expects,"	"targets,"	"plans," "projects,"	"could,"	"may,"	"should,"	"would"	or	similar	words	indicating	that	future	outcomes	are	uncertain.	In	accordance	with	"safe	harbor"	provisions	of	the	Private Securities	Litigation	Reform	Act	of	1995,	these	statements	are	accompanied	by	cautionary	language	identifying	important	factors,	though	not	necessarily	all	such factors,	which	could	cause	future	outcomes	to	differ	materially	from	those	set	forth	in	the	forward-looking	statements.	For	additional	risk	factors	affecting	our	business, see	Item	1A.	Risk	Factors	in	this	Annual	Report	on	Form	10-K.

Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	should	be	read	 in	conjunction	with the information	under	Item	1. Business,	Item	1A.	Risk	Factors	and	Item	8.	Financial	Statements	and	Supplementary	Data	found	in	this	Annual	Report	on	Form	10-K.

# Spin-off	Downstream	Business

On	June	30,	2011,	the	spin-off	of	Marathon's	downstream	business	was	completed,	creating	two	independent	energy	companies:	Marathon	Oil	and	MPC.	Marathon stockholders	at	the	close	of	business	on	the	record	date	of	June	27,	2011	received	one	share	of	MPC	common	stock	for	every	two	shares	of	Marathon	common	stock held.	A	private	letter	tax	ruling	received	in	June	2011	from	the	IRS	affirmed	the	tax-free	nature	of	the	spin-off.	Activities	related	to	the	downstream	business	have	been treated	as	discontinued	operations	for	all	periods	prior	to	the	spin-off	(see	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	3	to	the	consolidated	financial statements	for	additional	information).

# Overview	–	Market	Conditions

Prevailing	prices	for	the	various	qualities	of	crude	oil	and	natural	gas	that	we	produce	significantly	impact	our	revenues	and	cash	flows.		The	following	table	lists benchmark	crude	oil	and	natural	gas	price	averages	relative	to	our	North	America	E&P	and	International	E&P	segments	for	the	past	three	years.

| Benchmark | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| WTI\tcrude\toil\t(Dollars\tper\tbbl) | $98.05 | $94.15 | $95.11 |
| Brent\t(Europe)\tcrude\toil\t(Dollars\tper\tbbl) | $108.64 | $111.65 | $111.26 |
| Henry\tHub\tnatural\tgas\t(Dollars\tper\tmmbtu)(a) | $3.65 | $2.79 | $4.04 |

# North	America	E&P

Liquid	hydrocarbons	–	The	quality,	location	and	composition	of	our	liquid	hydrocarbon	production	mix	can	cause	our	North	America	E&P	price	realizations	to differ	from	the	WTI	benchmark.

Quality	–	Light	sweet	crude	contains	less	sulfur	and	tends	to	be	lighter	than	sour	crude	oil	so	that	refining	it	is	less	costly	and	has	historically	produced	higher	value products;	therefore,	light	sweet	crude	is	considered	of	higher	quality	and	has	historically	sold	at	a	price	that	approximates	WTI	or	at	a	premium	to	WTI.	The	percentage of	our	North	America	E&P	crude	oil	and	condensate	production	that	is	light	sweet	crude	has	been	increasing	as	onshore	production	from	the	Eagle	Ford	and	Bakken increases	and	production	from	the	Gulf	of	Mexico	declines.	In	2013,	the	percentage	of	our	U.S.	crude	oil	and	condensate	production	that	was	sweet	averaged	76	percent compared	to	63	percent	and	42	percent	in	2012	and	2011.

Location	–	In	recent	years,	crude	oil	sold	along	the	U.S.	Gulf	Coast,	such	as	that	from	the	Eagle	Ford,	has	been	priced	based	on	the	Louisiana	Light	Sweet	("LLS") benchmark	which	has	historically	priced	at	a	premium	to	WTI	and	has	historically	tracked	closely	to	Brent,	while	production	from	inland	areas	farther	from	large refineries	has	been	priced	lower.	The	average	annual	WTI

discount	to	Brent	was	narrower	in	2013	than	in	2012	and	2011.	As	a	result	of	the	significant	increase	in	U.S.	production	of	light	sweet	crude	oil,	the	historical relationship	between	WTI,	Brent	and	LLS	pricing	may	not	be	indicative	of	future	periods.

Composition	–	The	proportion	of	our	liquid	hydrocarbon	sales	volumes	that	are	NGLs	continues	to	increase	due	to	our	development	of	United	States	unconventional liquids-rich	plays.	NGLs	were	15	percent	of	our	North	America	E&P	liquid	hydrocarbon	sales	volumes	in	2013	compared	to	10	percent	in	2012	and	7	percent	in	2011.

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.		Average	Henry	Hub	settlement	prices	for	natural	gas	were	31	percent	higher	for	2013	than	for	2012.

# International	E&P

Liquid	hydrocarbons	–	Our	International	E&P	crude	oil	production	is	relatively	sweet	and	has	historically	sold	in	relation	to	the	Brent	crude	benchmark,	which	on average	was	3	percent	lower	for	2013	than	2012.

Natural	gas	–	Our	major	International	E&P	natural	gas-producing	regions	are	Europe	and	E.G.		Natural	gas	prices	in	Europe	have	been	considerably	higher	than the	U.S.	in	recent	years.		In	the	case	of	E.G.,	our	natural	gas	sales	are	subject	to	term	contracts,	making	realized	prices	in	these	areas	less	volatile.		The	natural	gas	sales from	E.G.	are	at	fixed	prices;	therefore,	our	reported	average	International	E&P	natural	gas	realized	prices	may	not	fully	track	market	price	movements.

# Oil	Sands	Mining

The	Oil	Sands	Mining	segment	produces	and	sells	various	qualities	of	synthetic	crude	oil.	Output	mix	can	be	impacted	by	operational	problems	or	planned	unit outages	at	the	mines	or	upgrader.	Sales	prices	for	roughly	two-thirds	of	the	normal	output	mix	has	historically	tracked	movements	in	WTI	and	one-third	has	historically tracked	movements	in	the	Canadian	heavy	crude	oil	marker,	primarily	WCS.	The	WCS	discount	to	WTI	has	been	increasing	on	average	in	each	year	presented	below. Despite	a	wider	WCS	discount	in	2013,	our	average	Oil	Sands	Mining	price	realizations	increased	due	to	a	greater	proportion	of	higher	value	synthetic	crude	oil	sales volumes	compared	to	2012.

The	operating	cost	structure	of	the	Oil	Sands	Mining	operations	is	predominantly	fixed	and	therefore	many	of	the	costs	incurred	in	times	of	full	operation	continue during	production	downtime.	Per-unit	costs	are	sensitive	to	production	rates.	Key	variable	costs	are	natural	gas	and	diesel	fuel,	which	track	commodity	markets	such	as the	AECO	natural	gas	sales	index	and	crude	oil	prices,	respectively.

The	table	below	shows	average	benchmark	prices	that	impact	both	our	revenues	and	variable	costs:

| Benchmark | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| WTI\tcrude\toil\t(Dollars\tper\tbbl) | $98.05 | $94.15 | $95.11 |
| WCS\t(Dollars\tper\tbbl)(a) | $72.77 | $73.18 | $77.97 |
| AECO\tnatural\tgas\tsales\tindex\t(Dollars\tper\tmmbtu)(b) | $3.08 | $2.39 | $3.68 |

(a) Monthly	pricing	based	upon	average	WTI	adjusted	for	differentials	unique	to	western	Canada.

(b) Monthly	average	day	ahead	index.

# Key	Operating	and	Financial	Activities

# Significant	2013	activities	related	to	our	strategic	imperatives:

# •Production	growth

•Total	company	net	sales	volume	growth	of	11	percent	(excluding	Alaska	and	Libya)

•North	America	E&P	net	sales	volumes	averaged	201	mboed,	a	21	percent	increase	over	last year

•Eagle	Ford	averaged	net	sales	volumes	of	81	mboed,	a	136	percent	increase

•Bakken	averaged	net	sales	volumes	of	39	mboed,	a	34	percent	increase

•Oklahoma	 resource	 basins	 averaged	 net	 sales	 volumes	 of	14	 mboed, a	 68	 percent increase

•Proved reserve replacement of 194 percent, excluding dispositions

•Total	net	proved	reserves	increased	8	percent	to	approximately	2.2	billion boe

•Quality resource capture through focused exploration

•Mirawa-1	discovery	on	operated	Harir	block	in	the	Kurdistan	Region	of

•Diaman-1B discovery on non-operated	 Diaba License in

# Gabon

•Shenandoah	 and	 Gunflint (both	 non-operated)	 prospects	 had	 successful	 appraisal	 wells in the	 Gulf	 of Mexico •Rigorous portfolio management •Exceeded three-year $1.5 billion to $3 billion divestiture target

•Agreements to	 sell	 working interests in	Angola	 Blocks	 31	 and	 32	 with	 an	 aggregate transaction	 value	 of	 $2.1	 billion,	 before	 closing adjustments

•Sold	our	 interests in	Alaska, the	DJ	Basin	and the	Neptune	gas plant

•Acquired	4,800	additional	net	acres in the	core	of the	Eagle	Ford shale

•Grew	SCOOP	acreage	position	over	20	percent

•Commenced	 efforts	 to	 market	 our	 U.K. and	 Norway assets

# •Competitive	shareholder	value

•Increased	 dividend	 by	 12	 percent to	 19	 cents	 per share

•Announced	$500	million	share	repurchase	to	begin	upon	closing	of	Angola	Block	31 sale

•Authorized $1.2 billion increase in share repurchase program to $2.5 billion remaining

Significant	2014	activity	through	February	28,	2014	includes:

•Closed	sale	of	our	interest	in	Angola	Block

# Consolidated	Results	of	Operations:	2013	compared	to	2012

Consolidated	income	from	continuing	operations	before	income	taxes	in	2013	was	20	percent	lower	than	2012	primarily	due	to	lower	liquid	hydrocarbon	net	sales volumes	in	the	International	E&P	segment	and	higher	DD&A	and	exploration	expenses,	partially	offset	by	higher	liquid	hydrocarbon	net	sales	volumes	in	the	North America	E&P	segment.	The	effective	tax	rate	for	continuing	operations	was	68	percent	in	2013	compared	to	74	percent	in	2012,	with	the	decrease	primarily	related	to lower	income	from	continuing	operations	in	Libya	and	Norway,	which	are	higher	tax	jurisdictions.

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

| (In	millions) | 2013 | 2012 |
| :--- | :--- | :--- |
| Sales\tand\tother\toperating\trevenues,\tincluding\trelated\tparty |  |  |
| North\tAmerica\tE&amp;P | $5,068 | $3,944 |
| International\tE&amp;P | 5,827 | 7,445 |
| Oil\tSands\tMining | 1,576 | 1,521 |
| Segment\tsales\tand\tother\toperating\trevenues,\tincluding\trelated\tparty | 12,471 | 12,910 |
| Unrealized\tgain\t(loss)\ton\tcrude\toil\tderivative\tinstruments | (52) | 53 |
| Sales\tand\tother\toperating\trevenues,\tincluding\trelated\tparty | $12,419 | $12,963 |

North	America	E&P	sales	and	other	operating	revenues	increased	$1,124	million	from	2012	to	2013	primarily	due	to	higher	liquid	hydrocarbon	net	sales	volumes resulting	from	ongoing	development	programs	in	the	Eagle	Ford,	Bakken	and	Oklahoma	resource	basins,	partially	offset	by	lower	natural	gas	net	sales	volumes, primarily	the	result	of	the	sale	of	our	Alaska	assets	in	early	2013.

The	following	table	gives	details	of	net	sales	volumes	and	average	price	realizations	of	our	North	America	E&P	segment:

|  | 2013 | 2012 |
| :--- | :--- | :--- |
| North\tAmerica\tE&amp;P\tOperating\tStatistics |  |  |
| Net\tliquid\thydrocarbon\tsales\tvolumes\t(mbbld) | 149 | 107 |
| Liquid\thydrocarbon\taverage\tprice\trealizations\t(per\tbbl)\t(a)\t(b) | $85.20 | $85.80 |
| Net\tcrude\toil\tand\tcondensate\tsales\tvolumes\t(mbbld) | 126 | 96 |
| \t\t\t\t\tCrude\toil\tand\tcondensate\taverage\tprice\trealizations\t(per\tbbl)\t(a) | $94.19 | $91.30 |
| \t\t\t\t\tNet\tnatural\tgas\tliquids\tsales\tvolumes\t(mbbld) | 23 | 11 |
| \t\t\t\t\tNatural\tgas\tliquids\taverage\tprice\trealizations\t(per\tbbl)\t(a) | $35.12 | $39.57 |
| Net\tnatural\tgas\tsales\tvolumes\t(mmcfd) | 312 | 358 |
| Natural\tgas\taverage\tprice\trealizations\t(per\tmcf)\t(a) | $3.84 | $3.92 |

(a) Excludes	gains	and	losses	on	derivative	instruments.

(b) Inclusion	of	realized	gains	(losses)	on	crude	oil	derivative	instruments	would	have	increased	(decreased)	average	liquid	hydrocarbon	price	realizations	per	bbl	by $(0.27)	for	2013	and	$0.40 for	2012.

International	 E&P	 sales	 and	 other	 operating	 revenues	 decreased	 $1,618	 million in	2013	 from the	 prior	 year.	This	 decrease	 was	 primarily	 due to lower liquid hydrocarbon	net	sales	volumes	in	Libya	and	Norway	and	lower	liquid	hydrocarbon	average	price	realizations.

The	following	table	gives	details	of	net	sales	volumes	and	average	price	realizations	of	our	International	E&P	segment:

|  | 2013 | 2012 |
| :--- | :--- | :--- |
| International\tE&amp;P\tOperating\tStatistics |  |  |
| \t\t\t\t\tNet\tliquid\thydrocarbon\tsales\tvolumes\t(mbbld)(a) |  |  |
| Europe | 86 | 97 |
| Africa | 58 | 78 |
| Total\tInternational\tE&amp;P | 144 | 175 |
| \t\t\t\t\tLiquid\thydrocarbon\taverage\tprice\trealizations\t(per\tbbl) |  |  |
| Europe | $112.60 | $115.16 |
| Africa | $86.29 | $98.52 |
| Total\tInternational\tE&amp;P | $102.10 | $107.78 |
| Net\tnatural\tgas\tsales\tvolumes\t(mmcfd) |  |  |
| Europe(b) | 83 | 101 |
| Africa | 464 | 443 |
| Total\tInternational\tE&amp;P | 547 | 544 |
| \t\t\t\t\tNatural\tgas\taverage\tprice\trealizations\t(per\tmcf) |  |  |
| Europe | $12.08 | $10.47 |
| Africa(c) | $0.49 | $0.43 |
| Total\tInternational\tE&amp;P | $2.25 | $2.29 |

(a) Corresponds	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	of	 7	mmcfd	and	15	mmcfd	for	2013	and	2012.

(c) Primarily	represents	fixed	prices	under	long-term	contracts	with	Alba	Plant	LLC,	AMPCO,	and	EGHoldings,	equity	method	investees.	We	include	our	share	of	Alba	Plant	LLC's,	AMPCO's and	EGHoldings'	income	in	our	International	E&P	segment.

Oil	Sands	Mining	sales	and	other	operating	revenues	increased	$55	million	in	2013	from	2012.	This	increase	was	primarily	due	to	a	higher	proportion	of	net	sales volumes	related	to	a	premium	grade	synthetic	crude	oil	and	the	associated	average	price	realizations	when	compared	to	2012.	The	increase	was	partially	offset	by	lower feedstock	sales	in	2013.

The	following	table	gives	details	of	net	sales	volumes	and	average	price	realizations	of	our	Oil	Sands	Mining	segment:

# (a) Includes	blendstocks.

Unrealized	gains	and	losses	on	crude	oil	derivative	instruments	are	included	in	total	sales	and	other	operating	revenues	but	are	not	allocated	to	the	segments.	These crude	oil	derivative	instruments,	all	of	which	had	terms	that	ended	in	December	2013,	resulted	in	a	$52	million	net	unrealized	loss	in	2013	compared	to	a	net	unrealized gain	of	$53	million	in	2012.	See	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	16	to	the	consolidated	financial	statements	for	information	about	our derivative	positions.

Marketing	revenues	decreased	$647	million	in	2013	from	2012.	North	America	E&P	segment	marketing	activities,	which	serve	to	aggregate	volumes	in	order	to satisfy	transportation	commitments	as	well	as	to	achieve	flexibility	within	product	types	and	delivery	points,	decreased	in	2013	as	a	result	of	market	dynamics.

	Income	from	equity	method	investments	increased	$53	million	in	2013	from	the	prior	year	primarily	due	to	higher	LNG	average	price	realizations.

Net	gain	(loss)	on	disposal	of	assets	in	2013	primarily	included	a	$114	million	pretax	loss	on	the	sale	of	our	interests	in	the	DJ	Basin,	a	$43	million	pretax	loss	on the	conveyance	of	our	interests	in	the	Marcellus	natural	gas	shale	play	to	the	operator,	a	$98	million	pretax	gain	on	the	sale	of	our	interest	in	the	Neptune	gas	plant,	and	a $55	million	pretax	gain	on	the	sale	of	our	remaining	assets	in	Alaska.	The	net	gain	on	disposal	of	assets	in	2012	consisted	primarily	of	a	$166	million	pretax	gain	on	the sale	of	our	interests	in	several	Gulf	of	Mexico	crude	oil	pipeline	systems	and	a	$36	million	pretax	loss	related	to	our	exit	from	Indonesia.	See	Item	8.	Financial Statements	and	Supplementary	Data	-	Note	6	to	the	consolidated	financial	statements	for	information	about	these	dispositions.

Production	expenses	increased	$129	million	in	2013	from	2012	primarily	related	to	increased	North	America	E&P	net	sales	volumes	in	the	Eagle	Ford	and	Bakken and	International	E&P	well	workovers	in	Norway.	The	production	expense	rate	(expense

per	boe)	decreased	 in	North	America	E&P	 in	2013	 compared	 to	2012	primarily	due	to	improved	operating	efficiencies	in the	Eagle	Ford.	The	International	E&P production	expense	rate	increased	in	2013	compared	to	2012	primarily	due	to	the	well	workovers	in	Norway.

The	following	table	provides	production	expense	rates	for	each	segment:

| ($	per	boe) | 2013 | 2012 |
| :--- | :--- | :--- |
| North\tAmerica\tE&amp;P | $10.86 | $11.59 |
| International\tE&amp;P | $6.24 | $5.13 |
| Oil\tSands\tMining\t(a) | $46.30 | $45.95 |

(a) Production	expense	per	synthetic	crude	oil	barrel	(before	royalties)	includes	production	costs,	shipping	and	handling,	taxes	other	than	income	and	insurance	costs	and	excludes	pre-development costs.

Marketing	expenses	decreased	$672	million	in	2013	from	the	prior	year,	consistent	with	the	decrease	in	marketing	revenues	discussed	above.

	Exploration	expenses	were	$282	million	higher	in	2013	than	in	2012,	primarily	due	to	larger	non-cash	unproved	property	impairments	in	our	North	America	E&P segment	related	to	Eagle	Ford	leases	that	either	expired	or	that	we	did	not	expect	to	drill,	partially	offset	by	reduced	geological	and	geophysical	costs.

The	following	table	summarizes	the	components	of	exploration	expenses:

| (In	millions) | 2013 | 2012 |
| :--- | :--- | :--- |
| Unproved\tproperty\timpairments | $580 | $227 |
| Dry\twell\tcosts | 218 | 230 |
| Geological\tand\tgeophysical | 84 | 135 |
| Other | 106 | 114 |
| Total\texploration\texpenses | $988 | $706 |

Depreciation,	depletion	and	amortization	increased	$313	million	in	2013	from	the	prior	year.		Our	segments	apply	the	units-of-production	method	to	the	majority of	their	assets,	including	capitalized	asset	retirement	costs.	Increased	DD&A	in	2013	primarily	reflects	the	impact	of	higher	North	America	E&P	sales	volumes	as	well as	increased	amortization	of	capitalized	asset	retirement	costs	due	to	revisions	of	estimates	for	abandonment	obligations	in	the	Gulf	of	Mexico	and	the	U.K.	However, the	disposition	of	our	Alaska	assets	in	January	2013	and	lower	International	E&P	DD&A	primarily	due	to	2013	reserve	additions	in	Norway	partially	offset	the	increase. See	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	6	to	the	consolidated	financial	statements	for	information	about	the	Alaska	disposition.

The	DD&A	rate	(expense	per	boe),	which	is	impacted	by	changes	in	reserves	and	capitalized	costs,	can	also	cause	changes	to	our	DD&A.		A	higher	2013	DD&A rate	in	North	America	E&P	versus	2012	is	due	to	the	ongoing	development	programs	in	the	U.S.	resource	plays.	A	lower	International	E&P	DD&A	rate	in	2013 compared	to	2012	was	primarily	due	to	reserve	increases	for	Norway.

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

| ($	per	boe) | 2013 | 2012 |
| :--- | :--- | :--- |
| North\tAmerica\tE&amp;P | $26.23 | $23.45 |
| International\tE&amp;P | $7.26 | $8.08 |
| Oil\tSands\tMining | $12.39 | $12.57 |

	Impairments	in	2013	primarily	related	to	capitalized	costs	associated	with	engineering	and	feasibility	studies	for	a	second	LNG	production	train	in	E.G.,	the	Ozona development	in	the	Gulf	of	Mexico,	and	our	Powder	River	Basin	asset	in	Wyoming.	Impairments	in	2012	were	also	related	to	the	Ozona	development	and	Powder	River Basin.		See	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	15	to	the	consolidated	financial	statements	for	information	about	these	impairments.

	Taxes	other	than	income	include	production,	severance	and	ad	valorem	taxes	in	the	United	States,	which	tend	to	increase	or	decrease	in	relation	to	net	sales volumes	and	revenues,	and	increased	$104	million	 in	2013	 from	2012.	With	the	increase	in	North	America	E&P	revenues	and	net	sales	volumes,	production	and severance	taxes	increased.	In	addition,	ad	valorem	taxes	were	higher	because	the	value	of	our	North	America	E&P	assets	has	increased	with	continued	acquisitions	in the	Eagle	Ford.

Net	interest	and	other	increased	$55	million	in	2013	from	2012	primarily	due	to	higher	interest	expense	related	to	our	$2	billion	issuance	of	senior	notes	in	late 2012.	See	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	9	to	the	consolidated	financial	statements	for	more	detailed	information.

Provision	for	income	taxes	decreased	$1,180	million	in	2013	from	2012	primarily	due	to	the	decrease	in	pretax	income	from	continuing	operations,	primarily	in Libya	and	Norway,	which	are	higher	tax	jurisdictions.	The	following	is	an	analysis	of	the	effective	tax	rates	for	2013	and	2012.

|  | 2013 | 2012 |
| :--- | :--- | :--- |
| Statutory\trate\tapplied\tto\tincome\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | 35% | 35% |
| Effects\tof\tforeign\toperations,\tincluding\tforeign\ttax\tcredits | 14 | 18 |
| Adjustments\tto\tvaluation\tallowances | 18 | 21 |
| Other | 1 | — |
| Effective\tincome\ttax\trate\ton\tcontinuing\toperations | 68% | 74% |

The	effective	income	tax	rate	is	influenced	by	a	variety	of	factors	including	the	geographic	sources	of	income	and	the	relative	magnitude	of	these	sources	of	income. The	provision	for	income	taxes	is	allocated	on	a	discrete,	stand-alone	basis	to	pretax	segment	income	and	to	individual	items	not	allocated	to	segments.	The	difference between	the	total	provision	and	the	sum	of	the	amounts	allocated	to	segments	appears	in	the	"Corporate	and	other	unallocated	items"	shown	in	the	reconciliation	of segment	income	to	net	income	below.

Effects	of	foreign	operations	–	The	effects	of	foreign	operations	on	our	effective	tax	rate	decreased	in	2013	as	compared	to	2012,	primarily	due	to	decreased	sales	in Libya	during	2013	as	a	result	of	third-party	labor	strikes	at	the	Es	Sider	oil	terminal.

Adjustments	to	valuation	allowances	–	In	2013	and	2012,	we	increased	the	valuation	allowance	against	foreign	tax	credits	because	it	is	more	likely	than	not	that	we will	be	unable	to	realize	all	U.S.	benefits	on	foreign	taxes	accrued	in	those	years.

See	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	10	to	the	consolidated	financial	statements	for	further	information	about	income	taxes.

Discontinued	operations	is	presented	net	of	tax.	In	2013,	we	entered	into	agreements	to	sell	our	Angola	assets;	therefore,	the	Angola	operations	are	reflected	as discontinued	operations	in	all	periods	presented.	See	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	6	to	the	consolidated	financial	statements.

Segment	income	for	2013	and	2012	is	summarized	and	reconciled	to	net	income	in	the	following	table.

| (In	millions) | 2013 | 2012 |
| :--- | :--- | :--- |
| North\tAmerica\tE&amp;P | $529 | \t $382 |
| International\tE&amp;P | 1,423 | 1,660 |
| Oil\tSands\tMining | 206 | 171 |
| Segment\tincome | 2,158 | 2,213 |
| Items\tnot\tallocated\tto\tsegments,\tnet\tof\tincome\ttaxes: |  |  |
| Corporate\tand\tother\tunallocated\titems | (473) | (475) |
| Unrealized\tgain\t(loss)\ton\tcrude\toil\tderivative\tinstruments | (33) | 34 |
| Net\tgain\t(loss)\ton\tdispositions | (20) | 72 |
| Impairments | (39) | (231) |
| Income\tfrom\tcontinuing\toperations | 1,593 | 1,613 |
| \t\t\t\tDiscontinued\toperations | 160 | (31) |
| Net\tincome | $1,753 | \t $1,582 |

	North	America	E&P	segment	income	increased	$147	million	in	2013	compared	to	2012.	The	increase	was	largely	due	to	increased	liquid	hydrocarbon	net	sales volumes	primarily	in	the	Eagle	Ford,	Bakken	and	Oklahoma	resource	basins,	partially	offset	by	higher	DD&A	associated	with	the	higher	sales	volumes.	Segment	income was	also	negatively	impacted	by	higher	exploration	expenses	related	to	non-cash	unproved	property	impairments	and	the	sale	of	our	Alaska	assets.

	International	E&P	segment	income	decreased	$237	million	in	2013	compared	to	2012.	The	decrease	was	primarily	related	to	the	lower	liquid	hydrocarbon	net	sales volumes	in	Libya	and	Norway	and	lower	average	liquid	hydrocarbon	price	realizations,	as	well	as	higher	exploration	expenses,	partially	offset	by	lower	DD&A associated	with	the	lower	sales	volumes.

	Oil	Sands	Mining	segment	income	increased	$35	million	in	2013	compared	to	2012.	This	increase	was	primarily	due	to	a	higher	proportion	of	net	sale	volumes	in 2013	related	to	a	premium	grade	of	synthetic	crude	oil	with	a	higher	corresponding	price	realization.

Consolidated	income	from	continuing	operations	before	income	taxes	in	2012	was	38	percent	higher	than	in	2011	primarily	related	to	increases	in	North	America E&P	and	International	E&P	liquid	hydrocarbon	net	sales	volumes	and	higher	average	price	realizations	in	International	E&P.	The	effective	tax	rate	for	continuing operations	was	74	percent	in	2012	compared	to	61	percent	in	2011,	with	the	increase	primarily	related	to	resumption	in	2012	of	sales	in	Libya,	which	is	a	higher	tax jurisdiction.	Also,	in	2011	we	were	not	in	an	excess	foreign	tax	credit	position	for	the	entire	year	as	we	were	in	2012.

| (In	millions) | 2012 | 2011 |
| :--- | :--- | :--- |
| Sales\tand\tother\toperating\trevenues,\tincluding\trelated\tparty |  |  |
| North\tAmerica\tE&amp;P | $3,944 | $3,364 |
| International\tE&amp;P | 7,445 | 5,851 |
| Oil\tSands\tMining | 1,521 | 1,535 |
| Segment\tsales\tand\tother\toperating\trevenues,\tincluding\trelated\tparty | 12,910 | 10,750 |
| Unrealized\tgain\t(loss)\ton\tcrude\toil\tderivative\tinstruments | 53 | — |
| Sales\tand\tother\toperating\trevenues,\tincluding\trelated\tparty | $12,963 | $10,750 |

North	America	E&P	sales	and	other	operating	revenues	increased	$580	million	in	2012	from	2011	primarily	due	to	higher	liquid	hydrocarbon	net	sales	volumes resulting	from	ongoing	development	programs	in	the	Eagle	Ford	and	Bakken,	partially	offset	by	lower	average	liquid	hydrocarbon	and	natural	gas	price	realizations, when	compared	to	2011.	Realized	gains	on	our	North	America	E&P	crude	oil	derivative	instruments	were	$15	million	in	2012,	while	there	were	no	open	crude	oil derivative	instruments	in	2011.

|  | 2012 | 2011 |
| :--- | :--- | :--- |
| North\tAmerica\tE&amp;P\tOperating\tStatistics |  |  |
| Net\tliquid\thydrocarbon\tsales\tvolumes\t(mbbld) | 107 | 75 |
| Liquid\thydrocarbon\taverage\tprice\trealizations\t(per\tbbl)\t(a)(b) | $85.80 | $92.55 |
| Net\tcrude\toil\tand\tcondensate\tsales\tvolumes\t(mbbld) | 96 | 70 |
| \t\t\t\t\tCrude\toil\tand\tcondensate\taverage\tprice\trealizations\t(per\tbbl)\t(a) | $91.30 | $94.80 |
| \t\t\t\t\tNet\tnatural\tgas\tliquids\tsales\tvolumes\t(mbbld) | 11 | 5 |
| \t\t\t\t\tNatural\tgas\tliquids\taverage\tprice\trealizations\t(per\tbbl)\t(a) | $39.57 | $58.53 |
| Net\tnatural\tgas\tsales\tvolumes\t(mmcfd) | 358 | 326 |
| Natural\tgas\taverage\tprice\trealizations\t(per\tmcf)\t(a) | $3.92 | $4.95 |

(b) Inclusion	of	realized	gains	on	crude	oil	derivative	instruments	would	have	increased	average	liquid	hydrocarbon	price	realizations	by $0.40	per	bbl	for	2012.	There	were	no	crude	oil	derivative instruments	in	2011.

International	E&P	sales	and	other	operating	revenues	increased	$1,594	million	in	2012	from	2011	primarily	as	a	result	of	the	previously	discussed	resumption	of	liquid hydrocarbon	sales	 in	Libya.	Higher	average	liquid	hydrocarbon	price	realizations	during	2012,	again	primarily	related	to	Libyan	crude	oil,	also	contributed	to	the revenue	increase.

# International	E&P	Operating	Statistics

|  | 2012 | 2011 |
| :--- | :--- | :--- |
| International\tE&amp;P\tOperating\tStatistics |  |  |
| \t\t\t\t\tNet\tliquid\thydrocarbon\tsales\tvolumes\t(mbbld)(a) |  |  |
| Europe | 97 | 101 |
| Africa | 78 | 43 |
| Total\tInternational\tE&amp;P | 175 | 144 |
| \t\t\t\t\tLiquid\thydrocarbon\taverage\tprice\trealizations\t(per\tbbl) |  |  |
| Europe | $115.16 | $115.55 |
| Africa | $98.52 | $73.21 |
| Total\tInternational\tE&amp;P | $107.78 | $102.96 |
| Net\tnatural\tgas\tsales\tvolumes\t(mmcfd) |  |  |
| Europe(b) | 101 | 97 |
| Africa | 443 | 443 |
| Total\tInternational\tE&amp;P | 544 | 540 |
| \t\t\t\t\tNatural\tgas\taverage\tprice\trealizations\t(per\tmcf) |  |  |
| Europe | $10.47 | $9.84 |
| Africa(c) | $0.43 | $0.24 |
| Total\tInternational\tE&amp;P | $2.29 | $1.97 |

Oil	Sands	Mining	sales	and	other	operating	revenues	decreased	$14	million	in	2012	from	2011.	This	decrease	was	primarily	the	result	of	lower	average	price realizations	which	were	partially	offset	by	higher	net	sales	volumes.

Unrealized	gains	and	losses	on	crude	oil	derivative	instruments	are	included	in	total	sales	and	other	operating	revenues	but	are	not	allocated	to	the	segments.	These crude	oil	derivative	instruments	resulted	in	a	net	unrealized	gain	of	$53	million	in	2012,	however,	there	were	no	open	crude	oil	derivative	instruments	in	2011.	See	Item 8.	Financial	Statements	and	Supplementary	Data	-	Note	16	to	the	consolidated	financial	statements	for	additional	information	about	our	derivative	positions.

Marketing	revenues	decreased	$1,190	million	in	2012	from	2011.	North	America	E&P	segment	marketing	activities,	which	serve	to	aggregate	volumes	in	order	to satisfy	transportation	commitments	as	well	as	to	achieve	flexibility	within	product	types	and	delivery	points,	decreased	in	2012	as	a	result	of	market	dynamics	and slightly	lower	commodity	prices.

	Income	from	equity	method	investments	decreased	$92	million	in	2012	from	the	prior	year	primarily	due	to	lower	natural	gas	prices	and	turnarounds	early	in	2012 at	our	facilities	in	E.G.	Also,	in	January	2012,	we	sold	our	equity	investments	in	several	Gulf	of	Mexico	crude	oil	pipelines.

Net	gain	(loss)	on	disposal	of	assets	in	2012	consisted	primarily	of	the	$166	million	pretax	gain	on	the	sale	of	our	interests	in	several	Gulf	of	Mexico	crude	oil pipeline	systems	and	a	$36	million	pretax	loss	related	to	our	exit	from	Indonesia.	In	2011,	the	net	gain	on	disposal	of	assets	was	primarily	related	to	the	$37	million pretax	gain	related	to	the	assignment	of	interests	in	our	DJ	Basin	acreage	position,	the	$34	million	pretax	gain	on	the	sale	of	our	interest	in	the	Burns	Point	gas	plant	and the	$8	million	pretax	gain	on	the	sale	of	our	interest	in	the	Alaska	LNG	facility.	See	Item	8.	Financial	Statements	and	Supplementary	Data	-	Note	6	to	the	consolidated financial	statements	for	information	about	these	dispositions.

Production	expenses	increased	$251	million	in	2012	from	2011.	The	increase	is	primarily	related	to	increased	liquid	hydrocarbon	net	sales	volumes	in	the	Eagle Ford,	Bakken	and	Libya	as	well	as	the	2012	planned	turnaround	in	the	U.K.

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

| ($	per	boe) | 2012 | 2011 |
| :--- | :--- | :--- |
| North\tAmerica\tE&amp;P | $11.59 | $11.51 |
| International\tE&amp;P | $5.13 | $4.80 |
| Oil\tSands\tMining\t(a) | $45.95 | $46.27 |

Marketing	expenses	decreased	$1,154	million	in	2012	from	the	prior	year,	consistent	with	the	decreases	in	marketing	revenues	discussed	above.

	Exploration	expenses	were	$65	million	 higher	 in	2012	 than	 in	2011,	 primarily	 due	 to	 larger	 non-cash	 unproved	 property	 impairments.	Unproved	 property impairments	in	2012	related	to	Marcellus,	Eagle	Ford	and	Indonesia.	The	following	table	summarizes	the	components	of	exploration	expenses.

| (In	millions) | 2012 | 2011 |
| :--- | :--- | :--- |
| Unproved\tproperty\timpairments | $227 | $79 |
| Dry\twell\tcosts | 230 | 278 |
| Geological\tand\tgeophysical | 135 | 124 |
| Other | 114 | 160 |
| Total\texploration\texpenses | $706 | $641 |

Depreciation,	depletion	and	amortization	increased	$214	million	in	2012	from	the	prior	year.		Our	segments	apply	the	units-of-production	method	to	the	majority of	their	assets;	therefore,	the	previously	discussed	increases	in	North	America	E&P	and	International	E&P	sales	volumes	generally	result	in	similar	changes	in	DD&A. There	was	no	depletion	of	our	Alaska	assets	for	much	of	2012	because	they	were	held	for	sale,	which	partially	offset	the	DD&A	increase.

The	DD&A	rate	(expense	per	boe),	which	is	impacted	by	changes	in	reserves	and	capitalized	costs,	can	also	cause	changes	in	our	DD&A.		The	decreases	in	both	the North	America	E&P	and	International	E&P	DD&A	rates	in	2012	compared	to	2011	were	primarily	due	to	proved	reserve	additions.

| ($	per	boe) | 2012 | 2011 |
| :--- | :--- | :--- |
| North\tAmerica\tE&amp;P | $23.45 | $25.15 |
| International\tE&amp;P | $8.08 | $9.70 |
| Oil\tSands\tMining | $12.57 | $12.43 |

Impairments	in	2012	primarily	related	to	the	Ozona	development	in	the	Gulf	of	Mexico	and	to	our	Powder	River	Basin	asset	in	Wyoming.		Impairments	in	2011 primarily	related	 to	 the	Droshky	development	 in	 the	Gulf	of	Mexico	and	an	 intangible	asset	for	an	LNG	delivery	contract	at	Elba	Island.	See	Item	8.	Financial Statements	and	Supplementary	Data	-	Note	15	to	the	consolidated	financial	statements	for	information	about	these	impairments.

	Taxes	other	than	income	include	production,	severance	and	ad	valorem	taxes	in	the	United	States,	which	tend	to	increase	or	decrease	in	relation	to	sales	volumes and	revenues,	and	increased	$55	million	in	2012	from	2011.	With	the	increase	in	revenues	related	to	higher	sales	volumes,	production	and	severance	taxes	increased.	In addition,	ad	valorem	taxes	are	higher	because	the	value	of	our	U.S.	assets	increased	with	the	acquisitions	in	the	Eagle	Ford	shale.

Net interest	and	other	increased	$112	million	 in	2012	 from	2011	 primarily	 due	 to	 lower	 capitalized interest in	 2012.	See	 Item	 8.	 Financial	 Statements	 and Supplementary	Data	-	Note	9	to	the	consolidated	financial	statements	for	more	detailed	information.

Loss	on	early	extinguishment	of	debt	relates	to	debt	retirements	in	February	and	March	of	2011.

Provision	for	income	taxes	increased	$1,791	million	in	2012	from	2011	primarily	due	to	the	increase	in	pretax	income	from	continuing	operations,	including	the impact	of	the	resumption	of	sales	in	Libya	in	the	first	quarter	of	2012.	The	following	is	an	analysis	of	the	effective	income	tax	rates	for	2012	and	2011:

|  | 2012 | 2011 |
| :--- | :--- | :--- |
| Statutory\trate\tapplied\tto\tincome\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | 35% | 35% |
| Effects\tof\tforeign\toperations,\tincluding\tforeign\ttax\tcredits | 18 | 6 |
| Change\tin\tpermanent\treinvestment\tassertion | — | 5 |
| Adjustments\tto\tvaluation\tallowances | 21 | 14 |
| Tax\tlaw\tchanges | — | 1 |
| Effective\tincome\ttax\trate\ton\tcontinuing\toperations | 74% | 61% |

Effects	of	foreign	operations	–	The	effects	of	foreign	operations	on	our	effective	tax	rate	increased	in	2012	as	compared	to	2011,	primarily	due	to	the	resumption	of sales	in	Libya	in	the	first	quarter	of	2012,	where	the	statutory	rate	is	in	excess	of	90	percent.

Change	in	permanent	reinvestment	assertion	–	In	the	second	quarter	of	2011,	we	recorded	$716	million	of	deferred	U.S.	tax	on	undistributed	earnings	of	$2,046 million	that	we	previously	intended	to	permanently	reinvest	in	foreign	operations.	Offsetting	this	tax	expense	were	associated	foreign	tax	credits	of	$488	million.	In addition,	we	reduced	our	valuation	allowance	related	to	foreign	tax	credits	by	$228	million	due	to	recognizing	deferred	U.S.	tax	on	previously	undistributed	earnings.

Discontinued	operations	is	presented	net	of	tax,	and	reflects	our	downstream	business	that	was	spun	off	June	30,	2011	and	our	Angola	business	which	we	agreed	to sell	in	2013.	See	Item	8.	Financial	Statements	and	Supplementary	Data	–	Notes	3	and	6	to	the	consolidated	financial	statements	for	additional	information.

| (In	millions) | 2012 | 2011 |
| :--- | :--- | :--- |
| North\tAmerica\tE&amp;P | $382 | $392 |
| International\tE&amp;P | 1,660 | 1,991 |
| Oil\tSands\tMining | 171 | 261 |
| Segment\tincome | 2,213 | 2,644 |
| Items\tnot\tallocated\tto\tsegments,\tnet\tof\tincome\ttaxes: |  |  |
| Corporate\tand\tother\tunallocated\titems | (475) | (359) |
| Unrealized\tgain\ton\tcrude\toil\tderivative\tinstruments | 34 | — |
| Net\tgain\ton\tdispositions | 72 | 45 |
| Impairments | (231) | (195) |
| \t\t\t\t\tLoss\ton\tearly\textinguishment\tof\tdebt | — | (176) |
| \t\t\t\t\tTax\teffect\tof\tsubsidiary\trestructuring | — | (122) |
| \t\t\t\t\tDeferred\tincome\ttax\titems | — | (61) |
| \t\t\t\t\tWater\tabatement\t-\tOil\tSands | — | (48) |
| \t\t\t\t\tEagle\tFord\ttransaction\tcosts | — | (10) |
| Income\tfrom\tcontinuing\toperations | 1,613 | 1,718 |
| \t\t\t\tDiscontinued\toperations | (31) | 1,228 |
| Net\tincome | $1,582 | $2,946 |

	North	America	E&P	segment	income	decreased	$10	million	in	2012	compared	to	2011.	The	decrease	is	largely	due	to	lower	liquid	hydrocarbon	price	realizations and	increased	exploration	expenses	due	to	non-cash	unproved	property	impairments,	partially	offset	by	higher	liquid	hydrocarbon	net	sales	volumes	primarily	in	the Eagle	Ford	and	Bakken.

	International	E&P	segment	income	decreased	$331	million	in	2012	compared	to	2011.	The	decrease	included	lower	earnings	in	the	U.K.	and	E.G.,	partially	offset by	higher	earnings	in	Libya.		Also,	in	2011	we	were	not	in	an	excess	foreign	tax	credit	position	for	the	entire	year	as	we	were	in	2012.

	Oil	Sands	Mining	segment	income	decreased	$90	million	in	2012	compared	to	2011.	The	decrease	is	primarily	due	to	lower	synthetic	crude	oil	price	realizations partially	offset	by	higher	net	sales	volumes.

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

# Cash	Flows

Net	cash	provided	by	continuing	operations	was	$5,091	million in	2013	compared	 to	$4,036	million	 in	2012	 and	$5,441	million	 in	2011.	The	$1,055	million increase	in	2013	primarily	reflects	the	impact	of	increased	North	America	E&P	liquid	hydrocarbon	net	sales	volumes	on	operating	income.	The	$1,405	million	decrease in	2012	was	primarily	the	result	of	working	capital	changes	related	to	the	2012	ramp-up	of	operations	in	the	Eagle	Ford	and	Libya	along	with	the	timing	of	tax	payments.

Net	cash	used	in	investing	activities	related	to	continuing	operations	totaled	$4,294	million	in	2013	compared	to	$5,092	million	in	2012	and	$6,865	million	in	2011. Significant	investing	activities	include	acquisitions,	additions	to	property,	plant	and	equipment	and	asset	disposals.

Acquisitions	in	2013,	2012	and	2011	included	proved	and	unproved	assets	in	the	Eagle	Ford.	See	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	5	to the	consolidated	financial	statements	for	further	information	about	the	transactions.	In	recent	years,	the	focus	of	most	of	our	capital	spending	has	been	in	our	North America	E&P	segment	related	to	unconventional	resource	plays	like	the	Eagle	Ford,	Bakken	and	Oklahoma	resource	basins.

Disposals	of	assets	totaled	$450	million,	$467	million,	and	$518	million	in	2013,	2012	and	2011.	In	2013,	net	proceeds	were	primarily	related	to	the	sales	of	our interests	in	Alaska,	the	Neptune	gas	plant,	and	the	DJ	Basin.	In	2012,	net	proceeds	were	primarily	from	the	sales	of	our	interests	in	several	Gulf	of	Mexico	crude	oil pipeline	systems,	a	sell-down	of	our	interests	in	the	Harir	and	Safen	blocks	in	the	Kurdistan	Region	of	Iraq,	and	the	final	collection	of	proceeds	on	a	2009	asset	sale. Several	sales	of	non-core	assets	and	acreage	sell-downs	in	2011	resulted	in	net	proceeds	of	$518	million.	See	Item	8.	Financial	Statements	and	Supplementary	Data	– Note	6	to	the	consolidated	financial	statements	for	more	information	about	dispositions.

Financing	activities	related	to	continuing	operations	resulted	in	a	use	of	cash	of	$1,162	million	in	2013,	provided	cash	of	$1,600	million	in	2012	and	used	cash	of $5,211	million	in	2011.	Debt	repayments	of	$182	million,	$145	million,	and	$2,877	million	occurred	in	2013,	2012	and	2011.	Purchases	of	common	stock	used	$500 million	in	cash	during	2013	and	$300	million	in	2011.	Dividend	payments	were	uses	of	cash	in	every	year.	Sources	of	cash	in	2012	included	the	issuance	of	a	net	$200 million	in	commercial	paper	and	$2	billion	in	senior	notes.	In	connection	with	the	spin-off,	we	distributed	$1,622	million	to	MPC	in	the	second	quarter	of	2011.

# Liquidity	and	Capital	Resources

Our	main	sources	of	liquidity	are	cash	and	cash	equivalents,	internally	generated	cash	flow	from	operations,	the	issuance	of	notes,	our	committed	revolving	credit facility	and	sales	of	non-strategic	assets.	Our	working	capital	requirements	are	supported	by	these	sources	and	we	may	issue	commercial	paper	backed	by	our	$2.5 billion	revolving	credit	facility	to	meet	short-term	cash	requirements.	We	issued	$10,870	million	and	repaid	$10,935	million	of	commercial	paper	in	2013,	leaving	a balance	of	$135	million	outstanding	at	December	31,	2013.	Because	of	the	alternatives	available	to	us	as	discussed	above	and	access	to	capital	markets	through	the	shelf registration	discussed	below,	we	believe	that	our	short-term	and	long-term	liquidity	is	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,	 share repurchase	program	and	other	amounts	that	may	ultimately	be	paid	in	connection	with	contingencies.

# Capital	Resources

# Credit	Arrangements	and	Borrowings

At	December	31,	2013,	we	had	$6,462	million	in	long-term	debt	outstanding,	$68	million	of	which	is	due	within	one	year.	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.

At	December	31,	2013,	we	had	no	borrowings	against	our	revolving	credit	facility	and	had	$135	million	in	commercial	paper	outstanding	under	our	commercial paper	program,	which	is	backed	by	the	revolving	credit	facility.	See	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	17	to	the	consolidated	financial statements	for	a	description	of	the	revolving	credit	facility.

# 2014	Asset	Disposals

The	sale	of	our	interest	in	Angola	Block	31	closed	in	February	2014	for	proceeds	of	$1.5	billion	before	closing	adjustments.	These	proceeds	will	be	used	to repurchase	$500	million	of	common	stock	with	the	remainder	to	be	used	for	general	corporate	purposes.	The	sale	of	our	interest	in	Angola	Block	32	for	proceeds	of	$590 million	before	closing	adjustments	is	expected	to	close	in	the	first	quarter	of	2014.

# Shelf	Registration

We	are	a	"well-known	seasoned	issuer"	for	purposes	of	SEC	rules,	thereby	allowing	us	to	use	a	universal	shelf	registration	statement	should	we	choose	to	issue	and sell	various	types	of	equity	and	debt	securities.		Beginning	in	the	first	quarter	of	2013,	we	changed	our	reportable	segments	and	subsequently	have	recast	all	periods presented	in	this	Annual	Report	on	Form	10-K	to	reflect	these	new	segments	in	our	consolidated	financial	statements.		We	expect	to	update	and	file	our	universal	shelf registration	statement	shortly	after	the	filing	of	this	Annual	Report	on	Form	10-K	with	the	SEC.

# Cash-Adjusted	Debt-To-Capital	Ratio

Our	cash-adjusted	debt-to-capital	ratio	(total	debt-minus-cash	to	total	debt-plus-equity-minus-cash)	was	25	percent	at	December	31,	2013	and	2012.

| (Dollars	in	millions) | 2013 | 2012 |
| :--- | :--- | :--- |
| Commercial\tpaper | $135 | $200 |
| Long-term\tdebt\tdue\twithin\tone\tyear | 68 | 184 |
| Long-term\tdebt | 6,394 | 6,512 |
| Total\tdebt | $6,597 | $6,896 |
| Cash | $264 | $684 |
| Equity | $19,344 | $18,283 |
| Calculation: |  |  |
| Total\tdebt | $6,597 | $6,896 |
| Minus\tcash | 264 | 684 |
| Total\tdebt\tminus\tcash | 6,333 | 6,212 |
| Total\tdebt | 6,597 | 6,896 |
| Plus\tequity | 19,344 | 18,283 |
| Minus\tcash | 264 | 684 |
| Total\tdebt\tplus\tequity\tminus\tcash | $25,677 | $24,495 |
| Cash-adjusted\tdebt-to-capital\tratio | 25% | 25% |

# Capital	Requirements

# Capital	Spending

Our	approved	capital,	investment	and	exploration	spending	budget	for	2014 is	$5,882	million.	Additional	 details	 related to this	2014	budget	are	discussed	in Outlook.

# Share	Repurchase	Program

In	2013,	our	Board	of	Directors	increased	the	authorization	for	repurchases	of	our	common	stock	by	$1.2	billion,	bringing	the	total	authorized	to	$6.2	billion	of which	$2.5	billion	is	remaining.	As	of	December	31,	2013,	we	had	repurchased	92	million	common	shares	at	a	cost	of	$3,722	million,	with	14	million	shares	acquired	at a	cost	of	$500	million	during	the	third	quarter	of	2013,	12	million	shares	acquired	at	a	cost	of	$300	million	in	the	third	quarter	of	2011	and	66	million	shares	purchased for	$2,922	million	prior	to	the	spin-off	of	our	downstream	business.	As	previously	discussed,	a	portion	of	the	proceeds	from	the	sale	of	our	interest	in	Angola	Block	31 will	be	used	 to	repurchase	$500	million	of	common	stock.	Purchases	under	 the	repurchase	program	may	be	 in	either	open	market	 transactions,	 including	block purchases,	or	in	privately	negotiated	transactions.	This	program	may	be	changed	based	upon	our	financial	condition	or	changes	in	market	conditions	and	is	subject	to termination	prior	to	completion.	The	program's	authorization	does	not	include	specific	price	targets	or	timetables.	The	timing	of	purchases	under	the	program	will	be influenced	by	cash	generated	from	operations,	proceeds	from	potential	asset	sales,	cash	from	available	borrowings	and	market	conditions.

# Other	Expected	Cash	Outflows

We	plan	to	make	contributions	of	up	to	$77	million	to	our	funded	pension	plans	during	2014,	and	$11	million	of	that	amount	was	paid	in	January	2014.	Cash contributions	to	be	paid	from	our	general	assets	for	the	unfunded	pension	and	postretirement	plans	are	expected	to	be	approximately	$74	million	and	$19	million	in 2014.	As	of	December	31,	2013,	$135	million	of	commercial	paper	and	$68	million	of	our	long-term	debt	is	due	in	the	next	twelve	months.

Dividends	of	$508	million	were	paid	during	2013	reflecting	quarterly	dividends	of	$0.17	per	share	in	the	first	two	quarters	of	the	year	and	$0.19	per	share	in	the	last two	quarters	for	a	per	share	increase	of	12	percent.	On	January	29,	2014,	we	announced	that	our	Board	of	Directors	had	declared	a	dividend	of	$0.19	cents	per	share	on Marathon	Oil	common	stock,	payable	March	10,	2014,	to	stockholders	of	record	at	the	close	of	business	on	February	19,	2014.

Our	opinions	concerning	liquidity	and	our	ability	to	avail	ourselves	in	the	future	of	the	financing	options	mentioned	in	the	above	forward-looking	statements	are based	on	currently	available	information.	If	this	information	proves	to	be	inaccurate,	future	availability	of	financing	may	be	adversely	affected.	Factors	that	affect	the availability	of	financing	include	our	performance	(as	measured	by	various	factors	including	cash	provided	from	operating	activities),	the	state	of	worldwide	debt	and equity	markets,	investor	perceptions	and	expectations	of	past	and	future	performance,	the	global	financial	climate,	and,	in	particular,	with	respect	to	borrowings,	the levels	of	our	outstanding	debt	and	credit	ratings	by	rating	agencies.	The	discussion	of	liquidity	above	also

contains	forward-looking	statements	regarding	the	use	of	proceeds	from	the	sale	of	our	interest	in	Angola	Block	31,	the	timing	and	amount	of	repurchasing	additional common	stock	and	the	timing	of	closing	the	sale	of	our	interest	in	Angola	Block	32.	The	expectations	with	respect	to	the	use	of	proceeds	from	the	sale	of	our	interest	in Angola	Block	31	and	the	timing	and	amount	of	repurchasing	additional	common	stock	could	be	affected	by	changes	in	the	prices	and	demand	for	liquid	hydrocarbons and	natural	gas,	actions	of	competitors,	disruptions	or	interruptions	of	our	exploration	or	production	operations,	unforeseen	hazards	such	as	weather	conditions	or	acts	of war	or	terrorist	acts	and	other	operating	and	economic	considerations.	The	sale	of	our	interest	in	Angola	Block	32	is	subject	to	customary	closing	conditions.	The discussion	of	liquidity	above	also	contains	forward-looking	statements	regarding	planned	funding	of	pension	plans,	which	are	based	on	current	expectations,	estimates and	projections	and	are	not	guarantees	of	actual	performance.

# Contractual	Cash	Obligations

The	table	below	provides	aggregated	information	on	our	consolidated	obligations	to	make	future	payments	under	existing	contracts	as	of	December	31,	2013.

| (In	millions) | Total | 2014 | 2015-<br>2016 | 2017-<br>2018 | Later<br>Years |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Short\tand\tlong-term\tdebt\t(excludes\tinterest)(a) | $6,572 | $203 | $1,068 | $1,536 | $3,765 |
| Lease\tobligations | 235 | 46 | 78 | 44 | 67 |
| Purchase\tobligations: |  |  |  |  |  |
| Oil\tand\tgas\tactivities(b) | 1,294 | 742 | 391 | 74 | 87 |
| Service\tand\tmaterials\tcontracts(c) | 925 | 192 | 231 | 100 | 402 |
| Transportation\tand\trelated\tcontracts | 1,345 | 211 | 330 | 201 | 603 |
| Drilling\trigs\tand\tfracturing\tcrews(d) | 1,037 | 554 | 461 | 22 | — |
| Other | 237 | 42 | 57 | 32 | 106 |
| Total\tpurchase\tobligations | 4,838 | 1,741 | 1,470 | 429 | 1,198 |
| Other\tlong-term\tliabilities\treported\tin\tthe\tconsolidated\tbalance\nsheet(e) | 1,258 | 181 | 276 | 244 | 557 |
| Total\tcontractual\tcash\tobligations(f) | $12,903 | $2,171 | $2,892 | $2,253 | $5,587 |

(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,	2013	our	minimum	commitment	would	be	$905 million.

(e) Primarily	includes	obligations	for	pension	and	other	postretirement	benefits	including	medical	and	life	insurance.	We	have	estimated	projected	funding	requirements	through	2023.	Also	includes amounts	for	uncertain	tax	positions.

(f) This	table	does	not	include	the	estimated	discounted	liability	for	dismantlement,	abandonment	and	restoration	costs	of	oil	and	gas	properties	of	$2,096	million.	See	Item	8.	Financial	Statements and	Supplementary	Data	–	Note	18	to	the	consolidated	financial	statements.

# Transactions	with	Related	Parties

We	own	a	63	percent	working	interest	in	the	Alba	field	offshore	E.G.	Onshore	E.G.,	we	own	a	52	percent	interest	in	an	LPG	processing	plant,	a	60	percent	interest	in an	LNG	production	facility	and	a	45	percent	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,	2013,	2012	and	2011	aggregated $119	million,	$139	million,	and	$231	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	insure	our	payments	for	outstanding	company	debt	and	future	abandonment	liabilities.

# Outlook

# Budget

Our	Board	of	Directors	approved	a	capital,	investment	and	exploration	spending	budget	of	$5,882	million	 for	2014,	including	budgeted	capital	expenditures	of $5,777	million.	Our	capital,	investment	and	exploration	spending	budget	is	broken	down	by	reportable	segment	in	the	table	below.

| (In	millions) | 2014	Budget | Total |
| :--- | :--- | :--- |
| North\tAmerica\tE&amp;P | $4,241 | 72% |
| International\tE&amp;P | 1,242 | 21% |
| Oil\tSands\tMining | 294 | 5% |
| Segment\ttotal | 5,777 | 98% |
| Corporate\tand\tother | 105 | 2% |
| Total\tcapital,\tinvestment\tand\texploration\tspending\tbudget | $5,882 | 100% |

We	continue	to	focus	on	growing	profitable	reserves	and	production	worldwide.	In	2014,	we	are	accelerating	drilling	activity	in	our	three	key	U.S.	unconventional resource	plays:	the	Eagle	Ford,	Bakken	and	Oklahoma	resource	basins,	which	account	for	approximately	60	percent	of	our	budget.	The	majority	of	spending	in	our unconventional	resource	plays	is	intended	for	drilling.	With	an	increased	number	of	rigs	in	each	of	these	areas,	we	plan	to	drill	more	net	wells	in	these	areas	than	in	any previous	year.	We	also	have	dedicated	a	portion	of	our	capital	budget	in	these	areas	to	facility	construction	and	recompletions.	In	our	conventional	assets,	we	will	follow a	disciplined	spending	plan	that	is	intended	to	provide	stable	production,with	approximately	23	percent	of	our	budget	allocated	to	the	development	of	these	assets worldwide.	We	also	plan	to	either	drill	or	participate	in	8	to	10	exploration	wells	throughout	our	portfolio,	with	10	percent	of	our	budget	allocated	to	exploration projects.	For	additional	information	about	expected	exploration	and	development	activities	see	Item	1.	Business.

The	above	discussion	includes	forward-looking	statements	with	respect	to	projected	spending	and	investment	in	exploration	and	development	activities	under	the 2014	capital,	investment	and	exploration	spending	budget,	accelerated	rig	and	drilling	activity	in	the	Eagle	Ford,	Bakken,	and	Oklahoma	resource	basins,	and	future exploratory	and	development	drilling	activity.	Some	factors	which	could	potentially	affect	these	forward-looking	statements	include	pricing,	supply	and	demand	for liquid	hydrocarbons	and	natural	gas,	the	amount	of	capital	available	for	exploration	and	development,	regulatory	constraints,	timing	of	commencing	production	from new	wells,	drilling	rig	availability,	availability	of	materials	and	labor,	other	risks	associated	with	construction	projects,	unforeseen	hazards	such	as	weather	conditions, acts	of	war	or	terrorist	acts	and	the	governmental	or	military	response,	and	other	geological,	operating	and	economic	considerations.	These	forward-looking	statements may	be	further	affected	by	the	inability	to	obtain	or	delay	in	obtaining	necessary	government	and	third-party	approvals	or	permits.	The	development	projects	could further	be	affected	by	presently	known	data	concerning	size	and	character	of	reservoirs,	economic	recoverability,	future	drilling	success	and	production	experience.	The foregoing	factors	(among	others)	could	cause	actual	results	to	differ	materially	from	those	set	forth	in	the	forward-looking	statements.

# Sales	Volumes

We	expect	to	increase	our	U.S.	resource	plays'	net	sales	volumes	by	more	than	30	percent	in	2014	compared	to	2013,	excluding	dispositions.	In	addition,	we	expect total	production	growth	to	be	approximately	4	percent	in	2014	versus	2013,	excluding	dispositions	and	Libya.

Excluded	from	our	budget	are	the	impacts	of	acquisitions	and	dispositions	not	previously	announced.	We	continually	evaluate	ways	to	optimize	our	portfolio through	acquisitions	and	divestitures	and	exceeded	our	previously	stated	goal	of	divesting	between	$1.5	billion	and	$3.0	billion	of	assets	over	the	period	of	2011	through 2013.	For	the	three-year	period	ended	December	31,	2013,	we	closed	or	entered	agreements	for	approximately	$3.5	billion	in	divestitures,	of	which	$2.1	billion	is	from the	sales	of	our	Angola	assets.	The	sale	of	our	interest	in	Angola	Block	31	closed	in	February	2014	and	the	sale	of	our	interest	in	Angola	Block	32	is	expected	to	close	in the	first	quarter	of	2014.

In	December	2013,	we	announced	the	commencement	of	efforts	to	market	our	assets	in	the	North	Sea,	both	in	the	U.K.	and	Norway,	which	would	simplify	and concentrate	our	portfolio	to	higher	margin	growth	opportunities	and	increase	our	production	growth	rate.

The	above	discussion	includes	forward-looking	statements	with	respect	to	our	percentage	growth	rate	of	production,	production	available	for	sale,	the	sale	of	our interest	in	Angola	Block	32	and	the	possible	sale	of	our	U.K.	and	Norway	assets.	Some	factors

which	could	potentially	affect	our	percentage	growth	rate	of	production	and	production	available	for	sale	include	pricing,	supply	and	demand	for	liquid	hydrocarbons and	natural	gas,	the	amount	of	capital	available	for	exploration	and	development,	regulatory	constraints,	timing	of	commencing	production	from	new	wells,	drilling	rig availability,	availability	of	materials	and	labor,	the	inability	to	obtain	or	delay	in	obtaining	necessary	government	or	third-party	approvals	and	permits,	unforeseen hazards	such	as	weather	conditions,	acts	of	war	or	terrorist	acts	and	the	governmental	or	military	response	thereto,	and	other	geological,	operating	and	economic considerations.	Actual	results	may	differ	materially	from	these	expectations,	estimates	and	projections	and	are	subject	to	certain	risks,	uncertainties	and	other	factors, some	of	which	are	beyond	our	control	and	difficult	to	predict.	The	timing	of	closing	the	sale	of	our	interest	in	Block	32	is	subject	to	customary	closing	conditions.	The possible	sale	of	our	U.K.	and	Norway	assets	is	subject	to	the	identification	of	one	or	more	buyers,	successful	negotiations,	board	approval	and	execution	of	definitive agreements.	The	foregoing	factors	(among	others)	could	cause	actual	results	to	differ	materially	from	those	set	forth	in	the	forward-looking	statements.

# 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.

Legislation	and	regulations	pertaining	to	climate	change	and	greenhouse	gas	emissions	have	the	potential	to	materially	adversely	impact	our	business,	financial condition,	results	of	operations	and	cash	flows,	including	costs	of	compliance	and	permitting	delays.	The	extent	and	magnitude	of	these	adverse	impacts	cannot	be reliably	or	accurately	estimated	at	this	time	because	specific	regulatory	and	legislative	requirements	have	not	been	finalized	and	uncertainty	exists	with	respect	to	the measures	being	considered,	the	costs	and	the	time	frames	for	compliance,	and	our	ability	to	pass	compliance	costs	on	to	our	customers.	For	additional	information	see Item	1A.	Risk	Factors.

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.	For	additional	information	see	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	25	to	the	consolidated	financial	statements.

New	or	expanded	environmental	requirements,	which	could	increase	our	environmental	costs,	may	arise	in	the	future.	We	comply	with	all	legal	requirements regarding	the	environment,	but	since	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

The	estimation	of	quantities	of	net	reserves	is	a	highly	technical	process	performed	by	our	engineers	for	liquid	hydrocarbons	and	natural	gas	and	by	outside consultants	for	synthetic	crude	oil,	which	is	based	upon	several	underlying	assumptions	that	are	subject	to	change.	Estimates	of	reserves	may	change,	either	positively	or negatively,	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.	The	data	for	a	given	reservoir	may	also	change	substantially	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.	Consequently,	material	revisions	(upward	or	downward)	to	existing	reserve	estimates	may	occur	from	time	to	time. Reserve	estimates	are	based	upon	an	unweighted	average	of	commodity	prices	in	the	prior	12-month	period,	using	the	closing	prices	on	the	first	day	of	each	month. These	prices	are	not	indicative	of	future	market	conditions.	For	a	discussion	of	our	reserve	estimation	process,	including	the	use	of	third-party	audits,	see	Item	1. Business.

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	liquid	hydrocarbon,	natural	gas	and	synthetic	crude	oil	reserves.

The	existence	and	the	estimated	amount	of	reserves	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.	Additionally,	both	the	expected future	cash	flows	to	be	generated	by	oil	and	gas	producing	properties	used	in	testing	such	properties	for	impairment	and	the	expected	future	taxable	income	available	to realize	deferred	tax	assets	also	rely,	in	part,	on	estimates	of	quantities	of	net	reserves.

Depreciation	and	depletion	of	liquid	hydrocarbon,	natural	gas	and	synthetic	crude	oil	producing	properties	is	determined	by	the	units-of-production	method	and could	change	with	revisions	to	estimated	proved	reserves.	Over	the	past	three	years,	the	impact	on	our	depreciation	and	depletion	rate	due	to	revisions	of	previous reserve	estimates	has	not	been	significant	to	any	of	our	segments.	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	five	percent	change	in	2013	proved	reserves	based	on	2013	production.

|  | Impact	of	a	Five	Percent	Increase	in<br>Proved	Reserves | Impact	of	a	Five	Percent	Increase	in<br>Proved	Reserves | Impact	of	a	Five	Percent	Decrease	in<br>Proved	Reserves | Impact	of	a	Five	Percent	Decrease	in<br>Proved	Reserves |
| :--- | :--- | :--- | :--- | :--- |
| (In\tmillions,\texcept\tper\tboe) | DD&amp;A\tper\tboe | Pretax\tIncome | DD&amp;A\tper\tboe | Pretax\tIncome |
| North\tAmerica\tE&amp;P | $(1.25) | \t $92 | \t $1.38 | \t $(101) |
| International\tE&amp;P | (0.35) | 30 | 0.38 | (33) |
| \t\t\tOil\tSands\tMining | $(0.46) | \t $7 | \t $0.73 | \t $(11) |

# 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,	including	bitumen	mining	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	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.	See	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	18	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	15	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;

•allocation	of	the	purchase	price	paid	to	acquire	businesses	to	the	assets	acquired	and	liabilities	assumed;

•recorded	value	of	derivative	instruments.

# Impairment	Assessments	of	Long-Lived	Assets	and	Goodwill

The	need	to	test	long-lived	assets	and	goodwill	for	impairment	can	be	based	on	several	indicators,	including	a	significant	reduction	in	prices	of	liquid	hydrocarbons, natural	gas	or	synthetic	crude	oil,	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.

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	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	for	our	North	America	E&P	and	International	E&P	assets	and	at	the	project	level	for	OSM	assets.	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.

Unlike	long-lived	assets,	goodwill	must	be	tested	for	impairment	at	least	annually,	or	between	annual	tests	if	an	event	occurs	or	circumstances	change	that	would more	likely	than	not	reduce	the	fair	value	of	a	reporting	unit	below	its	carrying	amount.	Goodwill	is	tested	for	impairment	at	the	reporting	unit	level.

Fair	value	calculated	for	the	purpose	of	testing	our	long-lived	assets	and	goodwill	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	liquid	hydrocarbon,	natural	gas	and	synthetic	crude	oil	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	liquid	hydrocarbon,	natural	gas	and	synthetic	crude	oil	prices	and	estimates	of	such	future	prices	are	inherently	imprecise.

•Estimated	quantities	of	liquid	hydrocarbons,	natural	gas	and	synthetic	crude	oil.	Such	quantities	are	based	on	a	combination	of	reserve	categories	such	that the	combined	volumes	represent	the	most	likely	expectation	of	recovery.

•Expected	timing	of	production.	Production	forecasts	are	the	outcome	of	engineer	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.	This	discount	rate	is	also	compared	to	recent	observable	market	transactions,	if	possible. 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	reasonable.	However,	actual	results	may	differ	from	these	projections.

An	estimate	of	the	sensitivity	to	net	income	resulting	from	impairment	calculations	is	not	practicable,	given	the	numerous	assumptions	(e.g.	reserves,	pricing	and discount	rates)	that	can	materially	affect	our	estimates.	That	is,	unfavorable	adjustments	to	some	of	the	above	listed	assumptions	may	be	offset	by	favorable	adjustments in	other	assumptions.

# Acquisitions

In	accounting	for	business	combinations,	the	purchase	price	paid	to	acquire	a	business	is	allocated	to	its	assets	and	liabilities	based	on	the	estimated	fair	values	of	the assets	acquired	and	liabilities	assumed	as	of	the	date	of	acquisition.	The	excess	of	the	purchase	price	over	the	fair	value	of	the	net	tangible	and	identifiable	intangible assets	acquired	is	recorded	as	goodwill.	A	significant	amount	of	judgment	is	involved	in	estimating	the	individual	fair	values	of	property,	plant	and	equipment	and identifiable	intangible	assets.	The	most	significant	assumptions	relate	to	the	estimated	fair	values	allocated	to	proved	and	unproved	liquid	hydrocarbon,	natural	gas	and synthetic	crude	oil	properties.	Estimated	fair	values	assigned	to	assets	acquired	can	have	a	significant	effect	on	our	results	of	operations	in	the	future.	We	use	all available	information	to	make	these	fair	value	determinations	and,	for	certain	acquisitions,	engage	third-party	consultants	for	assistance.	During	2013,	2012	and	2011, we	completed	several	business	combinations	in	the	Eagle	Ford,	the	purchase	prices	of	which	were	allocated	to	the	assets	acquired	and	liabilities	assumed	based	on	their estimated	fair	values	(see	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	5	to	the	consolidated	financial	statements).

The	fair	values	used	to	allocate	the	purchase	price	of	an	acquisition	are	often	estimated	using	the	expected	present	value	of	future	cash	flows	method,	which	requires us	to	estimate	reserves	as	described	above	under	Estimated	Quantities	of	Net	Reserves,	project	related	future	cash	inflows	and	outflows	and	apply	an	appropriate discount	rate.	The	estimates	used	in	determining	fair	values	are	based	on	assumptions	believed	to	be	reasonable	but	which	are	inherently	uncertain.	Accordingly,	actual results	may	differ	from	the	projected	results	used	to	determine	fair	value.

# 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	15	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.

We	have	recorded	deferred	tax	assets	and	liabilities	for	temporary	differences	between	book	basis	and	tax	basis,	tax	credit	carryforwards	and	operating	loss carryforwards.	We	routinely	assess	the	realizability	of	our	deferred	tax	assets	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.	In	assessing	the	need	for	additional	or	adjustments	to	existing	valuation	allowances,	we	consider	the preponderance	of	evidence	concerning	the	realization	of	the	deferred	tax	asset.	We	must	consider	any	prudent	and	feasible	tax	planning	strategies	that	might	minimize the	amount	of	deferred	tax	liabilities	recognized	or	the	amount	of	any	valuation	allowance	recognized	against	deferred	tax	assets,	if	we	can	implement	the	strategies	and we	expect	to	implement	them	in	the	event	the	forecasted	conditions	actually	occur.	Assumptions	related	to	the	permanent	reinvestment	of	the	earnings	of	our	foreign subsidiaries	are	reconsidered	quarterly	to	give	effect	to	changes	in	our	portfolio	of	producing	properties	and	in	our	tax	profile.

Our	net	deferred	tax	assets,	after	valuation	allowances,	are	expected	to	be	realized	through	our	future	taxable	income	and	the	reversal	of	temporary	differences. Numerous	judgments	and	assumptions	are	inherent	in	the	estimation	of	future	taxable	income,	including	factors	such	as	future	operating	conditions	(particularly	as related	to	prevailing	liquid	hydrocarbon,	natural	gas	and	synthetic	crude	oil	prices)	and	the	assessment	of	the	effects	of	foreign	taxes	on	our	U.S.	federal	income	taxes. The	estimates	and	assumptions	used	in	determining	future	taxable	income	are	consistent	with	those	used	in	our	planning	and	capital	investment	reviews.	We	consider	a combination	of	reserve	categories	related	to	our	existing	producing	properties,	as	well	as	estimated	quantities	of	liquid	hydrocarbon,	natural	gas	and	synthetic	crude	oil related	to	undeveloped	discoveries	if,	in	our	judgment,	it	is	likely	that	development	plans	will	be	approved	in	the	foreseeable	future.	Assumptions	regarding	our	ability	to realize	the	U.S.	federal	benefit	of	foreign	tax	credits	are	based	on	certain	estimates	concerning	future	operating	conditions	(particularly	as	related	to	liquid	hydrocarbon, natural	gas	and	synthetic	crude	oil	prices),	future	financial	conditions,	income	generated	from	foreign	sources	and	our	tax	profile	in	the	year	that	such	credits	may	be claimed.

# 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	percent	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	percent	change	in	the	discount	rates	of	4.28	percent	for	our	U.S.	pension	plans	and 4.85	percent	for	our	other	U.S.	postretirement	benefit	plans	is	summarized	in	the	table	below:

|  | Impact	of	a	0.25	Percent	Increase	in<br>Discount	Rate | Impact	of	a	0.25	Percent	Increase	in<br>Discount	Rate | Impact	of	a	0.25	Percent	Decrease	in<br>Discount	Rate | Impact	of	a	0.25	Percent	Decrease	in<br>Discount	Rate |
| :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Obligation | Expense | Obligation | Expense |
| U.S.\tpension\tplans | $(38) | \t $(4) | \t $40 | \t $4 |
| Other\tU.S.\tpostretirement\tbenefit\tplans | $(7) | \t $— \t $ | 8 | \t $— |

The	asset	rate	of	return	assumption	for	the	funded	U.S.	plan	considers	the	plan's	asset	mix	(currently	targeted	at	approximately	55	percent	equity	and	high-yield bonds	and	45	percent	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.	Our	long-term	asset	rate	of	return	assumption	is compared	to	those	of	other	companies	and	to	our	historical	returns	for	reasonableness.	Decreasing	the	6.75	percent	asset	rate	of	return	assumption	by	0.25	would	not have	a	significant	impact	on	our	defined	benefit	pension	expense.	Effective	January	1,	2014,	the	expected	long-term	rate	of	return	was	changed	from	7.25	percent	to 6.75	percent	and	this	change	also	did	not	have	a	significant	impact.

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	20	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,	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

In	June	2013,	the	FASB	ratified	the	Emerging	Issues	Task	Force	consensus	which	requires	that	an	unrecognized	tax	benefit	(or	a	portion	thereof	)	be	presented	as	a reduction	to	a	deferred	tax	asset	for	an	available	net	operating	loss	carryforward,	a	similar	tax	loss	or	tax	credit	carryforward.	This	accounting	standards	update	is effective	for	us	beginning	in	the	first	quarter	of	2014	and	should	be	applied	prospectively	to	unrecognized	tax	benefits	that	exist	as	of	the	effective	date.	Early	adoption and	retrospective	application	are	permitted.	Adoption	of	this	accounting	standards	update	will	not	have	a	significant	impact	on	our	consolidated	results	of	operations, financial	position	or	cash	flows.

In	February	2013,	an	accounting	standards	update	was	issued	to	provide	guidance	for	the	recognition,	measurement,	and	disclosure	of	obligations	resulting	from joint	and	several	liability	arrangements	for	which	the	total	amount	of	the	obligation	is	fixed	at	the	reporting	date,	except	for	obligations	such	as	asset	retirement	and environmental	obligations,	contingencies,	guarantees,	income	taxes	and	retirement	benefits,	which	are	separately	addressed	within	U.S.	GAAP.	An	entity	is	required	to measure	obligations	resulting	from	joint	and	several	liability	arrangements	for	which	the	total	amount	of	the	obligation	is	fixed	at	the	reporting	date	as	the	sum	of	1)	the amount	the	entity	agreed	to	pay	on	the	basis	of	its	arrangement	among	its	co-obligors	and	2)	any	amount	the	entity	expects	to	pay	on	behalf	of	its	co-obligors.	Disclosure of	the	nature	of	the	obligation,	including	how	the	liability	arose,	the	relationship	with	other	co-obligors	and	the	terms	and	conditions	of	the	arrangement	is	required.	In addition,	the	total	outstanding	amount	under	the	arrangement,	not	reduced	by	the	effect	of	any	amounts	that	may	be	recoverable	from	other	entities,	plus	the	carrying amount	of	any	liability	or	receivable	recognized	must	be	disclosed.	This	accounting	standards	update	is	effective	for	us	beginning	in	the	first	quarter	of	2014	and	should be	applied	retrospectively	for	those	in-scope	obligations	resulting	from	joint	and	several	liability	arrangements	that	exist	at	the	beginning	of	2014.	Early	adoption	is permitted.	Adoption	of	this	accounting	standards	update	will	not	have	a	significant	impact	on	our	consolidated	results	of	operations,	financial	position	or	cash	flows.

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

We	are	exposed	to	market	risks	related	to	the	volatility	of	liquid	hydrocarbon,	natural	gas	and	synthetic	crude	oil	prices.	We	employ	various	strategies,	including	the use	of	commodity	derivative	instruments,	to	manage	the	risks	related	to	these	price	fluctuations.	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.

We	believe	 that	our	use	of	derivative	 instruments,	along	with	our	risk	assessment	procedures	and	 internal	controls,	does	not	expose	us	 to	material	adverse consequences.	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	15	and	16	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,	as	deemed	appropriate.	We	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	different	businesses.	Our	consolidated	results	for 2013	and	2012	were	impacted	by	crude	oil	derivatives	related	to	a	portion	of	our	forecast	North	America	E&P	crude	oil	sales,	all	of	which	had	terms	that	ended	in December	2013.

We	regularly	use	commodity	derivative	instruments	in	the	North	America	E&P	segment	to	manage	natural	gas	price	risk.	Examples	would	include	the	hedging	of storage	and	transportation	assets,	and	when	appropriate,	managing	equity	price	exposure.

# Interest	Rate	Risk

We	are	impacted	by	interest	rate	fluctuations	which	affect	the	fair	value	of	certain	financial	instruments.	We	manage	our	exposure	to	interest	rate	movements	by utilizing	financial	derivative	instruments.	The	primary	objective	of	this	program	is	to	reduce	our	overall	cost	of	borrowing	by	managing	the	mix	of	fixed	and	floating interest	rate	debt	in	our	portfolio.	As	of	December	31,	2013,	we	had	multiple	interest	rate	swap	agreements	with	a	total	notional	of	$900	million	designated	as	fair	value hedges,	which	effectively	results	in	an	exchange	of	existing	obligations	to	pay	fixed	interest	rates	for	obligations	to	pay	floating	rates.

At	December	31,	2013,	our	portfolio	of	long-term	debt	was	substantially	comprised	of	fixed	rate	instruments.	Therefore,	the	fair	value	of	the	portfolio	is	relatively sensitive	to	interest	rate	fluctuations.	Our	sensitivity	to	interest	rate	declines	and	corresponding	increases	in	the	fair	value	of	our	debt	portfolio	unfavorably	affects	our results	of	operations	and	cash	flows	only	when	we	elect	to	repurchase	or	otherwise	retire	fixed-rate	debt	at	prices	above	carrying	value.

Sensitivity	analysis	of	the	incremental	effect	of	a	hypothetical	10	percent	change	in	interest	rates	on	financial	assets	and	liabilities	as	of	December	31,	2013,	is provided	in	the	following	table.

(a) Fair	values	of	cash	and	cash	equivalents,	receivables,	commercial	paper,	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.

# Foreign	Currency	Exchange	Rate	Risk

We	may	manage	our	exposure	to	foreign	currency	exchange	rates	by	utilizing	forward	and	option	contracts.	The	primary	objective	of	this	program	is	to	reduce	our exposure	to	movements	in	foreign	currency	exchange	rates	by	locking	in	such	rates.	As	of	December	31,	2013,	our	foreign	currency	forwards	had	a	notional	of	2,387 million	Norwegian	Kroner,	which	served	as	a	hedge	of	our	current	Norwegian	tax	liability.	The	incremental	change	in	the	fair	value	of	foreign	currency	derivative contracts	of	a	hypothetical	10	percent	change	in	exchange	rates	at	December	31,	2013	would	be	$39	million.

# Counterparty	Risk

We	are	also	exposed	to	financial	risk	in	the	event	of	nonperformance	by	counterparties.	The	creditworthiness	of	counterparties	is	reviewed	and	master	netting agreements	are	used	when	appropriate.

# Safe	Harbor

These	quantitative	and	qualitative	disclosures	about	market	risk	include	forward-looking	statements	with	respect	to	management's	opinion	about	risks	associated with	the	use	of	derivative	instruments.	These	statements	are	based	on	certain	assumptions	with	respect	to	market	prices	and	industry	supply	of	and	demand	for	liquid hydrocarbons,	natural	gas	and	synthetic	crude	oil.	If	these	assumptions	prove	to	be	inaccurate,	future	outcomes	with	respect	to	our	use	of	derivative	instruments	may differ	materially	from	those	discussed	in	the	forward-looking	statements.

# Item	8.	Financial	Statements	and	Supplementary	Data

# Index

| Management's	Responsibilities	for	Financial	Statements | 59 |
| :--- | :--- |
| Management's\tReport\ton\tInternal\tControl\tover\tFinancial\tReporting | 59 |
| Report\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm | 60 |
| Audited\tConsolidated\tFinancial\tStatements |  |
| Consolidated\tStatements\tof\tIncome | 61 |
| Consolidated\tStatements\tof\tComprehensive\tIncome | 62 |
| Consolidated\tBalance\tSheets | 63 |
| Consolidated\tStatements\tof\tCash\tFlows | 64 |
| Consolidated\tStatements\tof\tStockholders'\tEquity | 65 |
| Notes\tto\tConsolidated\tFinancial\tStatements | 66 |
| Select\tQuarterly\tFinancial\tData\t(Unaudited) | 101 |
| Supplementary\tInformation\ton\tOil\tand\tGas\tProducing\tActivities\t(Unaudited) | 102 |
| Supplemental\tStatistics\t(Unaudited) | 110 |

# 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

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).	An	evaluation	of	the	design	and	effectiveness	of	our	internal	control	over	financial	reporting,	based	on	the	original	1992 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,	2013.

The	effectiveness	of	Marathon	Oil's	internal	control	over	financial	reporting	as	of	December	31,	2013	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

In	our	opinion,	the	consolidated	financial	statements	listed	in	the	accompanying	index	present	fairly,	in	all	material	respects,	the	financial	position	of	Marathon	Oil Corporation	and	its	subsidiaries	(the	"Company")	at	December	31,	2013,	and	2012,	and	the	results	of	their	operations	and	their	cash	flows	for	each	of	the	three	years	in the	period	ended	December	31,	2013,	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States.	Also	in	our	opinion,	the	Company	maintained,	in all	material	respects,	effective	internal	control	over	financial	reporting	as	of	December	31,	2013,	based	on	criteria	established	in	the	original	1992	framework	in	Internal Control	 -	 Integrated	 Framework issued	 by	 the	 Committee	 of	 Sponsoring	 Organizations	 of	 the	 Treadway	 Commission	 (COSO).	The	 Company's	 management	 is responsible	for	these	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 these	financial	statements	and	on	the	Company's	internal	control	over	financial	reporting	based	on	our	integrated	audits.	We	conducted	our	audits	in	accordance	with	the standards	of	 the	Public	Company	Accounting	Oversight	Board	(United	States).	Those	standards	require	that	we	plan	and	perform	the	audits	to	obtain	reasonable assurance	about	whether	the	financial	statements	are	free	of	material	misstatement	and	whether	effective	internal	control	over	financial	reporting	was	maintained	in	all material	respects.	Our	audits	of	the	financial	statements	included	examining,	on	a	test	basis,	evidence	supporting	the	amounts	and	disclosures	in	the	financial	statements, assessing	the	accounting	principles	used	and	significant	estimates	made	by	management,	and	evaluating	the	overall	financial	statement	presentation.	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.

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

PricewaterhouseCoopers	LLP Houston,	Texas February	28,	2014

# Consolidated	Statements	of	Income

| (In	millions,	except	per	share	data) | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| Revenues\tand\tother\tincome: |  |  |  |
| Sales\tand\tother\toperating\trevenues,\tincluding\trelated\tparty | $12,419 | $12,963 | $10,750 |
| Marketing\trevenues | 2,082 | 2,729 | 3,919 |
| Income\tfrom\tequity\tmethod\tinvestments | 423 | 370 | 462 |
| Net\tgain\t(loss)\ton\tdisposal\tof\tassets | (29) | 127 | 103 |
| Other\tincome | 64 | 32 | 48 |
| Total\trevenues\tand\tother\tincome | 14,959 | 16,221 | 15,282 |
| Costs\tand\texpenses: |  |  |  |
| Production | 2,331 | 2,202 | 1,951 |
| Marketing,\tincluding\tpurchases\tfrom\trelated\tparties | 2,072 | 2,744 | 3,898 |
| Other\toperating | 439 | 425 | 533 |
| Exploration | 988 | 706 | 641 |
| Depreciation,\tdepletion\tand\tamortization | 2,790 | 2,477 | 2,263 |
| Impairments | 96 | 371 | 310 |
| Taxes\tother\tthan\tincome | 352 | 248 | 193 |
| General\tand\tadministrative | 687 | 699 | 663 |
| Total\tcosts\tand\texpenses | 9,755 | 9,872 | 10,452 |
| Income\tfrom\toperations | 5,204 | 6,349 | 4,830 |
| Net\tinterest\tand\tother | (274) | (219) | (107) |
| Loss\ton\tearly\textinguishment\tof\tdebt | — | — | (279) |
| Income\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | 4,930 | 6,130 | 4,444 |
| Provision\tfor\tincome\ttaxes | 3,337 | 4,517 | 2,726 |
| Income\tfrom\tcontinuing\toperations | 1,593 | 1,613 | 1,718 |
| Discontinued\toperations | 160 | (31) | 1,228 |
| Net\tincome | $1,753 | $1,582 | $2,946 |
| Per\tShare\tData |  |  |  |
| Basic: |  |  |  |
| Income\tfrom\tcontinuing\toperations | $2.26 | $2.28 | $2.42 |
| Discontinued\toperations | $0.23 | $(0.04) | $1.73 |
| Net\tincome | $2.49 | $2.24 | $4.15 |
| Diluted: |  |  |  |
| Income\tfrom\tcontinuing\toperations | $2.24 | $2.27 | $2.41 |
| Discontinued\toperations | $0.23 | $(0.04) | $1.72 |
| Net\tincome | $2.47 | $2.23 | $4.13 |
| Dividends | $0.72 | $0.68 | $0.80 |
| Weighted\taverage\tshares: |  |  |  |
| Basic | 705 | 706 | 710 |
| Diluted | 709 | 710 | 714 |

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

# Consolidated	Statements	of	Comprehensive	Income

| (In	millions) | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| Net\tincome | $1,753 | $1,582 | $2,946 |
| Other\tcomprehensive\tincome\t(loss) |  |  |  |
| Postretirement\tand\tpostemployment\tplans |  |  |  |
| Change\tin\tactuarial\tloss\tand\tother | 296 | (97) | 16 |
| Income\ttax\tbenefit\t(provision) | (112) | 35 | 20 |
| Postretirement\tand\tpostemployment\tplans,\tnet\tof\ttax | 184 | (62) | 36 |
| Derivative\thedges |  |  |  |
| Net\tunrecognized\tgain | 1 | 1 | 9 |
| Income\ttax\tprovision | — | — | (4) |
| Derivative\thedges,\tnet\tof\ttax | 1 | 1 | 5 |
| Foreign\tcurrency\ttranslation\tand\tother |  |  |  |
| Unrealized\tgain\t(loss) | (3) | 1 | (1) |
| Income\ttax\tbenefit\t(provision) | 1 | (3) | — |
| Foreign\tcurrency\ttranslation\tand\tother,\tnet\tof\ttax | (2) | (2) | (1) |
| Other\tcomprehensive\tincome\t(loss) | 183 | (63) | 40 |
| Comprehensive\tincome | $1,936 | $1,519 | $2,986 |

# Consolidated	Balance	Sheets

|  | December	31, | December	31, |
| :--- | :--- | :--- |
| (In\tmillions,\texcept\tper\tshare\tdata) | 2013 | 2012 |
| Assets |  |  |
| Current\tassets: |  |  |
| Cash\tand\tcash\tequivalents | $264 | $684 |
| Receivables | 2,134 | 2,418 |
| Inventories | 364 | 361 |
| Other\tcurrent\tassets | 213 | 299 |
| Total\tcurrent\tassets | 2,975 | 3,762 |
| Equity\tmethod\tinvestments | 1,201 | 1,279 |
| Property,\tplant\tand\tequipment,\tless\taccumulated\tdepreciation, |  |  |
| depletion\tand\tamortization\tof\t$21,895\tand\t$19,266 | 28,145 | 28,272 |
| Goodwill | 499 | 525 |
| Other\tnoncurrent\tassets | 2,800 | 1,468 |
| Total\tassets | $35,620 | $35,306 |
| Liabilities |  |  |
| Current\tliabilities: |  |  |
| Commercial\tpaper | $135 | $200 |
| Accounts\tpayable | 2,206 | 2,324 |
| Payroll\tand\tbenefits\tpayable | 240 | 217 |
| Accrued\ttaxes | 1,445 | 1,983 |
| Other\tcurrent\tliabilities | 239 | 173 |
| Long-term\tdebt\tdue\twithin\tone\tyear | 68 | 184 |
| Total\tcurrent\tliabilities | 4,333 | 5,081 |
| Long-term\tdebt | 6,394 | 6,512 |
| Deferred\ttax\tliabilities | 2,492 | 2,432 |
| Defined\tbenefit\tpostretirement\tplan\tobligations | 604 | 856 |
| Asset\tretirement\tobligations | 2,009 | 1,749 |
| Deferred\tcredits\tand\tother\tliabilities | 444 | 393 |
| Total\tliabilities | 16,276 | 17,023 |
| Commitments\tand\tcontingencies |  |  |
| Stockholders'\tEquity |  |  |
| Preferred\tstock\t-\tno\tshares\tissued\tor\toutstanding\t(no\tpar\tvalue, |  |  |
| \t26\tmillion\tshares\tauthorized) | — | — |
| Common\tstock: |  |  |
| Issued\t–\t770\tmillion\tand\t770\tmillion\tshares\t(par\tvalue\t$1\tper\tshare, |  |  |
| 1.1\tbillion\tshares\tauthorized) | 770 | 770 |
| Securities\texchangeable\tinto\tcommon\tstock\t–\tno\tshares\tissued |  |  |
| or\toutstanding\t(no\tpar\tvalue,\t29\tmillion\tshares\tauthorized) | — | — |
| Held\tin\ttreasury,\tat\tcost\t–\t73\tmillion\tand\t63\tmillion\tshares | (2,903) | (2,560) |
| Additional\tpaid-in\tcapital | 6,592 | 6,616 |
| Retained\tearnings | 15,135 | 13,890 |
| Accumulated\tother\tcomprehensive\tloss | (250) | (433) |
| Total\tstockholders'\tequity | 19,344 | 18,283 |
| Total\tliabilities\tand\tstockholders'\tequity | $35,620 | $35,306 |

# Consolidated	Statements	of	Cash	Flows

| (In	millions) | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| Increase\t(decrease)\tin\tcash\tand\tcash\tequivalents |  |  |  |
| Operating\tactivities: |  |  |  |
| Net\tincome | $1,753 | $1,582 | $2,946 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tprovided\tby\toperating\tactivities: |  |  |  |
| Discontinued\toperations | (160) | 31 | (1,228) |
| Loss\ton\tearly\textinguishment\tof\tdebt | — | — | 279 |
| Deferred\tincome\ttaxes | (60) | (224) | (193) |
| Depreciation,\tdepletion\tand\tamortization | 2,790 | 2,477 | 2,263 |
| Impairments | 96 | 371 | 310 |
| Pension\tand\tother\tpostretirement\tbenefits,\tnet | 45 | (31) | 64 |
| Exploratory\tdry\twell\tcosts\tand\tunproved\tproperty\timpairments | 798 | 457 | 357 |
| Net\t(gain)\tloss\ton\tdisposal\tof\tassets | 29 | (127) | (103) |
| Equity\tmethod\tinvestments,\tnet | 12 | 11 | 47 |
| Changes\tin: |  |  |  |
| Current\treceivables | 277 | (502) | 9 |
| Inventories | (16) | (32) | 33 |
| Current\taccounts\tpayable\tand\taccrued\tliabilities | (616) | 71 | 489 |
| All\tother\toperating,\tnet | 143 | (48) | 168 |
| Net\tcash\tprovided\tby\tcontinuing\toperations | 5,091 | 4,036 | 5,441 |
| Net\tcash\tprovided\tby\t(used\tin)\tdiscontinued\toperations | 179 | (19) | 1,083 |
| Net\tcash\tprovided\tby\toperating\tactivities | 5,270 | 4,017 | 6,524 |
| Investing\tactivities: |  |  |  |
| Acquisitions,\tnet\tof\tcash\tacquired | (74) | (1,033) | (4,470) |
| Additions\tto\tproperty,\tplant\tand\tequipment | (4,766) | (4,593) | (2,986) |
| Disposal\tof\tassets | 450 | 467 | 518 |
| Investments\t-\treturn\tof\tcapital | 61 | 57 | 59 |
| Investing\tactivities\tof\tdiscontinued\toperations | (227) | (347) | (802) |
| All\tother\tinvesting,\tnet | 35 | 10 | 14 |
| Net\tcash\tused\tin\tinvesting\tactivities | (4,521) | (5,439) | (7,667) |
| Financing\tactivities: |  |  |  |
| Commercial\tpaper,\tnet | (65) | 200 | — |
| Borrowings | — | 1,997 | — |
| Debt\tissuance\tcosts | — | (21) | — |
| Debt\trepayments | (182) | (145) | (2,877) |
| Purchases\tof\tcommon\tstock | (500) | — | (300) |
| Dividends\tpaid | (508) | (480) | (567) |
| Financing\tactivities\tof\tdiscontinued\toperations | — | — | 2,916 |
| Distribution\tin\tspin-off | — | — | (1,622) |
| All\tother\tfinancing,\tnet | 93 | 49 | 155 |
| Net\tcash\tprovided\tby\t(used\tin)\tfinancing\tactivities | (1,162) | 1,600 | (2,295) |
| Effect\tof\texchange\trate\tchanges\ton\tcash | (7) | 13 | (20) |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (420) | 191 | (3,458) |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 684 | 493 | 3,951 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $264 | $684 | $493 |

# Consolidated	Statements	of	Stockholders'	Equity

# Total	Equity	of	Marathon	Oil	Stockholders

|  |  |  | Total	Equity	of	Marathon	Oil	Stockholders | Total	Equity	of	Marathon	Oil	Stockholders | Total	Equity	of	Marathon	Oil	Stockholders |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Preferred\nStock | Common\nStock | Securities\nExchangeable\ninto\tCommon\nStock | Treasury\nStock | Additional\nPaid-in\nCapital | Retained\nEarnings | Accumulated\nOther\nComprehensive\nLoss | Non-\ncontrolling\nInterest | Total\nEquity |
| January\t1,\t2011\tBalance | $— | $770 | $— | $(2,665) | $6,756 | $19,907 | $(997) | $— | $23,771 |
| Shares\tissued\t-\tstock-based |  |  |  |  |  |  |  |  |  |
| compensation | — | — | — | 257 | (85) | — | — | — | 172 |
| Shares\trepurchased | — | — | — | (308) | — | — | — | — | (308) |
| Stock-based\tcompensation | — | — | — | — | 4 | — | — | — | 4 |
| Net\tincome | — | — | — | — | — | 2,946 | — | — | 2,946 |
| Other\tcomprehensive\tincome | — | — | — | — | — | — | 40 | — | 40 |
| Dividends\tpaid | — | — | — | — | — | (567) | — | — | (567) |
| Purchase\tof\tsubsidiary |  |  |  |  |  |  |  |  |  |
| shares\tfrom\tnon- |  |  |  |  |  |  |  |  |  |
| controlling\tinterest | — | — | — | — | — | — | — | 7 | 7 |
| Spin-off\tof\tdownstream | — | — | — | — | 5 | (9,498) | 587 | — | (8,906) |
| December\t31,\t2011\tBalance | $— | $770 | $— | $(2,716) | $6,680 | $12,788 | $(370) | $7 | $17,159 |
| Shares\tissued\t-\tstock-based |  |  |  |  |  |  |  |  |  |
| compensation | — | — | — | 164 | (75) | — | — | — | 89 |
| Shares\trepurchased | — | — | — | (8) | — | — | — | — | (8) |
| Stock-based\tcompensation | — | — | — | — | 22 | — | — | — | 22 |
| Net\tincome | — | — | — | — | — | 1,582 | — | — | 1,582 |
| Other\tcomprehensive\tloss | — | — | — | — | — | — | (63) | — | (63) |
| Dividends\tpaid | — | — | — | — | — | (480) | — | — | (480) |
| Purchase\tof\tsubsidiary |  |  |  |  |  |  |  |  |  |
| shares\tfrom\tnon- |  |  |  |  |  |  |  |  |  |
| controlling\tinterest | — | — | — | — | — | — | — | (7) | (7) |
| Other | — | — | — | — | (11) | — | — | — | (11) |
| December\t31,\t2012\tBalance | $— | $770 | $— | $(2,560) | $6,616 | $13,890 | $(433) | $— | $18,283 |
| Shares\tissued\t-\tstock-based |  |  |  |  |  |  |  |  |  |
| compensation | — | — | — | 170 | (44) | — | — | — | 126 |
| Shares\trepurchased | — | — | — | (513) | — | — | — | — | (513) |
| Stock-based\tcompensation | — | — | — | — | 20 | — | — | — | 20 |
| Net\tincome | — | — | — | — | — | 1,753 | — | — | 1,753 |
| Other\tcomprehensive\tincome | — | — | — | — | — | — | 183 | — | 183 |
| Dividends\tpaid | — | — | — | — | — | (508) | — | — | (508) |
| December\t31,\t2013\tBalance | $— | $770 | $— | $(2,903) | $6,592 | $15,135 | $(250) | $— | $19,344 |

| (Shares	in	millions) | Preferred<br>Stock | Common<br>Stock | Securities<br>Exchangeable<br>into	Common<br>Stock | Treasury<br>Stock |
| :--- | :--- | :--- | :--- | :--- |
| January\t1,\t2011\tBalance | — | 770 | — | 60 |
| Shares\tissued\t-\tstock-based |  |  |  |  |
| compensation | — | — | — | (6) |
| Shares\trepurchased | — | — | — | 12 |
| December\t31,\t2011\tBalance | — | 770 | — | 66 |
| Shares\tissued\t-\tstock-based |  |  |  |  |
| compensation | — | — | — | (3) |
| December\t31,\t2012\tBalance | — | 770 | — | 63 |
| Shares\tissued\t-\tstock-based |  |  |  |  |
| compensation | — | — | — | (4) |
| Shares\trepurchased | — | — | — | 14 |
| December\t31,\t2013\tBalance | — | 770 | — | 73 |

# Notes	to	Consolidated	Financial	Statements

# 1.	Summary	of	Principal	Accounting	Policies

We	are	engaged	in	worldwide	exploration,	production	and	marketing	of	liquid	hydrocarbons	and	natural	gas;	production	and	marketing	of	products	manufactured from	natural	gas,	such	as	LNG	and	methanol,	in	E.G.;	and	oil	sands	mining,	bitumen	transportation	and	upgrading,	and	marketing	of	synthetic	crude	oil	and	vacuum	gas oil	in	Canada.

Principles	applied	in	consolidation	–	These	consolidated	financial	statements	include	the	accounts	of	our	majority-owned,	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.

Equity	method	investments	are	carried	at	our	share	of	net	assets	plus	loans	and	advances.	Such	investments	are	assessed	for	impairment	whenever	changes	in	the facts	and	circumstances	indicate	a	loss	in	value	has	occurred,	if	the	loss	is	deemed	to	be	other	than	temporary.	When	the	loss	is	deemed	to	be	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	net	income.	Differences	in	the	basis	of	the investments	and	the	separate	net	asset	value	of	the	investees,	if	any,	are	amortized	into	net	income	over	the	remaining	useful	lives	of	the	underlying	assets,	except	for	the excess	related	to	goodwill.

Discontinued	operations	–	Disclosures	in	this	report	related	to	results	of	operations	and	cash	flows	are	presented	on	the	basis	of	continuing	operations	unless otherwise	 stated.	Due	to	the	agreements	entered	in	2013	to	sell	our	Angola	assets	(see	Note	6),	the	corresponding	results	of	operations	and	cash	flows	have	been classified	as	discontinued	operations	for	all	presented	periods.	As	a	result	of	the	spin-off	of	our	downstream	business	in	2011	(see	Note	3),	the	related	results	of operations	and	cash	flows	have	been	classified	as	discontinued	operations	for	all	periods	prior	to	the	spin-off.

Use	of	estimates	–	The	preparation	of	financial	statements	in	accordance	with	generally	accepted	accounting	principles	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.

Reclassifications	–	Beginning	in	2013,	we	changed	the	presentation	of	our	consolidated	statements	of	income,	primarily	to	present	additional	details	of	revenues and	expenses	and	to	classify	certain	expenses	more	consistently	with	our	peer	group	of	independent	exploration	and	production	companies.	To	effect	these	changes, reclassifications	of	previously	reported	amounts	were	made	and	are	reflected	in	these	consolidated	financial	statements.	As	a	result	of	the	reclassifications,	general	and administrative	expenses	for	2012	and	2011	increased	by	$144	million	and	$119	million	which	primarily	includes	certain	costs	associated	with	operations	support	and operations	management.	Offsetting	reductions	are	reflected	in	production,	other	operating	and	exploration	expenses	and	taxes	other	than	income.

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	 liquid	hydrocarbons	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.	In	Canada,	mined	bitumen	is	first	processed	through an	upgrader	and	then	sold	as	synthetic	crude	oil.	Both	bitumen	and	synthetic	crude	oil	may	be	stored	as	inventory.

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.

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.	Uncollectible	accounts	receivable	are	reserved	against	the	allowance	for	uncollectible	accounts	when	it is	determined	the	receivable	will	not	be	collected	and	the	amount	of	any	reserve	may	be	reasonably	estimated.

Inventories	–	Inventories	are	carried	at	the	lower	of	cost	or	market	value.	The	majority	of	our	inventories	are	recorded	at	average	cost.	The	last-in,	first-out ("LIFO")	method	is	used	for	our	U.S.	crude	oil	and	natural	gas	inventories.

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,	interest	rate	risk	and	foreign	currency	exchange	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	with	the	underlying	transactions.	Our	derivative	instruments	contain	no	significant	contingent	credit	features.

Cash	flow	hedges	–	We	may	use	foreign	currency	forwards	and	options	to	manage	foreign	currency	risk	associated	with	anticipated	transactions	and	designate	them as	cash	flow	hedges.	No	such	derivatives	were	outstanding	at	December	31,	2013	 and	2012.	The	effective	portion	of	changes	in	fair	value	is	recognized	in	other comprehensive	income	("OCI")	and	is	reclassified	to	net	income	when	the	underlying	forecasted	transaction	is	recognized	in	net	income.	Any	ineffective	portion	is recognized	in	net	interest	and	other	as	it	occurs.	For	a	discontinued	cash	flow	hedge,	prospective	changes	in	the	fair	value	of	the	derivative	are	recognized	in	net	income. The	accumulated	gain	or	loss	recognized	in	OCI	at	the	time	a	hedge	is	discontinued	continues	to	be	deferred	until	the	original	forecasted	transaction	occurs.	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	OCI	is immediately	reclassified	into	net	income.

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.	No	such	derivatives	were	outstanding	at	December	31,	2013	and	2012.

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;	commodity derivative	instruments	to	manage	the	price	risk	on	natural	gas	that	we	purchase	to	be	marketed	with	our	natural	gas	production;	and	foreign	currency	forwards	to	manage our	exposure	to	changes	in	the	value	of	foreign	currency	denominated	tax	liabilities.	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.

Derivatives	not	designated	as	hedges	–	Derivatives	that	are	not	designated	as	hedges	may	include	commodity	derivatives	used	primarily	to	manage	price	risk	on	the forecasted	sale	of	crude	oil,	natural	gas	and	synthetic	crude	oil	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.	When	significant	transfers	occur,	they are	disclosed	in	Note	15	to	the	consolidated	financial	statements.

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

Property	acquisition	costs	–	Costs	to	acquire	mineral	interests	in	traditional	oil	and	natural	gas	properties	or	in	oil	sands	mines,	to	drill	and	equip	exploratory	wells in	progress	and	those	that	find	proved	reserves,	to	drill	and	equip	development	wells	and	to	construct	or	expand	oil	sands	mines	and	upgrading	facilities	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,	which	include	bitumen	mining	and	upgrading	facilities,	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	are	depreciated	on	a	straight-line	basis	over	their	estimated	useful	lives	which	range	from	3	to	40	years.

Property,	plant	and	equipment	unrelated	to	oil	and	gas	producing	activities	is	recorded	at	cost	and	depreciated	on	a	straight-line	basis	over	the	estimated	useful	lives of	the	assets,	which	range	from	3	to	40	years.

Impairments	–	We	evaluate	our	oil	and	gas	producing	properties,	including	capitalized	costs	of	exploratory	wells,	development	costs	and	our	bitumen	mining	and upgrading	facilities,	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.	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	and	may	apply	an	undiscounted	future	net	cash	flow	approach	when	appropriate.	Information	such	as	drilling	results,	reservoir	performance, seismic	interpretation	or	future	plans	to	develop	acreage	are	also	considered.	When	unproved	property	investments	are	deemed	to	be	impaired	the	expense	is	reported	in exploration	expenses.

Dispositions	–	When	property,	plant	and	equipment	depreciated	on	an	individual	basis	are	sold	or	otherwise	disposed	of,	any	gains	or	losses	are	reported	in	net 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	when	the	assets	are	classified	as	held	for	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	reporting	units.	The	fair	value	of each	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	 –	 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.	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.

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,	which	include	our	bitumen	mining facilities.	Asset	retirement	obligations	for	such	facilities	include	costs	to	dismantle	and	relocate	or	dispose	of	production	platforms,	mine	assets,	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	structure,	depth	of	water,	reservoir	characteristics,	depth	of	the	reservoir,	market	demand	for	equipment,	currently	available	procedures	and	consultations	with construction	and	engineering	professionals.	Asset	retirement	obligations	have	not	been	recognized	for	certain	of	our	international	oil	and	gas	producing	facilities	as	we currently	do	not	have	a	legal	obligation	associated	with	the	retirement	of	those	facilities.	Asset	retirement	obligations	have	not	been	recognized	for	the	removal	of materials	and	equipment	from	or	the	closure	of	certain	bitumen	upgrading	assets	because	the	fair	value	cannot	be	reasonably	estimated	since	the	settlement	dates	of	the obligations	are	indeterminate.

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	for	oil	and	gas production	facilities,	which	include	our	bitumen	mining	facilities,	while	accretion	escalates	over	the	lives	of	the	assets.

Deferred	income	taxes	–	Deferred	tax	assets	and	liabilities	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	our	expectation	to	generate	sufficient	future	taxable	income	including	future	foreign	source income,	tax	credits,	operating	loss	carryforwards	and	management's	intent	regarding	the	permanent	reinvestment	of	the	income	from	certain	foreign	subsidiaries.

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	life	of	the	stock	option	award	and	the	expected	volatility	of our	stock	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.

# 2.	Accounting	Standards

# Not	Yet	Adopted

# Recently	Adopted

In	February	2013,	an	accounting	standards	update	was	issued	to	improve	the	reporting	of	reclassifications	out	of	accumulated	other	comprehensive	income.	This standard	requires	an	entity	to	provide	information	about	the	amounts	reclassified	out	of	accumulated	other	comprehensive	income	by	component.	In	addition,	an	entity	is required	 to	present,	either	on	 the	face	of	 the	statement	where	net	 income	 is	presented	or	 in	 the	notes,	significant	amounts	reclassified	out	of	accumulated	other comprehensive	income	by	the	respective	line	items	of	net	income	but	only	if	the	amount	reclassified	is	required	under	U.S.	GAAP	to	be	reclassified	to	net	income	in	its entirety	in	the	same	reporting	period.	For	other	amounts	that	are	not	required	under	U.S.	GAAP	to	be	reclassified	in	their	entirety	to	net	income,	an	entity	is	required	to cross-reference	to	other	disclosures	required	under	U.S.	GAAP	that	provide	additional	detail	about	those	amounts.	This	accounting	standards	update	was	effective	for	us beginning	the	first	quarter	of	2013

and	we	present	the	required	disclosures	in	Note	22.	Adoption	of	this	standard	did	not	have	a	significant	impact	on	our	consolidated	results	of	operations,	financial position	or	cash	flows.

In	December	2011,	an	accounting	standards	update	designed	to	enhance	disclosures	about	offsetting	assets	and	liabilities	was	issued.	Further	clarification	limiting the	scope	of	these	disclosures	to	derivatives,	repurchase	agreements	and	reverse	repurchase	agreements,	and	securities	borrowing	and	securities	lending	transactions	was issued	in	January	2013.	The	disclosures	are	intended	to	enable	financial	statement	users	to	evaluate	the	effect	or	potential	effect	of	netting	arrangements	on	an	entity's financial	position.	Entities	are	required	to	disclose	both	gross	information	and	net	information	about	in-scope	financial	instruments	that	are	either	offset	in	the	statement of	financial	position	or	subject	to	an	enforceable	master	netting	arrangement	or	similar	agreement,	irrespective	of	whether	they	are	offset.	The	accounting	standards update	was	effective	for	us	beginning	the	first	quarter	of	2013	and	we	include	the	required	disclosures	in	Note	16.	Adoption	of	this	standard	did	not	have	a	significant impact	on	our	consolidated	results	of	operations,	financial	position	or	cash	flows.

In	September	2011,	 the	FASB	amended	accounting	standards	 to	simplify	how	entities	 test	goodwill	for	 impairment.	The	amendment	reduces	complexity	by allowing	an	entity	the	option	to	make	a	qualitative	evaluation	of	whether	it	is	necessary	to	perform	the	two-step	goodwill	impairment	test.	Adoption	of	this	amendment	in 2012	did	not	have	a	significant	impact	on	our	consolidated	results	of	operations,	financial	position	or	cash	flows.

The	FASB	amended	the	reporting	standards	for	comprehensive	income	in	June	2011	to	eliminate	the	option	to	present	the	components	of	OCI	as	part	of	the statement	of	changes	in	stockholders'	equity.	All	non-owner	changes	in	stockholders'	equity	are	required	to	be	presented	either	in	a	single	continuous	statement	of comprehensive	 income	 or	 in	 two	 separate	 but	 consecutive	 statements.	In	 the	 two	statement	approach,	 the	first	statement	should	present	 total	net	 income	and	 its components	followed	consecutively	by	a	second	statement	that	should	present	total	other	comprehensive	income,	the	components	of	OCI,	and	total	comprehensive income.	The	presentation	of	items	that	are	reclassified	from	OCI	to	net	income	on	the	income	statement	is	also	required.	The	amendments	did	not	change	the	items	that must	be	reported	in	OCI	or	when	an	item	of	OCI	must	be	reclassified	to	net	income.	The	amendments	were	effective	for	us	beginning	with	the	first	quarter	of	2012, except	for	the	presentation	of	reclassifications,	which	was	deferred	and	addressed	in	the	February	2013	accounting	standards	update	discussed	above.	Adoption	of	this standard	did	not	have	a	significant	impact	on	our	consolidated	results	of	operations,	financial	position	or	cash	flows.

In	May	2011,	the	FASB	issued	an	update	amending	the	accounting	standards	for	fair	value	measurement	and	disclosure,	resulting	in	common	principles	and requirements	under	U.S.	GAAP	and	IFRS.	The	amendments	change	the	wording	used	to	describe	certain	of	the	U.S.	GAAP	requirements	either	to	clarify	the	intent	of existing	requirements,	to	change	measurement	or	expand	disclosure	principles	or	to	conform	to	the	wording	used	in	IFRS.	Adoption	of	the	amendments	in	2012	did	not have	a	significant	 impact	on	our	consolidated	results	of	operations,	financial	position	or	cash	flows.	To	 the	extent	 they	were	necessary,	we	made	 the	expanded disclosures	in	Notes	15	and	16.

# 3. Spin-off	of	Downstream	Business

On	June	30,	2011,	the	spin-off	of	Marathon's	downstream	business	was	completed,	creating	two	 independent	energy	companies:	Marathon	Oil	and	MPC.	On June	30,	2011,	stockholders	of	record	as	of	5:00	p.m.	Eastern	Daylight	Savings	time	on	June	27,	2011	(the	"Record	Date")	received	one	common	share	of	MPC	stock	for every	two	common	shares	of	Marathon	stock	held	as	of	the	Record	Date.

In	order	to	effect	the	spin-off	and	govern	our	relationship	with	MPC	after	the	spin-off,	we	entered	into	a	Separation	and	Distribution	Agreement,	a	Tax	Sharing Agreement	and	an	Employee	Matters	Agreement.	The	Separation	and	Distribution	Agreement	governed	the	separation	of	the	downstream	business,	the	distribution	of MPC's	shares	of	common	stock	to	our	stockholders,	transfer	of	assets	and	intellectual	property,	and	other	matters	related	to	our	relationship	with	MPC.	The	Separation and	Distribution	Agreement	provides	for	cross-indemnities	between	Marathon	Oil	and	MPC.	In	general,	we	have	agreed	to	indemnify	MPC	for	any	liabilities	relating	to our	historical	exploration	and	production	and	oil	sands	mining	operations,	and	MPC	has	agreed	to	indemnify	us	for	any	liabilities	relating	to	the	historical	downstream operations.

The	Tax	Sharing	Agreement	governs	the	respective	rights,	responsibilities	and	obligations	of	Marathon	Oil	and	MPC	with	respect	to	taxes	and	tax	benefits,	the filing	of	tax	returns,	the	control	of	audits	and	other	tax	matters.	In	addition,	the	Tax	Sharing	Agreement	reflects	each	company's	rights	and	obligations	related	to	taxes that	are	attributable	to	periods	prior	to	and	including	the	separation	date	and	taxes	resulting	from	transactions	effected	in	connection	with	the	separation.	In	general, under	the	Tax	Sharing	Agreement,	Marathon	Oil	is	responsible	for	all	U.S.	federal,	state,	local	and	foreign	income	taxes	attributable	to	Marathon	Oil	or	any	of	its subsidiaries	for	any	tax	period	that	begins	after	the	date	of	the	spin-off,	and	MPC	is	responsible	for	all	taxes	attributable	to	it	or	its	subsidiaries,	whether	accruing	before, on	or	after	the	spin-off.	The	Tax	Sharing	Agreement	contains	covenants	intended	to	protect	the	tax-free	status	of	the	spin-off.	These	covenants	may	restrict	the	ability	of Marathon	Oil	and	MPC	to	pursue	strategic	or	other	transactions	that	otherwise	could	maximize	the	values	of	their	respective	businesses	and	may	discourage	or	delay	a change	of	control	of	either	company.

The	Employee	Matters	Agreement	contains	provisions	concerning	benefit	protection	for	employees	who	became	MPC	employees	prior	to	December	31,	2011, treatment	of	holders	of	Marathon	stock	options,	stock	appreciation	rights,	restricted	stock	and	restricted	stock	units,	and	cooperation	between	Marathon	Oil	and	MPC	in the	sharing	of	employee	information	and	maintenance	of	confidentiality.	Unvested	equity-based	compensation	awards	were	converted	to	awards	of	the	entity	where	the employee	holding	them	worked	post-separation.	For	vested	equity-based	compensation	awards,	employees	received	both	Marathon	Oil	and	MPC	awards.

The	results	of	operations	of	our	downstream	business	have	been	reported	as	discontinued	operations	for	2011.	The	table	below	shows	selected	financial	information reported	in	discontinued	operations	related	to	the	spin-off.

# 4. Variable	Interest	Entities

The	owners	of	the	AOSP,	in	which	we	hold	a	20	percent	undivided	interest,	contracted	with	a	wholly	owned	subsidiary	of	a	publicly	traded	Canadian	limited partnership	("Corridor	Pipeline")	to	provide	materials	transportation	capabilities	among	the	Muskeg	River	and	Jackpine	mines,	the	Scotford	upgrader	and	markets	in Edmonton.	The	contract,	originally	signed	in	1999	by	a	company	we	acquired,	allows	each	holder	of	an	undivided	interest	in	the	AOSP	to	ship	materials	in	accordance with	its	undivided	interest.	Costs	under	this	contract	are	accrued	and	recorded	on	a	monthly	basis,	with	a	$3	million	current	liability	recorded	at	December	31,	2013, consistent	with	December	31,	2012.	Under	this	agreement,	the	AOSP	absorbs	all	of	the	operating	and	capital	costs	of	the	pipeline.	Currently,	no	third-party	shippers	use the	pipeline.	Should	shipments	be	suspended,	by	choice	or	due	to	force	majeure,	we	remain	responsible	for	the	portion	of	the	payments	related	to	our	undivided	interest for	all	remaining	periods.	The	contract	expires	in	2029;	however,	the	shippers	can	extend	its	term	perpetually.	This	contract	qualifies	as	a	variable	interest	contractual arrangement	and	the	Corridor	Pipeline	qualifies	as	a	variable	interest	entity	("VIE").	We	hold	a	variable	interest	but	are	not	the	primary	beneficiary	because	our shipments	are	only	20	percent	of	the	total;	therefore	the	Corridor	Pipeline	is	not	consolidated	by	Marathon	Oil.	Our	maximum	exposure	to	loss	as	a	result	of	our involvement	with	this	VIE	is	the	amount	we	expect	to	pay	over	the	contract	term,	which	was	$723	million	as	of	December	31,	2013.	The	liability	on	our	books	related	to this	contract	at	any	given	time	will	reflect	amounts	due	for	the	immediately	previous	month's	activity,	which	is	substantially	less	than	the	maximum	exposure	over	the contract	term.	We	have	not	provided	financial	assistance	to	Corridor	Pipeline	and	we	do	not	have	any	guarantees	of	such	assistance	in	the	future.

During	2013,	2012	and	2011,	our	business	combinations	related	to	properties	acquired	by	our	North	America	E&P	segment	in	the	Eagle	Ford	in	south	Texas.	 The pro	forma	impact	of	these	transactions,	individually	and	in	the	aggregate,	is	not	material	to	our	consolidated	statements	of	income	for	any	periods	presented.

The	fair	values	of	assets	acquired	and	liabilities	assumed	in	each	of	these	business	combinations	were	measured	primarily	using	an	income	approach,	specifically utilizing	a	discounted	cash	flow	analysis.	The	estimated	fair	values	were	based	on	significant	inputs	not	observable	in	the	market,	and	therefore	represent	Level	3 measurements.	Significant	inputs	included	estimated	reserve	volumes,	the	expected	future	production	profile,	estimated	commodity	prices	and	assumptions	regarding future	operating	and	development	costs.	The	discount	rates	used	in	the	discounted	cash	flow	analyses	were	approximately	10	percent	for	the	2013	and	2012	transactions and	11	percent	for	the	2011	transaction.

In	July	2013,	we	acquired	4,800	net	undeveloped	acres	in	the	Eagle	Ford	in	a	transaction	valued	at	$97	million,	including	carried	interest	of	$23	million.	The transaction	was	accounted	for	as	a	business	combination,	with	the	entire	up-front	cash	consideration	of	$74	million	allocated	to	property,	plant	and	equipment	at	the acquisition	date.

We	acquired	approximately	25,000	net	acres	in	the	core	of	the	Eagle	Ford	during	2012.	The	largest	transactions	were	the	acquisitions	of	Paloma	Partners	II,	LLC, which	closed	in	the	second	quarter	of	2012	for	cash	consideration	of	$768	million,	and	an	acquisition	of	proved	and	unproved	properties	that	closed	in	the	third	quarter	of 2012	for	cash	consideration	of	$232	million.	These	transactions	were	accounted	for	as	business	combinations.

During	the	fourth	quarter	of	2011,	we	closed	a	series	of	transactions	in	the	Eagle	Ford	that	were	accounted	for	as	a	business	combination.	The	most	significant	of these	transactions	was	the	acquisition	of	Hilcorp	Resources,	LLC.	The	total	cash	consideration	paid	for	all	the	transactions	including	approximately	167,000	net	acres	and a	gathering	system,	was	$4.5	billion.

The	following	table	summarizes	the	amounts	allocated	to	the	assets	acquired	and	liabilities	assumed	based	upon	their	fair	values	at	the	acquisition	dates:

|  | June	30, | September	30, | December	31, |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | 2012 | 2012 | 2011 |
| Current\tassets: |  |  |  |
| Cash | $8 | $— | $— |
| Receivables | 22 | 8 | 40 |
| Inventories | 1 | — | 4 |
| Other\tcurrent\tassets | — | — | 30 |
| Total\tcurrent\tassets\tacquired | 31 | 8 | 74 |
| Property,\tplant\tand\tequipment | 822 | 248 | 4,501 |
| Other\tnoncurrent\tassets | — | — | 21 |
| Total\tassets\tacquired | 853 | 256 | 4,596 |
| Current\tliabilities: |  |  |  |
| Accounts\tpayable | 78 | 23 | 101 |
| Other\tcurrent\tliabilities | — | — | 20 |
| Total\tcurrent\tliabilities\tassumed | 78 | 23 | 121 |
| Asset\tretirement\tobligations | 7 | 1 | 5 |
| Total\tliabilities\tassumed | 85 | 24 | 126 |
| Net\tassets\tacquired | $768 | $232 | $4,470 |

In	addition,	during	2011,	our	North	America	E&P	segment	acquired	approximately	108,000	net	acres	in	the	Eagle	Ford	for	approximately	$265	million.	These transactions	were	accounted	for	as	asset	acquisitions.

# 6.	Dispositions

In	January	2013,	we	closed	the	sale	of	our	remaining	assets	in	Alaska,	for	proceeds	of	$195	million,	subject	to	a	six-month	escrow	of	$50	million	which	was collected	in	July	2013.	After	closing	adjustments	were	made	in	the	second	quarter	of	2013,	the	pretax	gain	on	this	sale	was	$55	million.

Assets	held	for	sale	in	the	December	31,	2012	consolidated	balance	sheet	were	related	to	the	Neptune	gas	plant	and	Alaska	dispositions	that	were	pending	at	that date	and	included:

| (In	millions) | December	31,<br>2012 |
| :--- | :--- |
| Other\tcurrent\tassets | $50 |
| Other\tnoncurrent\tassets | 248 |
| Total\tassets | $298 |
| Deferred\tcredits\tand\tother\tliabilities | $83 |
| Total\tliabilities | $83 |

In	the	fourth	quarter	of	2013,	we	transfered	our	45	percent	working	interest	and	operatorship	in	the	Safen	block	in	the	Kurdistan	Region	of	Iraq	at	a	pretax	loss	of $17	million.

In	June	and	December	2013,	we	entered	into	agreements,	valued	in	total	at	$2.1	billion	before	closing	adjustments,	to	sell	our	non-operated	10	percent	working interests	in	the	Production	Sharing	Contracts	and	Joint	Operating	Agreements	for	Angola	Blocks	31	and	32.	The	sale	of	our	interest	in	Block	31	closed	in	February	2014 and	the	sale	of	our	interest	in	Block	32	is	expected	to	close	in	the	first	quarter	of	2014.	Block	31	is	presented	as	held	for	sale	and	Block	32	is	reflected	as	unproved property	in	property,	plant	and	equipment	in	the	December	31,	2013	consolidated	balance	sheet	(See	Note	13	for	discussion	of	the	capitalized	costs	related	to	suspended wells).	Our	entire	Angola	operations	are	reflected	as	discontinued	operations	in	the	consolidated	statements	of	income	and	the	consolidated	statements	of	cash	flows	for all	periods	presented.

Assets	held	for	sale	in	the	December	31,	2013	consolidated	balance	sheet	were	related	to	the	Angola	Block	31	disposition	that	was	pending	at	that	date	and included:

| (In	millions) | December	31,<br>2013 |
| :--- | :--- |
| Other\tcurrent\tassets | $41 |
| Other\tnoncurrent\tassets | 1,647 |
| Total\tassets | $1,688 |
| Other\tcurrent\tliabilities | $25 |
| Deferred\tcredits\tand\tother\tliabilities | 43 |
| Total\tliabilities | $68 |

| (In	millions) | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| Revenues\tapplicable\tto\tdiscontinued\toperations | $361 | $— | $— |
| Pretax\tincome\t(loss)\tfrom\tdiscontinued\toperations | $247 | $(17) | $(17) |

In	the	third	quarter	of	2012,	we	sold	approximately	5,800	net	undeveloped	acres	in	the	Eagle	Ford	for	proceeds	of	$9	million.	A	pretax	loss	of	$18	million	was recorded.

In	January	2012,	we	closed	on	the	sale	of	our	interests	in	several	Gulf	of	Mexico	crude	oil	pipeline	systems	for	proceeds	of	$206	million.	This	included	our	equity method	interests	in	Poseidon	Oil	Pipeline	Company,	L.L.C.	and	Odyssey	Pipeline	L.L.C.,	as	well	as	certain	other	oil	pipeline	interests,	including	the	Eugene	Island pipeline	system.	A	pretax	gain	of	$166	million	was	recorded.

In	May	2012,	we	executed	agreements	to	relinquish	our	operatorship	of	and	participating	interests	in	the	Bone	Bay	and	Kumawa	exploration	licenses	in	Indonesia. As	 a	 result,	 we	 reported	 a	$36	million	pretax	 loss	on	disposal	of	assets.	Government	ratification	of	 the	agreements	released	us	from	our	obligations	and	further commitments	related	to	these	licenses.

In	December	2011,	we	sold	our	50	percent	interest	in	the	Burns	Point	gas	plant,	a	cryogenic	processing	plant	located	in	St.	Mary	Parish,	Louisiana,	for	total consideration	of	$36	million	and	a	pretax	gain	of	$34	million.

In	September	2011,	we	sold	our	equity	interest	in	an	LNG	processing	facility	in	Alaska	and	a	pretax	gain	on	the	transaction	of	$8	million	was	recorded.

In	April	2011,	we	assigned	a	30	percent	undivided	working	interest	in	approximately	180,000	acres	in	the	Niobrara	shale	play	located	within	the	DJ	Basin	of southeast	Wyoming	and	northern	Colorado	for	total	consideration	of	$270	million,	recording	a	pretax	gain	of	$37	million.	See	the	discussion	of	our	2013	disposal	of	the remaining	interest	above.

# 7.				Income	per	Common	Share

Basic	income	per	share	is	based	on	the	weighted	average	number	of	common	shares	outstanding.	Diluted	income	per	share	assumes	exercise	of	stock	options	and stock	appreciation	rights,	provided	the	effect	is	not	antidilutive.

| (In	millions,	except	per	share	data) | Basic | Diluted | Basic | Diluted | Basic | Diluted |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Income\tfrom\tcontinuing\toperations | $1,593 | $1,593 | $1,613 | $1,613 | $1,718 | $1,718 |
| Discontinued\toperations | 160 | 160 | (31) | (31) | 1,228 | 1,228 |
| Net\tincome | $1,753 | $1,753 | $1,582 | $1,582 | $2,946 | $2,946 |
| Weighted\taverage\tcommon\tshares\toutstanding | 705 | 705 | 706 | 706 | 710 | 710 |
| Effect\tof\tdilutive\tsecurities | — | 4 | — | 4 | — | 4 |
| Weighted\taverage\tcommon\tshares,\tincluding\ndilutive\teffect | 705 | 709 | 706 | 710 | 710 | 714 |
| Per\tshare: |  |  |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $2.26 | $2.24 | $2.28 | $2.27 | $2.42 | $2.41 |
| Discontinued\toperations | $0.23 | $0.23 | $(0.04) | $(0.04) | $1.73 | $1.72 |
| Net\tincome | $2.49 | $2.47 | $2.24 | $2.23 | $4.15 | $4.13 |

The	per	share	calculations	above	exclude	5	million,	10	million	and	7	million	stock	options	in	2013,	2012	and	2011	that	were	antidilutive.

# 8.	Segment	Information

	 Beginning	 in	 2013,	 we	 changed	 our	 reportable	 segments	 and	 revised	 our	 management	 reporting	 to	 better	 reflect the	 growing importance	 of	 United	 States unconventional	resource	plays	to	our	business.	All	periods	presented	have	been	recast	to	reflect	these	new	segments.

We	have	three	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:

•North	America	 E&P	 ("N.A.	 E&P")	 –	 explores	 for,	 produces	 and	 markets liquid	 hydrocarbons	 and	 natural	 gas in	 North America;

•International	E&P	("Int'l	E&P")	–	explores	for,	produces	and	markets	liquid	hydrocarbons	and	natural	gas	outside	of	North	America	and	produces	and	markets products	manufactured	from	natural	gas,	such	as	LNG	and	methanol,	in	E.G.;	and

•Oil	Sands	Mining	("OSM")	–	mines,	extracts	and	transports	bitumen	from	oil	sands	deposits	in	Alberta,	Canada,	and	upgrades	the	bitumen	to	produce	and market	synthetic	crude	oil	and	vacuum	gas	oil.

Information	regarding	assets	by	segment	is	not	presented	because	it	is	not	reviewed	by	the	chief	operating	decision	maker	("CODM").		Segment	income	represents income	from	continuing	operations	excluding	certain	items	not	allocated	to	segments,	net	of	income	taxes,	attributable	to	the	operating	segments.	Our	corporate	and operations	support	general	and	administrative	costs	are	not	allocated	to	the	operating	segments.	These	costs	primarily	consist	of	employment	costs	(including	pension effects),	professional	services,	facilities	and	other	costs	associated	with	corporate	and	operations	support	activities,	net	of	associated	income	tax	effects.	Unrealized	gains or	losses	on	crude	oil	derivative	instruments,	certain	impairments,	gains	or	losses	on	dispositions	or	other	items	that	affect	comparability	(as	determined	by	the	CODM) also	are	not	allocated	to	operating	segments.

In	2013,	we	entered	into	agreements	to	sell	our	Angola	assets;	therefore,	the	Angola	operations	are	reflected	as	discontinued	operations	and	excluded	from	the International	E&P	segment	in	all	periods	presented.

As	discussed	 in	Note	3,	our	downstream	business	was	spun-off	on	June	30,	2011	and	has	been	reported	as	discontinued	operations	for	2011.		Sales	to	MPC previously	reported	as	intersegment	revenues	are	reported	as	sales	and	other	operating	revenues	because	such	sales	were	expected	to	continue	subsequent	to	the	spin-off.

These	sales	were	$1.4	billion	in	the	first	six	months	of	2011.

| 2013 |  |  |  | Not	Allocated |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | N.A.\tE&amp;P | Int'l\tE&amp;P | OSM | to\tSegments |  | Total |
| Sales\tand\tother\toperating\trevenues | $5,068 | $5,827 | $1,576 | $(52) | (c) | $12,419 |
| Marketing\trevenues | 1,797 | 267 | 18 | — |  | 2,082 |
| Total\trevenues | 6,865 | 6,094 | 1,594 | (52) |  | 14,501 |
| Income\tfrom\tequity\tmethod\tinvestments | — | 427 | — | (4) | (d) | 423 |
| Net\tgain\t(loss)\ton\tdisposal\tof\tassets\tand\tother\tincome | 12 | 50 | 5 | (32) |  | 35 |
| Production\texpenses | 797 | 534 | 1,000 | — |  | 2,331 |
| Marketing\tcosts | 1,796 | 258 | 18 | — |  | 2,072 |
| Exploration\texpenses | 725 | 263 | — | — |  | 988 |
| Depreciation,\tdepletion\tand\tamortization | 1,927 | 621 | 218 | 24 |  | 2,790 |
| Impairments | 41 | — | — | 55 |  | 96 |
| Other\texpenses\t(a) | 420 | 239 | 66 | 401 |  | 1,126 |
| Taxes\tother\tthan\tincome | 318 | 7 | 22 | 5 |  | 352 |
| Net\tinterest\tand\tother | — | — | — | 274 |  | 274 |
| Provision\t(benefit)\tfor\tincome\ttaxes | 324 | 3,226 | 69 | (282) |  | 3,337 |
| Segment\tincome/Income\tfrom\tcontinuing\toperations | $529 | $1,423 | $206 | $(565) |  | $1,593 |
| Capital\texpenditures\t(b) | $3,649 | $764 | $286 | $285 |  | $4,984 |

(a) Includes	other	operating	expenses	and	general	and	administrative	expenses.

(b) Includes	accruals.

(c) Unrealized	gain	(loss)	on	crude	oil	derivative	instruments.

(d) EGHoldings	impairment	(see	Note	15).

| 2012 |  |  |  | Not	Allocated |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | N.A.\tE&amp;P | Int'l\tE&amp;P | OSM | to\tSegments |  | Total |
| Sales\tand\tother\toperating\trevenues | $3,944 | $7,445 | $1,521 | $53 | (c) | $12,963 |
| Marketing\trevenues | 2,451 | 248 | 30 | — |  | 2,729 |
| Total\trevenues | 6,395 | 7,693 | 1,551 | 53 |  | 15,692 |
| Income\tfrom\tequity\tmethod\tinvestments | 2 | 368 | — | — |  | 370 |
| Net\tgain\t(loss)\ton\tdisposal\tof\tassets\tand\tother\tincome | 11 | 30 | 4 | 114 |  | 159 |
| Production\texpenses | 706 | 500 | 996 | — |  | 2,202 |
| Marketing\tcosts | 2,444 | 269 | 31 | — |  | 2,744 |
| Exploration\texpenses | 588 | 118 | — | — |  | 706 |
| Depreciation,\tdepletion\tand\tamortization | 1,428 | 787 | 217 | 45 |  | 2,477 |
| Impairments | 11 | — | — | 360 |  | 371 |
| Other\texpenses\t(a) | 400 | 200 | 60 | 464 |  | 1,124 |
| Taxes\tother\tthan\tincome | 226 | 5 | 22 | (5) |  | 248 |
| Net\tinterest\tand\tother | — | — | — | 219 |  | 219 |
| Provision\t(benefit)\tfor\tincome\ttaxes | 223 | 4,552 | 58 | (316) |  | 4,517 |
|  | $382 | $1,660 | $171 | $(600) |  | $1,613 |
| Segment\tincome/Income\tfrom\tcontinuing\toperations\nCapital\texpenditures\t(b) | $3,988 | $489 | $188 | $466 |  | $5,131 |

| 2011 |  |  |  | Not	Allocated |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | N.A.\tE&amp;P | Int'l\tE&amp;P | OSM | to\tSegments | Total |
| Sales\tand\tother\toperating\trevenues | $3,364 | $5,851 | $1,535 | $— | $10,750 |
| Marketing\trevenues | 3,614 | 252 | 53 | — | 3,919 |
| Total\trevenues | 6,978 | 6,103 | 1,588 | — | 14,669 |
| Income\tfrom\tequity\tmethod\tinvestments | 20 | 442 | — | — | 462 |
| Net\tgain\t(loss)\ton\tdisposal\tof\tassets\tand\tother\tincome | 21 | 73 | (17) | 74 | 151 |
| Production\texpenses | 545 | 409 | 915 | 82 | 1,951 |
| Marketing\tcosts | 3,598 | 247 | 53 | — | 3,898 |
| Exploration\texpenses | 388 | 253 | — | — | 641 |
| Depreciation,\tdepletion\tand\tamortization | 1,191 | 828 | 196 | 48 | 2,263 |
| Impairments | 12 | — | — | 298 | 310 |
| Other\texpenses\t(a) | 494 | 191 | 46 | 465 | 1,196 |
| Taxes\tother\tthan\tincome | 182 | 6 | 17 | (12) | 193 |
| Net\tinterest\tand\tloss\ton\tearly\textinguishment\tof\tdebt | — | — | — | 386 | 386 |
| Provision\t(benefit)\tfor\tincome\ttaxes | 217 | 2,693 | 83 | (267) | 2,726 |
| Segment\tincome/Income\tfrom\tcontinuing\toperations | $392 | $1,991 | $261 | $(926) | $1,718 |
| Capital\texpenditures\t(b) | $2,163 | $544 | $308 | $384 | $3,399 |

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

| (In	millions) | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| United\tStates | $6,813 | $6,448 | $6,978 |
| Norway | 3,183 | 3,714 | 3,563 |
| Canada | 1,594 | 1,551 | 1,588 |
| Libya(a) | 1,106 | 1,989 | 216 |
| Other\tinternational | 1,805 | 1,990 | 2,324 |
| Total\trevenues | $14,501 | $15,692 | $14,669 |

(a) See	Note	13	for	discussion	of	Libya	operations.

In	2013,	sales	to	British	Petroleum	and	its	affiliates	accounted	for	approximately	11	percent	of	our	total	revenues.	In	2012,	Statoil,	the	purchaser	of	the	majority	of our	Libyan	crude	oil,	accounted	for	approximately	15	percent	of	our	total	revenues,	while	sales	to	Shell	Oil	and	its	affiliates	accounted	for	approximately	12	percent	of total	revenues.	In	2011,	our	sales	to	MPC	accounted	for	approximately	18	percent	of	total	revenues.

Revenues	by	product	line	were:

| (In	millions) | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| Liquid\thydrocarbons | $11,932 | $12,983 | $11,778 |
| Natural\tgas | 937 | 1,052 | 1,203 |
| Synthetic\tcrude\toil | 1,542 | 1,409 | 1,442 |
| Other | 90 | 248 | 246 |
| Total\trevenues | $14,501 | $15,692 | $14,669 |

The	following	summarizes	certain	long-lived	assets	by	geographic	area,	including	property,	plant	and	equipment	and	equity	method	investments.

(a) Excludes	$1	million	and	$10	million	paid	by	United	States	Steel	in	2012	and	2011	on	assumed	debt.

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

| (In	millions) | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| Net\tinterest\tand\tother | $16 | $4 | $24 |
| Provision\tfor\tincome\ttaxes | 105 | (80) | 57 |
| Aggregate\tforeign\tcurrency\tgains\t(losses) | $121 | $(76) | $81 |

# 10.	Income	Taxes

Income	tax	provisions	(benefits)	for	continuing	operations	were:

|  |  | 2013 |  |  | 2012 |  |  | 2011 |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Current | \t Deferred | \t Total | \t Current | \t Deferred | \t Total | \t Current | \t Deferred | \t Total |
| Federal | $63 | $(46) | $17 | $(80) | $(30) | $(110) | $(193) | $(217) | $(410) |
| State\tand\tlocal | 44 | 1 | 45 | (23) | 47 | 24 | 24 | 82 | 106 |
| Foreign | 3,290 | (15) | 3,275 | 4,844 | (241) | 4,603 | 3,088 | (58) | 3,030 |
| Total | $3,397 | $(60) | $3,337 | $4,741 | $(224) | $4,517 | $2,919 | $(193) | $2,726 |

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

|  | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| Statutory\trate\tapplied\tto\tincome\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | 35% | 35% | 35% |
| Effects\tof\tforeign\toperations,\tincluding\tforeign\ttax\tcredits | 14 | 18 | 6 |
| Change\tin\tpermanent\treinvestment\tassertion | — | — | 5 |
| Adjustments\tto\tvaluation\tallowances | 18 | 21 | 14 |
| Tax\tlaw\tchanges | — | — | 1 |
| Other | 1 | — | — |
| Effective\tincome\ttax\trate\ton\tcontinuing\toperations | 68% | 74% | 61% |

The	effective	income	tax	rate	is	influenced	by	a	variety	of	factors	including	the	geographic	and	functional	sources	of	income,	the	relative	magnitude	of	these	sources of	income,	and	foreign	currency	remeasurement	effects.	The	provision	for	income	taxes	is	allocated	on	a	discrete,	stand-alone	basis	to	pretax	segment	income	and	to individual	items	not	allocated	to	segments.	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	8.

Effects	of	foreign	operations	–	The	effects	of	foreign	operations	on	our	effective	tax	rate	decreased	in	2013	as	compared	to	2012,	primarily	due	to	decreased	sales	in Libya	in	2013	as	a	result	of	third-party	labor	strikes	at	the	Es	Sider	oil	terminal.	The	effects	of	foreign	operations	on	our	effective	tax	rate	increased	in	2012	from	2011, primarily	due	to	the	resumption	of	sales	of	Libyan	production	in	2012.

Adjustments	to	valuation	allowances	–	In	2013,	2012	and	2011,	we	increased	the	valuation	allowance	against	foreign	tax	credits	because	it	is	more	likely	than	not that	we	will	be	unable	to	realize	all	U.S.	benefits	on	foreign	taxes	accrued	in	those	years.

Tax	law	changes	–	The	U.K.	enacted	Finance	Bill	2013	in	July	2013	and	Finance	Bill	2012	in	July	2012,	which	did	not	change	the	rate	of	corporation	tax	or	the supplementary	corporation	tax	for	U.K.	ring-fenced	activities	in	the	oil	and	gas	sector.	As	such,	this	legislation	did	not	have	a	material	impact	on	our	consolidated income	tax	provision.	In	July	2011,	the	U.K.	enacted	Finance	Bill	2011	which	increased	the	rate	of	the	supplementary	charge	levied	on	profits	from	U.K.	oil	and	gas production	from	20	percent	to	32	percent.	As	a	result	of	this	legislation,	we	recorded	deferred	tax	expense	of	$10	million	in	2011.

On	May	25,	2011,	Michigan	enacted	legislation	that	replaced	the	Michigan	Business	Tax	("MBT")	with	a	corporate	income	tax	("CIT"),	effective	January	1,	2012. The	CIT	legislation	eliminated	the	"book-tax	difference	deduction"	that	was	provided	under	the	MBT	to	mitigate	the	net	increase	in	a	taxpayer's	deferred	tax	liability resulting	when	Michigan	moved	from	the	Single	Business	Tax,	a	non-income	tax,	to	the	MBT,	an	income	tax,	on	July	12,	2007.	Such	a	change	in	the	tax	law	must	be recognized	in	earnings	in	the	period	enacted	regardless	of	the	effective	date.	The	total	effect	of	tax	law	changes	on	deferred	tax	balances	is	recorded	as	income	tax expense	related	to	continuing	operations	in	the	period	the	law	is	enacted,	even	if	a	portion	of	the	deferred	tax	balances	relates	to	discontinued	operations.	As	a	result	of the	new	CIT	legislation,	we	recorded	deferred	tax	expense	of	$32	million	in	the	second	quarter	of	2011.

Deferred	tax	assets	and	liabilities	resulted	from	the	following:

|  | December	31, |  |
| :--- | :--- | :--- |
| (In\tmillions) | 2013 | 2012 |
| Deferred\ttax\tassets: |  |  |
| Employee\tbenefits | $387 | $510 |
| Operating\tloss\tcarryforwards | 284 | 368 |
| Foreign\ttax\tcredits | 5,730 | 4,351 |
| Other | 98 | 121 |
| Valuation\tallowances: |  |  |
| Federal | (2,997) | (2,067) |
| State,\tnet\tof\tfederal\tbenefit | (67) | (60) |
| Foreign | (149) | (210) |
| Total\tdeferred\ttax\tassets | 3,286 | 3,013 |
| Deferred\ttax\tliabilities: |  |  |
| Property,\tplant\tand\tequipment | 4,018 | 3,691 |
| Investments\tin\tsubsidiaries\tand\taffiliates | 794 | 840 |
| Other | 67 | 12 |
| Total\tdeferred\ttax\tliabilities | 4,879 | 4,543 |
| Net\tdeferred\ttax\tliabilities | $1,593 | $1,530 |

Tax	carryforwards	–	At	December	31,	2013,	our	operating	loss	carryforwards	included	$744	million	from	Canada	which	expire	in	2026	through	2030	and	$128 million	from	the	Kurdistan	Region	of	Iraq	that	expire	in	2016	through	2018.	State	operating	loss	carryforwards	of	$1,503	million	expire	in	2014	through	2033.	Foreign tax	credit	carryforwards	of	$3,560	million	expire	in	2022	through	2023.

Valuation	allowances	 –	The	 estimated realizability	 of	the	benefit	of	foreign	 tax	credits	 is	based	on	certain	estimates	concerning	future	operating	conditions (particularly	as	related	to	prevailing	liquid	hydrocarbon,	natural	gas	and	synthetic	crude	oil	prices),	future	financial	conditions,	income	generated	from	foreign	sources and	our	tax	profile	in	the	years	that	such	credits	may	be	claimed.	Federal	valuation	allowances	increased	$930	million,	$1,277	million	and	$585	million	in	2013,	2012 and	2011,	because	it	is	more	likely	than	not	that	we	will	be	unable	to	realize	all	U.S.	benefits	on	foreign	taxes	accrued	in	those	years.

Foreign	valuation	allowances	decreased	$61	million	in	2013,	primarily	due	the	disposal	of	our	Indonesian	assets.	Foreign	valuation	allowances	increased	$16 million	and	$52	million	in	2012	and	2011,	primarily	due	to	deferred	tax	assets	generated	in	the	Kurdistan	Region	of	Iraq,	Angola	and	Indonesia.

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

|  | December	31, | December	31, |
| :--- | :--- | :--- |
| (In\tmillions) | 2013 | 2012 |
| Assets: |  |  |
| Other\tcurrent\tassets | $53 | $57 |
| Other\tnoncurrent\tassets | 847 | 849 |
| Liabilities: |  |  |
| Other\tcurrent\tliabilities | 1 | 4 |
| Noncurrent\tdeferred\ttax\tliabilities | 2,492 | 2,432 |
| Net\tdeferred\ttax\tliabilities | $1,593 | $1,530 |

We	are	continuously	undergoing	examination	of	our	U.S.	federal	income	tax	returns	by	the	IRS.	Such	audits	have	been	completed	through	the	2009	tax	year.	We believe	adequate	provision	has	been	made	for	federal	income	taxes	and	interest	which	may	become	payable	for	years	not	yet	settled.	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,	2013,	our	income	tax	returns	remain	subject	to	examination	in	the	following	major	tax	jurisdictions	for	the	tax	years	indicated:

If	the	unrecognized	tax	benefits	as	of	December	31,	2013	were	recognized,	$98	million	would	affect	our	effective	income	tax	rate.	There	 were	$11	million	of uncertain	tax	positions	as	of	December	31,	2013	for	which	it	is	reasonably	possible	that	the	amount	of	unrecognized	tax	benefits	would	significantly	increase	or	decrease during	the	next	twelve	months.

Interest	and	penalties	are	recorded	as	part	of	the	tax	provision	and	were	$13	million,	$4	million	and	$13	million	related	to	unrecognized	tax	benefits	in	2013,	2012 and	2011.	As	of	December	31,	2013	and	2012,	$15	million	and	$24	million	of	interest	and	penalties	were	accrued	related	to	income	taxes.

Pretax	income	from	continuing	operations	included	amounts	attributable	to	foreign	sources	of	$4,874	million,	$6,382	million	and	$4,886	million	in	2013,	2012	and 2011.

Undistributed	 income	 of	 certain	 consolidated	 foreign	 subsidiaries	 at	December	31,	2013	 amounted	 to	$1,438	million	 for	 which	 no	 U.S.	 deferred	 income	 tax provision	has	been	recorded	because	we	intend	to	permanently	reinvest	such	income	in	our	foreign	operations.	If	such	income	was	not	permanently	reinvested,	income tax	expense	of	approximately	$503	million	would	be	recorded,	not	including	potential	utilization	of	foreign	tax	credits.

# 11.	Inventories

Inventories	are	carried	at	the	lower	of	cost	or	market	value.	The	LIFO	method	accounted	for	4	percent	and	6	percent	of	total	inventory	value	at	December	31,	2013 and	2012.	Current	acquisition	costs	were	estimated	to	exceed	the	LIFO	inventory	value	at	December	31,	2013	and	2012	by	$32	million	and	$29	million.

|  | December	31, | December	31, |
| :--- | :--- | :--- |
| (In\tmillions) | 2013 | 2012 |
| Liquid\thydrocarbons,\tnatural\tgas\tand\tbitumen | $55 | $73 |
| Supplies\tand\tother\titems | 309 | 288 |
| Inventories\tat\tcost | $364 | $361 |

# 12.	Equity	Method	Investments	and	Related	Party	Transactions

During	2013,	2012	and	2011	only	our	equity	method	investees	were	considered	related	parties	and	they	included:

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

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

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

Our	equity	method	investments	are	summarized	in	the	following	table:

|  | Ownership	as	of | December	31, | December	31, |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | December\t31,\t2013 | 2013 | 2012 |
| EGHoldings | 60% | $748 | $817 |
| Alba\tPlant\tLLC | 52% | 263 | 264 |
| AMPCO | 45% | 189 | 187 |
| Other\tinvestments |  | 1 | 11 |
| Total |  | $1,201 | $1,279 |

Dividends	and	partnership	distributions	received	from	equity	method	investees	(excluding	distributions	that	represented	a	return	of	capital	previously	contributed) were	$435	million	in	2013,	$381	million	in	2012	and	$509	million	in	2011.

Summarized	financial	information	for	equity	method	investees	is	as	follows:

| (In	millions) | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| Income\tdata\t–\tyear: |  |  |  |
| Revenues\tand\tother\tincome | $1,444 | $1,330 | $1,544 |
| Income\tfrom\toperations | 849 | 755 | 942 |
| Net\tincome | 727 | 635 | 820 |
| Balance\tsheet\tdata\t–\tDecember\t31: |  |  |  |
| Current\tassets | $644 | $607 |  |
| Noncurrent\tassets | 1,590 | 1,743 |  |
| Current\tliabilities | 384 | 395 |  |
| Noncurrent\tliabilities | 33 | 29 |  |

Revenues	from	related	parties	were	$55	million,	$58	million	 and	$60	million	in	2013,	2012	and	2011,	with	the	majority	related	to	EGHoldings	in	all	years. Purchases	from	related	parties	were	$242	million,	$248	million	and	$250	million	in	2013,	2012	and	2011	with	the	majority	related	to	Alba	Plant	LLC	in	all	years.

Current	receivables	from	related	parties	at	December	31,	2013	and	2012,	approximately	split	evenly	between	EGHoldings	and	AMPCO,	were	$30	million	and	$27 million.	Payables	to	related	parties	were	$20	million	at	December	31,	2013	and	2012,	with	the	majority	related	to	Alba	Plant	LLC.

# 13.	Property,	Plant	and	Equipment

|  | December	31, | December	31, |
| :--- | :--- | :--- |
| (In\tmillions) | 2013 | 2012 |
| North\tAmerica\tE&amp;P | $26,755 | $23,748 |
| International\tE&amp;P | 12,428 | 13,214 |
| Oil\tSands\tMining | 10,436 | 10,127 |
| Corporate | 421 | 449 |
| Total\tproperty,\tplant\tand\tequipment | 50,040 | 47,538 |
| Less\taccumulated\tdepreciation,\tdepletion\tand\tamortization | (21,895) | (19,266) |
| Net\tproperty,\tplant\tand\tequipment | $28,145 | $28,272 |

During	the	third	quarter	of	2013,	our	Libya	production	operations	were	impacted	by	third-party	labor	strikes	at	the	Es	Sider	oil	terminal.	We	have	had	no	oil	liftings in	Libya	since	July	2013.	Uncertainty	around	production	and	sales	levels	from	Libya	have	existed	since	the	first	quarter	of	2011	when	production	operations	were suspended	until	the	fourth	quarter	of	that	year.		We

and	our	partners	in	the	Waha	concessions	continue	to	assess	the	condition	of	our	assets	in	Libya	and	uncertainty	around	production	and	sales	levels	remains.	As	of December	31,	2013,	our	net	property,	plant	and	equipment	investment	in	Libya	is	approximately	$761	million	and	total	proved	reserves	(unaudited)	in	Libya	are	249 mmboe.

Deferred	exploratory	well	costs	were	as	follows:

Exploratory	well	costs	capitalized	greater	than	one	year	after	completion	of	drilling	as	of	December	31,	2013	are	summarized	by	geographical	area	below:

| (In	millions) |  |
| :--- | :--- |
| Angola | $153 |
| Norway | 70 |
| E.G. | 22 |
| Canada | 36 |
| Total | $281 |

Well	costs	that	have	been	suspended	for	longer	than	one	year	are	associated	with	seven	projects.	Management	believes	these	projects	with	suspended	exploratory drilling	costs	exhibit	sufficient	quantities	of	hydrocarbons	to	justify	potential	development.

Angola	 –	Exploration	on	Angola	Block	31	began	in	2004,	with	costs	accumulating	through	2009.	Exploration	on	Angola	Block	32	began	in	2011,	with	costs accumulating	through	2013.	In	June	and	December	2013,	we	entered	into	agreements	to	sell	our	non-operated	working	interests	in	Angola	Blocks	31	and	32	(see	Note 6).

Norway –	Three	 offshore	 Norway	 projects	 had	 costs	 incurred	 from	 2009	 through	 2011.	The	 development	 plan	 for	 Boyla	 was	 approved	 by	 the	 Norwegian government	 in	October	2012.	This	will	tie-back	to	the	Alvheim	FPSO	and	development	drilling	is	planned	in	2014,	with	first	production	expected	in	early	2015. Development	options	are	being	evaluated	for	the	Caterpillar	and	Viper	projects.

E.G.	–	The	Corona	well	on	Block	D	offshore	E.G.	was	drilled	in	2004,	and	we	acquired	an	additional	interest	in	the	well	in	2012.	We	plan	to	develop	Block	D through	a	unitization	with	the	Alba	field,	which	is	currently	being	negotiated.

Canada	–	Exploration	began	on	our	Canadian	in-situ	assets	at	Birchwood	in	2010	with	costs	accumulating	through	2011.	In	2012,	we	submitted	a	regulatory application	for	a	proposed	12	mbbld	SAGD	demonstration	project.		We	expect	to	receive	regulatory	approval	for	this	project	by	the	end	of	2014.		Upon	receiving	this approval,	we	will	further	evaluate	our	development	plans.

# 14.	Goodwill

Goodwill	is	tested	for	impairment	on	an	annual	basis,	or	when	events	or	changes	in	circumstances	indicate	the	fair	value	of	a	reporting	unit	with	goodwill	has	been reduced	below	its	carrying	value.	We	performed	our	annual	impairment	tests	during	2013,	2012	and	2011	and	no	impairment	was	required.	The	fair	value	of	each	of	our reporting	units	with	goodwill	exceeded	the	book	value	appreciably.

	The	changes	in	the	carrying	amount	of	goodwill	for	2012	were	as	follows	for	the	Exploration	and	Production	("E&P")	and	OSM	segments	in	place	for	that	year:

| (In	millions) | E&amp;P | OSM | Total |
| :--- | :--- | :--- | :--- |
| 2012 |  |  |  |
| Beginning\tbalance,\tgross | $536 | $1,412 | $1,948 |
| Less:\taccumulated\timpairments | — | (1,412) | (1,412) |
| Beginning\tbalance,\tnet | 536 | — | 536 |
| Dispositions | (11) | — | (11) |
| Ending\tbalance,\tnet | $525 | $— | $525 |

As	discussed	in	Note	8,	beginning	in	2013,	we	changed	our	reportable	segments.	Goodwill	related	to	the	previously	reported	E&P	segment	was	allocated	between the	North	America	E&P	and	International	E&P	segments	as	of	January	1,	2013	based	on	the	relative	fair	values	of	those	reporting	units.	The	fair	values	of	the	reporting units	were	measured	using	an	income	approach	based	upon	internal	estimates	of	future	production	levels,	commodity	prices	and	discount	rates,	all	of	which	are	Level	3 inputs.		Inputs	to	the	fair	value	measurements	included	reserve	and	production	estimates	made	by	our	reservoir	engineers,	estimated	commodity	prices	adjusted	for quality	and	location	differentials,	and	forecasted	operating	expenses.	The	table	below	displays	the	allocated	beginning	goodwill	balances	by	segment	along	with	changes in	the	carrying	amount	of	goodwill	for	2013:

| (In	millions) | N.A.	E&amp;P |  | Int'l	E&amp;P | OSM | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 2013 |  |  |  |  |  |
| Beginning\tbalance,\tgross | $343 |  | $182 | $1,412 | $1,937 |
| Less:\taccumulated\timpairments | — |  | — | (1,412) | (1,412) |
| Beginning\tbalance,\tnet | 343 |  | 182 | — | 525 |
| Dispositions | 4 | (a) | (30) | — | (26) |
| Ending\tbalance,\tnet | $347 |  | $152 | $— | $499 |

(a) Goodwill	related	to	our	Alaska	disposition	was	less	than	the	estimate	classified	as	held	for	sale	in	2012.

# 15.	Fair	Value	Measurements

# Fair	values	–	Recurring

The	following	tables	present	assets	and	liabilities	accounted	for	at	fair	value	on	a	recurring	basis	as	of	December	31,	2013	and	2012	by	fair	value	hierarchy	level.

| (In	millions) | Level	1 | Level	2 | Level	3 | Collateral | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Derivative\tinstruments,\tassets |  |  |  |  |  |
| Interest\trate | $— | $8 | $— | $— | $8 |
| Foreign\tcurrency | — | 2 | — | — | 2 |
| Derivative\tinstruments,\tassets | $— | $10 | $— | $— | $10 |
| Derivative\tinstruments,\tliabilities |  |  |  |  |  |
| \t\t\t\t\tForeign\tcurrency | $— | $4 | $— | $— | $4 |
| Derivative\tinstruments,\tliabilities | $— | $4 | $— | $— | $4 |

| (In	millions) | Level	1 | Level	2 | Level	3 | Collateral | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Derivative\tinstruments,\tassets |  |  |  |  |  |
| \t\t\t\t\tCommodity | $— | $52 | $— | $1 | $53 |
| \t\t\t\t\tInterest\trate | — | 21 | — | — | 21 |
| \t\t\t\t\tForeign\tcurrency | — | 18 | — | — | 18 |
| \t\t\t\t\t\t\t\t\t\tDerivative\tinstruments,\tassets | $— | $91 | $— | $1 | $92 |

Interest	rate	swaps	are	measured	at	fair	value	with	a	market	approach	using	actionable	broker	quotes	which	are	Level	2	inputs.		Foreign	currency	forwards	are measured	at	fair	value	with	a	market	approach	using	third-party	pricing	services,	such	as

Bloomberg	L.P.,	which	have	been	corroborated	with	data	from	active	markets	for	similar	assets	or	liabilities,	and	are	Level	2	inputs.

Commodity	swaps	in	Level	2	are	measured	at	fair	value	with	a	market	approach	using	prices	obtained	from	exchanges	or	pricing	services,	which	have	been corroborated	with	data	from	active	markets	for	similar	assets	or	liabilities.		Commodity	options	in	Level	2	are	valued	using	the	Black-Scholes	Model.		Inputs	to	this model	include	prices	as	noted	above,	discount	factors,	and	implied	market	volatility.		The	inputs	to	this	fair	value	measurement	are	categorized	as	Level	2	because predominantly	all	assumptions	and	inputs	are	observable	in	active	markets	throughout	the	term	of	the	instruments.		Collateral	deposits	related	to	commodity	derivatives are	in	broker	accounts	covered	by	master	netting	agreements.

# 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.

| (In	millions) | Fair	Value | Impairment | Fair	Value | Impairment | Fair	Value | Impairment |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Long-lived\tassets\theld\tfor\tuse | $5 | $96 | $16 | $371 | $226 | $285 |
| Intangible\tassets | — | — | — | — | — | 25 |

Long-lived	assets	held	for	use	–	In	light	of	E.G.'s	recent	natural	gas	policy	developments	related	to	the	country's	natural	gas	resources,	we	elected	to	cease	our efforts	to	develop	a	second	LNG	production	train	on	Bioko	Island	and	recorded	a	$40	million	impairment	of	all	capitalized	costs	associated	with	engineering	and feasibility	studies	in	the	fourth	quarter	of	2013.	In	addition,	our	share	of	income	from	EGHoldings	included	a	$4	million	impairment	related	to	the	same	project	which	is reflected	in	income	from	equity	method	investments	in	the	2013	consolidated	statement	of	income.

Long-lived	assets	held	for	use	–	The	fair	values	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	included	reserve	and	production	estimates	made	by	our	reservoir	engineers, estimated	commodity	prices	adjusted	for	quality	and	location	differentials,	and	forecasted	operating	expenses	for	the	remaining	estimated	life	of	the	reservoir.

In	the	fourth	quarter	of	2012,	declining	natural	gas	prices	related	to	our	Powder	River	Basin	asset	prompted	lower	production	expectations	and	reductions	in estimated	reserves	which	resulted	in	an	impairment	of	$73	million.	Subsequently,	in	the	first	quarter	of	2013,	as	a	result	of	our	decision	to	wind	down	operations	in	the Powder	River	Basin	due	to	poor	economics,	an	additional	impairment	of	$15	million	was	recorded	to	write	down	the	asset's	remaining	fair	value.

During	early	2012,	production	rates	from	the	Ozona	development	in	the	Gulf	of	Mexico	declined	significantly.		Accordingly,	our	reserve	engineers	performed evaluations	of	our	future	production	as	well	as	our	reserves	and	an	 impairment	was	recorded	 in	 the	first	quarter	of	2012.	As	 the	development	produced	 toward abandonment	pressures,	further	downward	revisions	of	reserves	were	taken	for	an	aggregate	impairment	of	$289	million	in	2012.		Ozona	production	ceased	in	the	first quarter	of	2013	and	an	additional	$21	million	impairment	was	recorded.

In	May	2011,	significant	water	production	and	reservoir	pressure	declines	occurred	at	our	Droshky	development	in	the	Gulf	of	Mexico.	Plans	for	a	waterflood	were canceled	and	due	to	a	decrease	in	proved	reserves,	a	$273	million	impairment	of	this	asset	to	its	$226	million	fair	value	was	recorded	in	2011.

Other	impairments	of	long-lived	assets	held	for	use	in	2013,	2012	 and	2011	were	a	result	of	reduced	drilling	expectations,	reductions	of	estimated	reserves	or declining	natural	gas	prices.

Intangible	assets	–	In	the	second	quarter	of	2011,	our	outlook	for	U.S.	natural	gas	prices	made	it	unlikely	that	sufficient	U.S.	demand	for	LNG	would	materialize	by 2021,	which	is	when	the	rights	lapse	under	our	arrangements	at	the	Elba	Island,	Georgia	regasification	facility.	Using	an	income	approach	based	upon	internal	estimates of	gas	prices	and	future	deliveries,	which	are	Level	3	inputs,	we	determined	that	the	contract	had	no	remaining	fair	value	and	recorded	a	full	impairment	of	this intangible	asset.

# Fair	values	–	Financial	instruments

Our	current	assets	and	liabilities	include	financial	instruments,	the	most	significant	of	which	are	receivables,	commercial	paper	and	payables.	We	believe	the carrying	values	of	our	receivables,	commercial	paper	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	investment-grade	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,	commercial	paper,	payables	and	derivative	financial	instruments,	and	their	reported fair	value	by	individual	balance	sheet	line	item	at	December	31,	2013	and	2012.

| (In	millions) | Fair<br>Value | Carrying<br>Amount | Fair<br>Value | Carrying<br>Amount |
| :--- | :--- | :--- | :--- | :--- |
| Financial\tassets |  |  |  |  |
| Other\tnoncurrent\tassets | $154 | $147 | $189 | $186 |
| Total\tfinancial\tassets | $154 | $147 | $189 | $186 |
| Financial\tliabilities |  |  |  |  |
| Other\tcurrent\tliabilities | $13 | $13 | $13 | $13 |
| Long-term\tdebt,\tincluding\tcurrent\tportion(a) | 6,922 | 6,427 | 7,610 | 6,642 |
| Deferred\tcredits\tand\tother\tliabilities | 149 | 147 | 94 | 94 |
| Total\tfinancial\tliabilities | $7,084 | $6,587 | $7,717 | $6,749 |

# (a) Excludes	capital	leases.

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

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.

For	further	information	regarding	the	fair	value	measurement	of	derivative	instruments	see	Note	15.	See	Note	1	for	discussion	of	the	types	of	derivatives	we	use	and the	reasons	for	them.	All	of	our	interest	rate	and	commodity	derivatives	are	subject	to	enforceable	master	netting	arrangements	or	similar	agreements	under	which	we may	report	net	amounts.	Netting	is	assessed	by	counterparty,	and	as	of	December	31,	2013	and	2012,	there	were	no	offsetting	amounts.	Positions	by	contract	were	all either	assets	or	liabilities.	The	following	tables	present	the	gross	fair	values	of	derivative	instruments,	excluding	cash	collateral,	and	the	reported	net	amounts	along	with where	they	appear	on	the	consolidated	balance	sheets	as	of	December	31,	2013	and	2012.

| (In	millions) | Asset | Liability | Net	Asset | Balance	Sheet	Location |
| :--- | :--- | :--- | :--- | :--- |
| Fair\tValue\tHedges |  |  |  |  |
| \t\t\t\t\tInterest\trate | $21 | \t $— \t $ | 21 | \t Other\tnoncurrent\tassets |
| \t\t\t\t\tForeign\tcurrency | 18 | — | 18 | \t Other\tcurrent\tassets |
| Total\tDesignated\tHedges | 39 | — | 39 |  |
| Not\tDesignated\tas\tHedges |  |  |  |  |
| \t\t\t\t\tCommodity | 52 | — | 52 | \t Other\tcurrent\tassets |
| Total\tNot\tDesignated\tas\tHedges | 52 | — | 52 |  |
| \t\t\t\t\tTotal | $91 | \t $— \t $ | 91 |  |

# Derivatives	Designated	as	Fair	Value	Hedges

The	following	table	presents	by	maturity	date,	information	about	our	interest	rate	swap	agreements	as	of	December	31,	2013,	including	the	weighted	average, London	Interbank	Offer	Rate	("LIBOR")-based,	floating	rate.

| Maturity	Dates | Aggregate	Notional	Amount	(in<br>millions) | Weighted	Average,	LIBOR-<br>Based,	Floating	Rate |
| :--- | :--- | :--- |
| October\t1,\t2017 | $600 | 4.65% |
| March\t15,\t2018 | $300 | 4.50% |

As	of	December	31,	2012,	we	had	multiple	interest	rate	swap	agreements	with	a	total	notional	amount	of	$600	million,	a	weighted	average,	LIBOR-based,	floating rate	of	4.70	percent	and	a	maturity	date	of	October	1,	2017.

In	connection	with	debt	retirements	in	February	and	March	2011,	we	settled	interest	rate	swaps	with	a	notional	amount	of	$1,450	million.	We recorded	 a	$29 million	gain,	which	reduced	the	loss	on	early	extinguishment	of	debt.

As	 of	December	31,	2013	 and	2012,	our	foreign	currency	forwards	had	an	aggregate	notional	amount	of	2,387	million	 and	3,043	million	Norwegian	Kroner	at weighted	average	forward	rates	of	6.060	 and	5.780.	These	forwards	hedge	our	current	Norwegian	tax	liability	and	those	outstanding	at	December	31,	2013	have settlement	dates	through	June	2014.

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

| (In	millions) | Income	Statement	Location | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- | :--- |
| Derivative |  |  |  |  |
| Interest\trate | Net\tinterest\tand\tother | $(13) | \t $16 | \t $28 |
| Interest\trate | Loss\ton\tearly\textinguishment\tof\tdebt | — | — | 29 |
| Foreign\tcurrency | Provision\tfor\tincome\ttaxes | (44) | (1) | — |
| Hedged\tItem |  |  |  |  |
| Long-term\tdebt | Net\tinterest\tand\tother | $13 | \t $(16) | \t $(28) |
| Long-term\tdebt | Loss\ton\tearly\textinguishment\tof\tdebt | — | — | (29) |
| Accrued\ttaxes | Provision\tfor\tincome\ttaxes | 44 | 1 | — |

# 	Derivatives	Not	Designated	as	Hedges

In	August	2012,	we	entered	into	crude	oil	derivative	instruments	related	to	a	portion	of	our	forecasted	North	America	E&P	crude	oil	sales.	These	commodity derivatives	were	not	designated	as	hedges	and	had	terms	that	ended	in	December	2013.

The	impact	of	all	commodity	derivative	instruments	not	designated	as	hedges	appears	in	sales	and	other	operating	revenues	in	our	consolidated	statements	of	income and	were	a	net	loss	of	$67	million	in	2013	and	net	gains	of	$70	million	and	$5	million	in	2012	and	2011.

# Short-term	debt

As	of	December	31,	2013,	we	had	no	borrowings	against	our	revolving	credit	facility,	as	described	below,	and	we	had	$135	million	in	commercial	paper	outstanding under	our	U.S.	commercial	paper	program	that	is	backed	by	the	revolving	credit	facility.

Our	$2.5	billion	unsecured	five-year	revolving	credit	facility	(the	"Credit	Facility")	was	entered	in	April	2012.		The	Credit	Facility	matures	in	April	2017,	but	allows us	to	request	two	one-year	extensions.			It	contains	an	option	to	increase	the	commitment	amount	by	up	to	an	additional	$1.0	billion,	subject	to	the	consent	of	any increasing	lenders,	and	includes	sub-facilities	for	swing-line	loans	and	letters	of	credit	up	to	an	aggregate	amount	of	$100	million	and	$500	million,	respectively.		The agreement	contains	a	covenant	that	requires	our	ratio	of	total	debt	to	total	capitalization	not	to	exceed	65	percent	as	of	the	last	day	of	each	fiscal	quarter.		If	an	event	of default	occurs,	the	lenders	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.

# Long-term	debt

The	following	table	details	our	long-term	debt:

|  | December	31, |  |
| :--- | :--- | :--- |
| (In\tmillions) | 2013 | 2012 |
| Senior\tunsecured\tnotes: |  |  |
| 9.125%\tnotes\tdue\t2013 | $— | $114 |
| 0.900%\tnotes\tdue\t2015(a) | 1,000 | 1,000 |
| 6.000%\tnotes\tdue\t2017(a) | 682 | 682 |
| 5.900%\tnotes\tdue\t2018(a) | 854 | 854 |
| 7.500%\tnotes\tdue\t2019(a) | 228 | 228 |
| \t2.800%\tnotes\tdue\t2022(a) | 1,000 | 1,000 |
| 9.375%\tnotes\tdue\t2022 | 32 | 32 |
| Series\tA\tnotes\tdue\t2022 | 3 | 3 |
| 8.500%\tnotes\tdue\t2023 | 70 | 70 |
| 8.125%\tnotes\tdue\t2023 | 131 | 131 |
| 6.800%\tnotes\tdue\t2032(a) | 550 | 550 |
| 6.600%\tnotes\tdue\t2037 | 750 | 750 |
| Capital\tleases: |  |  |
| Capital\tlease\tobligation\tof\tconsolidated\tsubsidiary\tdue\t2014\t–\t2049 | 10 | 11 |
| Other\tobligations: |  |  |
| 4.550%\tpromissory\tnote,\tsemi-annual\tpayments\tdue\t2014\t–\t2015 | 136 | 204 |
| 5.125%\tobligation\trelating\tto\trevenue\tbonds\tdue\t2037 | 1,000 | 1,000 |
| Other | — | 35 |
| Total(b) | 6,446 | 6,664 |
| Unamortized\tdiscount | (9) | (11) |
| Fair\tvalue\tadjustments(c) | 25 | 43 |
| Amounts\tdue\twithin\tone\tyear | (68) | (184) |
| Total\tlong-term\tdebt\tdue\tafter\tone\tyear | $6,394 | $6,512 |

(a) These	notes	contain	a	make-whole	provision	allowing	us	the	right	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,	2013,	may	be	declared	immediately	due	and	payable.

(c) See	Notes	15	and	16	for	information	on	interest	rate	swaps.

The	following	table	shows	five	years	of	long-term	debt	payments:

# (In	millions)

The	following	summarizes	the	changes	in	asset	retirement	obligations:

# 20.	Defined	Benefit	Postretirement	Plans	and	Defined	Contribution	Plan

We	have	noncontributory	defined	benefit	pension	plans	covering	substantially	all	domestic	employees	as	well	as	international	employees	located	in	Norway	and	the U.K.	Benefits	under	these	plans	are	based	on	plan	provisions	specific	to	each	plan.

We	also	have	defined	benefit	plans	for	other	postretirement	benefits	covering	our	U.S.	employees.	Health	care	benefits	are	provided	 through	comprehensive hospital,	surgical	and	major	medical	benefit	provisions	subject	to	various	cost-sharing	features.	Life	insurance	benefits	are	provided	to	certain	retiree	beneficiaries.	Other postretirement	benefits	are	not	funded	in	advance.

Obligations	and	funded	status	–	The	accumulated	benefit	obligation	for	all	defined	benefit	pension	plans	was	$1,359	million	and	$1,442	million	as	of	December	31, 2013	and	2012.

As	 of	December	31,	2013,	our	U.S.	plans	had	accumulated	benefit	obligations	in	excess	of	plan	assets,	and	as	of	December	31,	2012,	our	U.S.	plans	and	our international	("Int'l")	plans	had	accumulated	benefit	obligations	in	excess	of	plan	assets.	Summary	information	for	these	defined	benefit	pension	plans	follows.

|  | 2013 |  | 2012 |  | Other	Benefits |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | U.S. | Int'l | U.S. | Int'l | 2013 | 2012 |
| Change\tin\tbenefit\tobligations: |  |  |  |  |  |  |
| Beginning\tbalance | $1,146 | $565 | $986 | $465 | $311 | $301 |
| Service\tcost | 33 | 22 | 31 | 19 | 4 | 4 |
| Interest\tcost | 40 | 24 | 42 | 22 | 12 | 14 |
| Actuarial\tloss\t(gain) | (140) | 40 | 196 | 49 | (31) | 8 |
| Foreign\tcurrency\texchange\trate\tchanges | — | 11 | — | 25 | — | — |
| Benefits\tpaid | (146) | (13) | (109) | (15) | (17) | (16) |
| Ending\tbalance | $933 | $649 | $1,146 | $565 | $279 | $311 |
| Change\tin\tfair\tvalue\tof\tplan\tassets: |  |  |  |  |  |  |
| Beginning\tbalance | $630 | $500 | $516 | $412 | $— | $— |
| Actual\treturn\ton\tplan\tassets | 65 | 74 | 66 | 57 | — | — |
| Employer\tcontributions | 76 | 23 | 157 | 24 | — | — |
| Foreign\tcurrency\texchange\trate\tchanges | — | 13 | — | 22 | — | — |
| Benefits\tpaid | (146) | (13) | (109) | (15) | — | — |
| Ending\tbalance | $625 | $597 | $630 | $500 | $— | $— |
| Funded\tstatus\tof\tplans\tat\tDecember\t31 | $(308) | $(52) | $(516) | $(65) | $(279) | $(311) |
| Amounts\trecognized\tin\tthe\tconsolidated\tbalance\tsheets: |  |  |  |  |  |  |
| Current\tliabilities | (16) | — | (17) | — | (19) | (19) |
| Noncurrent\tliabilities | (292) | (52) | (499) | (65) | (260) | (292) |
| Accrued\tbenefit\tcost | $(308) | $(52) | $(516) | $(65) | $(279) | $(311) |
| Pretax\tamounts\tin\taccumulated\tother\ncomprehensive\tloss: |  |  |  |  |  |  |
| Net\tloss\t(gain) | $262 | $59 | $511 | $74 | $(8) | $23 |
| Prior\tservice\tcost\t(credit) | 15 | 9 | 21 | 10 | (5) | (11) |

# Components	of	net	periodic	benefit	cost	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.

|  | 2013 |  | 2012 |  | 2011 |  |  | Other	Benefits |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | U.S. | Int'l | U.S. | Int'l | U.S. | Int'l | 2013 | 2012 | 2011 |
| Components\tof\tnet\tperiodic\tbenefit\tcost: |  |  |  |  |  |  |  |  |  |
| Service\tcost | $33 | $22 | $31 | $19 | $28 | $19 | $4 | $4 | $4 |
| Interest\tcost | 40 | 24 | 42 | 22 | 44 | 22 | 12 | 14 | 16 |
| Expected\treturn\ton\tplan\tassets | (43) | (24) | (43) | (22) | (43) | (23) | — | — | — |
| Amortization: |  |  |  |  |  |  |  |  |  |
| -\tprior\tservice\tcost\t(credit) | 6 | 1 | 7 | 1 | 6 | — | (6) | (7) | (7) |
| -\tactuarial\tloss | 43 | 4 | 48 | 4 | 47 | 2 | — | — | — |
| Net\tsettlement\tloss(a) | 45 | — | 45 | — | 30 | — | — | — | — |
| Net\tperiodic\tbenefit\tcost(b) | $124 | $27 | $130 | $24 | $112 | $20 | $10 | $11 | $13 |
| Other\tchanges\tin\tplan\tassets\tand\tbenefit\tobligations\trecognized\nin\tother\tcomprehensive\t(income)\tloss\t(pretax): |  |  |  |  |  |  |  |  |  |
| Actuarial\tloss\t(gain) | $(161) | $(11) | $172 | $15 | $97 | $24 | $(31) | $7 | $1 |
| Amortization\tof\tactuarial\t(loss)\tgain | (88) | (4) | (93) | (4) | (77) | (2) | — | — | — |
| Prior\tservice\tcost\t(credit) | — | — | — | 1 | — | (11) | — | — | — |
| Amortization\tof\tprior\tservice\tcredit\t(cost) | (6) | (1) | (7) | (1) | (6) | — | 6 | 7 | 7 |
| Spin-off\tdownstream\tbusiness\t(c) | — | — | — | — | (24) | — | — | — | — |
| Total\trecognized\tin\tother\tcomprehensive\t(income)\tloss | $(255) | $(16) | $72 | $11 | $(10) | $11 | $(25) | $14 | $8 |
| Total\trecognized\tin\tnet\tperiodic\tbenefit\tcost\tand\tother\ncomprehensive\t(income)\tloss | $(131) | $11 | $202 | $35 | $102 | $31 | $(15) | $25 | $21 |

(a) 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.	Such	settlements	occurred	in	one	or	more	of	our U.S.	plans	in	2013,	2012	and	2011.

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

(c) Includes	net	inter-company	transfers	of	(gains)/losses	due	to	the	spin-off	of	the	downstream	business.

The	estimated	net	loss	and	prior	service	cost	for	our	defined	benefit	pension	plans	that	will	be	amortized	from	accumulated	other	comprehensive	loss	into	net periodic	benefit	cost	in	2014	are	$24	million	and	$6	million.	The	estimated	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	2014	is	$5	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	2013,	2012	and	2011.

|  | 2013 |  | 2012 |  | 2011 |  |  | Other	Benefits |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | U.S. | Int'l | U.S. | Int'l | U.S. | Int'l | 2013 | 2012 | 2011 |
| Weighted\taverage\tassumptions\tused\tto\tdetermine\tbenefit\nobligation: |  |  |  |  |  |  |  |  |  |
| Discount\trate | 4.28% | 4.60% | 3.44% | 4.40% | 4.45% | 4.70% | 4.85% | 4.06% | 4.90% |
| Rate\tof\tcompensation\tincrease | 5.00% | 4.90% | 5.00% | 4.50% | 5.00% | 4.30% | 5.00% | 5.00% | 5.00% |
| Weighted\taverage\tassumptions\tused\tto\tdetermine\tnet\nperiodic\tbenefit\tcost: |  |  |  |  |  |  |  |  |  |
| Discount\trate | 3.79% | 4.40% | 4.21% | 4.70% | 5.05% | 5.40% | 4.06% | 4.90% | 5.55% |
| Expected\tlong-term\treturn\ton\tplan\tassets | 7.25% (a) | 4.90% | 7.75% | 5.20% | 8.50% | 5.86% | — | — | — |
| Rate\tof\tcompensation\tincrease | 5.00% | 4.50% | 5.00% | 4.30% | 5.00% | 5.10% | 5.00% | 5.00% | 5.00% |

(a) Effective	January	1,	2014,	the	expected	long-term	return	on	U.S.	plan	assets	was	changed	from	 7.25	percent	to	6.75	percent.

# Expected	long-term	return	on	plan	assets

U.S.	plan	–	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.	The	tool	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	derive	an	expected	long-term	rate	of	return	on	those	assets.	Capital	market	assumptions	reflect	the	long-term	capital	market outlook.	The	assumptions	for	equity	and	fixed	income	investments	are	developed	using	a	building-block	approach,	reflecting	observable	inflation	information	and interest	 rate	 information	 available	 in	 the	 fixed	 income	 markets.	Long-term	 assumptions	 for	 other	 asset	 categories	 are	 based	 on	 historical	 results,	 current	 market characteristics	and	the	professional	judgment	of	our	internal	and	external	investment	teams.

International	plans	–	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	in	our	international pension	plans	to	develop	the	overall	expected	long-term	return	on	plan	assets	assumption.

# Assumed	health	care	cost	trend	rates

(a) An	employee	group	waiver	plan	("EGWP")	is	a	group	Medicare	Part	D	prescription	drug	plan.	Effective	January	1,	2013,	we	implemented	the	EGWP	as	a	result	of	the	Patient	Protection	and Affordable	Care	Act,	which	ended	tax-free	status	of	retiree	drug	subsidy	programs	but	increased	federal	funding	to	Part	D	prescription	drug	plans.

Assumed	health	care	cost	trend	rates	have	a	significant	effect	on	the	amounts	reported	for	defined	benefit	retiree	health	care	plans.	A	one-percentage-point	change	in assumed	health	care	cost	trend	rates	would	have	the	following	effects:

| (In	millions) | 1-Percentage-<br>Point	Increase | 1-Percentage-<br>Point	Decrease |
| :--- | :--- | :--- |
| Effect\ton\ttotal\tof\tservice\tand\tinterest\tcost\tcomponents | $2 | $(2) |
| Effect\ton\tother\tpostretirement\tbenefit\tobligations | $30 | $(25) |

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	 the	 legal requirements	of	all	applicable	laws;	(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	plans'	investment	committees	and	protecting	the	assets	from	any	erosion	of	purchasing	power;	and	(3)	position	the	portfolios	with	a	long-term risk/return	orientation.

U.S.	plan	–	Historical	performance	and	future	expectations	suggest	that	common	stocks	will	provide	higher	total	investment	returns	than	fixed	income	securities over	a	long-term	investment	horizon.	Short-term	investments	are	utilized	for	pension	payments,	expenses,	and	other	liquidity	needs.	However,	to	reduce	volatility	in returns	and	to	better	match	the	plan's	liabilities	over	time,

as	the	plan's	funded	ratio	(as	defined	by	the	investment	policy)	improves,	the	allocation	to	equity	securities	will	decrease	while	the	amount	allocated	to	fixed	income securities	will	increase.	As	such,	the	plan's	current	targeted	asset	allocation	is	comprised	of	55	percent	equity	securities	and	high-yield	bonds	and	45	percent	other	fixed income	securities.

The	plan's	assets	are	managed	by	a	third-party	investment	manager.	The	investment	manager	is	limited	to	pursuing	the	investment	strategies	regarding	asset	mix	and purchases	and	sales	of	securities	within	the	parameters	defined	in	the	investment	policy	guidelines	and	investment	management	agreement.	Investment	performance	and risk	is	measured	and	monitored	on	an	ongoing	basis	through	quarterly	investment	meetings	and	periodic	asset	and	liability	studies.

International	plans	–	Our	international	plans'	target	asset	allocation	is	comprised	of	70	percent	equity	securities	and	30	percent	fixed	income	securities.	The	plan assets	are	invested	in	eleven	separate	portfolios,	mainly	pooled	fund	vehicles,	managed	by	several	professional	investment	managers.	Investments	are	diversified	by industry	and	type,	limited	by	grade	and	maturity.	The	use	of	derivatives	by	the	investment	managers	is	permitted,	subject	to	strict	guidelines.	The	investment	managers' performance	is	measured	independently	by	a	third-party	asset	servicing	consulting	firm.	Overall,	investment	performance	and	risk	is	measured	and	monitored	on	an ongoing	basis	through	quarterly	investment	portfolio	reviews	and	periodic	asset	and	liability	studies.

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,	2013	and	2012.

Cash	and	cash	equivalents	–	Cash	and	cash	equivalents	include	cash	on	deposit	and	an	investment	in	a	money	market	mutual	fund	that	invests	mainly	in	short-term instruments	and	cash,	both	of	which	are	valued	using	a	market	approach	and	are	considered	Level	1.	The	money	market	mutual	fund	is	valued	at	the	net	asset	value ("NAV")	of	shares	held.	Cash	and	cash	equivalents	also	include	a	cash	reserve	account	(a	collective	short-term	investment	fund)	that	is	valued	using	an	income	approach and	is	considered	Level	2.	The	underlying	assets	are	usually	short-term	bonds,	discount	notes,	and	commercial	paper.

Equity	securities	–	Investments	in	common	stock,	preferred	stock,	and	real	estate	investment	trusts	("REIT")	are	valued	using	a	market	approach	at	the	closing	price reported	 in	 an	 active	 market	 and	 are	 therefore	 considered	 Level	 1.	The	non-public	 investment	 trust	 is	valued	using	a	market	approach	based	on	 the	underlying investments	in	the	trust,	which	are	publicly-traded	securities,	and	is	considered	Level	2.	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,	determined	using	a	combination	of	market,	 income	and	cost approaches,	plus	working	capital,	adjusted	for	liabilities,	currency	translation	and	estimated	performance	incentives.	These	private	equity	investments	are	considered Level	3.

Mutual	funds	–	Investments	in	mutual	funds	are	valued	using	a	market	approach.	The	shares	or	units	held	are	traded	on	the	public	exchanges	and	such	prices	are Level	1	inputs.

Pooled	funds	–	Investments	in	pooled	funds	are	valued	using	a	market	approach	at	the	NAV	of	units	held,	but	investment	opportunities	in	such	funds	are	limited	to institutional	 investors	on	 the	behalf	of	defined	benefit	plans.	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	are	valued	at	the	closing	price reported	in	an	active	market,	and	are	considered	Level	1.	Treasury	inflation-protected	securities	("TIPS")	are	valued	at	the	daily	closing	price	reported	in	an	active market.	TIPS	prices	exclude	adjustment	factors	for	inflation	and	are	considered	Level	1.	Corporate	bonds,	non-U.S.	government	bonds,	private	placements,	and	yankee bonds	are	valued	using	calculated	yield	curves	created	by	models	that	incorporate	factors	such	as	interest	rate,	benchmark	quotes,	trade	data,	dealer	quotes,	primary	and secondary	 market	 spread	 activity,	 and	 other	 market	 information	 and	 are	 considered	 Level	 2.	Taxable	 municipal	 bonds	 are	 valued	 using	 calculated	 yield	 curves considering	market	factors	such	as	benchmark	issues,	trades,	trading	spreads	between	similar	issuers	or	creditors,	historical	trading	spreads	over	widely	accepted	market benchmarks,	and	verified	bid	information.	These	assets	are	considered	Level	2.	Municipal	bonds	are	valued	by	an	evaluation	of	terms	and	conditions	of	the	security	and considering	market	factors	such	as	benchmark	curves,	trades,	bid	price	or	spreads,	two-sided	markets,	and	quotes.	These	assets	are	considered	Level	2.	The	investment	in the	commingled	fund	is	valued	using	the	NAV	of	units	held,	and	is	considered	Level	2.	The	commingled	fund	consists	mostly	of	high-yield	U.S.	and	non-U.S.	corporate bonds.	Investment	opportunities	in	this	fund	are	limited	to	qualified	retirement	plans	and	their	plan	participants.	The	investment	objective	of	the	portfolio	is	to	provide long-term	total	return	in	excess	of	the	Barclays	U.S.	High	Yield	Bond	Index.

Real	estate	–	Real	estate	investments	are	valued	using	a	combination	of	the	income	and	market	approaches	that	is	based	on	discounted	cash	flows,	comparable sales,	outside	appraisals,	price	per	square	foot	or	some	combination	thereof	and	therefore	are	considered	Level	3.

Other	–	Other	investments	are	composed	of	an	investment	in	an	unallocated	annuity	contract,	an	investment	contract	with	an	international	insurance	carrier,	and investments	in	two	limited	liability	companies	("LLCs")	with	no	public	market.	The	LLCs	were	formed	to	acquire	timberland	in	the	northwest	and	other	properties.	The investment	in	an	unallocated	annuity	contract	is	valued	using	a	market	approach	based	on	the	experience	of	the	assets	held	in	an	insurer's	general	account.	The	majority of	the	general	account	is	invested	in	a	well-diversified	portfolio	of	high-quality	fixed	income	securities,	primarily	consisting	of	investment-grade	bonds.	Investment income	is	allocated	among	pension	plans	participating	in	the	general	account	based	on	the	investment	year	method.	Under	this	method,	a	record	of	the	book	value	of assets	held	is	maintained	in	subdivisions	according	to	the	calendar	year	in	which	the	funds	are	invested.	The	earnings	rate	for	each	of	these	calendar	year	subdivisions varies	from	year	to	year,	reflecting	the	actual	earnings	on	the	assets	attributed	to	that	year.	Due	to	the	lack	of	transparency	in	the	use	of	investment	year	subdivisions,	this asset	is	considered	Level	3.	The	insurance	carrier	contract	is	funded	by	premiums	paid	annually	by	the	participating	plans	and	the	funds	are	invested	by	the	insurance carrier	in	portfolios	with	different	risk	profiles	(low,	medium,	high)	that	can	be	elected	by	clients.	The	majority	of	the	underlying	investments	consists	of	a	well- diversified	mix	of	non-U.S.	publicly	traded	equity	securities	valued	at	the	closing	price	reported	in	an	active	market	and	fixed	income	securities	valued	using	calculated yield	curves.	This	asset	is	considered	Level	2.	The	values	of	the	LLCs	are	determined	using	a	cost	approach	based	on	historical	cost	less	depletion	for	timber	previously harvested.	These	assets	are	considered	Level	3.

The	following	tables	present	the	fair	values	of	our	defined	benefit	pension	plans'	assets,	by	level	within	the	fair	value	hierarchy,	as	of	December	31,	2013	and	2012.

| (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 | $19 | $1 | $1 | $— | $— | $— | $20 | $1 |
| Equity\tsecurities: |  |  |  |  |  |  |  |  |
| Common\tstock(a) | 288 | — | — | — | — | — | 288 | — |
| Preferred\tstock | 4 | — | — | — | — | — | 4 | — |
| Private\tequity | — | — | — | — | 23 | — | 23 | — |
| REIT | 2 | — | — | — | — | — | 2 | — |
| Mutual\tfunds(b) | — | 219 | — | — | — | — | — | 219 |
| Pooled\tfunds(c) | — | — | — | 186 | — | — | — | 186 |
| Fixed\tincome\tsecurities: |  |  |  |  |  |  |  |  |
| U.S.\ttreasury\tnotes | 63 | — | — | — | — | — | 63 | — |
| Exchange\ttraded\tfunds | 1 | — | — | — | — | — | 1 | — |
| Corporate\tbonds(d) | — | — | 127 | — | — | — | 127 | — |
| Municipal\tbonds | — | — | 1 | — | — | — | 1 |  |
| Non-U.S.\tgovernment\tbonds | — | — | 7 | — | — | — | 7 | — |
| Private\tplacements | — | — | 21 | — | — | — | 21 | — |
| Taxable\tmunicipal\tbonds | — | — | 13 | — | — | — | 13 | — |
| Treasury\tinflation-protected\tsecurities | 1 | — | — | — | — | — | 1 | — |
| Yankee\tbonds | — | — | 3 | — | — | — | 3 | — |
| Commingled\tfund(e) | — | — | 17 | — | — | — | 17 | — |
| Pooled\tfunds(f) | — | — | — | 178 | — | — | — | 178 |
| Real\testate(g) | — | — | — | — | 22 | — | 22 | — |
| Other | — | — | — | 13 | 12 | — | 12 | 13 |
| Total\tinvestments,\tat\tfair\tvalue | $378 | $220 | $190 | $377 | $57 | $— | $625 | $597 |

| (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 | $16 | $1 | $1 | $— | $— | $— | $17 | $1 |
| Equity\tsecurities: |  |  |  |  |  |  |  |  |
| \t\tCommon\tstock(a) | 312 | — | — | — | — | — | 312 | — |
| \t\tPrivate\tequity | — | — | — | — | 25 | — | 25 | — |
| \t\tREIT | 2 | — | — | — | — | — | 2 | — |
| Investment\ttrust | — | — | 1 | — | — | — | 1 | — |
| Mutual\tfunds(b) | — | 171 | — | — | — | — | — | 171 |
| Pooled\tfunds(c) | — | — | — | 152 | — | — | — | 152 |
| Fixed\tincome\tsecurities: |  |  |  |  |  |  |  |  |
| U.S.\ttreasury\tnotes | 67 | — | — | — | — | — | 67 | — |
| Exchange\ttraded\tfunds | 8 | — | — | — | — | — | 8 | — |
| Corporate\tbonds(d) | — | — | 96 | — | — | — | 96 | — |
| Non-U.S.\tgovernment\tbonds | — | — | 5 | — | — | — | 5 | — |
| Private\tplacements | — | — | 18 | — | — | — | 18 | — |
| Taxable\tmunicipal\tbonds | — | — | 14 | — | — | — | 14 | — |
| Yankee\tbonds | — | — | 2 | — | — | — | 2 | — |
| Commingled\tfund(e) | — | — | 28 | — | — | — | 28 | — |
| Pooled\tfunds(f) | — | — | — | 166 | — | — | — | 166 |
| Real\testate(g) | — | — | — | — | 23 | — | 23 | — |
| Other | — | — | — | 10 | 12 | — | 12 | 10 |
| Total\tinvestments,\tat\tfair\tvalue | $405 | $172 | $165 | $328 | $60 | $— | $630 | $500 |

(a) Includes	 approximately	60	 percent	 of	 investments	 held	 in	 U.S.	 and	 non-U.S.	 common	 stocks	 in	 the	 banking,	 pharmaceuticals,	 oil	 and	 gas,	 insurance,	 telecommunications, electric, aerospace/defense,	retail,	transportation,	food	processing,	semiconductors,	and	chemicals	sectors.	The	remaining	40	percent	of	common	stock	is	held	in	various	other	sectors.

(b) Includes	approximately	75	percent	of	investments	held	in	U.S.	and	non-U.S.	common	stocks	in	the	consumer	staples,	financial	services,	health	care,	energy,	basic	materials,	leisure,	and	industrial goods	and	services	sectors	and	25	percent	of	investments	held	among	various	other	sectors.	The	funds'	objective	is	to	outperform	their	respective	benchmark	indexes,	FTSE	ALL	Share	5% Capped	Index	and	MSCI	World	Index,	as	defined	by	the	investment	policy.

(c) Includes	approximately	80	percent	of	investments	held	in	non-U.S.	publicly	traded	common	stocks	(specifically	Asia	Pacific,	except	Japan,	and	the	U.K.)	in	the	financial,	consumer	staples, information	technology,	materials,	energy,	industrials,	and	telecommunication	services	sectors	and	the	remaining	20	percent	of	investments	held	among	various	other	sectors.	The	funds'	objective is	to	outperform	their	respective	benchmark	indexes,	MSCI	AC	Asia	Pacific	ex	Japan	Index,	FTSE	Small	Cap	Index,	and	MSCI	Emerging	Markets	Index,	as	defined	by	the	investment	policy.

(d) Includes	approximately	70	percent	of	U.S.	and	non-U.S.	corporate	bonds	in	the	banking	and	finance,	utilities,	oil	and	gas,	news/media,	and	health	care	sectors.	The	remaining	 30	percent	of corporate	bonds	are	in	various	other	sectors.

(e) Includes	approximately	90	percent	of	investments	held	in	U.S.	and	non-U.S.	corporate	bonds	in	the	consumer	discretionary,	financial,	industrial,	telecommunication	services,	energy,	health	care, information	technology	and	materials	sectors	and	10	percent	of	investments	held	among	various	other	sectors.

(f) Includes	 approximately	75	percent	of	 investments	held	 in	U.S.	and	non-U.S.	publicly	 traded	 investment	grade	government	and	corporate	bonds	which	 include	gilts,	 treasuries,	financial, corporates,	and	collateralized	asset	backed	securities	and	25	percent	of	investments	held	among	various	other	sectors.	The	funds'	objective	is	to	outperform	their	respective	benchmark	indexes,	as defined	by	the	investment	policy.

(g) Includes	investments	diversified	by	property	type	and	location.	The	largest	property	sector	holdings,	which	represent	approximately	 70	percent	of	investments	held,	are	office,	hotel,	residential, and	retail	with	the	greatest	percentage	of	investments	made	in	the	U.S.	and	Asia,	which	includes	the	emerging	markets	of	China	and	India.

	The	following	is	a	reconciliation	of	the	beginning	and	ending	balances	recorded	for	plan	assets	classified	as	Level	3	in	the	fair	value	hierarchy.

| (In	millions) | Private<br>Equity | Real<br>Estate | Other | Total |
| :--- | :--- | :--- | :--- | :--- |
| Beginning\tbalance | $25 | \t $23 | \t $12 | \t $60 |
| Actual\treturn\ton\tplan\tassets: |  |  |  |  |
| Realized\tgain | 6 | 1 | — | 7 |
| Unrealized\tgain\t(loss) | (1) | 1 | — | — |
| Purchases | 6 | 1 | — | 7 |
| Sales | (13) | (4) | — | (17) |
| Ending\tbalance | $23 | \t $22 | \t $12 | \t $57 |

| (In	millions) | Private<br>Equity | Real<br>Estate | Other | Total |
| :--- | :--- | :--- | :--- | :--- |
| Beginning\tbalance | $23 | \t $21 | \t $14 | \t $58 |
| Actual\treturn\ton\tplan\tassets: |  |  |  |  |
| Realized\tgain | 2 | — | — | 2 |
| Unrealized\tgain\t(loss) | 1 | 1 | (2) | — |
| Purchases | 4 | 3 | — | 7 |
| Sales | (5) | (2) | — | (7) |
| Ending\tbalance | $25 | \t $23 | \t $12 | \t $60 |

Estimated	future	benefit	payments	–	The	following	gross	benefit	payments,	which	were	estimated	based	on	actuarial	assumptions	applied	at	December	31,	2013	and reflect	expected	future	services,	as	appropriate,	are	to	be	paid	in	the	years	indicated.

|  | Pension	Benefits |  | Other |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | U.S. | Int'l | Benefits |
| 2014(a) | $96 | $14 | $19 |
| 2015 | 94 | 14 | 20 |
| 2016 | 95 | 16 | 20 |
| 2017 | 96 | 18 | 20 |
| 2018 | 92 | 21 | 20 |
| 2019\tthrough\t2023 | 368 | 120 | 98 |

(a) Primarily	as	a	result	of	retirements	effective	January	1,	2014,	actual	2014	U.S.	gross	benefit	payments	will	exceed	the	actuarial	estimate	above,	including	approximately	$163	million	which	will be	paid	during	the	first	quarter	of	2014.

Contributions	to	defined	benefit	plans	–	We	expect	to	make	contributions	to	the	funded	pension	plans	of	up	to	$77	million	in	2014,	and	$11	million	of	that	amount was	paid	in	January	2014.	Cash	contributions	to	be	paid	from	our	general	assets	for	the	unfunded	pension	and	postretirement	plans	are	expected	to	be	approximately	$74 million	and	$19	million	in	2014.

Contributions	to	defined	contribution	plan	–	We	contribute	to	a	defined	contribution	plan	for	eligible	employees.	Contributions	to	this	plan	totaled	$26	million,	$25 million	and	$21	million	in	2013,	2012	and	2011.

# 21.	Incentive	Based	Compensation

Description	of	stock-based	compensation	plans	–	The	Marathon	Oil	Corporation	2012	Incentive	Compensation	Plan	(the	"2012	Plan")	was	approved	by	our stockholders	in	April	2012	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	awards	to	employees.	The	2012	Plan	also	allows	us	to	provide	equity	compensation	to	our	non-employee	directors.	No more	than	50	million	shares	of	our	common	stock	may	be	issued	under	the	2012	Plan.	For	stock	options	and	SARs,	the	number	of	shares	available	for	issuance	under the	2012	Plan	will	be	reduced	by	one	share	for	each	share	of	our	common	stock	in	respect	of	which

the	award	is	granted.	For	awards	other	than	stock	options	or	SARs,	the	number	of	shares	available	for	issuance	under	the	2012	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	2012	Plan	that	are	forfeited,	are	terminated	or	expire	unexercised	become	available	for	future	grants.	In	addition,	the	number	of shares	of	our	common	stock	reserved	for	issuance	under	the	2012	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	2012	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	2012	Plan,	no	new	grants	were	or	will	be	made	from	the	2007	Incentive	Compensation	Plan,	the	2003	Incentive	Compensation	Plan	(the	"2003 Plan"),	the	Non-Employee	Director	Stock	Plan	and	the	deferred	stock	benefit	provision	of	the	Deferred	Compensation	Plan	for	Non-Employee	Directors	(collectively, the	"Prior	Plans").	Any	awards	previously	granted	under	the	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	2012	Plan	and	previously	granted	stock	options	under	certain	of	the	Prior	Plans.	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.

Stock	appreciation	rights	–	Prior	to	2005,	we	granted	SARs	under	the	2003	Plan.	No	SARs	have	been	granted	since	then.	SARs	represent	the	right	to	receive	shares of	common	stock	equal	in	value	to	the	excess	of	the	fair	market	value	of	shares	of	common	stock	on	the	date	the	right	is	exercised	over	the	grant	price.	In	general,	SARs vested	ratably	over	a	three-year	period	and	have	a	maximum	term	of	ten	years	from	the	date	they	were	granted.

Restricted	stock	–	We	grant	restricted	stock	and	restricted	stock	units	(collectively,	"restricted	stock	awards")	under	the	2012	Plan	and	previously	granted	such awards	under	certain	of	the	Prior	Plans.	The	restricted	stock	awards	granted	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	and	restricted	stock	units	to	certain	international	employees,	based	on	their performance	within	certain	guidelines	and	for	retention	purposes.	The	restricted	stock	awards	to	non-officers	generally	vest	in	one-third	increments	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	are	not	transferable	and	are	held	by	our	transfer	agent.

Stock-based	performance	units	–	Beginning	in	2013,	we	grant	stock-based	performance	units	to	officers	under	the	2012	Plan.	At	the	grant	date,	each	unit	represents the	value	of	one	share	of	our	common	stock.	These	units	provide	a	cash	payout,	based	on	the	value	of	anywhere	from	zero	to	two	times	the	number	of	units	granted, upon	the	achievement	of	certain	performance	goals	at	the	end	of	a	36-month	performance	period.	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	the	Board	of	Directors.	Dividend	equivalents	accrue	during	the performance	period	and	are	paid	in	cash	at	the	end	of	the	performance	period	based	on	the	number	of	shares	that	would	represent	the	value	of	the	units.

Common	stock	units	–	We	maintain	an	equity	compensation	program	for	our	non-employee	directors	under	the	2012	Plan	and	previously	maintained	such	a program	under	certain	of	the	Prior	Plans.		All	non-employee	directors	receive	annual	grants	of	common	stock	units.		Those	units	granted	prior	to	2012	must	be	held until	completion	of	board	service,	at	which	time	the	non-employee	director	will	receive	common	shares.		Common	shares	will	be	issued	for	units	granted	on	or	after January	1,	2012	upon	completion	of	board	service	or	three	years	from	the	date	of	grant,	whichever	is	earlier.	When	dividends	are	paid	on	our	common	stock,	directors receive	dividend	equivalents	in	the	form	of	additional	common	stock	units.

Total	stock-based	compensation	expense	–	Total	employee	stock-based	compensation	expense	was	$75	million,	$70	million	and	$65	million	 in	2013,	2012	and 2011,	while	the	total	related	income	tax	benefits	were	$27	million,	$25	million	and	$23	million	in	the	same	years.	In	2013,	2012	and	2011,	cash	received	upon	exercise of	stock	option	awards	was	$58	million,	$41	million	and	$77	million.	Tax	benefits	realized	for	deductions	for	stock	awards	exercised	during	2013,	2012	and	2011	totaled $36	million,	$24	million	and	$32	million.

	Stock	option	awards	–	During	2013,	2012	and	2011,	we	granted	stock	option	awards	to	both	officer	and	non-officer	employees.	The	weighted	average	grant	date fair	value	of	these	awards	was	based	on	the	following	weighted	average	Black-Scholes	assumptions:

The	following	table	presents	information	related	to	stock	option	awards	at	December	31,	2013.

|  |  | Outstanding |  | Exercisable | Exercisable |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Range\tof\nExercise\nPrices | Number\nof\tShares\nUnder\tOption | Weighted\nAverage\nRemaining\nContractual\tLife | Weighted\nAverage\nExercise\tPrice | Number\nof\tShares\nUnder\tOption | Weighted\nAverage\nExercise\tPrice |
| $7.99-12.75 | 259,164 | 0.3\tyears | $10.53 | 259,164 | $10.53 |
| $12.76-16.81 | 1,937,181 | 3\tyears | $15.13 | 1,937,181 | $15.13 |
| $16.82-23.20 | 4,255,365 | 5\tyears | $18.57 | 4,255,365 | $18.57 |
| $23.21-29.24 | 1,740,398 | 4\tyears | $24.59 | 1,489,683 | $24.05 |
| $29.25-36.03 | 7,541,433 | 7\tyears | $33.06 | 3,967,422 | $32.70 |
| $36.04-46.41 | 2,371,346 | 3\tyears | $38.19 | 2,277,817 | $38.26 |
| Total | 18,104,887 | 5\tyears | $27.27 | 14,186,632 | $25.64 |

As	of	December	31,	2013,	the	aggregate	intrinsic	value	of	stock	option	awards	outstanding	was	$152	million.	The	aggregate	intrinsic	value	and	weighted	average remaining	contractual	life	of	stock	option	awards	currently	exercisable	were	$144	million	and	4	years.

As	of	December	31,	2013,	the	number	of	fully-vested	stock	option	awards	and	stock	option	awards	expected	to	vest	was	18,023,888.	The	weighted	average	exercise price	and	weighted	average	remaining	contractual	life	of	these	stock	option	awards	were	$27.24	and	5	years	and	the	aggregate	intrinsic	value	was	$152	million.	As	of December	31,	2013,	unrecognized	compensation	cost	related	to	stock	option	awards	was	$16	million,	which	is	expected	to	be	recognized	over	a	weighted	average	period of	2	years.

	Restricted	stock	awards	–	The	following	is	a	summary	of	restricted	stock	award	activity	in	2013.

|  | Awards | Weighted	Average<br>Grant	Date<br>Fair	Value |
| :--- | :--- | :--- |
| Unvested\tat\tbeginning\tof\tyear | 4,177,884 | $29.02 |
| Granted | 2,120,839 | $33.69 |
| Vested | (1,713,763) | $27.78 |
| Forfeited | (553,072) | $30.58 |
| Unvested\tat\tend\tof\tyear | 4,031,888 | $31.80 |

As	of	December	31,	2013,	there	was	$96	million	of	unrecognized	compensation	cost	related	to	restricted	stock	awards	which	is	expected	to	be	recognized	over	a weighted	average	period	of	2	years.

Stock-based	performance	unit	awards	–	During	2013,	we	granted	353,600	stock-based	performance	unit	awards	to	officers	and	at	December	31,	2013,	there	were 93,100	units	outstanding.	The	key	assumptions	used	in	the	Monte	Carlo	simulation	to	determine	the	December	31,	2013	fair	value	of	stock-based	performance	units were:

| Valuation	date	stock	price | $35.30 |
| :--- | :--- |
| Expected\tannual\tdividend\tyield | 2.1% |
| Expected\tvolatility | 26% |
| 2-Year\trisk-free\tinterest\trate | 0.4% |
| Fair\tvalue\tof\tstock-based\tperformance\tunits\toutstanding | $34.08 |

Cash-based	performance	unit	awards	 –	Prior to	2013,	cash-based	performance	unit	awards	were	granted	 to	officers	 that	provide	a	cash	payment	upon	 the achievement	of	certain	performance	goals	at	the	end	of	a	defined	measurement	period.	The	performance	goals	are	tied	to	our	TSR	as	compared	to	TSR	for	a	group	of peer	companies	determined	by	the	Compensation	Committee	of	the	Board	of	Directors.	The	target	value	of	each	performance	unit	is	$1,	with	a	maximum	payout	of	$2 per	unit,	but	the	actual	payout	could	be	anywhere	between	zero	and	the	maximum.	Because	performance	units	are	to	be	settled	in	cash	at	the	end	of	the	performance period,	they	are	accounted	for	as	liability	awards.

During	2012,	we	granted	12.7	million	performance	units,	all	having	a	36-month	 performance	 period.	During	the	third	quarter	of	2011,	we	granted	15	million performance	units,	a	portion	of	which	had	a	30-month	performance	period	and	a	portion	of	which	had	an	18-month	performance	period	to	reflect	the	remaining	periods of	the	original	2011	and	2010	performance	unit	grants	outstanding	prior	to	the	spin-off.	Compensation	expense	associated	with	cash-based	performance	units	was	$9 million,	$12	million	and	$32	million	in	2013,	2012	and	2011.	The	expense	for	2011	included	$14	million	paid	on	three	groups	of	performance	unit	grants	outstanding	at June	30,	2011,	that	were	accelerated	with	the	total	payout	determined	based	on	performance	through	the	effective	date	of	the	spin-off	of	our	downstream	business.

# 22.		Reclassifications	Out	of	Accumulated	Other	Comprehensive	Loss

The	following	table	presents	a	summary	of	amounts	reclassified	from	accumulated	other	comprehensive	loss	to	net	income	in	their	entirety:

| (In	millions) | 2013 | Income	Statement	Line |
| :--- | :--- | :--- |
| Accumulated\tOther\tComprehensive\tLoss\tComponents | Income\t(Expense) |  |
| Postretirement\tand\tpostemployment\tplans |  |  |
| Amortization\tof\tactuarial\tloss | $(47) | General\tand\tadministrative |
| Net\tsettlement\tloss | (45) | General\tand\tadministrative |
|  | 35 | Provision\tfor\tincome\ttaxes |
|  | (57) | Net\tof\ttax |
| Other\tinsignificant\titems,\tnet\tof\ttax | (1) |  |
| Total\treclassifications\tfor\tthe\tperiod | $(58) | Net\tincome |

# 23.	Stockholders'	Equity

Share	repurchase	plan	–	In	the	third	quarter	of	2013,	we	acquired	14	million	common	shares	at	a	cost	of	$500	million	under	our	share	repurchase	program, initially	authorized	in	2006,	bringing	our	total	repurchases	to	92	million	common	shares	at	a	cost	of	$3,722	million.	In	December	2013,	our	Board	of	Directors	increased the	authorization	by	an	additional	$1.2	billion,	bringing	the	total	remaining	share	repurchase	authorization	to	$2.5	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	 capital	 lease	 obligations	 and	 for	 operating	 lease	 obligations	 having noncancellable	lease	terms	in	excess	of	one	year	are	as	follows:

| (In	millions) | Capital<br>Lease<br>Obligations | Operating<br>Lease<br>Obligations |
| :--- | :--- | :--- |
| 2014 | $1 | $45 |
| 2015 | 1 | 42 |
| 2016 | 1 | 34 |
| 2017 | 1 | 22 |
| 2018 | 1 | 20 |
| Later\tyears | 23 | 48 |
| Sublease\trentals | — | (4) |
| Total\tminimum\tlease\tpayments | $28 | $207 |

Operating	lease	rental	expense	related	to	continuing	operations	was	$106	million,	$103	million	and	$70	million	in	2013,	2012	and	2011.

# 25.	Commitments	and	Contingencies

We	 are	 a	 defendant	 in	 a	 number	 of	 lawsuits	 arising	 in	 the	 ordinary	 course	 of	 business,	 including,	 but	 not	 limited	 to,	 royalty	 claims,	 contract	 claims	 and environmental	claims.	While	the	ultimate	outcome	and	impact	to	us	cannot	be	predicted	with	certainty,	we	believe	that	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.

Litigation	–	In	March	2011,	Noble	Drilling	(U.S.)	LLC	("Noble")	filed	a	lawsuit	against	us	in	the	District	Court	of	Harris	County,	Texas,	alleging,	among	other things,	breach	of	contract,	breach	of	the	duty	of	good	faith	and	fair	dealing,	and	negligent	misrepresentation,	relating	to	a	multi-year	drilling	contract	for	a	newly constructed	drilling	rig	to	be	deployed	in	the	U.S.	Gulf	of	Mexico.		We	filed	an	answer	in	April	2011,	contending,	among	other	things,	failure	to	perform,	failure	to comply	with	material	obligations,	failure	to	mitigate	alleged	damages	and	that	Noble	failed	to	provide	the	rig	according	to	the	operating,	performance	and	safety requirements	specified	in	the	drilling	contract.	In	April	2013,	we	filed	a	counterclaim	against	Noble	alleging,	among	other	things,	breach	of	contract	and	breach	of	the duty	of	good	faith	relating	to	the	multi-year	drilling	contract.	The	counterclaim	also	included	a	breach	of	contract	claim	for	reimbursement	for	the	value	of	fuel	used	by Noble	under	an	offshore	daywork	drilling	contract.	The	parties	settled	this	litigation	in	the	fourth	quarter	of	2013,	and	the	settlement	did	not	have	a	material	adverse effect	on	our	consolidated	results	of	operations,	financial	position	or	cash	flows.

	Environmental	matters	–	We	are	subject	to	federal,	state,	local	and	foreign	laws	and	regulations	relating	to	the	environment.	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,	2013	 and	2012,	 accrued	 liabilities	 for	 remediation	 were	 not	 significant.	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	guarantee	of	a	long-term	transportation	services	agreement	and	a	performance	guarantee	related	to	asset	retirement	obligations with	aggregate	maximum	potential	undiscounted	payments	totaling	$96	million	as	of	December	31,	2013.	Under	the	terms	of	these	guarantee	arrangements,	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,	2013	 and	2012,	contractual	commitments	to	acquire	property,	plant	and	equipment totaled	$1,270	million	and	$949 million.

Other	contingencies	–	During	the	second	quarter	of	2011,	the	AOSP	operator	determined	the	need	and	developed	preliminary	plans	to	address	water	flow	into	a previously	mined	and	contained	section	of	the	Muskeg	River	mine.	Our	share	of	the	estimated	costs	in	the	amount	of	$64	million	was	recorded	to	production	expense	in 2011.	At	December	31,	2013,	the	remaining	liability	is	$29	million.

# Select	Quarterly	Financial	Data	(Unaudited)

|  |  | 2013 |  |  |  | 2012 |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions,\texcept\tper\tshare\tdata) | 1st\tQtr. | 2nd\tQtr. | 3rd\tQtr. | 4th\tQtr. | 1st\tQtr. | 2nd\tQtr. | 3rd\tQtr. | 4th\tQtr. |
| Revenues | $3,784 | $3,839 | $3,699 | $3,179 | $3,793 | $3,732 | $4,036 | $4,131 |
| Income\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | 1,367 | 1,467 | 1,278 | 818 | 1,350 | 1,421 | 1,733 | 1,626 |
| Income\tfrom\tcontinuing\toperations | 380 | 399 | 518 | 296 | 423 | 406 | 469 | 315 |
| Discontinued\toperations\t(a) | 3 | 27 | 51 | 79 | (6) | (13) | (19) | 7 |
| Net\tincome | $383 | $426 | $569 | $375 | $417 | $393 | $450 | $322 |
| Income\tper\tshare: |  |  |  |  |  |  |  |  |
| Basic: |  |  |  |  |  |  |  |  |
| Continuing\toperations | $0.54 | $0.56 | $0.73 | $0.43 | $0.60 | $0.58 | $0.67 | $0.45 |
| Discontinued\toperations\t(a) | $0.00 | $0.04 | $0.07 | $0.11 | ($0.01) | ($0.02) | ($0.03) | $0.01 |
| Net\tincome | $0.54 | $0.60 | $0.80 | $0.54 | $0.59 | $0.56 | $0.64 | $0.46 |
| Diluted: |  |  |  |  |  |  |  |  |
| Continuing\toperations | $0.54 | $0.56 | $0.73 | $0.43 | $0.60 | $0.58 | $0.66 | $0.44 |
| Discontinued\toperations\t(a) | $0.00 | $0.04 | $0.07 | $0.11 | ($0.01) | ($0.02) | ($0.03) | $0.01 |
| Net\tincome | $0.54 | $0.60 | $0.80 | $0.54 | $0.59 | $0.56 | $0.63 | $0.45 |
| Dividends\tpaid\tper\tshare | $0.17 | $0.17 | $0.19 | $0.19 | $0.17 | $0.17 | $0.17 | $0.17 |

(a)	In	2013,	we	entered	into	agreements	to	sell	our	Angola	assets;	therefore,	our	Angola	operations	are	reflected	as	discontinued	operations	in	all	periods	presented.

# Supplementary	Information	on	Oil	and	Gas	Producing	Activities	(Unaudited)

The	supplementary	information	is	disclosed	by	the	following	geographic	areas:	the	U.S.;	Canada;	E.	G.;	Other	Africa,	which	primarily	includes	activities	in	Gabon, Kenya,	Ethiopia	and	Libya;	Europe,	which	primarily	includes	activities	in	Norway	and	the	U.K.;	and	Other	International	("Other	Int'l"),	which	includes	activities	in	the Kurdistan	Region	of	Iraq.	Our	Angola	operations	are	shown	as	discontinued	operations	("Disc	Ops")	in	all	periods	since	we	entered	into	agreements	to	sell	these	assets	in 2013.

# Estimated	Quantities	of	Proved	Oil	and	Gas	Reserves

The	estimation	of	net	recoverable	quantities	of	liquid	hydrocarbons,	natural	gas	and	synthetic	crude	oil	is	a	highly	technical	process,	which	is	based	upon	several underlying	assumptions	that	are	subject	to	change.	For	a	discussion	of	our	reserve	estimation	process,	including	the	use	of	third-party	audits,	see	Item	1.	Business	– Reserves.

| (mmbbl) | U.S. | Canada | E.G.(a) | Other<br>Africa | Europe | Disc	Ops | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Liquid\tHydrocarbons |  |  |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2011 | 173 | — | 119 | 224 | 99 | 15 | 630 |
| Revisions\tof\tprevious\testimates | 16 | — | 11 | — | 21 | 2 | 50 |
| Improved\trecovery | 1 | — | — | — | — | — | 1 |
| Purchases\tof\treserves\tin\tplace | 89 | — | — | — | — | — | 89 |
| Extensions,\tdiscoveries\tand\tother |  |  |  |  |  |  |  |
| additions | 27 | — | — | — | 14 | 1 | 42 |
| Production | (27) | — | (13) | (2) | (37) | — | (79) |
| End\tof\tyear\t-\t2011 | 279 | — | 117 | 222 | 97 | 18 | 733 |
| Revisions\tof\tprevious\testimates | 9 | — | 6 | (5) | 28 | — | 38 |
| Improved\trecovery | 2 | — | — | — | — | — | 2 |
| Purchases\tof\treserves\tin\tplace | 52 | — | — | — | — | — | 52 |
| Extensions,\tdiscoveries\tand\tother |  |  |  |  |  |  |  |
| additions | 172 | — | — | 7 | — | — | 179 |
| Production | (39) | — | (13) | (15) | (36) | — | (103) |
| End\tof\tyear\t-\t2012 | 475 | — | 110 | 209 | 89 | 18 | 901 |
| Revisions\tof\tprevious\testimates | 46 | — | (1) | 12 | 26 | (1) | 82 |
| Improved\trecovery | — | — | — | — | — | 11 | 11 |
| Purchases\tof\treserves\tin\tplace | 14 | — | — | — | — | — | 14 |
| Extensions,\tdiscoveries\tand\tother |  |  |  |  |  |  |  |
| additions | 137 | — | 1 | 3 | 5 | 3 | 149 |
| Production | (55) | — | (12) | (9) | (31) | (3) | (110) |
| Sales\tof\treserves\tin\tplace | (1) | — | — | — | — | — | (1) |
| End\tof\tyear\t-\t2013 | 616 | — | 98 | 215 | 89 | 28 | 1,046 |
| Proved\tdeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2011 | 124 | — | 86 | 180 | 89 | — | 479 |
| End\tof\tyear\t-\t2011 | 141 | — | 78 | 179 | 84 | — | 482 |
| End\tof\tyear\t-\t2012 | 198 | — | 68 | 168 | 84 | — | 518 |
| End\tof\tyear\t-\t2013 | 292 | — | 55 | 176 | 78 | 19 | 620 |
| Proved\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2011 | 49 | — | 33 | 44 | 10 | 15 | 151 |
| End\tof\tyear\t-\t2011 | 138 | — | 39 | 43 | 13 | 18 | 251 |
| End\tof\tyear\t-\t2012 | 277 | — | 42 | 41 | 5 | 18 | 383 |
| End\tof\tyear\t-\t2013 | 324 | — | 43 | 39 | 11 | 9 | 426 |

# Estimated	Quantities	of	Proved	Oil	and	Gas	Reserves	(continued)

| (bcf) | U.S. | Canada | E.G.(a) | Other<br>Africa | Europe | Disc	Ops | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Natural\tGas |  |  |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2011 | 745 | — | 1,651 | 105 | 116 | — | 2,617 |
| Revisions\tof\tprevious\testimates | 18 | — | 81 | (1) | 22 | — | 120 |
| Purchases\tof\treserves\tin\tplace | 119 | — | — | — | — | — | 119 |
| Extensions,\tdiscoveries\tand\tother |  |  |  |  |  |  |  |
| additions | 109 | — | — | — | 11 | — | 120 |
| Production(b) | (119) | — | (161) | — | (30) | — | (310) |
| End\tof\tyear\t-\t2011 | 872 | — | 1,571 | 104 | 119 | — | 2,666 |
| Revisions\tof\tprevious\testimates | (29) | — | 10 | (1) | 15 | — | (5) |
| Purchases\tof\treserves\tin\tplace | 105 | — | — | — | — | — | 105 |
| Extensions,\tdiscoveries\tand\tother |  |  |  |  |  |  |  |
| additions | 224 | — | — | 111 | — | — | 335 |
| Production(b) | (129) | — | (157) | (5) | (31) | — | (322) |
| End\tof\tyear\t-\t2012 | 1,043 | — | 1,424 | 209 | 103 | — | 2,779 |
| Revisions\tof\tprevious\testimates | (4) | — | 45 | 4 | 43 | — | 88 |
| Purchases\tof\treserves\tin\tplace | 13 | — | 3 | — | — | — | 16 |
| Extensions,\tdiscoveries\tand\tother |  |  |  |  |  |  |  |
| additions | 163 | — | 9 | — | 3 | — | 175 |
| Production(b) | (114) | — | (161) | (8) | (28) | — | (311) |
| Sales\tof\treserves\tin\tplace | (76) | — | — | — | — | — | (76) |
| End\tof\tyear\t-\t2013 | 1,025 | — | 1,320 | 205 | 121 | — | 2,671 |
| Proved\tdeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2011 | 591 | — | 1,186 | 104 | 43 | — | 1,924 |
| End\tof\tyear\t-\t2011 | 551 | — | 1,104 | 104 | 40 | — | 1,799 |
| End\tof\tyear\t-\t2012 | 546 | — | 980 | 99 | 28 | — | 1,653 |
| End\tof\tyear\t-\t2013 | 540 | — | 823 | 95 | 41 | — | 1,499 |
| Proved\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2011 | 154 | — | 465 | 1 | 73 | — | 693 |
| End\tof\tyear\t-\t2011 | 321 | — | 467 | — | 79 | — | 867 |
| End\tof\tyear\t-\t2012 | 497 | — | 444 | 110 | 75 | — | 1,126 |
| End\tof\tyear\t-\t2013 | 485 | — | 497 | 110 | 80 | — | 1,172 |

| (mmbbl) | U.S. | Canada | E.G.(a) | Other<br>Africa | Europe | Disc	Ops | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Synthetic\tcrude\toil |  |  |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2011 | — | 572 | — | — | — | — | 572 |
| Revisions\tof\tprevious\testimates | — | 17 | — | — | — | — | 17 |
| Extensions,\tdiscoveries\tand\tother |  |  |  |  |  |  |  |
| additions | — | 48 | — | — | — | — | 48 |
| Production | — | (14) | — | — | — | — | (14) |
| End\tof\tyear\t-\t2011 | — | 623 | — | — | — | — | 623 |
| Revisions\tof\tprevious\testimates | — | 45 | — | — | — | — | 45 |
| Production | — | (15) | — | — | — | — | (15) |
| End\tof\tyear\t-\t2012 | — | 653 | — | — | — | — | 653 |
| Revisions\tof\tprevious\testimates | — | 36 | — | — | — | — | 36 |
| Extensions,\tdiscoveries\tand\tother |  |  |  |  |  |  |  |
| additions | — | 6 | — | — | — | — | 6 |
| Production | — | (15) | — | — | — | — | (15) |
| End\tof\tyear\t-\t2013 | — | 680 | — | — | — | — | 680 |
| Proved\tdeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2011 | — | 433 | — | — | — | — | 433 |
| End\tof\tyear\t-\t2011 | — | 623 | — | — | — | — | 623 |
| End\tof\tyear\t-\t2012 | — | 653 | — | — | — | — | 653 |
| End\tof\tyear\t-\t2013 | — | 674 | — | — | — | — | 674 |
| Proved\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2011 | — | 139 | — | — | — | — | 139 |
| End\tof\tyear\t-\t2011 | — | — | — | — | — | — | — |
| End\tof\tyear\t-\t2012 | — | — | — | — | — | — | — |
| End\tof\tyear\t-\t2013 | — | 6 | — | — | — | — | 6 |

| (mmboe) | U.S. | Canada | E.G.(a) | Other<br>Africa | Europe | Disc	Ops | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Total\tProved\tReserves |  |  |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2011 | 297 | 572 | 394 | 242 | 118 | 15 | 1,638 |
| Revisions\tof\tprevious\testimates | 19 | 17 | 25 | (1) | 25 | 2 | 87 |
| Improved\trecovery | 1 | — | — | — | — | — | 1 |
| Purchases\tof\treserves\tin\tplace | 109 | — | — | — | — | — | 109 |
| Extensions,\tdiscoveries\tand\tother |  |  |  |  |  |  |  |
| additions | 45 | 48 | — | — | 16 | 1 | 110 |
| Production(b) | (47) | (14) | (40) | (2) | (42) | — | (145) |
| End\tof\tyear\t-\t2011 | 424 | 623 | 379 | 239 | 117 | 18 | 1,800 |
| Revisions\tof\tprevious\testimates | 5 | 45 | 7 | (5) | 30 | — | 82 |
| Improved\trecovery | 2 | — | — | — | — | — | 2 |
| Purchases\tof\treserves\tin\tplace | 70 | — | — | — | — | — | 70 |
| Extensions,\tdiscoveries\tand\tother |  |  |  |  |  |  |  |
| additions | 209 | — | — | 26 | — | — | 235 |
| Production(b) | (61) | (15) | (39) | (16) | (41) | — | (172) |
| End\tof\tyear\t-\t2012 | 649 | 653 | 347 | 244 | 106 | 18 | 2,017 |
| Revisions\tof\tprevious\testimates | 45 | 36 | 7 | 12 | 33 | (1) | 132 |
| Improved\trecovery | — | — | — | — | — | 11 | 11 |
| Purchases\tof\treserves\tin\tplace | 16 | — | 1 | — | — | — | 17 |
| Extensions,\tdiscoveries\tand\tother |  |  |  |  |  |  |  |
| additions | 164 | 6 | 2 | 3 | 6 | 3 | 184 |
| Production(b) | (74) | (15) | (39) | (10) | (36) | (3) | (177) |
| Sales\tof\treserves\tin\tplace | (13) | — | — | — | — | — | (13) |
| End\tof\tyear\t-\t2013 | 787 | 680 | 318 | 249 | 109 | 28 | 2,171 |
| Proved\tdeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2011 | 222 | 433 | 284 | 198 | 96 | — | 1,233 |
| End\tof\tyear\t-\t2011 | 233 | 623 | 262 | 196 | 91 | — | 1,405 |
| End\tof\tyear\t-\t2012 | 289 | 653 | 231 | 185 | 88 | — | 1,446 |
| End\tof\tyear\t-\t2013 | 382 | 674 | 193 | 192 | 84 | 19 | 1,544 |
| Proved\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t-\t2011 | 75 | 139 | 110 | 44 | 22 | 15 | 405 |
| End\tof\tyear\t-\t2011 | 191 | — | 117 | 43 | 26 | 18 | 395 |
| End\tof\tyear\t-\t2012 | 360 | — | 116 | 59 | 18 | 18 | 571 |
| End\tof\tyear\t-\t2013 | 405 | 6 | 125 | 57 | 25 | 9 | 627 |

(a) Consists	of	estimated	reserves	from	properties	governed	by	production	sharing	contracts.

(b) Excludes	the	resale	of	purchased	natural	gas	used	in	reservoir	management.

# Capitalized	Costs	and	Accumulated	Depreciation,	Depletion	and	Amortization

| (In	millions) | U.S. | Canada | E.G. | Other<br>Africa	(a) | Europe | Other<br>Int'l | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2013\tCapitalized\tCosts: |  |  |  |  |  |  |  |
| Proved\tproperties | $24,165 | $9,276 | $1,683 | $2,257 | $8,898 | $— | $46,279 |
| Unproved\tproperties | 2,097 | 1,508 | 31 | 693 | 296 | 214 | 4,839 |
| Total | 26,262 | 10,784 | 1,714 | 2,950 | 9,194 | 214 | 51,118 |
| Accumulated\tdepreciation, |  |  |  |  |  |  |  |
| depletion\tand\tamortization: |  |  |  |  |  |  |  |
| Proved\tproperties | 11,568 | 989 | 918 | 307 | 7,607 | — | 21,389 |
| Unproved\tproperties | 180 | 1 | — | 13 | 7 | 8 | 209 |
| Total | 11,748 | 990 | 918 | 320 | 7,614 | 8 | 21,598 |
| Net\tcapitalized\tcosts | $14,514 | $9,794 | $796 | $2,630 | $1,580 | $206 | $29,520 |
| 2012\tCapitalized\tCosts: |  |  |  |  |  |  |  |
| Proved\tproperties | $21,106 | $8,963 | $1,586 | $1,898 | $8,690 | $— | $42,243 |
| Unproved\tproperties | 3,222 | 1,513 | 29 | 602 | 160 | 146 | 5,672 |
| Total | 24,328 | 10,476 | 1,615 | 2,500 | 8,850 | 146 | 47,915 |
| Accumulated\tdepreciation, |  |  |  |  |  |  |  |
| depletion\tand\tamortization: |  |  |  |  |  |  |  |
| Proved\tproperties | 10,493 | 781 | 824 | 174 | 7,191 | — | 19,463 |
| Unproved\tproperties | 293 | 1 | — | 13 | — | 20 | 327 |
| Total | 10,786 | 782 | 824 | 187 | 7,191 | 20 | 19,790 |
| Net\tcapitalized\tcosts | $13,542 | $9,694 | $791 | $2,313 | $1,659 | $126 | $28,125 |

# (a) Includes	Angola	costs.

# Costs	Incurred	for	Property	Acquisition,	Exploration	and	Development (a)

| (In	millions) | U.S. | Canada | E.G. | Other<br>Africa | Europe | Other<br>Int'l | Disc	Ops | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2013\tProperty\tacquisition: |  |  |  |  |  |  |  |  |
| Proved | $51 | $30 | $9 | $— | $— | $— | $— | $90 |
| Unproved | 157 | — | — | 44 | — | 21 | — | 222 |
| Exploration | 885 | 9 | 4 | 124 | 102 | 137 | 10 | 1,271 |
| Development | 2,876 | 280 | 84 | 46 | 354 | 1 | 227 | 3,868 |
| Total | $3,969 | $319 | $97 | $214 | $456 | $159 | $237 | $5,451 |
| 2012\tProperty\tacquisition: |  |  |  |  |  |  |  |  |
| Proved | $756 | $— | $— | $— | $3 | $— | $— | $759 |
| Unproved | 432 | — | 18 | 63 | — | (13) | 5 | 505 |
| Exploration | 1,587 | 31 | 3 | 25 | 54 | 136 | 20 | 1,856 |
| Development | 2,469 | 195 | 22 | 15 | 468 | 5 | 353 | 3,527 |
| Total | $5,244 | $226 | $43 | $103 | $525 | $128 | $378 | $6,647 |
| 2011\tProperty\tacquisition: |  |  |  |  |  |  |  |  |
| Proved | $1,782 | $5 | $1 | $— | $— | $— | $— | $1,788 |
| Unproved | 3,271 | — | — | — | 7 | 57 | 1 | 3,336 |
| Exploration | 782 | 42 | — | 10 | 109 | 168 | 23 | 1,134 |
| Development | 889 | 293 | 18 | (5) | 388 | — | 299 | 1,882 |
| Total | $6,724 | $340 | $19 | $5 | $504 | $225 | $323 | $8,140 |

(a) Includes	costs	incurred	whether	capitalized	or	expensed.

# Results	of	Operations	for	Oil	and	Gas	Producing	Activities

| (In	millions) | U.S. | Canada | E.G. | Other<br>Africa | Europe | Other<br>Int'l | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2013 Revenues\tand\tother\tincome: |  |  |  |  |  |  |  |
| Sales | $5,059 | $1,376 | $33 | $1,106 | $924 | $— | $8,498 |
| Transfers | 3 | — | 715 | — | 2,941 | — | 3,659 |
| Other\tincome(a) | (9) | — | — | — | — | (8) | (17) |
| Total\trevenues\tand\tother\tincome | 5,053 | 1,376 | 748 | 1,106 | 3,865 | (8) | 12,140 |
| Expenses: |  |  |  |  |  |  |  |
| Production\tcosts | (1,318) | (867) | (113) | (73) | (498) | — | (2,869) |
| Exploration\texpenses | (717) | (8) | (3) | (65) | (123) | (72) | (988) |
| Depreciation,\tdepletion\tand\tamortization(b) | (1,980) | (218) | (97) | (28) | (440) | — | (2,763) |
| Administrative\texpenses | (185) | (21) | (30) | (19) | (36) | (14) | (305) |
| Total\texpenses | (4,200) | (1,114) | (243) | (185) | (1,097) | (86) | (6,925) |
| Results\tbefore\tincome\ttaxes | 853 | 262 | 505 | 921 | 2,768 | (94) | 5,215 |
| Income\ttax\t(provision)\tbenefit | (323) | (66) | (182) | (920) | (2,004) | 26 | (3,469) |
| Results\tof\tcontinuing\toperations | $530 | $196 | $323 | $1 | $764 | $(68) | $1,746 |
| Results\tof\tdiscontinued\toperations | $— | $— | $— | $160 | $— | $— | $160 |
| 2012 Revenues\tand\tother\tincome: |  |  |  |  |  |  |  |
| Sales | $3,879 | $1,261 | $29 | $2,000 | $835 | $— | $8,004 |
| Transfers | 2 | — | 818 | — | 3,601 | — | 4,421 |
| Other\tincome(a) | (8) | — | — | — | — | (32) | (40) |
| Total\trevenues\tand\tother\tincome | 3,873 | 1,261 | 847 | 2,000 | 4,436 | (32) | 12,385 |
| Expenses: |  |  |  |  |  |  |  |
| Production\tcosts | (1,054) | (826) | (141) | (58) | (398) | — | (2,477) |
| Exploration\texpenses | (558) | (30) | (5) | (10) | (34) | (69) | (706) |
| Depreciation,\tdepletion\tand\tamortization(b) | (1,792) | (217) | (95) | (43) | (615) | — | (2,762) |
| Administrative\texpenses | (193) | (8) | (5) | (4) | (40) | (12) | (262) |
| Total\texpenses | (3,597) | (1,081) | (246) | (115) | (1,087) | (81) | (6,207) |
| Results\tbefore\tincome\ttaxes | 276 | 180 | 601 | 1,885 | 3,349 | (113) | 6,178 |
| Income\ttax\t(provision)\tbenefit | (100) | (45) | (210) | (1,795) | (2,486) | 51 | (4,585) |
| Results\tof\tcontinuing\toperations | $176 | $135 | $391 | $90 | $863 | $(62) | $1,593 |
| Results\tof\tdiscontinued\toperations | $— | $— | $— | $(31) | $— | $— | $(31) |
| 2011 Revenues\tand\tother\tincome: |  |  |  |  |  |  |  |
| Sales | $3,058 | $1,332 | $29 | $216 | $1,000 | $— | $5,635 |
| Transfers | 63 | — | 905 | — | 3,546 | — | 4,514 |
| Other\tincome(a) | 41 | — | — | — | 15 | — | 56 |
| Total\trevenues\tand\tother\tincome | 3,162 | 1,332 | 934 | 216 | 4,561 | — | 10,205 |
| Expenses: |  |  |  |  |  |  |  |
| Production\tcosts(c) | (961) | (818) | (118) | (24) | (376) | — | (2,297) |
| Exploration\texpenses | (377) | (11) | (1) | 1 | (86) | (167) | (641) |
| Depreciation,\tdepletion\tand\tamortization(b) | (1,472) | (196) | (104) | (9) | (684) | — | (2,465) |
| Administrative\texpenses | (182) | (10) | — | (1) | (18) | (10) | (221) |
| Total\texpenses | (2,992) | (1,035) | (223) | (33) | (1,164) | (177) | (5,624) |
| Results\tbefore\tincome\ttaxes | 170 | 297 | 711 | 183 | 3,397 | (177) | 4,581 |
| Income\ttax\t(provision)\tbenefit | (59) | (75) | (254) | (176) | (2,176) | 65 | (2,675) |
| Results\tof\tcontinuing\toperations | $111 | $222 | $457 | $7 | $1,221 | $(112) | $1,906 |
| Results\tof\tdiscontinued\toperations | $— | $— | $— | $(11) | $— | $— | $(11) |

(a) Includes	net	gain	(loss)	on	dispositions.

(b) Includes	long-lived	asset	impairments.

(c) 2011	Canada	production	costs	include	$64	million	accrued	for	Oil	Sands	water	abatement.

The	following	reconciles	results	of	operations	for	oil	and	gas	producing	activities	to	segment	income:

| (In	millions) | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| Results\tof\tcontinuing\toperations | $1,746 | $1,593 | $1,906 |
| Items\tnot\tincluded\tin\tresults\tof\toil\tand\tgas\toperations,\tnet\tof\ttax: |  |  |  |
| Marketing\tincome\tand\tother\tnon-oil\tand\tgas\tproducing\trelated\tactivities | 42 | 49 | 182 |
| Income\tfrom\tequity\tmethod\tinvestments | 340 | 309 | 351 |
| Items\tnot\tallocated\tto\tsegment\tincome,\tnet\tof\ttax: |  |  |  |
| Loss\t(gain)\ton\tasset\tdispositions | 20 | 31 | (24) |
| Long-lived\tasset\timpairments | 10 | 231 | 181 |
| Water\tabatement-Oil\tSands\tMining | — | — | 48 |
| Segment\tincome | $2,158 | $2,213 | $2,644 |

# Standardized	Measure	of	Discounted	Future	Net	Cash	Flows	Relating	to	Proved	Reserves

|  |  |  | December	31, | December	31, |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | U.S. | Canada | E.G. | Other\nAfrica | Europe | Total |
| 2013 |  |  |  |  |  |  |
| Future\tcash\tinflows | $54,099 | $59,585 | $5,911 | $28,195 | $11,395 | $159,185 |
| Future\tproduction\tand\tadministrative\tcosts | (16,774) | (35,954) | (1,619) | (976) | (2,986) | (58,309) |
| Future\tdevelopment\tcosts | (9,685) | (9,694) | (367) | (793) | (2,178) | (22,717) |
| Future\tincome\ttax\texpenses | (7,592) | (3,098) | (1,032) | (24,982) | (4,581) | (41,285) |
| Future\tnet\tcash\tflows | $20,048 | $10,839 | $2,893 | $1,444 | $1,650 | $36,874 |
| 10\tpercent\tannual\tdiscount\tfor\testimated\ttiming\tof\tcash\tflows | (9,940) | (8,300) | (1,084) | (828) | (252) | (20,404) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\t- |  |  |  |  |  |  |
| related\tto\tcontinuing\toperations | $10,108 | $2,539 | $1,809 | $616 | $1,398 | $16,470 |
| related\tto\tdiscontinued\toperations | $— | $— | $— | $1,302 | $— | $1,302 |
| 2012 |  |  |  |  |  |  |
| Future\tcash\tinflows | $42,710 | $55,171 | $6,627 | $28,173 | $11,271 | $143,952 |
| Future\tproduction\tand\tadministrative\tcosts | (13,765) | (32,131) | (1,829) | (1,015) | (2,302) | (51,042) |
| Future\tdevelopment\tcosts | (11,104) | (9,350) | (451) | (787) | (1,673) | (23,365) |
| Future\tincome\ttax\texpenses | (4,489) | (2,948) | (1,191) | (25,020) | (5,274) | (38,922) |
| Future\tnet\tcash\tflows | $13,352 | $10,742 | $3,156 | $1,351 | $2,022 | $30,623 |
| 10\tpercent\tannual\tdiscount\tfor\testimated\ttiming\tof\tcash\tflows | (6,956) | (7,842) | (1,178) | (743) | (327) | (17,046) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\t- |  |  |  |  |  |  |
| related\tto\tcontinuing\toperations | $6,396 | $2,900 | $1,978 | $608 | $1,695 | $13,577 |
| related\tto\tdiscontinued\toperations | $— | $— | $— | $642 | $— | $642 |
| 2011 |  |  |  |  |  |  |
| Future\tcash\tinflows | $28,108 | $59,365 | $7,318 | $28,197 | $12,120 | $135,108 |
| Future\tproduction\tand\tadministrative\tcosts | (10,751) | (28,048) | (1,931) | (1,099) | (2,752) | (44,581) |
| Future\tdevelopment\tcosts | (6,341) | (10,346) | (435) | (559) | (1,702) | (19,383) |
| Future\tincome\ttax\texpenses | (2,740) | (4,490) | (1,368) | (25,463) | (5,375) | (39,436) |
| Future\tnet\tcash\tflows | $8,276 | $16,481 | $3,584 | $1,076 | $2,291 | $31,708 |
| 10\tpercent\tannual\tdiscount\tfor\testimated\ttiming\tof\tcash\tflows | (4,539) | (11,845) | (1,331) | (509) | (446) | (18,670) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\t- |  |  |  |  |  |  |
| related\tto\tcontinuing\toperations | $3,737 | $4,636 | $2,253 | $567 | $1,845 | $13,038 |
| related\tto\tdiscontinued\toperations | $— | $— | $— | $743 | $— | $743 |

# Changes	in	the	Standardized	Measure	of	Discounted	Future	Net	Cash	Flows

| (In	millions) | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| Sales\tand\ttransfers\tof\toil\tand\tgas\tproduced,\tnet\tof\tproduction\tand\tadministrative\tcosts | $(8,997) | $(9,696) | $(7,637) |
| Net\tchanges\tin\tprices\tand\tproduction\tand\tadministrative\tcosts\trelated\tto\tfuture\tproduction | (243) | (1,445) | 11,786 |
| Extensions,\tdiscoveries\tand\timproved\trecovery,\tless\trelated\tcosts | 3,457 | 2,763 | 1,369 |
| Development\tcosts\tincurred\tduring\tthe\tperiod | 3,708 | 3,197 | 1,600 |
| Changes\tin\testimated\tfuture\tdevelopment\tcosts | 622 | 25 | (1,069) |
| Revisions\tof\tprevious\tquantity\testimates(a) | 3,123 | 1,652 | 2,453 |
| Net\tchanges\tin\tpurchases\tand\tsales\tof\tminerals\tin\tplace | (229) | 909 | 230 |
| Accretion\tof\tdiscount | 3,054 | 3,073 | 1,989 |
| Net\tchange\tin\tincome\ttaxes | (1,602) | 61 | (6,607) |
| Net\tchange\tfor\tthe\tyear | 2,893 | 539 | 4,114 |
| Beginning\tof\tthe\tyear\trelated\tto\tcontinuing\toperations | 13,577 | 13,038 | 8,924 |
| End\tof\tthe\tyear\trelated\tto\tcontinuing\toperations | $16,470 | $13,577 | $13,038 |
| Net\tchange\tfor\tthe\tyear\trelated\tto\tdiscontinued\toperations | $660 | $(101) | $478 |

(a) Includes	amounts	resulting	from	changes	in	the	timing	of	production	and	other.

# Supplemental	Statistics	(Unaudited)

| (In	millions) | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| Segment\tIncome |  |  |  |
| North\tAmerica\tE&amp;P | $529 | \t $382 | \t $392 |
| International\tE&amp;P | 1,423 | 1,660 | 1,991 |
| Oil\tSands\tMining | 206 | 171 | 261 |
| Segment\tincome | 2,158 | 2,213 | 2,644 |
| Items\tnot\tallocated\tto\tsegments,\tnet\tof\tincome\ttaxes | (565) | (600) | (926) |
| Income\tfrom\tcontinuing\toperations | 1,593 | 1,613 | 1,718 |
| Discontinued\toperations(a) | 160 | (31) | 1,228 |
| Net\tincome | $1,753 | \t $1,582 | \t $2,946 |
| Capital\tExpenditures(b) |  |  |  |
| North\tAmerica\tE&amp;P | $3,649 | \t $3,988 | \t $2,163 |
| International\tE&amp;P | 764 | 489 | 544 |
| Oil\tSands\tMining | 286 | 188 | 308 |
| Corporate | 58 | 115 | 75 |
| Discontinued\toperations(a) | 227 | 351 | 309 |
| Total | $4,984 | \t $5,131 | \t $3,399 |
| Exploration\tExpenses |  |  |  |
| North\tAmerica\tE&amp;P | $725 | \t $588 | \t $388 |
| International\tE&amp;P | 263 | 118 | 253 |
| Total | $988 | \t $706 | \t $641 |

(a) In	2013,	we	entered	into	agreements	to	sell	our	Angola	assets;	therefore,	our	Angola	operations	are	reflected	as	discontinued	operations	in	all	periods	presented.	The	spin-off	of	the	downstream business	was	completed	on	June	30,	2011	and	has	been	reported	as	discontinued	operations	in	2011.

(b) Capital	expenditures	include	changes	in	accruals.

| Net	Sales	Volumes | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| North\tAmerica\tE&amp;P |  |  |  |
| Crude\tOil\tand\tCondensate\t(mbbld) |  |  |  |
| Bakken | 35 | 27 | 16 |
| Eagle\tFord | 51 | 23 | 2 |
| Oklahoma\tresource\tbasins | 2 | 1 | — |
| Other\tNorth\tAmerica | 38 | 45 | 52 |
| Total\tCrude\tOil\tand\tCondensate | 126 | 96 | 70 |
| Natural\tGas\tLiquids\t(mbbld) |  |  |  |
| Bakken | 2 | 1 | — |
| Eagle\tFord | 14 | 5 | — |
| Oklahoma\tresource\tbasins | 4 | 2 | 1 |
| Other\tNorth\tAmerica | 3 | 3 | 4 |
| Total\tNatural\tGas\tLiquids | 23 | 11 | 5 |
| Total\tLiquid\tHydrocarbons\t(mbbld) |  |  |  |
| Bakken | 37 | 28 | 16 |
| Eagle\tFord | 65 | 28 | 2 |
| Oklahoma\tresource\tbasins | 6 | 3 | 1 |
| Other\tNorth\tAmerica | 41 | 48 | 56 |
| Total\tLiquid\tHydrocarbons | 149 | 107 | 75 |
| Natural\tGas\t(mmcfd) |  |  |  |
| Bakken | 13 | 8 | 6 |
| Eagle\tFord | 94 | 37 | 2 |
| Oklahoma\tresource\tbasins | 48 | 32 | 7 |
| Alaska | 7 | 92 | 94 |
| Other\tNorth\tAmerica | 150 | 189 | 217 |
| Total\tNatural\tGas | 312 | 358 | 326 |
| Total\tNorth\tAmerica\tE&amp;P\t(mboed) | 201 | 166 | 129 |

| Net	Sales	Volumes | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| International\tE&amp;P |  |  |  |
| Total\tLiquid\tHydrocarbons\t(mbbld) |  |  |  |
| Equatorial\tGuinea | 34 | 36 | 38 |
| Norway | 71 | 81 | 80 |
| United\tKingdom | 15 | 16 | 21 |
| Libya | 24 | 42 | 5 |
| Total\tLiquid\tHydrocarbons | 144 | 175 | 144 |
| Natural\tGas\t(mmcfd) |  |  |  |
| Equatorial\tGuinea | 442 | 428 | 443 |
| Norway | 51 | 53 | 42 |
| United\tKingdom(c) | 32 | 48 | 55 |
| Libya | 22 | 15 | — |
| Total\tNatural\tGas | 547 | 544 | 540 |
| Total\tInternational\tE&amp;P\t(mboed) | 234 | 266 | 234 |
| Oil\tSands\tMining |  |  |  |
| Synthetic\tCrude\tOil\t(mbbld)(d) | 48 | 47 | 43 |
| Total\tContinuing\tOperations\t(mboed) | 483 | 479 | 406 |
| Discontinued\tOperations\t(mboed)(e) | 10 | — | — |
| Total\tCompany\t(mboed) | 493 | 479 | 406 |
| Net\tSales\tVolumes\tof\tEquity\tMethod\tInvestees |  |  |  |
| LNG\t(mtd) | 6,548 | 6,290 | 6,681 |
| Methanol\t(mtd) | 1,249 | 1,298 | 1,282 |

(c)	Includes	natural	gas	acquired	for	injection	and	subsequent	resale	of	7	mmcfd,	15	mmcfd	and	16	mmcfd	for	2013,	2012,	and	2011.

(d)	Includes	blendstocks.

(e)	In	2013,	we	entered	into	agreements	to	sell	our	Angola	assets;	therefore,	our	Angola	operations	are	reflected	as	discontinued	operations	and	excluded	from	segments	in	all	periods	presented.

| Average	Price	Realizations	(f) | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| North\tAmerica\tE&amp;P |  |  |  |
| Crude\tOil\tand\tCondensate\t(per\tbbl) |  |  |  |
| Bakken | $90.25 | $83.11 | $90.60 |
| Eagle\tFord | 99.69 | 100.14 | 101.46 |
| Oklahoma\tresource\tbasins | 94.84 | 89.26 | — |
| Other\tNorth\tAmerica | 90.42 | 91.75 | 95.91 |
| Total\tCrude\tOil\tand\tCondensate | 94.19 | 91.30 | 94.80 |
| Natural\tGas\tLiquids\t(per\tbbl) |  |  |  |
| Bakken | $41.60 | $42.35 | — |
| Eagle\tFord | 30.16 | 32.96 | — |
| Oklahoma\tresource\tbasins | 35.28 | 31.82 | $36.95 |
| Other\tNorth\tAmerica | 55.69 | 52.51 | 62.24 |
| Total\tNatural\tGas\tLiquids | 35.12 | 39.57 | 58.53 |
| Total\tLiquid\tHydrocarbons\t(per\tbbl)\t(g) |  |  |  |
| Bakken | $87.76 | $81.36 | $90.29 |
| Eagle\tFord | 84.95 | 88.09 | 95.84 |
| Oklahoma\tresource\tbasins | 50.77 | 49.21 | 36.95 |
| Other\tNorth\tAmerica | 88.16 | 89.03 | 93.70 |
| Total\tLiquid\tHydrocarbons | 85.20 | 85.80 | 92.55 |
| Natural\tGas\t(per\tmcf) |  |  |  |
| Bakken | $3.90 | $3.11 | $6.92 |
| Eagle\tFord | 3.67 | 3.03 | 4.12 |
| Oklahoma\tresource\tbasins | 3.78 | 3.05 | 3.45 |
| Alaska | 7.79 | 6.86 | 6.53 |
| Other\tNorth\tAmerica | 3.76 | 2.84 | 4.26 |
| Total\tNatural\tGas | 3.84 | 3.92 | 4.95 |

(f)	Excludes	gains	or	losses	on	derivative	instruments.

(g)	Inclusion	of	realized	gains	(losses)	on	crude	oil	derivative	instruments	would	have	increased	(decreased)	average	liquid	hydrocarbon	price	realizations	per	barrel	by $(0.27)	and	$0.40	for	2013	and 2012.

| Average	Price	Realizations | 2013 | 2012 | 2011 |
| :--- | :--- | :--- | :--- |
| International\tE&amp;P |  |  |  |
| Total\tLiquid\tHydrocarbons\t(per\tbbl) |  |  |  |
| Equatorial\tGuinea | $60.34 | $64.33 | $67.70 |
| Norway | 113.38 | 116.70 | 116.62 |
| United\tKingdom | 108.92 | 107.31 | 111.55 |
| Libya | 122.92 | 127.31 | 112.56 |
| Total\tLiquid\tHydrocarbons | 102.10 | 107.78 | 102.96 |
| Natural\tGas\t(per\tmcf) |  |  |  |
| Equatorial\tGuinea(h) | $0.24 | $0.24 | $0.24 |
| Norway | 13.01 | 11.15 | 10.60 |
| United\tKingdom | 10.64 | 9.72 | 9.26 |
| Libya | 5.44 | 5.76 | 0.70 |
| Total\tNatural\tGas | 2.25 | 2.29 | 1.97 |
| Oil\tSands\tMining |  |  |  |
| Synthetic\tCrude\tOil\t(per\tbbl) | $87.51 | $81.72 | $91.65 |
| Discontinued\tOperations\t(per\tbbl)(e) | $104.77 | — | — |
| Total\tProved\tReserves\t(at\tyear\tend) |  |  |  |
| Liquid\tHydrocarbons\t(mmbbl) |  |  |  |
| North\tAmerica\tE&amp;P | 616 | 475 | 279 |
| International\tE&amp;P | 402 | 408 | 436 |
| Total\tContinuing\tOperations | 1,018 | 883 | 715 |
| Natural\tGas\t(bcf) |  |  |  |
| North\tAmerica\tE&amp;P | 1,025 | 1,043 | 872 |
| International\tE&amp;P | 1,646 | 1,736 | 1,794 |
| Total\tContinuing\tOperations | 2,671 | 2,779 | 2,666 |
| Synthetic\tCrude\tOil\t(mmbbl) |  |  |  |
| Oil\tSands\tMining | 680 | 653 | 623 |
| Continuing\tOperations\t(mmboe) | 2,143 | 1,999 | 1,782 |
| Discontinued\tOperations\t(mmboe)(e) | 28 | 18 | 18 |
| Total\tProved\tReserves\t(mmboe) | 2,171 | 2,017 | 1,800 |

(h)	Primarily	represents	fixed	prices	under	long-term	contracts	with	Alba	Plant	LLC,	AMPCO	and	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.

# 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,	2013.

# Internal	Control	Over	Financial	Reporting

In	the	first	quarter	of	2013,	we	completed	the	update	of	our	existing	Enterprise	Resource	Planning	("ERP")	system.	This	update	included	a	new	general	ledger, consolidations	system	and	reporting	tools.	During	the	fourth	quarter	of	2013,	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.	See	Item	8.	Financial	Statements	and	Supplementary	Data	— Management's	Report	on	Internal	Control	over	Financial	Reporting	and	–	Report	of	Independent	Registered	Public	Accounting	Firm.

# Item	9B.	Other	Information

# PART	III

# Item	10.	Directors,	Executive	Officers	and	Corporate	Governance

Information	concerning	our	directors	required	by	this	item	is	incorporated	by	reference	to	the	material	appearing	under	the	heading	"Election	of	Directors"	in	our Proxy	Statement	for	the	2014	Annual	Meeting	of	Stockholders.

Our	Board	of	Directors	has	established	 the	Audit	and	Finance	Committee	and	determined	our	"Audit	Committee	Financial	Expert."	The	related	 information required	by	this	item	is	incorporated	by	reference	to	the	material	appearing	under	the	sub-heading	"Audit	and	Finance	Committee"	located	under	the	heading	"The	Board of	Directors	and	Governance	Matters"	in	our	Proxy	Statement	for	the	2014	Annual	Meeting	of	Stockholders.

We have adopted a Code of Ethics for Senior Financial Officers.	It is available on our website at http://www.marathonoil.com/Investor_Center/Corporate_Governance/Code_of_Ethics_for_Senior_Financial_Officers/.

See	Item	1.	Business	–	Executive	Officers	of	the	Registrant	for	the	names,	ages	and	titles	of	our	executive	officers.

# Section	16(a)	Beneficial	Ownership	Reporting	Compliance

Section	16(a)	of	the	Securities	Exchange	Act	of	1934,	as	amended,	requires	that	our	directors	and	executive	officers,	and	persons	who	own	more	than	ten	percent	of a	registered	class	of	our	equity	securities,	file	reports	of	beneficial	ownership	on	Form	3	and	changes	in	beneficial	ownership	on	Form	4	or	Form	5	with	the	SEC.	Based solely	on	our	review	of	the	reporting	forms	and	written	representations	provided	to	us	from	the	individuals	required	to	file	reports,	we	believe	that	each	of	our	directors and	executive	officers	has	complied	with	the	applicable	reporting	requirements	for	transactions	in	Marathon	Oil	securities	during	the	fiscal	year	ended	December	31, 2013.

# Item	11.	Executive	Compensation

Information	required	by	this	item	is	incorporated	by	reference	to	the	material	appearing	under	the	heading	"Executive	Compensation	Tables	and	Other	Information," under	the	sub-headings	"Compensation	Committee"	and	"Compensation	Committee	Interlocks	and	Insider	Participation,"	under	the	heading	"The	Board	of	Directors	and Governance	Matters"	and	under	the	heading	"Compensation	Committee	Report"	in	our	Proxy	Statement	for	the	2014	Annual	Meeting	of	Stockholders.

# Item	12.	Security	Ownership	of	Certain	Beneficial	Owners	and	Management	and	Related	Stockholder	Matters

Information	concerning	security	ownership	of	certain	beneficial	owners	and	management	required	by	this	item	is	incorporated	by	reference	to	the	material	appearing under	the	headings	"Security	Ownership	of	Certain	Beneficial	Owners"	and	"Security	Ownership	of	Directors	and	Executive	Officers"	in	our	Proxy	Statement	for	the 2014	Annual	Meeting	of	Stockholders.

# Securities	Authorized	for	Issuance	Under	Equity	Compensation	Plans

The	following	table	provides	information	as	of	December	31,	2013	with	respect	to	shares	of	Marathon	Oil	common	stock	that	may	be	issued	under	our	existing equity	compensation	plans:

•Marathon	 Oil	 Corporation 2012 Incentive	 Compensation	 Plan (the "2012 Plan")

•Marathon	Oil	Corporation	2007	Incentive	Compensation	Plan	(the	"2007	Plan")	–	No	additional	awards	will	be	granted	under	this plan.

•Deferred	Compensation	Plan	for	Non-Employee	Directors	–	No	additional	awards	will	be	granted	under	this

plan.

| Plan	category | Number	of<br>securities	to<br>be	issued<br>upon<br>exercise	of<br>outstanding<br>options,<br>warrants<br>and	rights |  | Weighted-<br>average<br>exercise<br>price	of<br>outstanding<br>options,<br>warrants<br>and	rights(c) | Number	of<br>securities<br>remaining<br>available	for<br>future<br>issuance<br>under	equity<br>compensation<br>plans |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Equity\tcompensation\tplans\tapproved\tby\tstockholders | 19,244,830 | (a) | $27.27 | 45,950,524 | (d) |
| Equity\tcompensation\tplans\tnot\tapproved\tby\tstockholders | 20,984 | (b) | N/A | — |  |
| Total | 19,265,814 |  | N/A | 45,950,524 |  |

(a) Includes	the	following:

•2,465,332	stock	options	outstanding	under	the	2003	Plan	and	the	net	number	of	stock-settled	SARs	that	could	be	issued	from	this	Plan.	The	number	of	stock-settled	SARs	is	based	on	the closing	price	of	Marathon	Oil	common	stock	on	December	31,	2013	of	$35.30	per	share;

•324,672	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	2012	Plan,	2007	Plan	and	2003	Plan;	common	stock	units	credited	under	the	2012	Plan,	2007	Plan	and	2003	Plan	were	51,196,	222,215	and	51,261,

respectively;

In	addition	to	the	awards	reported	above	2,014,310	and	1,094,122	shares	of	restricted	stock	were	issued	and	outstanding	as	of	 December	31,	2013,	but	subject	to	forfeiture	restrictions	under	the 2012	Plan	and	2007	Plan,	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	2012	Plan.	No	more	than	18,810,490	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	the	material	appearing	under	the	heading	"Certain	Relationships	and	Related	Person	Transactions," and	under	the	sub-heading	"Board	and	Committee	Independence"	under	the	heading	"The	Board	of	Directors	and	Governance	Matters"	in	our	Proxy	Statement	for	the 2014	Annual	Meeting	of	Stockholders.

# Item	14.	Principal	Accounting	Fees	and	Services

Information	required	by	this	item	is	incorporated	by	reference	to	the	material	appearing	under	the	heading	"Information	Regarding	the	Independent	Registered Public	Accounting	Firm's	Fees,	Services	and	Independence"	in	our	Proxy	Statement	for	the	2014	Annual	Meeting	of	Stockholders.

# 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	Report	regarding	financial	statements)

# 2.	Financial	Statement	Schedules

Financial	statement	schedules	required	under	SEC	rules	but	not	included	in	this	Report	are	omitted	because	they	are	not	applicable	or	the	required	information	is contained	in	the	consolidated	financial	statements	or	notes	thereto.

# 3.	Exhibits:

References	to	Marathon	Ashland	Petroleum	LLC	or	MAP	are	references	to	the	entity	now	known	as	Marathon	Petroleum	Corporation.

| Exhibit |  |  | Incorporated	by	Reference | Incorporated	by	Reference |  | Filed | Furnished |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Number | Exhibit\tDescription | Form | Exhibit | Filing\tDate | SEC\tFile\tNo. | Herewith | Herewith |
| 2 | Plan\tof\tAcquisition,\tReorganization,\tArrangement,\tLiquidation\tor\tSuccession | Plan\tof\tAcquisition,\tReorganization,\tArrangement,\tLiquidation\tor\tSuccession | Plan\tof\tAcquisition,\tReorganization,\tArrangement,\tLiquidation\tor\tSuccession |  |  |  |  |
| 2.1++ | Separation\tand\tDistribution\tAgreement\tdated\tas | 8-K | 2.1 | 5/26/2011 | 001-05153 |  |  |
|  | of\tMay\t25,\t2011\tamong\tMarathon\tOil |  |  |  |  |  |  |
|  | Corporation,\tMarathon\tOil\tCompany\tand |  |  |  |  |  |  |
|  | Marathon\tPetroleum\tCorporation |  |  |  |  |  |  |
| 3 | \t Articles\tof\tIncorporation\tand\tBylaws |  |  |  |  |  |  |
| 3.1 | Restated\tCertificate\tof\tIncorporation\tof | 10-Q | 3.1 | 8/8/2013 | 001-05153 |  |  |
|  | Marathon\tOil\tCorporation |  |  |  |  |  |  |
| 3.2 | Amended\tBy-Laws\tof\tMarathon\tOil |  |  |  |  | X |  |
|  | Corporation\teffective\tFebruary\t25,\t2014 |  |  |  |  |  |  |
| 3.3 | Specimen\tof\tCommon\tStock\tCertificate |  |  |  |  | X |  |
| 4 | Instruments\tDefining\tthe\tRights\tof\tSecurity\tHolders,\tIncluding\tIndentures | Instruments\tDefining\tthe\tRights\tof\tSecurity\tHolders,\tIncluding\tIndentures | Instruments\tDefining\tthe\tRights\tof\tSecurity\tHolders,\tIncluding\tIndentures |  |  |  |  |
| 4.1 | Credit\tAgreement,\tdated\tas\tof\tApril\t5,\t2012, | 8-K | 4.1 | 4/10/2012 | 001-05153 |  |  |

| Exhibit |  |  | Incorporated	by	Reference | Incorporated	by	Reference |  | Filed | Furnished |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Number | Exhibit\tDescription | Form | Exhibit | Filing\tDate | SEC\tFile\tNo. | Herewith | Herewith |
| 4.2 | Indenture,\tdated\tas\tof\tFebruary\t26,\t2002, |  |  |  |  | X |  |
|  | between\tMarathon\tOil\tCorporation\tand\tThe |  |  |  |  |  |  |
|  | Bank\tof\tNew\tYork\tTrust\tCompany,\tN.A., |  |  |  |  |  |  |
|  | successor\tin\tinterest\tto\tJPMorgan\tChase\tBank |  |  |  |  |  |  |
|  | as\tTrustee,\trelating\tto\tsenior\tdebt\tsecurities\tof |  |  |  |  |  |  |
|  | Marathon\tOil\tCorporation.\tPursuant\tto\tCFR |  |  |  |  |  |  |
|  | 229.601(b)(4)(iii),\tinstruments\twith\trespect\tto |  |  |  |  |  |  |
|  | long-term\tdebt\tissues\thave\tbeen\tomitted\twhere |  |  |  |  |  |  |
|  | the\tamount\tof\tsecurities\tauthorized\tunder\tsuch |  |  |  |  |  |  |
|  | instruments\tdoes\tnot\texceed\t10\tpercent\tof\tthe |  |  |  |  |  |  |
|  | total\tconsolidated\tassets\tof\tMarathon\tOil. |  |  |  |  |  |  |
|  | Marathon\tOil\thereby\tagrees\tto\tfurnish\ta\tcopy\tof |  |  |  |  |  |  |
|  | any\tsuch\tinstrument\tto\tthe\tSecurities\tand |  |  |  |  |  |  |
|  | Exchange\tCommission\tupon\tits\trequest. |  |  |  |  |  |  |
| 10 | \t Material\tContracts |  |  |  |  |  |  |
| 10.1 | Tax\tSharing\tAgreement\tdated\tas\tof\tMay\t25, | 8-K | 10.1 | 5/26/2011 | 001-05153 |  |  |
|  | 2011\tamong\tMarathon\tOil\tCorporation, |  |  |  |  |  |  |
|  | Marathon\tPetroleum\tCorporation\tand\tMPC |  |  |  |  |  |  |
|  | Investment\tLLC |  |  |  |  |  |  |
| 10.2 | Employee\tMatters\tAgreement\tdated\tas\tof | 8-K | 10.2 | 5/26/2011 | 001-05153 |  |  |
|  | May\t25,\t2011\tamong\tMarathon\tOil\tCorporation |  |  |  |  |  |  |
|  | and\tMarathon\tPetroleum\tCorporation |  |  |  |  |  |  |
| 10.3 | Amendment\tto\tEmployee\tMatters\tAgreement | 10-Q | 10.3 | 8/8/2011 | 001-05153 |  |  |
|  | dated\tas\tof\tJune\t30,\t2011\tbetween\tMarathon |  |  |  |  |  |  |
|  | Oil\tCorporation\tand\tMarathon\tPetroleum |  |  |  |  |  |  |
|  | Corporation |  |  |  |  |  |  |
| 10.4 | Marathon\tOil\tCorporation\t2012\tIncentive | DEF\t14A | App.\tIII | 3/8/2012 | 001-05153 |  |  |
|  | Compensation\tPlan |  |  |  |  |  |  |
| 10.5 | Form\tof\tInitial\tCEO\tOption\tGrant\tAgreement | 10-Q | 10.1 | 11/6/2013 | 001-05153 |  |  |
|  | granted\tunder\tMarathon\tOil\tCorporation's\t2012 |  |  |  |  |  |  |
|  | Incentive\tCompensation\tPlan. |  |  |  |  |  |  |
| 10.6 | Form\tof\tCEO\tRestricted\tStock\tAgreement | 10-Q | 10.2 | 11/6/2013 | 001-05153 |  |  |
|  | granted\tunder\tMarathon\tOil\tCorporation's\t2012 |  |  |  |  |  |  |
|  | Incentive\tCompensation\tPlan\t(3-year\tprorata |  |  |  |  |  |  |
|  | vesting). |  |  |  |  |  |  |
| 10.7 | Form\tof\tCEO\tRestricted\tStock\tAward | 10-Q | 10.3 | 11/6/2013 | 001-05153 |  |  |
|  | Agreement\tgranted\tunder\tMarathon\tOil |  |  |  |  |  |  |
|  | Corporation's\t2012\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan\t(3-year\tcliff\tvesting). |  |  |  |  |  |  |
| 10.8 | Marathon\tOil\tCorporation\tBonus\tAgreement | 10-Q | 10.4 | 11/6/2013 | 001-05153 |  |  |
|  | Upon\tCommencement\tof\tEmployment\tfor\tLee |  |  |  |  |  |  |
|  | M.\tTillman. |  |  |  |  |  |  |
| 10.9 | Form\tof\tPerformance\tUnit\tAward\tAgreement | 10-Q | 10.1 | 5/10/2013 | 001-05153 |  |  |

| Exhibit |  |  | Incorporated	by	Reference | Incorporated	by	Reference |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Number | Exhibit\tDescription | Form | Exhibit | Filing\tDate | SEC\tFile\tNo. |
| 10.10 | Form\tof\tPerformance\tUnit\tAward | 10-Q | 10.2 | 5/10/2013 | 001-05153 |
|  | Agreement\t(2013-2015\tPerformance |  |  |  |  |
|  | Cycle)\tfor\tOfficers\tgranted\tunder |  |  |  |  |
|  | Marathon\tOil\tCorporation's\t2012 |  |  |  |  |
|  | Incentive\tCompensation\tPlan |  |  |  |  |
| 10.11 | Form\tof\tNonqualified\tStock\tOption | 10-K | 10.5 | 2/22/2013 | 001-05153 |
|  | Award\tAgreement\tfor\tSection\t16 |  |  |  |  |
|  | reporting\tOfficers\tgranted\tunder |  |  |  |  |
|  | Marathon\tOil\tCorporation's\t2012 |  |  |  |  |
|  | Incentive\tCompensation\tPlan\t(3-year |  |  |  |  |
|  | prorata\tvesting) |  |  |  |  |
| 10.12 | Form\tof\tNonqualified\tStock\tOption | 10-K | 10.6 | 2/22/2013 | 001-05153 |
|  | Award\tAgreement\tfor\tOfficers |  |  |  |  |
|  | granted\tunder\tMarathon\tOil |  |  |  |  |
|  | Corporation's\t2012\tIncentive |  |  |  |  |
|  | Compensation\tPlan\t(3-year\tprorata |  |  |  |  |
|  | vesting) |  |  |  |  |
| 10.13 | Form\tof\tRestricted\tStock\tAward | 10-K | 10.7 | 2/22/2013 | 001-05153 |
|  | Agreement\tfor\tSection\t16\treporting |  |  |  |  |
|  | Officers\tgranted\tunder\tMarathon\tOil |  |  |  |  |
|  | Corporation's\t2012\tIncentive |  |  |  |  |
|  | Compensation\tPlan\t(3-year\tcliff |  |  |  |  |
|  | vesting) |  |  |  |  |
| 10.14 | Form\tof\tRestricted\tStock\tAward | 10-K | 10.8 | 2/22/2013 | 001-05153 |
|  | Agreement\tfor\tOfficers\tgranted\tunder |  |  |  |  |
|  | Marathon\tOil\tCorporation's\t2012 |  |  |  |  |
|  | Incentive\tCompensation\tPlan\t(3-year |  |  |  |  |
|  | cliff\tvesting) |  |  |  |  |
| 10.15 | Form\tof\tRestricted\tStock\tAward | 10-K | 10.9 | 2/22/2013 | 001-05153 |
|  | Agreement\tfor\tSection\t16\treporting |  |  |  |  |
|  | Officers\tgranted\tunder\tMarathon\tOil |  |  |  |  |
|  | Corporation's\t2012\tIncentive |  |  |  |  |
|  | Compensation\tPlan\t(3-year\tprorata |  |  |  |  |
|  | vesting) |  |  |  |  |
| 10.16 | Form\tof\tRestricted\tStock\tAward | 10-K | 10.10 | 2/22/2013 | 001-05153 |
|  | Agreement\tfor\tOfficers\tgranted\tunder |  |  |  |  |
|  | Marathon\tOil\tCorporation's\t2012 |  |  |  |  |
|  | Incentive\tCompensation\tPlan\t(3-year |  |  |  |  |
|  | prorata\tvesting) |  |  |  |  |
| 10.17 | Form\tof\tNonqualified\tStock\tOption | 10-K | 10.11 | 2/22/2013 | 001-05153 |
|  | Award\tAgreement\tfor\tnon-officers |  |  |  |  |
|  | granted\tunder\tMarathon\tOil |  |  |  |  |
|  | Corporation's\t2012\tIncentive |  |  |  |  |
|  | Compensation\tPlan\t(3-year\tprorata |  |  |  |  |
|  | vesting) |  |  |  |  |
| 10.18 | Form\tof\tNonqualified\tStock\tOption | 10-K | 10.12 | 2/22/2013 | 001-05153 |
|  | Award\tAgreement\tfor\tnon-officers\tin |  |  |  |  |
|  | Canada\tgranted\tunder\tMarathon\tOil |  |  |  |  |
|  | Corporation's\t2012\tIncentive |  |  |  |  |
|  | Compensation\tPlan\t(3-year\tprorata |  |  |  |  |
|  | vesting) |  |  |  |  |
| 10.19 | Form\tof\tRestricted\tStock\tAward | 10-K | 10.13 | 2/22/2013 | 001-05153 |

| Exhibit |  |  | Incorporated	by	Reference | Incorporated	by	Reference |  | Filed | Furnished |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Number | Exhibit\tDescription | Form | Exhibit | Filing\tDate | SEC\tFile\tNo. | Herewith | Herewith |
| 10.20 | Form\tof\tRestricted\tStock\tAward\tAgreement\tfor | 10-K | 10.14 | 2/22/2013 | 001-05153 |  |  |
|  | non-officers\tgranted\tunder\tMarathon\tOil |  |  |  |  |  |  |
|  | Corporation's\t2012\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan\t(3-year\tprorata\tvesting) |  |  |  |  |  |  |
| 10.21 | Marathon\tOil\tCorporation\t2007\tIncentive | 10-K | 10.5 | 2/29/2012 | 001-05153 |  |  |
|  | Compensation\tPlan |  |  |  |  |  |  |
| 10.22 | Form\tof\tNonqualified\tStock\tOption\tAward | 10-K | 10.6 | 2/29/2012 | 001-05153 |  |  |
|  | Agreement\tfor\tOfficers\tgranted\tunder\tMarathon |  |  |  |  |  |  |
|  | Oil\tCorporation's\t2007\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan,\teffective\tMay\t30,\t2007 |  |  |  |  |  |  |
| 10.23 | Form\tof\tNonqualified\tStock\tOption\tAward | 10-K | 10.5 | 2/28/2011 | 001-05153 |  |  |
|  | Agreement\tfor\tOfficers\tgranted\tunder\tMarathon |  |  |  |  |  |  |
|  | Oil\tCorporation's\t2007\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan,\teffective\tFebruary\t24,\t2010 |  |  |  |  |  |  |
| 10.24 | Form\tof\tOfficer\tRestricted\tStock\tAward | 10-K | 10.8 | 2/29/2012 | 001-05153 |  |  |
|  | Agreement\tgranted\tunder\tMarathon\tOil |  |  |  |  |  |  |
|  | Corporation's\t2007\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan,\teffective\tMay\t30,\t2007 |  |  |  |  |  |  |
| 10.25 | Form\tof\tOfficer\tRestricted\tStock\tAward | 10-K | 10.7 | 2/28/2011 | 001-05153 |  |  |
|  | Agreement\tfor\tSection\t16\tofficers\tgranted |  |  |  |  |  |  |
|  | under\tMarathon\tOil\tCorporation's\t2007 |  |  |  |  |  |  |
|  | Incentive\tCompensation\tPlan,\teffective |  |  |  |  |  |  |
|  | February\t24,\t2010 |  |  |  |  |  |  |
| 10.26 | Form\tof\tPerformance\tUnit\tAward\tAgreement | 10-K | 10.12 | 2/29/2012 | 001-05153 |  |  |
|  | (30\tmonth\tPerformance\tCycle)\tfor\tSection\t16 |  |  |  |  |  |  |
|  | Officers\tgranted\tunder\tMarathon\tOil |  |  |  |  |  |  |
|  | Corporation's\t2007\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan,\teffective\tJuly\t27,\t2011 |  |  |  |  |  |  |
| 10.27 | Form\tof\tPerformance\tUnit\tAward\tAgreement | 10-K | 10.13 | 2/29/2012 | 001-05153 |  |  |
|  | (30\tmonth\tPerformance\tCycle)\tfor\tOfficers |  |  |  |  |  |  |
|  | granted\tunder\tMarathon\tOil\tCorporation's\t2007 |  |  |  |  |  |  |
|  | Incentive\tCompensation\tPlan,\teffective\tJuly\t27, |  |  |  |  |  |  |
|  | 2011 |  |  |  |  |  |  |
| 10.28 | Form\tof\tRestricted\tStock\tAward\tAgreement\tfor | 10-K | 10.27 | 2/26/2010 | 001-05153 |  |  |
|  | Section\t16\tofficers\tgranted\tunder\tMarathon\tOil |  |  |  |  |  |  |
|  | Corporation's\t2007\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan. |  |  |  |  |  |  |
| 10.29 | Form\tof\tNonqualified\tStock\tOption\tAward | 10-K | 10.26 | 2/26/2010 | 001-05153 |  |  |
|  | Agreement\tgranted\tunder\tMarathon\tOil |  |  |  |  |  |  |
|  | Corporation's\t2007\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan |  |  |  |  |  |  |
| 10.30 | Marathon\tOil\tCorporation\t2003\tIncentive | 10-K | 10.9 | 2/26/2010 | 001-05153 |  |  |
|  | Compensation\tPlan,\tEffective\tJanuary\t1,\t2003 |  |  |  |  |  |  |
| 10.31 | Form\tof\tNonqualified\tStock\tOption\twith | 10-K | 10.15 | 2/26/2010 | 001-05153 |  |  |

| Exhibit |  |  | Incorporated	by	Reference | Incorporated	by	Reference |  | Filed | Furnished |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Number | Exhibit\tDescription | Form | Exhibit | Filing\tDate | SEC\tFile\tNo. | Herewith | Herewith |
| 10.32 | Form\tof\tNonqualified\tStock\tOption\twith | 10-K | 10.16 | 2/26/2010 | 001-05153 |  |  |
|  | Tandem\tStock\tAppreciation\tRight\tAward |  |  |  |  |  |  |
|  | Agreement\tfor\tExecutive\tCommittee\tmembers |  |  |  |  |  |  |
|  | granted\tunder\tMarathon\tOil\tCorporation's\t2003 |  |  |  |  |  |  |
|  | Incentive\tCompensation\tPlan,\teffective |  |  |  |  |  |  |
|  | January\t1,\t2003 |  |  |  |  |  |  |
| 10.33 | Form\tof\tNonqualified\tStock\tOption\twith | 10-K | 10.17 | 2/26/2010 | 001-05153 |  |  |
|  | Tandem\tStock\tAppreciation\tRight\tAward |  |  |  |  |  |  |
|  | Agreement\tfor\tOfficers\tgranted\tunder\tMarathon |  |  |  |  |  |  |
|  | Oil\tCorporation's\t2003\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan,\teffective\tJanuary\t1,\t2003 |  |  |  |  |  |  |
| 10.34 | Form\tof\tStock\tAppreciation\tRight\tAward | 10-K | 10.19 | 2/26/2010 | 001-05153 |  |  |
|  | Agreement\tfor\tChief\tExecutive\tOfficer\tgranted |  |  |  |  |  |  |
|  | under\tMarathon\tOil\tCorporation's\t2003 |  |  |  |  |  |  |
|  | Incentive\tCompensation\tPlan,\teffective\tJanuary |  |  |  |  |  |  |
|  | 1,\t2003 |  |  |  |  |  |  |
| 10.35 | Form\tof\tStock\tAppreciation\tRight\tAward | 10-K | 10.20 | 2/26/2010 | 001-05153 |  |  |
|  | Agreement\tfor\tExecutive\tCommittee\tmembers |  |  |  |  |  |  |
|  | granted\tunder\tMarathon\tOil\tCorporation's\t2003 |  |  |  |  |  |  |
|  | Incentive\tCompensation\tPlan,\teffective\tJanuary |  |  |  |  |  |  |
|  | 1,\t2003 |  |  |  |  |  |  |
| 10.36 | Form\tof\tStock\tAppreciation\tRight\tAward | 10-K | 10.21 | 2/26/2010 | 001-05153 |  |  |
|  | Agreement\tfor\tOfficers\tgranted\tunder\tMarathon |  |  |  |  |  |  |
|  | Oil\tCorporation's\t2003\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan,\teffective\tJanuary\t1,\t2003 |  |  |  |  |  |  |
| 10.37 | Form\tof\tNonqualified\tStock\tOption\tAward | 10-K | 10.22 | 2/26/2010 | 001-05153 |  |  |
|  | Agreement\tfor\tOfficers\tgranted\tunder\tMarathon |  |  |  |  |  |  |
|  | Oil\tCorporation's\t2003\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan |  |  |  |  |  |  |
| 10.38 | Form\tof\tOfficer\tRestricted\tStock\tAward | 10-K | 10.23 | 2/26/2010 | 001-05153 |  |  |
|  | Agreement\tgranted\tunder\tMarathon\tOil |  |  |  |  |  |  |
|  | Corporation's\t2003\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan |  |  |  |  |  |  |
| 10.39 | Form\tof\tNonqualified\tStock\tOption\tAward | 10-K | 10.18 | 2/26/2010 | 001-05153 |  |  |
|  | Agreement\tfor\tMAP\tofficers\tgranted\tunder |  |  |  |  |  |  |
|  | Marathon\tOil\tCorporation's\t2003\tIncentive |  |  |  |  |  |  |
|  | Compensation\tPlan,\teffective\tJanuary\t1,\t2003 |  |  |  |  |  |  |
| 10.40 | Marathon\tOil\tCorporation\tDeferred | 10-K | 10.14 | 2/27/2009 | 001-05153 |  |  |
|  | Compensation\tPlan\tfor\tNon-Employee |  |  |  |  |  |  |
|  | Directors\t(Amended\tand\tRestated\tas\tof\tJanuary |  |  |  |  |  |  |
|  | 1,\t2009) |  |  |  |  |  |  |
| 10.41 | Marathon\tOil\tCompany\tDeferred | 10-K | 10.32 | 2/29/2012 | 001-05153 |  |  |
|  | Compensation\tPlan\tAmended\tand\tRestated |  |  |  |  |  |  |
|  | Effective\tJune\t30,\t2011 |  |  |  |  |  |  |
| 10.42 | Marathon\tOil\tCompany\tExcess\tBenefit\tPlan | 10-K | 10.31 | 2/29/2012 | 001-05153 |  |  |
|  | Amended\tand\tRestated |  |  |  |  |  |  |
| 10.43 | Marathon\tOil\tExecutive\tChange\tin\tControl | 10-K | 10.35 | 2/27/2009 | 001-05153 |  |  |

# 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.

February	28,	2014 MARATHON	OIL	CORPORATION

Pursuant	to	the	requirements	of	the	Securities	Exchange	Act	of	1934,	this	report	has	been	signed	below	by	the	following	persons	on	February	28,	2014	on	behalf	of the	registrant	and	in	the	capacities	indicated.

| Exhibit |  |  | Incorporated	by	Reference | Incorporated	by	Reference |  | Filed | Furnished |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Number | Exhibit\tDescription | Form | Exhibit | Filing\tDate | SEC\tFile\tNo. | Herewith | Herewith |
| 2 | Plan\tof\tAcquisition,\tReorganization,\tArrangement,\tLiquidation\tor\tSuccession | Plan\tof\tAcquisition,\tReorganization,\tArrangement,\tLiquidation\tor\tSuccession | Plan\tof\tAcquisition,\tReorganization,\tArrangement,\tLiquidation\tor\tSuccession |  |  |  |  |
| 2.1++ | Separation\tand\tDistribution\tAgreement\tdated\tas | 8-K | 2.1 | 5/26/2011 | 001-05153 |  |  |
|  | of\tMay\t25,\t2011\tamong\tMarathon\tOil |  |  |  |  |  |  |
|  | Corporation,\tMarathon\tOil\tCompany\tand |  |  |  |  |  |  |
|  | Marathon\tPetroleum\tCorporation |  |  |  |  |  |  |
| 3 | \t Articles\tof\tIncorporation\tand\tBylaws |  |  |  |  |  |  |
| 3.1 | Restated\tCertificate\tof\tIncorporation\tof | 10-Q | 3.1 | 8/8/2013 | 001-05153 |  |  |
|  | Marathon\tOil\tCorporation |  |  |  |  |  |  |
| 3.2 | Amended\tBy-Laws\tof\tMarathon\tOil |  |  |  |  | X |  |
|  | Corporation\teffective\tFebruary\t25,\t2014 |  |  |  |  |  |  |
| 3.3 | Specimen\tof\tCommon\tStock\tCertificate |  |  |  |  | X |  |
| 4 | Instruments\tDefining\tthe\tRights\tof\tSecurity\tHolders,\tIncluding\tIndentures | Instruments\tDefining\tthe\tRights\tof\tSecurity\tHolders,\tIncluding\tIndentures | Instruments\tDefining\tthe\tRights\tof\tSecurity\tHolders,\tIncluding\tIndentures |  |  |  |  |
| 4.1 | Credit\tAgreement,\tdated\tas\tof\tApril\t5,\t2012, | 8-K | 4.1 | 4/10/2012 | 001-05153 |  |  |
|  | among\tMarathon\tOil\tCorporation,\tThe\tRoyal |  |  |  |  |  |  |
|  | Bank\tof\tScotland\tplc,\tas\tsyndication\tagent, |  |  |  |  |  |  |
|  | Citibank,\tN.A.,\tMorgan\tStanley\tSenior |  |  |  |  |  |  |
|  | Funding,\tInc.\tand\tUBS\tSecurities\tLLC,\tas |  |  |  |  |  |  |
|  | documentation\tagents,\tJPMorgan\tChase\tBank, |  |  |  |  |  |  |
|  | N.A.,\tas\tadministrative\tagent,\tand\tcertain\tother |  |  |  |  |  |  |
|  | commercial\tlending\tinstitutions\tnamed\ttherein. |  |  |  |  |  |  |
| 4.2 | Indenture,\tdated\tas\tof\tFebruary\t26,\t2002, |  |  |  |  | X |  |
|  | between\tMarathon\tOil\tCorporation\tand\tThe |  |  |  |  |  |  |
|  | Bank\tof\tNew\tYork\tTrust\tCompany,\tN.A., |  |  |  |  |  |  |
|  | successor\tin\tinterest\tto\tJPMorgan\tChase\tBank |  |  |  |  |  |  |
|  | as\tTrustee,\trelating\tto\tsenior\tdebt\tsecurities\tof |  |  |  |  |  |  |
|  | Marathon\tOil\tCorporation.\tPursuant\tto\tCFR |  |  |  |  |  |  |
|  | 229.601(b)(4)(iii),\tinstruments\twith\trespect\tto |  |  |  |  |  |  |
|  | long-term\tdebt\tissues\thave\tbeen\tomitted\twhere |  |  |  |  |  |  |
|  | the\tamount\tof\tsecurities\tauthorized\tunder\tsuch |  |  |  |  |  |  |
|  | instruments\tdoes\tnot\texceed\t10\tpercent\tof\tthe |  |  |  |  |  |  |
|  | total\tconsolidated\tassets\tof\tMarathon\tOil. |  |  |  |  |  |  |
|  | Marathon\tOil\thereby\tagrees\tto\tfurnish\ta\tcopy\tof |  |  |  |  |  |  |
|  | any\tsuch\tinstrument\tto\tthe\tSecurities\tand |  |  |  |  |  |  |
|  | Exchange\tCommission\tupon\tits\trequest. |  |  |  |  |  |  |
| 10 | \t Material\tContracts |  |  |  |  |  |  |
| 10.1 | Tax\tSharing\tAgreement\tdated\tas\tof\tMay\t25, | 8-K | 10.1 | 5/26/2011 | 001-05153 |  |  |
|  | 2011\tamong\tMarathon\tOil\tCorporation, |  |  |  |  |  |  |
|  | Marathon\tPetroleum\tCorporation\tand\tMPC |  |  |  |  |  |  |
|  | Investment\tLLC |  |  |  |  |  |  |
| 10.2 | Employee\tMatters\tAgreement\tdated\tas\tof | 8-K | 10.2 | 5/26/2011 | 001-05153 |  |  |

| Exhibit |  |  | Incorporated	by	Reference | Incorporated	by	Reference |  | Filed | Furnished |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Number | Exhibit\tDescription | Form | Exhibit | Filing\tDate | SEC\tFile\tNo. | Herewith | Herewith |
| 10.3 | Amendment\tto\tEmployee\tMatters\tAgreement | 10-Q | 10.3 | 8/8/2011 | 001-05153 |  |  |
|  | dated\tas\tof\tJune\t30,\t2011\tbetween\tMarathon |  |  |  |  |  |  |
|  | Oil\tCorporation\tand\tMarathon\tPetroleum |  |  |  |  |  |  |
|  | Corporation |  |  |  |  |  |  |
| 10.4 | Marathon\tOil\tCorporation\t2012\tIncentive | DEF\t14A | App.\tIII | 3/8/2012 | 001-05153 |  |  |
|  | Compensation\tPlan |  |  |  |  |  |  |
| 10.5 | Form\tof\tInitial\tCEO\tOption\tGrant\tAgreement | 10-Q | 10.1 | 11/6/2013 | 001-05153 |  |  |
|  | granted\tunder\tMarathon\tOil\tCorporation's\t2012 |  |  |  |  |  |  |
|  | Incentive\tCompensation\tPlan. |  |  |  |  |  |  |
| 10.6 | Form\tof\tCEO\tRestricted\tStock\tAgreement | 10-Q | 10.2 | 11/6/2013 | 001-05153 |  |  |
|  | granted\tunder\tMarathon\tOil\tCorporation's\t2012 |  |  |  |  |  |  |
|  | Incentive\tCompensation\tPlan\t(3-year\tprorata |  |  |  |  |  |  |
|  | vesting). |  |  |  |  |  |  |
| 10.7 | Form\tof\tCEO\tRestricted\tStock\tAward | 10-Q | 10.3 | 11/6/2013 | 001-05153 |  |  |
|  | Agreement\tgranted\tunder\tMarathon\tOil |  |  |  |  |  |  |
|  | Corporation's\t2012\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan\t(3-year\tcliff\tvesting). |  |  |  |  |  |  |
| 10.8 | Marathon\tOil\tCorporation\tBonus\tAgreement | 10-Q | 10.4 | 11/6/2013 | 001-05153 |  |  |
|  | Upon\tCommencement\tof\tEmployment\tfor\tLee |  |  |  |  |  |  |
|  | M.\tTillman. |  |  |  |  |  |  |
| 10.9 | Form\tof\tPerformance\tUnit\tAward\tAgreement | 10-Q | 10.1 | 5/10/2013 | 001-05153 |  |  |
|  | (2013-2015\tPerformance\tCycle)\tfor\tSection\t16 |  |  |  |  |  |  |
|  | Officers\tgranted\tunder\tMarathon\tOil |  |  |  |  |  |  |
|  | Corporation's\t2012\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan |  |  |  |  |  |  |
| 10.10 | Form\tof\tPerformance\tUnit\tAward\tAgreement | 10-Q | 10.2 | 5/10/2013 | 001-05153 |  |  |
|  | (2013-2015\tPerformance\tCycle)\tfor\tOfficers |  |  |  |  |  |  |
|  | granted\tunder\tMarathon\tOil\tCorporation's\t2012 |  |  |  |  |  |  |
|  | Incentive\tCompensation\tPlan |  |  |  |  |  |  |
| 10.11 | Form\tof\tNonqualified\tStock\tOption\tAward | 10-K | 10.5 | 2/22/2013 | 001-05153 |  |  |
|  | Agreement\tfor\tSection\t16\treporting\tOfficers |  |  |  |  |  |  |
|  | granted\tunder\tMarathon\tOil\tCorporation's\t2012 |  |  |  |  |  |  |
|  | Incentive\tCompensation\tPlan\t(3-year\tprorata |  |  |  |  |  |  |
|  | vesting) |  |  |  |  |  |  |
| 10.12 | Form\tof\tNonqualified\tStock\tOption\tAward | 10-K | 10.6 | 2/22/2013 | 001-05153 |  |  |
|  | Agreement\tfor\tOfficers\tgranted\tunder\tMarathon |  |  |  |  |  |  |
|  | Oil\tCorporation's\t2012\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan\t(3-year\tprorata\tvesting) |  |  |  |  |  |  |
| 10.13 | Form\tof\tRestricted\tStock\tAward\tAgreement\tfor | 10-K | 10.7 | 2/22/2013 | 001-05153 |  |  |
|  | Section\t16\treporting\tOfficers\tgranted\tunder |  |  |  |  |  |  |
|  | Marathon\tOil\tCorporation's\t2012\tIncentive |  |  |  |  |  |  |
|  | Compensation\tPlan\t(3-year\tcliff\tvesting) |  |  |  |  |  |  |
| 10.14 | Form\tof\tRestricted\tStock\tAward\tAgreement\tfor | 10-K | 10.8 | 2/22/2013 | 001-05153 |  |  |

| Exhibit |  |  | Incorporated	by	Reference | Incorporated	by	Reference |  | Filed | Furnished |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Number | Exhibit\tDescription | Form | Exhibit | Filing\tDate | SEC\tFile\tNo. | Herewith | Herewith |
| 10.15 | Form\tof\tRestricted\tStock\tAward\tAgreement\tfor | 10-K | 10.9 | 2/22/2013 | 001-05153 |  |  |
|  | Section\t16\treporting\tOfficers\tgranted\tunder |  |  |  |  |  |  |
|  | Marathon\tOil\tCorporation's\t2012\tIncentive |  |  |  |  |  |  |
|  | Compensation\tPlan\t(3-year\tprorata\tvesting) |  |  |  |  |  |  |
| 10.16 | Form\tof\tRestricted\tStock\tAward\tAgreement\tfor | 10-K | 10.10 | 2/22/2013 | 001-05153 |  |  |
|  | Officers\tgranted\tunder\tMarathon\tOil |  |  |  |  |  |  |
|  | Corporation's\t2012\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan\t(3-year\tprorata\tvesting) |  |  |  |  |  |  |
| 10.17 | Form\tof\tNonqualified\tStock\tOption\tAward | 10-K | 10.11 | 2/22/2013 | 001-05153 |  |  |
|  | Agreement\tfor\tnon-officers\tgranted\tunder |  |  |  |  |  |  |
|  | Marathon\tOil\tCorporation's\t2012\tIncentive |  |  |  |  |  |  |
|  | Compensation\tPlan\t(3-year\tprorata\tvesting) |  |  |  |  |  |  |
| 10.18 | Form\tof\tNonqualified\tStock\tOption\tAward | 10-K | 10.12 | 2/22/2013 | 001-05153 |  |  |
|  | Agreement\tfor\tnon-officers\tin\tCanada\tgranted |  |  |  |  |  |  |
|  | under\tMarathon\tOil\tCorporation's\t2012 |  |  |  |  |  |  |
|  | Incentive\tCompensation\tPlan\t(3-year\tprorata |  |  |  |  |  |  |
|  | vesting) |  |  |  |  |  |  |
| 10.19 | Form\tof\tRestricted\tStock\tAward\tAgreement\tfor | 10-K | 10.13 | 2/22/2013 | 001-05153 |  |  |
|  | non-officers\tgranted\tunder\tMarathon\tOil |  |  |  |  |  |  |
|  | Corporation's\t2012\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan\t(3-year\tprorata\tvesting) |  |  |  |  |  |  |
| 10.20 | Form\tof\tRestricted\tStock\tAward\tAgreement\tfor | 10-K | 10.14 | 2/22/2013 | 001-05153 |  |  |
|  | non-officers\tgranted\tunder\tMarathon\tOil |  |  |  |  |  |  |
|  | Corporation's\t2012\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan\t(3-year\tprorata\tvesting) |  |  |  |  |  |  |
| 10.21 | Marathon\tOil\tCorporation\t2007\tIncentive | 10-K | 10.5 | 2/29/2012 | 001-05153 |  |  |
|  | Compensation\tPlan |  |  |  |  |  |  |
| 10.22 | Form\tof\tNonqualified\tStock\tOption\tAward | 10-K | 10.6 | 2/29/2012 | 001-05153 |  |  |
|  | Agreement\tfor\tOfficers\tgranted\tunder\tMarathon |  |  |  |  |  |  |
|  | Oil\tCorporation's\t2007\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan,\teffective\tMay\t30,\t2007 |  |  |  |  |  |  |
| 10.23 | Form\tof\tNonqualified\tStock\tOption\tAward | 10-K | 10.5 | 2/28/2011 | 001-05153 |  |  |
|  | Agreement\tfor\tOfficers\tgranted\tunder\tMarathon |  |  |  |  |  |  |
|  | Oil\tCorporation's\t2007\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan,\teffective\tFebruary\t24,\t2010 |  |  |  |  |  |  |
| 10.24 | Form\tof\tOfficer\tRestricted\tStock\tAward | 10-K | 10.8 | 2/29/2012 | 001-05153 |  |  |
|  | Agreement\tgranted\tunder\tMarathon\tOil |  |  |  |  |  |  |
|  | Corporation's\t2007\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan,\teffective\tMay\t30,\t2007 |  |  |  |  |  |  |
| 10.25 | Form\tof\tOfficer\tRestricted\tStock\tAward | 10-K | 10.7 | 2/28/2011 | 001-05153 |  |  |

| Exhibit |  |  | Incorporated	by	Reference | Incorporated	by	Reference |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Number | Exhibit\tDescription | Form | Exhibit | Filing\tDate | SEC\tFile\tNo. |
| 10.26 | Form\tof\tPerformance\tUnit\tAward | 10-K | 10.12 | 2/29/2012 | 001-05153 |
|  | Agreement\t(30\tmonth\tPerformance |  |  |  |  |
|  | Cycle)\tfor\tSection\t16\tOfficers\tgranted |  |  |  |  |
|  | under\tMarathon\tOil\tCorporation's |  |  |  |  |
|  | 2007\tIncentive\tCompensation\tPlan, |  |  |  |  |
|  | effective\tJuly\t27,\t2011 |  |  |  |  |
| 10.27 | Form\tof\tPerformance\tUnit\tAward | 10-K | 10.13 | 2/29/2012 | 001-05153 |
|  | Agreement\t(30\tmonth\tPerformance |  |  |  |  |
|  | Cycle)\tfor\tOfficers\tgranted\tunder |  |  |  |  |
|  | Marathon\tOil\tCorporation's\t2007 |  |  |  |  |
|  | Incentive\tCompensation\tPlan, |  |  |  |  |
|  | effective\tJuly\t27,\t2011 |  |  |  |  |
| 10.28 | Form\tof\tRestricted\tStock\tAward | 10-K | 10.27 | 2/26/2010 | 001-05153 |
|  | Agreement\tfor\tSection\t16\tofficers |  |  |  |  |
|  | granted\tunder\tMarathon\tOil |  |  |  |  |
|  | Corporation's\t2007\tIncentive |  |  |  |  |
|  | Compensation\tPlan. |  |  |  |  |
| 10.29 | Form\tof\tNonqualified\tStock\tOption | 10-K | 10.26 | 2/26/2010 | 001-05153 |
|  | Award\tAgreement\tgranted\tunder |  |  |  |  |
|  | Marathon\tOil\tCorporation's\t2007 |  |  |  |  |
|  | Incentive\tCompensation\tPlan |  |  |  |  |
| 10.30 | Marathon\tOil\tCorporation\t2003 | 10-K | 10.9 | 2/26/2010 | 001-05153 |
|  | Incentive\tCompensation\tPlan, |  |  |  |  |
|  | Effective\tJanuary\t1,\t2003 |  |  |  |  |
| 10.31 | Form\tof\tNonqualified\tStock\tOption | 10-K | 10.15 | 2/26/2010 | 001-05153 |
|  | with\tTandem\tStock\tAppreciation |  |  |  |  |
|  | Right\tAward\tAgreement\tfor\tChief |  |  |  |  |
|  | Executive\tOfficer\tgranted\tunder |  |  |  |  |
|  | Marathon\tOil\tCorporation's\t2003 |  |  |  |  |
|  | Incentive\tCompensation\tPlan, |  |  |  |  |
|  | effective\tJanuary\t1,\t2003 |  |  |  |  |
| 10.32 | Form\tof\tNonqualified\tStock\tOption | 10-K | 10.16 | 2/26/2010 | 001-05153 |
|  | with\tTandem\tStock\tAppreciation |  |  |  |  |
|  | Right\tAward\tAgreement\tfor |  |  |  |  |
|  | Executive\tCommittee\tmembers |  |  |  |  |
|  | granted\tunder\tMarathon\tOil |  |  |  |  |
|  | Corporation's\t2003\tIncentive |  |  |  |  |
|  | Compensation\tPlan,\teffective |  |  |  |  |
|  | January\t1,\t2003 |  |  |  |  |
| 10.33 | Form\tof\tNonqualified\tStock\tOption | 10-K | 10.17 | 2/26/2010 | 001-05153 |
|  | with\tTandem\tStock\tAppreciation |  |  |  |  |
|  | Right\tAward\tAgreement\tfor\tOfficers |  |  |  |  |
|  | granted\tunder\tMarathon\tOil |  |  |  |  |
|  | Corporation's\t2003\tIncentive |  |  |  |  |
|  | Compensation\tPlan,\teffective\tJanuary |  |  |  |  |
|  | 1,\t2003 |  |  |  |  |
| 10.34 | Form\tof\tStock\tAppreciation\tRight | 10-K | 10.19 | 2/26/2010 | 001-05153 |
|  | Award\tAgreement\tfor\tChief |  |  |  |  |
|  | Executive\tOfficer\tgranted\tunder |  |  |  |  |
|  | Marathon\tOil\tCorporation's\t2003 |  |  |  |  |
|  | Incentive\tCompensation\tPlan, |  |  |  |  |
|  | effective\tJanuary\t1,\t2003 |  |  |  |  |
| 10.35 | Form\tof\tStock\tAppreciation\tRight | 10-K | 10.20 | 2/26/2010 | 001-05153 |

| Exhibit |  |  | Incorporated	by	Reference | Incorporated	by	Reference |  | Filed | Furnished |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Number | Exhibit\tDescription | Form | Exhibit | Filing\tDate | SEC\tFile\tNo. | Herewith | Herewith |
| 10.36 | Form\tof\tStock\tAppreciation\tRight\tAward | 10-K | 10.21 | 2/26/2010 | 001-05153 |  |  |
|  | Agreement\tfor\tOfficers\tgranted\tunder\tMarathon |  |  |  |  |  |  |
|  | Oil\tCorporation's\t2003\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan,\teffective\tJanuary\t1,\t2003 |  |  |  |  |  |  |
| 10.37 | Form\tof\tNonqualified\tStock\tOption\tAward | 10-K | 10.22 | 2/26/2010 | 001-05153 |  |  |
|  | Agreement\tfor\tOfficers\tgranted\tunder\tMarathon |  |  |  |  |  |  |
|  | Oil\tCorporation's\t2003\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan |  |  |  |  |  |  |
| 10.38 | Form\tof\tOfficer\tRestricted\tStock\tAward | 10-K | 10.23 | 2/26/2010 | 001-05153 |  |  |
|  | Agreement\tgranted\tunder\tMarathon\tOil |  |  |  |  |  |  |
|  | Corporation's\t2003\tIncentive\tCompensation |  |  |  |  |  |  |
|  | Plan |  |  |  |  |  |  |
| 10.39 | Form\tof\tNonqualified\tStock\tOption\tAward | 10-K | 10.18 | 2/26/2010 | 001-05153 |  |  |
|  | Agreement\tfor\tMAP\tofficers\tgranted\tunder |  |  |  |  |  |  |
|  | Marathon\tOil\tCorporation's\t2003\tIncentive |  |  |  |  |  |  |
|  | Compensation\tPlan,\teffective\tJanuary\t1,\t2003 |  |  |  |  |  |  |
| 10.40 | Marathon\tOil\tCorporation\tDeferred | 10-K | 10.14 | 2/27/2009 | 001-05153 |  |  |
|  | Compensation\tPlan\tfor\tNon-Employee |  |  |  |  |  |  |
|  | Directors\t(Amended\tand\tRestated\tas\tof\tJanuary |  |  |  |  |  |  |
|  | 1,\t2009) |  |  |  |  |  |  |
| 10.41 | Marathon\tOil\tCompany\tDeferred | 10-K | 10.32 | 2/29/2012 | 001-05153 |  |  |
|  | Compensation\tPlan\tAmended\tand\tRestated |  |  |  |  |  |  |
|  | Effective\tJune\t30,\t2011 |  |  |  |  |  |  |
| 10.42 | Marathon\tOil\tCompany\tExcess\tBenefit\tPlan | 10-K | 10.31 | 2/29/2012 | 001-05153 |  |  |
|  | Amended\tand\tRestated |  |  |  |  |  |  |
| 10.43 | Marathon\tOil\tExecutive\tChange\tin\tControl | 10-K | 10.35 | 2/27/2009 | 001-05153 |  |  |
|  | Severance\tBenefits\tPlan,\teffective\tas\tof |  |  |  |  |  |  |
|  | December\t31,\t2008 |  |  |  |  |  |  |
| 10.44 | First\tAmendment\tto\tthe\tMarathon\tOil | 10-Q | 10.3 | 5/4/2012 | 001-05153 |  |  |
|  | Corporation\tExecutive\tChange\tin\tControl |  |  |  |  |  |  |
|  | Severance\tBenefits\tPlan,\teffective\tOctober\t26, |  |  |  |  |  |  |
|  | 2011. |  |  |  |  |  |  |
| 10.45 | Marathon\tOil\tCorporation\t2011\tOfficer\tChange | 10-Q | 10.4 | 5/4/2012 | 001-05153 |  |  |
|  | in\tControl\tSeverance\tBenefits\tPlan\t(For |  |  |  |  |  |  |
|  | Officers\tHired\tor\tPromoted\tafter\tOctober\t26, |  |  |  |  |  |  |
|  | 2011). |  |  |  |  |  |  |
| 10.46 | Marathon\tOil\tCorporation\tPolicy\tfor | 10-K | 10.10 | 2/28/2011 | 001-05153 |  |  |
|  | Repayment\tof\tAnnual\tCash\tBonus\tAmounts |  |  |  |  |  |  |
| 10.47 | Marathon\tOil\tExecutive\tTax,\tEstate,\tand | 10-K | 10.32 | 2/27/2009 | 001-05153 |  |  |
|  | Financial\tPlanning\tProgram,\tAmended\tand |  |  |  |  |  |  |
|  | Restated,\tEffective\tJanuary\t1,\t2009 |  |  |  |  |  |  |
| 10.48 | Form\tof\tPerformance\tUnit\tAward\tAgreement | 10-Q | 10.2 | 5/4/2012 | 001-05153 |  |  |
|  | (2012-2014\tPerformance\tCycle)\tgranted\tunder |  |  |  |  |  |  |
|  | Marathon\tOil\tCorporation's\t2007\tIncentive |  |  |  |  |  |  |
|  | Compensation\tPlan. |  |  |  |  |  |  |
| 12.1 | Computation\tof\tRatio\tof\tEarnings\tto\tFixed |  |  |  |  | X |  |
|  | Charges |  |  |  |  |  |  |
| 14.1 | Code\tof\tEthics\tfor\tSenior\tFinancial\tOfficers | 10-K | 14.1 | 2/26/2010 | 001-05153 |  |  |
| 21.1 | List\tof\tSignificant\tSubsidiaries |  |  |  |  | X |  |

| Exhibit |  |  | Incorporated	by	Reference | Incorporated	by	Reference |  | Filed | Furnished |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Number | Exhibit\tDescription | Form | Exhibit | Filing\tDate | SEC\tFile\tNo. | Herewith | Herewith |
| 23.1 | Consent\tof\tIndependent\tRegistered\tPublic |  |  |  |  | X |  |
|  | Accounting\tFirm |  |  |  |  |  |  |
| 23.2 | Consent\tof\tGLJ\tPetroleum\tConsultants\tLTD., |  |  |  |  | X |  |
|  | independent\tpetroleum\tengineers\tand\tgeologists |  |  |  |  |  |  |
| 23.3 | Consent\tof\tRyder\tScott\tCompany,\tL.P., |  |  |  |  | X |  |
|  | independent\tpetroleum\tengineers\tand\tgeologists |  |  |  |  |  |  |
| 23.4 | Consent\tof\tNetherland,\tSewell\t&amp;\tAssociates, |  |  |  |  | X |  |
|  | Inc.,\tindependent\tpetroleum\tengineers\tand |  |  |  |  |  |  |
|  | geologists |  |  |  |  |  |  |
| 31.1 | Certification\tof\tPresident\tand\tChief\tExecutive |  |  |  |  | X |  |
|  | Officer\tpursuant\tto\tRule\t13(a)-14\tand\t15(d)-14 |  |  |  |  |  |  |
|  | under\tthe\tSecurities\tExchange\tAct\tof\t1934 |  |  |  |  |  |  |
| 31.2 | Certification\tof\tExecutive\tVice\tPresident\tand |  |  |  |  | X |  |
|  | Chief\tFinancial\tOfficer\tpursuant\tto\tRule\t13(a)- |  |  |  |  |  |  |
|  | 14\tand\t15(d)-14\tunder\tthe\tSecurities\tExchange |  |  |  |  |  |  |
|  | Act\tof\t1934 |  |  |  |  |  |  |
| 32.1 | Certification\tof\tPresident\tand\tChief\tExecutive |  |  |  |  | X |  |
|  | Officer\tpursuant\tto\t18\tU.S.C.\tSection\t1350 |  |  |  |  |  |  |
| 32.2 | Certification\tof\tExecutive\tVice\tPresident\tand |  |  |  |  | X |  |
|  | Chief\tFinancial\tOfficer\tpursuant\tto\t18\tU.S.C. |  |  |  |  |  |  |
|  | Section\t1350 |  |  |  |  |  |  |
| 99.1 | Report\tof\tGLJ\tPetroleum\tConsultants\tLTD., |  |  |  |  | X |  |
|  | independent\tpetroleum\tengineers\tand\tgeologists |  |  |  |  |  |  |
|  | for\t2013 |  |  |  |  |  |  |
| 99.2 | Report\tof\tGLJ\tPetroleum\tConsultants\tLTD., | 10-K | 99.1 | 2/22/2013 | 001-05153 |  |  |
|  | independent\tpetroleum\tengineers\tand\tgeologists |  |  |  |  |  |  |
|  | for\t2012 |  |  |  |  |  |  |
| 99.3 | Report\tof\tGLJ\tPetroleum\tConsultants\tLTD., | 10-K | 99.1 | 2/29/2012 | 001-05153 |  |  |
|  | independent\tpetroleum\tengineers\tand\tgeologists |  |  |  |  |  |  |
|  | for\t2011 |  |  |  |  |  |  |
| 99.4 | Summary\treport\tof\taudits\tperformed\tby |  |  |  |  | X |  |
|  | Netherland,\tSewell\t&amp;\tAssociates,\tInc., |  |  |  |  |  |  |
|  | independent\tpetroleum\tengineers\tand\tgeologists |  |  |  |  |  |  |
|  | for\t2013 |  |  |  |  |  |  |
| 99.5 | Summary\treport\tof\taudits\tperformed\tby | 10-K | 99.4 | 2/22/2013 | 001-05153 |  |  |
|  | Netherland,\tSewell\t&amp;\tAssociates,\tInc., |  |  |  |  |  |  |
|  | independent\tpetroleum\tengineers\tand\tgeologists |  |  |  |  |  |  |
|  | for\t2012 |  |  |  |  |  |  |
| 99.6 | Summary\treport\tof\taudits\tperformed\tby | 10-K | 99.4 | 2/29/2012 | 001-05153 |  |  |
|  | Netherland,\tSewell\t&amp;\tAssociates,\tInc., |  |  |  |  |  |  |
|  | independent\tpetroleum\tengineers\tand\tgeologists |  |  |  |  |  |  |
|  | for\t2011 |  |  |  |  |  |  |
| 99.7 | Summary\treport\tof\taudits\tperformed\tby\tRyder |  |  |  |  | X |  |
|  | Scott\tCompany,\tL.P.,\tindependent\tpetroleum |  |  |  |  |  |  |
|  | engineers\tand\tgeologists\tfor\t2013 |  |  |  |  |  |  |
| 99.8 | Summary\treport\tof\taudits\tperformed\tby\tRyder | 10-K | 99.6 | 2/22/2013 | 001-05153 |  |  |

# ++ 	 Marathon	Oil	agrees	to	furnish	supplementally	a	copy	of	any	omitted	schedule	to	the	SEC	upon	request.



Question: by what percentage did the average price of wti crude oil increase from 2011 to 2013?
Calculation: wti_crude_oil_price = 98.05
benchmark_price = 95.11
percent_increase = (wti_crude_oil_price - benchmark_price) / benchmark_price
answer = percent_increase * 100
Answer: 3.1%