# Table	of	Contents

# 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,	2011

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

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

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		þ

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

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

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

Indicate	by	check	mark	whether	the	registrant	is	a	large	accelerated	filer,	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.	(Check	one):

Large	accelerated	filer		þ				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		þ

The	aggregate	market	value	of	Common	Stock	held	by	non-affiliates	as	of	June	30,	2011:	$22,773	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	703,925,642	shares	of	Marathon	Oil	Corporation	Common	Stock	outstanding	as	of	January	31,	2012.

Documents	Incorporated	By	Reference:

Portions	of	the	registrant's	proxy	statement	relating	to	its	2012	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).

# DEFINITIONS

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

AMPCO	–	Atlantic	Methanol	Production	Company	LLC,	a	company	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	U.S.	gallons	liquid	volume.

bbld	–	barrels	per	day.

bboe	–	Billion	barrels	of	oil	equivalent.	Natural	gas	is	converted	to	a	boe	based	on	the	energy	equivalent,	which	on	a	dry	gas	basis	is	six	mcf	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	equivalency	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	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.

# EG	–	Equatorial	Guinea.

EGHoldings	–	Equatorial	Guinea	LNG	Holdings	Limited,	an	LNG	production	company	located	in	Equatorial	Guinea	in	which	we	own	a	60	percent	equity	interest.

E&P	–	Our	Exploration	and	Production	segment	which	explores	for,	produces	and	markets	liquid	hydrocarbons	and	natural	gas	on	a	worldwide	basis.

# 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	gas	in	an	unproved	area,	find	a	new	reservoir	in	a	field	previously	found	to	be	productive	in	another	reservoir,	or	extend	a known	reservoir.

FASB	–	Financial	Accounting	Standards	Board.

Farmout	–	An	assignment	of	an	interest	in	a	drilling	location	and	related	acreage	conditional	upon	the	drilling	of	a	well	on	that	location.

FPSO	–	Floating	production,	storage	and	offloading	vessel.

IASB	–	International	Accounting	Standards	Board.

IFRS	–	International	Financial	Reporting	Standards.

IG	–	Our	Integrated	Gas	segment	which	produces	and	markets	products	manufactured	from	natural	gas,	such	as	LNG	and	methanol,	in	EG.

IP	–	Average	daily	rate	of	production	from	a	well	in	the	initial	30	days	of	its	operation,	which	may	not	be	indicative	of	the	rate	of	future	production.

IRS	–	U.S.	Internal	Revenue	Service.

KRG	–	Kurdistan	Regional	Government.

LNG	–	Liquefied	natural	gas.

LPG	–	Liquefied	petroleum	gas.

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	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.

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.

# 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.

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	oil,	natural	gas	and	synthetic	crude	oil	reserves	are	those	quantities	of	oil,	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	in	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	oil	and	gas produced.

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

SAGE	–	U.K.	Scottish	Area	Gas	Evacuation	system	composed	of	a	pipeline	and	processing	terminal.

SEC	–	U.S.	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).

# 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.

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	typically	burdened	by	overriding	royalty	interest	or other	interests.

WTI	–	West	Texas	Intermediate	crude	oil,	an	index	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	Report	may	include,	but	are	not	limited	to,	levels	of	revenues,	income	from	operations,	net	income	or	earnings	per	share;	levels of	capital,	exploration,	environmental	or	maintenance	expenditures;	the	success	or	timing	of	completion	of	ongoing	or	anticipated	capital,	exploration	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;	the	potential	effect	of	judicial	proceedings	on	our	business	and	financial	condition;	levels	of	common	share	repurchases;	and	the	anticipated	effects	of actions	of	third	parties	such	as	competitors,	or	federal,	foreign,	state	or	local	regulatory	authorities.

# PART	I

# Item	1.	Business

# General

Marathon	Oil	Corporation	was	incorporated	in	2001	and	is	an	international	energy	company	engaged	in	exploration	and	production,	oil	sands	mining	and	integrated gas	with	operations	in	the	United	States,	Angola,	Canada,	Equatorial	Guinea,	Indonesia,	the	Iraqi	Kurdistan	Region,	Libya,	Norway,	Poland	and	the	United	Kingdom. We	are	based	in	Houston,	Texas	with	our	corporate	headquarters	at	5555	San	Felipe	Road,	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 shareholders	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.	Fractional	shares	of	MPC	common	stock	were	not	distributed	and	any	fractional	share	of	MPC	common	stock	otherwise	issuable	to	a	Marathon	shareholder	was sold	in	the	open	market	on	such	shareholder's	behalf,	and	such	shareholder	received	a	cash	payment	with	respect	to	that	fractional	share.	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	in	all periods	 presented	 in	 this	Annual	 Report	 on	 Form	 10-K,	 with	 additional	 information	 in	 Item	 8.	 Financial	 Statements	 and	 Supplementary	 Data	 –	 Note	 3	 to	 the consolidated	financial	statements.

# Strategy	and	Results	Summary

Assets	within	our	three	segments	are	at	various	stages	in	their	lifecycle:	base,	growth	or	exploration.	We	have	a	stable	group	of	base	assets,	which	include	our OSM	and	IG	segments	and	E&P	assets	in	Norway,	Equatorial	Guinea,	Libya,	the	U.K.	and	the	U.S.	These	assets	generate	much	of	the	cash	that	will	be	available	for investment	in	our	growth	assets	and	exploration	projects.	Growth	assets	are	where	we	expect	to	make	significant	investment	in	order	to	realize	oil	and	gas	production and	reserve	increases.	We	are	focused	on	U.S.	liquid	hydrocarbon	growth	by	developing	liquids-rich	shale	play	positions,	including	most	recently	the	establishment	of	a strong	position	in	the	core	of	the	Eagle	Ford	shale	play.	In	addition	to	the	U.S.	shale	plays,	growth	assets	include	the	development	of	Angola	Block	31,	our	discoveries in	the	Iraqi	Kurdistan	Region,	select	Gulf	of	Mexico	blocks	and	our	Canadian	in-situ	assets.	Our	areas	of	exploration	are	Poland,	the	Iraqi	Kurdistan	Region,	Norway and	the	Gulf	of	Mexico.	We	continually	evaluate	ways	to	optimize	our	portfolio	through	acquisitions	and	divestitures,	with	a	previously	stated	goal	of	divesting	between $1.5	and	$3.0	billion	of	non-core	assets	between	2011	and	2013.	Through	January	2012,	we	closed	such	transaction	having	values	of	$640	million.

We	ended	2011	with	proved	reserves	of	1.8	bboe,	an	10	percent	increase	over	2010.	Average	sales	volumes	were	219	mbbld	of	liquid	hydrocarbon,	866	mmcfd	of natural	gas	and	43	mbbld	of	synthetic	crude	oil,	with	66	percent	of	our	liquid	hydrocarbon	sales	volumes	from	international	operations,	for	which	average	realizations have	exceeded	WTI	prices.	We	invested	in	the	development	of	assets	in	all	our	segments,	totaling	$3.4	billion	in	capital	expenditures	related	to	continuing	operations	for the	year,	with	$3	billion	related	to	our	E&P	segment.	We	expect	continued	capital	expenditures,	primarily	funded	with	cash	flow	from	operations,	in	exploration	and development	activities	in	order	to	realize	continued	reserve	and	sales	growth.	See	Item	7.	Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of Operations-Outlook,	for	discussion	of	our	$4.8	billion	capital	spending	budget	for	2012.

The	above	discussion	of	strategy	and	results	includes	forward-looking	statements	with	respect	to	the	goal	of	divesting	between	$1.5	and	$3.0	billion	of	non-core assets	between	2011	and	2013	and	expected	investment	in	exploration	and	development	activities.	Some	factors	that	could	potentially	affect	the	divestiture	of	non-core assets	and	expected	investment	in	exploration	and	development	activities	include	changes	in	prices	of	and	demand	for	liquid	hydrocarbons	and	natural	gas,	actions	of competitors,	occurrence	of	acquisitions	or	dispositions	of	oil	and	natural	gas	properties,	future	financial	condition	and	operating	results,	and	economic,	and/or	regulatory factors	affecting	our	businesses,	the	identification	of	buyers	and	the	negotiation	of	acceptable	prices	and	other	terms,	as	well	as	other	customary	closing	conditions.	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.

# Exploration	and	Production	Segment

In	the	discussion	that	follows	regarding	our	exploration	and	production	operations,	references	to	net	wells,	sales	or	investment	indicate	our	ownership	interest	or share,	as	the	context	requires.

We	are	engaged	in	oil	and	gas	exploration,	development	and/or	production	activities	in	the	United	States,	Angola,	Canada,	Equatorial	Guinea,	Indonesia,	the	Iraqi Kurdistan	Region,	Libya,	Norway,	Poland,	and	the	United	Kingdom.

# Liquids-Rich	Shale	Plays

Eagle	Ford	–	In	the	fourth	quarter	of	2011,	we	closed	several	acquisitions	in	the	Eagle	Ford	shale	play	of	south	Texas	for	a	total	cash	consideration	of	$4.5	billion. See	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	5	to	the	consolidated	financial	statements	for	additional	information	about	these	acquisitions.

Upon	finalization	of	the	2011	Eagle	Ford	acquisition	transactions,	we	will	have	just	over	300,000	net	acres	in	the	Eagle	Ford	shale	with	an	average	working	interest of	approximately	80	percent.	As	of	December	31,	2011,	we	had	14	operated	drilling	rigs	active	in	the	play,	with	plans	to	increase	to	18	drilling	rigs	and	4	dedicated hydraulic	fracturing	crews	by	the	end	of	2012.	Our	plans	include	drilling	and	completing	200	–	230	gross	(160	–	185	net)	operated	wells	in	2012.

Including	the	impact	of	our	fourth	quarter	2011	acquisitions,	annual	net	sales	for	2011	were	2	mboed,	with	a	December	exit	rate	of	13	mboed.	Our	production	from the	Eagle	Ford	shale	is	either	sold	at	the	lease	or	moved	via	truck	or	pipeline	to	markets.	We	own	and	operate	the	Sugarloaf	gathering	system,	a	42-mile	natural	gas pipeline	through	the	heart	of	our	recently	purchased	acreage	in	Karnes,	Atascosa,	and	Bee	Counties	of	south	Texas.	Our	future	production	estimates	will	require additional	markets,	transportation,	storage	and	plant	processing	to	be	either	contracted	or	constructed	and	a	variety	of	negotiations	are	underway	with	a	goal	of	continued access	to	adequate	infrastructure	and	markets.	Key	considerations	in	this	development	will	be	the	timing	of	contract	availability	and	efforts	to	receive	optimal	price	based upon	delivery	location.

Bakken	–	We	hold	just	over	400,000	net	acres	in	the	Bakken	shale	oil	play	in	the	Williston	Basin	of	North	Dakota	and	eastern	Montana	with	an	average	working interest	in	the	acreage	of	approximately	80	percent.	Throughout	2011,	we	continued	selective	acreage	acquisitions	and	leasing,	adding	approximately	40,000	net	acres which	expanded	to	a	new	prospect	area.	In	2011	we	drilled	61	gross	(55	net)	operated	wells	and	completed	71	gross	(63	net)	operated	wells.	We	also	moved	from	20- stage	to	30-stage	hydraulic	fracturing,	which	increases	both	production	rates	and	estimated	ultimate	recovery	from	the	wells.	At	December	31,	2011,	we	had	7	operated drilling	rigs	and	2	dedicated	hydraulic	fracturing	crews	in	our	Bakken	shale	program,	and	expect	to	add	one	more	rig	in	2012	to	accomplish	plans	to	drill	69	gross	(53 net)	and	complete	72	–	84	gross	(53	–	61	net)	operated	wells	in	2012.

Our	net	sales	from	the	Bakken	shale	averaged	17	mboed	in	2011,	a	36	percent	increase	over	2010,	and	our	production	exit	rate	for	2011	was	24	mboed.	We	sell	our Bakken	production	into	local	markets	predominately	via	trucking.	A	variety	of	negotiations	are	underway	to	provide	adequate	infrastructure	and	markets	for	our	future estimated	production	levels,	including	the	potential	export	of	volumes	from	the	regional	markets	via	pipeline	or	rail	projects.

Anadarko	 Woodford	–	 In the	Anadarko	Woodford	 shale	 play	 in	 Oklahoma,	 we	 hold	 160,000	 net	 acres	 of	 which	 approximately	 100,000	 acres	 are	 held	 by production.	In	2011,	we	executed	an	operated	drilling	program	focused	on	the	liquids-rich	areas	of	the	play,	drilling	15	gross	(11	net)	exploration	and	8	gross	(6	net) development	wells,	of	which	11	gross	(9	net)	wells	were	completed.

The	Shi	Randall	well,	in	which	we	hold	a	50	percent	working	interest,	was	completed	in	the	third	quarter	of	2011.	The	Shi	Randall	had	a	gross	IP	of	455	bbld	of liquid	hydrocarbons	and	6	mmcfd	of	natural	gas,	subject	to	pipeline	constraints.	It	was	one	of	the	initial	wells	in	the	Knox	area	(southern	Woodford)	and	is	helping	to prove	up	a	prospective	area	where	we	have	a	strong	acreage	position.

The	Anadarko	Woodford	shale	averaged	net	sales	of	2	mboed	during	2011.	In	2012,	we	plan	to	maintain	our	current	level	of	6	rigs	and	drill	35	–	40	gross	(19	–	22 net)	operated	wells	with	more	focus	on	development	drilling.	Outside-operated	projects	could	add	an	additional	30	–	50	gross	(6	–	10	net)	wells.	See	below	for	additional discussion	of	our	conventional,	primarily	natural	gas	production	operations	in	Oklahoma.

DJ	 Basin	–	In	2010,	we	began	leasing	in	the	Niobrara	play	in	the	DJ	Basin	of	northern	Colorado	and	southeast	Wyoming	and	built	an	acreage	position	of approximately	180,000	acres.	In	April	2011,	we	farmed-out	a	30	percent	undivided	working	interest	retaining	70	percent	and	operatorship.	See	Item	8.	Financial Statements	and	Supplementary	Data	–	Note	6	to	the	consolidated	financial	statements	for	additional	information	regarding	this	transaction.	As	of	December	31,	2011	we hold	151,000	net	acres.	In	2011,	we	drilled	a	total	of	12	gross	(7	net)	operated	wells,	with	four	gross	(two	net)	operated	wells	completed.	We	are	currently	operating	2 drilling	rigs	in	the	DJ	Basin	and	expect	to	drill	25	–	35	gross	(13	–	19	net)	operated	wells	in	2012.	Outside-operated	projects	could	add	an	additional	25	–	35	gross	(4	–	5 net)	wells.	We	exited	December	with	a	net	production	rate	of	86	boed.	We	have	other	natural	gas	assets	in	Colorado	which	are	discussed	below.

# United	States

Alaska	–	We	produce	natural	gas	in	the	Cook	Inlet	and	adjacent	Kenai	Peninsula	of	Alaska	where	we	have	operated	and	outside-operated	interests	in	10	fields covering	118,000	net	acres.	In	2011,	we	drilled	1	operated	well	in	the	Ninilchik	field	and	participated	in	1	non-operated	horizontal	well	in	the	McArthur	River	field,	both in	the	Cook	Inlet.	Plans	for	2012	include	continued	investments	in	production	optimization	and	operational	reliability.

Net	natural	gas	sales	from	Alaska	averaged	94	mmcfd	in	2011.	Typically,	our	natural	gas	sales	from	Alaska	are	seasonal	in	nature,	trending	down	during	the	second and	third	quarters	of	each	year	and	increasing	during	the	fourth	and	first	quarters.	To	manage	supplies	to	meet	contractual	demand	we	produce	and	store	natural	gas	in	a partially	depleted	reservoir	in	the	Kenai	natural	gas	field.

Complementing	our	production	operations	in	Alaska	is	our	majority	ownership	in	four	operated	natural	gas	pipelines	totaling	140	miles.	These	are	bidirectional systems	providing	transportation	from	multiple	producers	to	numerous	end	users	in	and	around	the	Cook	Inlet.

Colorado	–	We	hold	leases	of	8,700	net	acres	with	natural	gas	production	in	the	Piceance	Basin	of	Colorado,	located	in	the	Greater	Grand	Valley	field	complex, with	net	sales	of	20	mmcfd	in	2011.	Currently	the	field	has	77	gross/net	wells	producing.

Oklahoma	–	We	have	long-established	operated	and	non-operated	conventional	production	operations	in	several	Oklahoma	fields	from	which	2011	sales	averaged	2 mbbld	of	liquid	hydrocarbons	and	53	mmcfd	of	natural	gas.	In	2011	we	participated	in	7	gross	(2	net),	non-operated	wells	in	the	state.	We	also	drilled	1	company operated	well.	Plans	for	2012	include	11	gross	(2	net)	wells,	targeting	liquids.

Texas/North	Louisiana/New	Mexico	–	In	east	Texas	and	north	Louisiana,	we	hold	184,000	net	acres.	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	3	gross	(1	net)	non-operated	wells	in	the	area	during 2011.	Conventional	production	was	primarily	from	the	Mimms	Creek,	Pearwood	and	Oletha	fields,	in	2011.	Net	sales	from	east	Texas	and	north	Louisiana	averaged	7 mboed.

We	also	participate	in	several	outside-operated	Permian	Basin	fields	in	west	Texas	and	New	Mexico.	Net	sales	from	this	area	were	7	mboed	in	2011.	Activity	in 2012	will	center	around	carbon	dioxide	flood	programs	in	the	Seminole	and	Vacuum	fields.

Wyoming	–	We	hold	260,000	net	acres	in	Wyoming	and	have	almost	100	years	of	exploration	and	development	in	the	state.	We	have	ongoing	enhanced	oil	recovery projects	at	the	mature	Bighorn	Basin	and	Wind	River	Basin	fields	and	initiated	an	additional	enhanced	recovery	project	at	our	100	percent	owned	and	operated	Pitchfork field	in	2011.	We	have	conventional	natural	gas	operations	in	the	Greater	Green	River	Basin	and	unconventional	coal	bed	natural	gas	operations	in	the	Powder	River Basin.	In	2011,	we	drilled	17	gross	(17	net)	operated	development	wells	in	Wyoming,	which	included	five	wellbore	re-entries	and	plan	3	–	4	gross	(3	–	4	net)	operated wells	in	2012.	Our	Wyoming	sales	averaged	17	mbbld	of	liquid	hydrocarbons	and	75	mmcfd	of	natural	gas	during	2011.	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.

West	Virginia/Pennsylvania	–	In	the	Appalachian	Basin	we	hold	82,000	net	acres	in	the	Marcellus	shale	natural	gas	play	in	Pennsylvania	and	West	Virginia.	In February	2011,	we	entered	into	a	joint	venture	on	a	large	portion	of	our	Marcellus	shale	acreage	position.	Under	the	agreement	which	ends	in	2012,	our	joint	venture partner	will	earn	50	percent	of	approximately	60,000	acres	under	a	drilling	carry	and	has	an	option	to	acquire	our	remaining	acreage	while	we	retain	the	rights	to continue	to	market	the	acreage	to	others.	In	2011,	2	gross	(1	net)	outside-operated	wells	were	drilled	with	1	gross	(0.5	net)	well	awaiting	completion.	We	expect	to participate	in	4	gross	(2	net)	wells	in	2012.

# Gulf	of	Mexico	–	Production

On	December	31,	2011,	we	held	material	interests	in	seven	producing	fields,	four	of	which	are	company-operated.

We	operate	and	have	a	65	percent	working	interest	in	the	Ewing	Bank	Block	873	platform	which	is	located	130	miles	south	of	New	Orleans,	Louisiana.	The platform	started	operations	in	1994	and	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	own	a	50	percent	working	interest	in	the	outside-operated	Petronius	field	on	Viosca	Knoll	Blocks	786	and	830	located	130	miles	southeast	of	New	Orleans, which	includes	six	producing	wells.	The	Petronius	platform	is	capable	of	providing	processing	and	transportation	services	to	nearby	third-party	fields.	During	2012,	we plan	to	acquire	seismic	data	in	order	to	identify	future	drilling	opportunities.

We	hold	a	30	percent	working	interest	in	the	outside-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.	Additional	drilling	and	recompletion	activity	is	being	considered	for	2012.

We	have	a	100	percent	operated	working	interest	and	an	81	percent	net	revenue	interest	in	the	Droshky	development	located	on	Green	Canyon	Block	244	off	the coast	of	Louisiana.	This	development	began	production	in	mid-July	of	2010	and	reached	peak	net	production	of	45	mboed	in	the	third	quarter	of	2010.	The	field	will	be produced	to	abandonment	pressures	which	are	expected	to	be	reached	in	the	first	half	of	2012.

We	hold	a	68	percent	working	interest	in	Ozona.	Development	of	our	operated	Ozona	prospect,	located	on	Garden	Banks	Block	515,	was	delayed	by	the	Drilling Moratorium	(discussed	below)	and	subsequent	regulatory	changes.	In	2011,	we	completed	the	Ozona	well	as	a	single	zone	producer	tied	back	to	a	non-operated	host platform.	First	production	began	in	late	December	2011.

Average	net	sales	for	2011	from	the	Gulf	of	Mexico	were	30	mbbld	of	liquid	hydrocarbons	and	24	mmcfd	of	natural	gas.

We	also	own	a	34	percent	outside-operated	interest	in	the	Neptune	gas	plant	located	onshore	Louisiana.	This	high	efficiency	gas	plant,	which	services	four	high pressure	offshore	and	onshore	pipelines,	has	a	650	mmcfd	capacity.

# Gulf	of	Mexico	–	Exploration

We	have	21	prospects,	16	of	which	are	operated	in	the	Gulf	of	Mexico.	As	a	result	of	an	explosion	and	significant	spill	from	a	deepwater	rig	in	the	Gulf	of	Mexico, the	U.S.	Department	of	the	Interior	issued	a	drilling	moratorium	on	May	30,	2010	("Drilling	Moratorium"),	to	suspend	the	drilling	of	deepwater	wells,	and	prohibit drilling	any	new	deepwater	wells

(defined	as	greater	than	500	foot	water	depth).	The	Drilling	Moratorium	was	lifted	on	October	12,	2010.	Our	first	exploration	plan	approval	was	received	in	August 2011.	In	2011,	we	received	lease	extensions	for	26	blocks	in	the	Gulf	of	Mexico	which	had	been	impacted	by	the	Drilling	Moratorium.

A	successful	deepwater	oil	discovery	well	was	drilled	on	the	Gunflint	prospect	located	on	Mississippi	Canyon	Block	948,	160	miles	southeast	of	New	Orleans	in 2008.	We	own	a	15.25	percent	interest	in	this	outside-operated	prospect.	Gunflint	prospect	appraisal	wells	were	subject	to	the	Drilling	Moratorium.	Drilling	of	the	first appraisal	well	began	in	December	2011,	and	a	second	appraisal	well	is	planned	for	mid-year	2012.

In	the	first	quarter	of	2009,	we	participated	in	a	deepwater	oil	discovery	on	the	Shenandoah	prospect	located	on	Walker	Ridge	Block	52.	We	own	a	10	percent interest	in	this	outside-operated	prospect.	The	first	appraisal	well	is	planned	for	mid-year	2012.

In	March	2011,	we	completed	our	evaluation	of	the	Flying	Dutchman	exploratory	well,	located	on	Green	Canyon	Block	511.	We	determined	that	the	options	to develop	were	not	viable	and	all	well	costs	have	been	expensed.

In	accordance	with	the	federal	government's	Drilling	Moratorium,	we	temporarily	suspended	drilling	an	exploratory	well	on	the	Innsbruck	prospect	located	on Mississippi	Canyon	Block	993	at	a	depth	of	19,800	feet	as	compared	to	a	proposed	total	depth	of	29,500	feet.	In	2011,	we	received	approval	for	our	current	exploration plan	from	the	BOEMRE.	We	have	contracted	a	rig	for	this	project	and	drilling	is	expected	to	commence	in	the	third	quarter	of	2012.	In	December	2011,	we	assigned	a 40	percent	interest	in	the	portion	of	Mississippi	Canyon	Block	993	that	includes	Innsbruck,	in	exchange	for	a	30	percent	non-operated	interest	in	Green	Canyon	Blocks 403	and	404	in	the	Kilchurn	prospect	plus	reimbursement	of	certain	well	costs	incurred	to	date	on	Innsbruck.	We	now	have	a	45	percent	working	interest	in	Innsbruck and	continue	to	operate	the	prospect.	The	operator	commenced	drilling	on	the	Kilchurn	prospect	in	December	2011.

In	October	2011,	we	received	approval	of	an	exploration	plan	from	the	BOEMRE	for	the	Key	Largo	prospect	located	on	Walker	Ridge	Block	578.	We	have	a	60 percent	working	interest	and	are	the	operator	of	this	prospect.	Drilling	is	expected	in	the	second	half	of	2012.

# Africa

Equatorial	Guinea	–	We	own	a	63	percent	operated	working	interest	under	a	PSC	in	the	Alba	field	which	is	offshore	EG.	During	2011,	EG	net	liquid	hydrocarbon sales	averaged	38	mbbld,	and	net	natural	gas	sales	were	443	mmcfd.	Planned	maintenance	in	EG	is	scheduled	for	a	28-day	period	from	late	first	quarter	through	early second	quarter	2012,	with	operations	expected	to	be	completely	shut	down	for	eight	of	those	days.

We	hold	a	63	percent	operated	working	interest	in	the	Deep	Luba	discovery	on	the	Alba	Block	and	we	are	the	operator	with	a	90	percent	interest	in	the	Corona	well on	Block	D.	These	wells	are	part	of	our	long-term	LNG	strategy.	We	expect	these	discoveries	to	be	developed	when	the	natural	gas	supply	from	the	nearby	Alba	field starts	to	decline.

We	also	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	the	natural	gas	in	its	operations.	During	2011,	a	gross	890	mmcfd	of	natural	gas	was	supplied	to	the	LPG	production	facility	and	4	mbbld	of secondary	condensate	and	11	mbbld	of	LPG	were	produced	by	Alba	Plant	LLC.	Our	share	of	the	income	ultimately	generated	by	the	subsequent	export	of	secondary condensate	and	LPG	produced	by	Alba	Plant	LLC	is	reflected	in	our	E&P	segment.

As	part	of	our	Integrated	Gas	segment,	we	own	45	percent	of	AMPCO	and	60	percent	of	EGHoldings,	both	of	which	are	accounted	for	as	equity	method investments.	AMPCO	operates	a	methanol	plant	and	EGHoldings	operates	an	LNG	production	facility,	both	located	on	Bioko	Island.	Dry	natural	gas	from	the	Alba field,	which	remains	after	the	condensate	and	LPG	are	removed	by	Alba	Plant	LLC,	is	supplied	to	both	of	these	facilities	under	long-term	contracts	at	fixed	prices. Because	of	the	location	of	and	limited	local	demand	for	natural	gas	in	Equatorial	Guinea,	we	consider	the	prices	under	the	contracts	with	Alba	Plant	LLC,	AMPCO	and EGHoldings	to	be	comparable	to	the	price	that	could	be	realized	from	transactions	with	unrelated	parties	in	this	market	under	the	same	or	similar	circumstances.	Our share	of	the	income	ultimately	generated	by	the	subsequent	export	of	methanol	produced	by	AMPCO	and	LNG	produced	by	EGHoldings	is	reflected	in	our	Integrated Gas	segment	as	discussed	below.	During	2011,	a	gross	127	mmcfd	of	dry	natural	gas	was	supplied	to	the	methanol	plant	and	a	gross	668	mmcfd	of	dry	gas	was	supplied to	the	LNG	production	facility.	Any	remaining	dry	gas	is	returned	offshore	and	reinjected	into	the	Alba	field	for	later	production.

Libya	–	Civil	unrest,	which	began	in	February	2011	in	parts	of	North	Africa,	escalated	to	armed	conflict	in	Libya	where	we	hold	a	16	percent	working	interest	in	the Waha	concessions,	which	encompass	almost	13	million	acres	located	in	the	Sirte	Basin	of	eastern	Libya.	During	the	first	quarter	2011,	all	production	operations	in	Libya were	suspended.	In	the

fourth	quarter	of	2011,	limited	production	resumed	from	the	Waha	concessions,	but	we	made	no	deliveries	of	hydrocarbons.	In	January	2012,	Libya	produced	190	gross mbbld	(25	net	mbbld),	and	sales	are	planned	to	resume	in	the	first	quarter	of	2012.	The	return	of	our	operations	in	Libya	to	pre-conflict	levels	is	unknown	at	this	time; however,	we	and	our	partners	in	the	Waha	concessions	are	assessing	the	condition	of	our	assets	and	determining	when	the	full	resumption	of	operations	will	be	viable.

Angola	–	Offshore	Angola,	we	hold	10	percent	working	interests	in	Blocks	31	and	32,	both	of	which	are	outside-operated.	The	discoveries	on	Blocks	31	and	32 represent	several	potential	development	hubs.	In	2008,	we	received	approval	to	proceed	with	the	first	deepwater	development	project,	called	the	PSVM	development, which	includes	the	Plutao,	Saturno,	Venus	and	Marte	discoveries	and	one	successful	appraisal	well	in	the	northeastern	portion	of	Block	31.	The	PSVM	development	will utilize	an	FPSO	with	a	total	of	48	production	and	injection	wells.	Development	drilling	began	in	2010	and	first	production	is	anticipated	in	mid-2012.	The	potential	for	a second	development	hub	on	this	block	is	being	evaluated.	Studies	are	underway	to	establish	a	development	in	the	eastern	part	of	Block	32	and	to	assess	the	development potential	of	the	other	discoveries.	We	anticipate	at	least	one	development	on	Block	32.

# Europe

Norway	–	We	operate	10	licenses	and	hold	interests	in	over	249,000	net	acres	on	the	offshore	Norwegian	continental	shelf.	In	2011,	net	sales	from	Norway averaged	80	mbbld	of	liquid	hydrocarbons	and	42	mmcfd	of	gas.

The	Alvheim	development	is	comprised	of	the	Kameleon,	East	Kameleon	and	Kneler	fields,	in	which	we	have	a	65	percent	working	interest,	and	the	Boa	field,	in which	 we	 have	 a	 58	 percent	 working	 interest.	 It	 is	 produced	 to	 the	Alvheim	 complex	 which	 consists	 of	 an	 FPSO	 with	 subsea	 infrastructure.	 In	 2011,	 due	 to debottlenecking	efforts,	capacity	of	the	FPSO	increased	to	86	mbbld	net	(149	mbbld	gross).	Produced	oil	is	transported	by	shuttle	tanker	and	produced	natural	gas	is transported	to	the	SAGE	system	by	pipeline.	At	the	end	of	2011,	the	Alvheim	development	included	13	producing	wells	and	two	water	disposal	wells.	An	additional development	well	is	planned	in	2012.

The	nearby	outside-operated	Vilje	field,	in	which	we	own	a	47	percent	working	interest,	began	producing	through	the	Alvheim	complex	in	August	2008.	At	the	end of	2011,	two	wells	were	producing	and	an	additional	development,	Vilje	Sor	had	been	approved.	Production	from	Vilje	Sor	is	estimated	to	begin	near	the	end	of	2013.

The	Volund	field,	five	miles	south	of	the	Alvheim	FPSO	was	the	second	subsea	development	tied	back	to	the	Alvheim	complex.	The	Volund	development,	in	which we	own	a	65	percent	operated	working	interest,	consists	of	three	production	wells	and	one	water	injection	well.	First	production	from	Volund	was	announced	in September	2009.	It	initially	functioned	as	a	swing	producer	to	allow	us	to	maintain	full	capacity	on	the	Alvheim	FPSO	until	the	second	quarter	of	2010	when	we commenced	full	production.	Drilling	of	an	additional	development	well	at	Volund	is	planned	for	fourth	quarter	2012,	with	first	production	scheduled	in	early	2013.

Also	offshore	Norway,	are	the	Boyla	(formerly	Marihone)	and	Viper	discoveries	in	which	we	hold	a	65	percent	operated	working	interest.	The	Boyla	oil	discovery is	located	in	license	PL340	about	12	miles	south	of	the	Volund	and	Alvheim	fields.	The	Viper	oil	discovery	is	located	in	license	PL203,	immediately	next	to	the	Volund field	in	license	PL150.	Both	discoveries	are	being	evaluated	for	possible	tie	back	to	the	Alvheim	complex.	An	investment	decision	on	Boyla	could	occur	in	the	second quarter	of	2012,	with	first	production	estimated	to	begin	in	the	fourth	quarter	of	2014.

Exploration	activities	will	continue	in	2012	and	2013.	The	Velsemøy	well	is	expected	to	begin	drilling	late	in	2012	in	license	PL531	where	we	hold	a	10	percent carried	working	interest.	Drilling	is	expected	to	commence	in	the	first	quarter	of	2013	on	the	Sverdrup	well	in	license	PL	330	where	we	hold	a	30	percent	operated working	interest.

United	Kingdom	–	Net	sales	from	the	U.K.	averaged	21	mbbld	of	liquid	hydrocarbons	and	55	mmcfd	of	natural	gas.	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	field,	which	is	produced	via the	Brae	Bravo	platform,	and	the	East	Brae	field,	which	is	produced	via	the	East	Brae	platform,	are	natural	gas	condensate	fields.	The	East	Brae	platform	also	hosts	the nearby	Braemar	field	in	which	we	have	a	28	percent	working	interest.	Two	development	wells	were	completed	at	West	Brae	in	early	2011	and	we	continue	to	pursue Brae	complex	projects	designed	to	maximize	natural	gas	recovery	and	maintain	deliverability	rates	to	the	U.K.	market.

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	twenty-five	third-party	fields	are	contracted	to	use	the	Brae	system	and	73	mboed	are	being	processed	or	transported	through	the	Brae infrastructure.	In	2011,	we	installed	a	new	module	to	accommodate	the	tie	back	of	the	third-party	operated	Devenick	field.	In	addition	to	generating	processing	and pipeline	tariff	revenue,	this	third-party	business	optimizes	infrastructure	usage.

The	Brae	group	owns	a	50	percent	interest	in	the	outside-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.

In	the	U.K.	Atlantic	Margin	west	of	the	Shetland	Islands,	we	own	an	average	30	percent	working	interest	in	the	outside-operated	Foinaven	area	complex,	consisting of	a	28	percent	working	interest	in	the	main	Foinaven	field,	47	percent	working	interest	in	East	Foinaven	and	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.	An	upgrade	of	equipment	on	the	FPSO	is	expected	to	extend	the	life	of	the	fields	through	2021.	Additionally,	the	planned	installation	of	replacement	flowlines should	secure	the	long-term	integrity	of	the	subsea	infrastructure,	but	the	related	downtime	is	expected	to	cause	a	reduction	in	sales	volumes	in	2012.	Average	net	sales from	Foinaven	were	12	mboed	in	2011.

Poland	–	Between	December	2009	and	October	2010,	we	acquired	eleven	5-year	 licenses,	 totaling	2.3	million	gross	acres.	In	2011,	we	farmed-out	 to	 two companies	an	aggregate	49	percent	undivided	interest	in	ten	of	these	licenses	which	will	be	earned	through	drilling.	As	of	December	31,	2011,	we	hold	a	51	percent working	interest	in	these	10	concessions,	a	100	percent	interest	in	the	remaining	concession	for	a	total	of	1.2	million	net	acres.	We	are	operator	under	all	licenses.	We	are in	the	early	stages	of	exploring	and	evaluating	the	full	potential	of	these	holdings.	We	drilled,	cored	and	logged	our	first	vertical	exploratory	well	in	late	2011	and	are evaluating	the	data.	In	addition,	we	expect	to	complete	proprietary	2-D	seismic	acquisitions	in	the	first	quarter	of	2012.	We	have	a	drilling	commitment	of	one	well	per license	and	plan	to	drill	6	–	7	gross	(3	–	4	net)	exploration	wells	in	2012.

# Canada

We	hold	interests	in	both	operated	and	outside-operated	exploration	stage	oil	sand	leases	in	Alberta,	Canada,	which	would	be	developed	using	in-situ	methods	of extraction.	These	leases	cover	approximately	143,000	gross	acres	(52,000	net)	in	four	project	areas:	Namur,	in	which	we	hold	a	60	percent	operated	interest;	Birchwood, in	which	we	hold	a	100	percent	operated	interest;	Ells	River,	in	which	we	hold	a	20	percent	outside-operated	interest	and	Saleski	in	which	we	hold	a	33	percent	outside- operated	interest.	Exploration	on	the	Birchwood	prospect	continued	in	the	winter	of	2011-2012	with	a	seismic	program	and	water	well	drilling.	Approximately	100 stratigraphic	test	wells	were	drilled	on	the	Birchwood	prospect	in	the	winter	of	2010-2011	providing	data	for	the	ongoing	assessment	of	reservoir	quality.	We	expect sanction	of	a	pilot	project	in	2013.

# Other	International

Iraqi	Kurdistan	Region	–	In	October	2010,	we	acquired	a	position	in	four	exploration	blocks	in	the	Iraqi	Kurdistan	Region.	In	aggregate,	these	contracts	provide	us with	access	to	approximately	368,000	net	acres.	We	signed	PSCs	for	operatorship	and	80	percent	ownership	in	the	Harir	and	Safen	blocks	northeast	of	Erbil.	The	KRG holds	a	20	percent	carried	interest	in	these	blocks.	We	have	committed	to	a	seismic	program	and	to	drilling	one	well	on	both	Hafir	and	Safen	during	the	initial	three-year exploration	period.	We	were	assigned	interests	in	two	additional	outside-operated	blocks	located	north-northwest	of	Erbil:	Atrush,	in	which	we	have	a	16	percent ownership	(the	KRG	holds	a	4	percent	carried	interest),	and	Sarsang,	in	which	we	have	a	20	percent	interest	(the	KRG	holds	a	5	percent	carried	interest).	In	2011,	we announced	the	Atrush-1	discovery	on	the	Atrush	block	and	a	second	discovery,	the	Swara	Tika-1	well	on	the	Sarsang	block.	The	Swara	Tika-2,	an	appraisal	well	on	the Sarsang	block,	commenced	drilling	in	the	fourth	quarter	of	2011.	The	Atrush-2,	an	appraisal	well	on	the	Atrush	block,	is	planned	for	2012.	Planning	is	underway	on extended	well	testing	and	early	production	systems,	with	first	production	expected	in	the	fourth	quarter	of	2012.

Indonesia	–	We	are	the	operator	of	three	exploration	licenses	in	Indonesia:	the	Pasangkayu	block	with	a	70	percent	interest,	the	Kumawa	block	with	a	55	percent interest,	and	the	Bone	Bay	block	with	a	55	percent	interest.	In	2011	and	2010,	wells	were	drilled	on	the	Bravo	and	Romeo	prospects	in	the	Pasangkayu	block.	These wells	were	expensed	as	dry	holes.	We	have	notified	our	joint	venture	partner	and	the	Indonesian	government	that	we	intend	to	relinquish	the	PSC	on	the	Pasangkayu block.	Discussions	continue	and	we	are	awaiting	a	government	response.	We	are	evaluating	the	Bone	Bay	and	Kumawa	blocks.

# Acquisitions	and	Dispositions

As	previously	discussed,	during	2011	we	closed	several	acquisition	transactions	in	the	Eagle	Ford	shale	play	and	farmed-out	minority	interests	in	our	DJ	Basin	and Poland	acreage.	Also,	in	March	2011,	we	closed	the	sale	of	our	outside-operated	interests	in	the	Gudrun	field	development	and	the	Brynhild	and	Eirin	exploration	areas offshore	Norway.

In	October	2011,	we	entered	into	definitive	agreements	to	sell	our	equity	method	interests	in	Poseidon	Oil	Pipeline	Company,	L.L.C.	and	Odyssey	Pipeline	L.L.C. and	certain	other	oil	pipeline	interests	including	the	Eugene	Island	Pipeline	System.	The	transaction	closed	on	January	3,	2012.

In	December	2011	we	sold	our	25	percent	interest	in	the	Stones	prospect	located	on	Walker	Ridge	Block	508	to	the	operator.	We	also	exchanged	a	100	percent interest	in	Atwater	Valley	Block	398	in	the	Sandpiper	prospect,	for	a	100	percent	interest	in	Walker	Ridge	Block	577	in	the	Key	Largo	prospect	and	a	20	percent	interest in	Green	Canyon	Block	286	in	the	Hypnos	prospect.	After	this	transaction,	we	hold	a	50	percent	interest	in	Green	Canyon	Block	286	and	a	100	percent	interest	in	Walker Ridge	Block	577.

See	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	5	to	the	consolidated	financial	statements	for	additional	information	about	the	acquisitions	and Note	6	for	additional	information	about	the	farm-outs	and	divestitures.

The	above	discussion	of	the	E&P	segment	includes	forward-looking	statements	with	respect	to	anticipated	future	exploratory	and	development	drilling	activity, drilling	rig	activity	in	the	U.S.,	planned	maintenance	downtime,	timing	of	reaching	abandonment	pressures	in	Droshky,	continued	investments	in	Alaska,	timing	of	first production	from	Vilje	Sor,	Boyla	and	Kurdistan,	planned	acquisition	of	seismic	data	for	Petronius,	plans	to	achieve	first	production	from	the	PSVM	development	on Block	31	offshore	Angola	and	other	possible	developments,	plans	to	resume	sales	in	Libya	and	the	expected	extension	of	the	Foinaven	fields.	Some	factors	which	could possibly	affect	these	forward-looking	statements	include	pricing,	supply	and	demand	for	petroleum	products,	the	amount	of	capital	available	for	exploration	and development,	regulatory	constraints,	drilling	rig	availability,	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	foregoing	forward-looking	statements	may	be	further	affected	by the	inability	to	obtain	or	delay	in	obtaining	necessary	government	and	third-party	approvals	and	permits.	The	offshore	developments	could	further	be	affected	by presently	 known	 data	 concerning	 size	 and	 character	 of	 reservoirs,	 economic	 recoverability,	 future	 drilling	 success	 and	 production	 experience.	 Predicted	 planned maintenance	and	FPSO	downtime	are	good	faith	estimates	and	preliminary,	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.

# Productive	and	Drilling	Wells

For	our	E&P	segment,	the	following	tables	set	forth	gross	and	net	productive	wells	and	service	wells	as	of	December	31,	2011,	2010	and	2009	and	drilling	wells	as of	December	31,	2011.

|  | Oil<br>Gross | Productive	Wells^(a)<br>Net | Natural	Gas<br>Gross | Net | Service	Wells<br>Gross | Net | Drilling	Wells<br>Gross | Net |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2011 |  |  |  |  |  |  |  |  |
| United\tStates | \t\t\t\t\t5,809 | \t\t\t\t\t2,058 | \t\t\t\t\t3,121 | \t\t\t\t\t1,876 | \t\t\t\t\t2,313 | \t\t\t\t\t\t\t734 | \t\t\t\t\t\t\t\t\t55 | \t\t\t\t\t\t\t\t\t28 |
| Equatorial\tGuinea | - | - | 14 | 9 | 4 | 3 | - | - |
| Other\tAfrica^(b) | - | - | - | - | 1 | - | - | - |
| Total\tAfrica | - | - | 14 | 9 | 5 | 3 | - | - |
| Total\tEurope | 73 | 31 | 40 | 16 | 28 | 10 | 2 | 1 |
| Total\tOther\tInternational | - | - | - | - | - | - | 1 | - |
| Worldwide | 5,882 | 2,089 | 3,175 | 1,901 | 2,346 | 747 | 58 | 29 |
| 2010 |  |  |  |  |  |  |  |  |
| United\tStates | 4,818 | 1,860 | 3,145 | 1,905 | 2,466 | 746 |  |  |
| Equatorial\tGuinea | - | - | 13 | 9 | 5 | 3 |  |  |
| Other\tAfrica | 1,022 | 168 | 3 | - | 94 | 16 |  |  |
| Total\tAfrica | 1,022 | 168 | 16 | 9 | 99 | 19 |  |  |
| Total\tEurope | 71 | 30 | 40 | 16 | 29 | 11 |  |  |
| Worldwide | 5,911 | 2,058 | 3,201 | 1,930 | 2,594 | 776 |  |  |
| 2009 |  |  |  |  |  |  |  |  |
| United\tStates | 4,806 | 1,788 | 5,158 | 3,569 | 2,447 | 734 |  |  |
| Equatorial\tGuinea | - | - | 13 | 9 | 5 | 3 |  |  |
| Other\tAfrica | 976 | 160 | - | - | 91 | 15 |  |  |
| Total\tAfrica | 976 | 160 | 13 | 9 | 96 | 18 |  |  |
| Total\tEurope | 67 | 27 | 44 | 18 | 27 | 10 |  |  |
| Worldwide | 5,849 | 1,975 | 5,215 | 3,596 | 2,570 | 762 |  |  |

Of	the	gross	productive	wells,	wells	with	multiple	completions	operated	by	us	totaled	168,	164	and	170	as	of	December	31,	2011,	2010	and	2009.	Information	on	wells	with	multiple	completions	operated	by others	is	unavailable	to	us. (a)

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.	Production	from	Libya	at December	31,	2011	was	approximately	30	percent	of	the	45	mboed	pre-conflict	level. (b)

# Drilling	Activity

For	our	E&P	segment,	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 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2011 |  |  |  |  |  |  |  |  |  |
| United\tStates | \t\t\t\t\t\t\t46 | \t\t\t\t\t\t\t\t\t17 | \t\t\t\t\t\t\t\t\t3 | \t\t\t\t\t\t\t\t\t66 | \t\t\t\t\t\t\t\t\t37 | \t\t\t\t\t\t\t\t4 | \t\t\t\t\t\t\t\t\t1 | \t\t\t\t\t\t\t\t\t42 | \t\t\t\t\t\t\t\t\t108 |
| Total\tAfrica^(a) | 2 | - | - | 2 | - | - | - | - | 2 |
| Total\tEurope | 2 | - | - | 2 | - | - | - | - | 2 |
| Total\tOther\tInternational | - | - | - | - | - | - | 1 | 1 | 1 |
| Worldwide | 50 | 17 | 2 | 70 | 37 | 4 | 2 | 43 | 113 |
| 2010 |  |  |  |  |  |  |  |  |  |
| United\tStates | 35 | 46 | 1 | 82 | 20 | 11 | 3 | 34 | 116 |
| Total\tAfrica | 5 | - | - | 5 | 1 | - | - | 1 | 6 |
| Total\tEurope | 2 | - | - | 2 | - | - | - | - | 2 |
| Total\tOther\tInternational | - | - | - | - | 1 | - | 1 | 2 | 2 |
| Worldwide | 42 | 46 | 1 | 89 | 22 | 11 | 4 | 37 | 126 |
| 2009 |  |  |  |  |  |  |  |  |  |
| United\tStates | 11 | 54 | 2 | 67 | 37 | 9 | 2 | 48 | 115 |
| Total\tAfrica | 5 | 1 | - | 6 | - | - | - | - | 6 |
| Total\tEurope | 1 | - | - | 1 | 1 | - | - | 1 | 2 |
| Worldwide | 17 | 55 | 2 | 74 | 38 | 9 | 2 | 49 | 123 |
| (a)\nActivity\tin\tLibya\tthrough\tFebruary\t2011. |  |  |  |  |  |  |  |  |  |

Activity	in	Libya	through	February	2011. (a)

# Acreage

We	believe	we	have	satisfactory	title	to	our	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	exploration	and	production	acreage	held	in	our	E&P	segment	as	of December	31,	2011.

|  |  |  |  |  | Developed	and |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Developed |  | Undeveloped |  | Undeveloped |  |
| (In\tthousands) | \t\t\t\tGross | Net | \t\t\t\tGross | Net | \t\t\t\tGross | Net |
| United\tStates | 1,620 | 1,215 | 1,449 | 1,143 | 3,069 | 2,358 |
| Canada | - | - | 143 | 55 | 143 | 55 |
| Total\tNorth\tAmerica | 1,620 | 1,215 | 1,592 | 1,198 | 3,212 | 2,413 |
| Equatorial\tGuinea | 45 | 29 | 92 | 69 | 137 | 98 |
| Other\tAfrica | 12,909 | 2,108 | 2,580 | 258 | 15,489 | 2,366 |
| Total\tAfrica | 12,954 | 2,137 | 2,672 | 327 | 15,626 | 2,464 |
| Total\tEurope | 131 | 68 | 3,173 | 1,449 | 3,304 | 1,517 |
| Other\tInternational | - | - | 3,985 | 2,334 | 3,985 | 2,334 |
| Worldwide | \t\t\t\t14,705 | \t\t\t\t\t3,420 | \t\t\t\t11,422 | \t\t\t\t\t5,308 | \t\t\t\t26,127 | \t\t\t\t\t8,728 |

Of	the	5.3	million	net	undeveloped	acres	held	at	December	31,	2011,	15	percent,	9	percent	and	20	percent	of	those	acres	are	under	agreements	scheduled	to	expire in	the	years	2012,	2013,	and	2014.

# Marketing	Activities

Our	E&P	segment	includes	activities	related	to	the	marketing	and	transportation	of	substantially	all	of	our	liquid	hydrocarbon	and	natural	gas	production.	These activities	include	the	transportation	of	production	to	market	centers,	the	sale	of	commodities	to	third	parties	and	storage	of	production.	We	balance	our	various	sales, storage	and	transportation	positions	through	what	we	call	supply	optimization,	which	can	include	the	purchase	of	commodities	from	third	parties	for	resale.	Supply optimization	serves	to	aggregate	volumes	in	order	to	satisfy	transportation	commitments	thereby	optimizing	transportation	capacity	and	value	and	to	achieve	flexibility within	product	types	and	delivery	points.

# Oil	Sands	Mining	Segment

We	hold	a	20	percent	outside-operated	interest	in	the	AOSP,	an	oil	sands	mining	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.	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.	As	of	December	31,	2011,	we	own	or	have	rights	to	participate	in	developed	and	undeveloped	leases	totaling	approximately 216,000	gross	(43,000	net)	acres.	The	underlying	developed	leases	are	held	for	the	duration	of	the	project,	with	royalties	payable	to	the	province	of	Alberta.	The upgrading	assets	are	located	at	Fort	Saskatchewan,	northeast	of	Edmonton,	Alberta.

The	five	year	AOSP	Expansion	1	was	completed	in	2011.	The	Jackpine	mine	commenced	production	under	a	phased	start-up	in	the	third	quarter	of	2010	and	began supplying	oil	sands	ore	to	the	base	processing	facility	in	the	fourth	quarter	of	2010.	The	upgrader	expansion	was	completed	and	commenced	operations	in	the	second quarter	of	2011.	Synthetic	crude	oil	sales	volumes	for	2011	were	43	mbbld,	with	production	of	38	mbbld.	Phase	one	of	debottlenecking	opportunities	was	approved	in 2011	and	potential	future	expansions	and	additional	debottlenecking	opportunities	remain	under	review.

Current	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	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	oil	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	announced	in	the	second	quarter	of	2011,	the	governments	of	Alberta	and	Canada	have	agreed	to	partially	fund	Quest	CCS	for	865	million	Canadian	dollars. Financing	would	be	received	over	a	period	of	15	years,	including	development,	construction	and	10	years	of	operations.	However,	the	funding	is	subject	to	conditions	of achieving	certain	performance	objectives.	We	expect	a	final	investment	decision	on	this	project	in	2012.

The	above	discussions	include	forward-looking	statements	with	respect	to	Quest	CCS.	Some	factors	that	could	potentially	affect	these	forward-looking	statements include	projected	costs	and	satisfaction	of	remaining	conditions	necessary	for	final	investment	decision.	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	net	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,	2011,	2010	and	2009.	Approximately	65	percent	of	our	proved reserves	are	located	in	Organization	for	Economic	Cooperation	and	Development	("OECD")	countries.

Reserves	are	disclosed	by	continent,	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.

|  |  | North	America |  |  | Africa |  | Europe |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | \t\tUnited |  |  |  |  |  |  | Grand |
| December\t31,\t2011 | \t\tStates | Canada | \t\tTotal | \t\tEG | Other | \t\t\t\tTotal | Total | Total |
| Proved\tDeveloped\tReserves |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mmbbl) | 141 | - | 141 | 78 | 179 | 257 | 84 | 482 |
| Natural\tgas\t(bcf) | 551 | - | 551 | \t1,104 | 104 | 1,208 | 40 | \t1,799 |
| Synthetic\tcrude\toil\t(mmbbl) | - | 623 | 623 | - | - | - | - | 623 |
| Total\tproved\tdeveloped\treserves\t(mmboe) | 233 | 623 | 856 | 262 | 196 | 458 | 91 | \t1,405 |
| Proved\tUndeveloped\tReserves |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mmbbl) | 138 | - | 138 | 39 | 61 | 100 | 13 | 251 |
| Natural\tgas\t(bcf) | 321 | - | 321 | 467 | - | 467 | 79 | 867 |
| Total\tproved\tundeveloped\treserves\t(mmboe) | 191 | - | 191 | 117 | 61 | 178 | 26 | 395 |
| Total\tProved\tReserves |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mmbbl) | 279 | - | 279 | 117 | 240 | 357 | 97 | 733 |
| Natural\tgas\t(bcf) | 872 | - | 872 | \t1,571 | 104 | 1,675 | 119 | \t2,666 |
| Synthetic\tcrude\toil\t(mmbbl) | - | 623 | 623 | - | - | - | - | 623 |
| Total\tproved\treserves\t(mmboe) | 424 | 623 | 1,047 | 379 | 257 | 636 | 117 | \t1,800 |

|  |  | North	America |  |  | Africa |  | Europe |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | \t\tUnited |  |  |  |  |  |  | Grand |
| December\t31,\t2010 | \t\tStates | Canada | \t\tTotal | \t\tEG | Other | \t\t\t\tTotal | Total | Total |
| Proved\tDeveloped\tReserves |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mmbbl) | 124 | - | 124 | 86 | 180 | 266 | 89 | 479 |
| Natural\tgas\t(bcf) | 591 | - | 591 | \t1,186 | 104 | 1,290 | 43 | \t1,924 |
| Synthetic\tcrude\toil\t(mmbbl) | - | 433 | 433 | - | - | - | - | 433 |
| Total\tproved\tdeveloped\treserves\t(mmboe) | 222 | 433 | 655 | 284 | 198 | 482 | 96 | \t1,233 |
| Proved\tUndeveloped\tReserves |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mmbbl) | 49 | - | 49 | 33 | 59 | 92 | 10 | 151 |
| Natural\tgas\t(bcf) | 154 | - | 154 | 465 | 1 | 466 | 73 | 693 |
| Synthetic\tcrude\toil\t(mmbbl) | - | 139 | 139 | - | - | - | - | 139 |
| Total\tproved\tundeveloped\treserves\t(mmboe) | 75 | 139 | 214 | 110 | 59 | 169 | 22 | 405 |
| Total\tProved\tReserves |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mmbbl) | 173 | - | 173 | 119 | 239 | 358 | 99 | 630 |
| Natural\tgas\t(bcf) | 745 | - | 745 | \t1,651 | 105 | 1,756 | 116 | \t2,617 |
| Synthetic\tcrude\toil\t(mmbbl) | - | 572 | 572 | - | - | - | - | 572 |
| Total\tproved\treserves\t(mmboe) | 297 | 572 | 869 | 394 | 257 | 651 | 118 | \t1,638 |

|  | North	America | North	America |  |  | Africa |  | Europe |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | \t\tUnited |  |  |  |  |  |  | Grand |
| December\t31,\t2009 | \t\tStates | Canada | \t\tTotal | EG | Other | \t\t\t\tTotal | Total | Total |
| Proved\tDeveloped\tReserves |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mmbbl) | 120 | - | 120 | 83 | 186 | 269 | 87 | 476 |
| Natural\tgas\t(bcf) | 652 | - | 652 | \t1,102 | 107 | 1,209 | 50 | \t1,911 |
| Synthetic\tcrude\toil\t(mmbbl) | - | 392 | 392 | - | - | - | - | 392 |
| Total\tproved\tdeveloped |  |  |  |  |  |  |  |  |
| reserves\t(mmboe) | 229 | 392 | 621 | 267 | 204 | 471 | 95 | \t1,187 |
| Proved\tUndeveloped\tReserves |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mmbbl) | 50 | - | 50 | 39 | 42 | 81 | 15 | 146 |
| Natural\tgas\t(bcf) | 168 | - | 168 | 586 | - | 586 | 59 | 813 |
| Synthetic\tcrude\toil\t(mmbbl) | - | 211 | 211 | - | - | - | - | 211 |
| Total\tproved\tundeveloped |  |  |  |  |  |  |  |  |
| reserves\t(mmboe) | 78 | 211 | 289 | 136 | 42 | 178 | 25 | 492 |
| Total\tProved\tReserves |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mmbbl) | 170 | - | 170 | 122 | 228 | 350 | 102 | 622 |
| Natural\tgas\t(bcf) | 820 | - | 820 | \t1,688 | 107 | 1,795 | 109 | \t2,724 |
| Synthetic\tcrude\toil\t(mmbbl) | - | 603 | 603 | - | - | - | - | 603 |
| Total\tproved\treserves\t(mmboe) | 307 | 603 | 910 | 403 | 246 | 649 | 120 | \t1,679 |

The	significant	increase	in	proved	reserves	from	2010	to	2011	was	primarily	due	to	the	Eagle	Ford	shale	acquisitions.	Also,	synthetic	crude	oil	reserves	increased, primarily	because	of	the	inclusion	of	additional	lease	portions	in	the	Jackpine	mine	and	technical	and	economic	reevaluations	at	year	end.

The	 above	 estimated	 quantities	 of	 net	 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	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

Our	estimation	of	economically	producible	volumes	of	liquid	hydrocarbons	and	natural	gas	is	a	highly	technical	process	performed	primarily	by	in-house	teams	of reservoir	engineers	and	geoscience	professionals.	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	her staff	of	Coordinators.	Reserve	estimates	are	developed	and	reviewed	by	Qualified	Reserve	Estimators	("QRE").	QREs	are	engineers	or	geoscientists	with	a	minimum	of 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	Qualified	Reserve	Estimator	training	course.	The	Reserve	Coordinators	review	all	reserve	estimates	for	all	fields	with	proved	reserves greater	than	3	mmboe	at	a	minimum	of	once	every	three	years.	Any	change	to	proved	reserve	estimates	in	excess	of	2.5	mmboe	on	a	total	field	basis,	within	a	single month,	must	be	approved	by	Corporate	Reserves	Group	management.	All	other	proved	reserve	changes	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	a	Master	of Business	Administration.	Her	37	years	of	experience	in	the	industry	include	26	with	Marathon	Oil.	She	is	active	in	industry	and	professional	groups,	having	served	on the	Society	of	Petroleum	Engineers	("SPE")	Oil	and	Gas	Reserves	Committee	("OGRC"),	chairing	in	2008	and	2009.	As	a	member	of	the	OGRC,	she	participated	in	the development	of	the	Petroleum	Resource	Management	System.	She	chaired	the	development	of	the	OGRC	comments	on	the	SEC's	proposed	modernization	of	oil	and gas	reporting	and	was	a	member	of	the	American	Petroleum	Institute's	Ad	Hoc	group	that	provided	comments	on	the	same	topic.

Estimates	of	synthetic	crude	oil	reserves	are	prepared	by	GLJ	Petroleum	Consultants	of	Calgary,	Canada,	third-party	consultants.	Their	reports	for	all	years	are	filed as	exhibits	to	this	Annual	Report	on	Form	10-K.	The	engineer	responsible

for	the	estimates	of	our	oil	sands	mining	reserves	has	33	years	of	experience	in	petroleum	engineering	and	has	conducted	surface	mineable	oil	sands	evaluations	since 1986.	He	is	a	member	of	SPE,	having	served	as	regional	director	from	1998	through	2001	and	is	a	registered	Practicing	Professional	Engineer	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	the	in-house	reserve	estimates.	We	met	this	goal	for	the	four-year	period	ended	December	31,	2011.	We	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	our	team	and	the	consultants	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.	This	process	did	not	result	in	significant	changes	to	our	reserve	estimates in	2011	or	2009.	There	were	no	third-party	audits	performed	in	2010.

During	2011,	Netherland,	Sewell	&	Associates,	Inc.	("NSAI")	prepared	a	Certification	of	December	31,	2010	reserves	for	the	Alba	field	in	Equatorial	Guinea.	The NSAI	summary	report	is	filed	as	an	exhibit	to	this	Annual	Report	on	Form	10-K.	The	senior	members	of	the	NSAI	team	have	over	50	years	of	industry	experience between	them,	having	worked	for	large,	international	oil	and	gas	companies	before	joining	NSAI.	The	team	lead	has	a	Master	of	Science	in	mechanical	engineering	and is	a	member	of	SPE.	The	senior	technical	advisor	has	a	Bachelor	of	Science	degree	in	geophysics	and	is	a	member	of	the	Society	of	Exploration	Geophysicists,	the American	Association	of	Petroleum	Geologists	and	the	European	Association	of	Geoscientists	and	Engineers.	Both	are	licensed	in	the	state	of	Texas.

Ryder	Scott	Company	("Ryder	Scott")	performed	audits	of	several	of	our	fields	in	2011	and	2009.	Their	summary	report	on	audits	performed	in	2011	is	filed	as	an exhibit	to	this	Annual	Report	on	Form	10-K.	The	team	lead	for	Ryder	Scott	has	over	20	years	of	industry	experience,	having	worked	for	a	major	international	oil	and gas	company	before	joining	Ryder	Scott.	He	has	a	Bachelor	of	Science	degree	in	mechanical	engineering,	is	a	member	of	SPE	and	is	a	registered	Professional	Engineer in	the	state	of	Texas.

The	Corporate	Reserves	Group	also	performs	separate,	detailed	technical	reviews	of	reserve	estimates	for	significant	fields	that	were	acquired	recently	or	for properties	with	other	indicators	such	as	excessively	short	or	long	lives,	performance	above	or	below	expectations	or	changes	in	economic	or	operating	conditions.

# Changes	in	Proved	Undeveloped	Reserves

As	of	December	31,	2011,	395	mmboe	of	proved	undeveloped	reserves	were	reported,	a	decrease	of	10	mmboe	from	December	31,	2010.	The	following	table shows	changes	in	total	proved	undeveloped	reserves	for	2011:

Significant	additions	to	proved	undeveloped	reserves	during	2011	include	91	mmboe	due	to	acreage	acquisition	in	the	Eagle	Ford	shale,	26	mmboe	related	to Anadarko	Woodford	shale	development,	10	mmboe	for	development	drilling	in	the	Bakken	shale	play	and	8	mmboe	for	additional	drilling	in	Norway.	Additionally,	139 mmboe	were	transferred	from	proved	undeveloped	to	proved	developed	reserves	due	to	startup	of	the	Jackpine	upgrader	expansion	in	Canada.	Costs	incurred	in	2011, 2010	and	2009	relating	to	the	development	of	proved	undeveloped	reserves,	were	$1,107	million,	$1,463	million	and	$792	million.

Projects	can	remain	in	proved	undeveloped	reserves	for	extended	periods	in	certain	situations	such	as	behind-pipe	zones	where	reserves	will	not	be	accessed	until the	primary	producing	zone	depletes,	large	development	projects	which	take	more	than	five	years	to	complete,	and	the	timing	of	when	additional	gas	compression	is needed.	Of	the	395	mmboe	of	proved	undeveloped	reserves	at	year	end	2011,	34	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	Equatorial	Guinea	that	was	sanctioned	by	our	Board	of	Directors	in 2004	and	is	expected	to	be	completed	by	2016.	Performance	of	this	field	has	exceeded	expectations,	and	estimates	of	initial	dry	gas	in	place	increased	by	roughly 10	percent	between	2004	and	2010.	Production	is	not	expected	to	experience	a	natural	decline	from	facility-limited	plateau	production	until	2014,	or	possibly	2015.	The timing	of	the	installation	of	compression	is	being	driven	by	the	reservoir	performance.

Proved	undeveloped	reserves	for	the	North	Gialo	project,	located	in	the	Libyan	Sahara	desert,	were	booked	for	the	first	time	as	proved	undeveloped	reserves	in 2010.	This	project,	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.	In	2010,	an	engineering	firm	was	awarded	the	front-end engineering	and	design	activities.	The	remoteness	of	the	North	Gialo	project	is	expected	to	extend	the	duration	of	project	execution	more	than	five	years	after	the reserves	 were	 initially	 booked.	 For	 example,	 lead	 time	 for	 delivery	 of	 required	 highly	 specialized	 compressors	 is	 approximately	 24	 months.	There	 are	 no	 other significant	undeveloped	reserves	expected	to	be	developed	more	than	five	years	after	their	original	booking.

As	of	December	31,	2011,	future	development	costs	estimated	to	be	required	for	the	development	of	proved	undeveloped	liquid	hydrocarbon,	natural	gas	and synthetic	crude	oil	reserves	for	the	years	2012	through	2016	are	projected	to	be	$2,023	million,	$1,537	million,	$1,229	million,	$804	million,	and	$439	million.

The	timing	of	future	projects	and	estimated	future	development	costs	relating	to	the	development	of	proved	undeveloped	liquid	hydrocarbons,	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

|  | United<br>		States | North	America<br>Canada^(a) | Total | EG | Africa<br>Other | Total | Europe<br>Total | Disc.<br>Ops^(b) | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Year\tEnded\tDecember\t31,\t2011 |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mbbld)^(c) | 75 | - | 75 | 38 | 5 | 43 | 101 | - | 219 |
| Natural\tgas\t(mmcfd)^(d)(e) | 326 | - | 326 | 443 | - | 443 | 81 | - | 850 |
| Synthetic\tcrude\toil\t(mbbld) | - | 38 | 38 | - | - | - | - | - | 38 |
| Total\tproduction\tsold\t(mboed) | 129 | 38 | 167 | 112 | 5 | 117 | 115 | - | 399 |
| Year\tEnded\tDecember\t31,\t2010 |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mbbld)^(c) | 70 | - | 70 | 38 | 45 | 83 | 92 | - | 245 |
| Natural\tgas\t(mmcfd)^(d)(e) | 364 | - | 364 | 405 | 4 | 409 | 87 | - | 860 |
| Synthetic\tcrude\toil\t(mbbld) | - | 24 | 24 | - | - | - | - | - | 24 |
| Total\tproduction\tsold\t(mboed) | \t\t\t\t131 | \t\t\t\t\t\t24 | \t\t\t\t155 | \t\t\t\t106 | \t\t\t\t\t\t\t45 | \t\t\t\t151 | \t\t\t\t106 | - | 412 |
| Year\tEnded\tDecember\t31,\t2009 |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(mbbld)^(c) | 64 | - | 64 | 42 | 45 | 87 | 92 | 5 | 248 |
| Natural\tgas\t(mmcfd)^(d)(e) | 373 | - | 373 | 426 | 4 | 430 | 116 | 17 | 936 |
| Total\tproduction\tsold\t(mboed) | 126 | - | 126 | 113 | 46 | 159 | 111 | \t\t\t\t\t\t\t\t\t7 | \t\t\t\t\t403 |

Before	December	31,	2009,	reserves	related	to	OSM	were	not	included	in	the	SEC's	definition	of	oil	and	gas	producing	activities;	therefore,	synthetic	crude	oil	production	of	27	mbbld	is	not	reported	for	2009.

Our	businesses	in	Ireland	and	Gabon	were	sold	in	2009	and	were	reported	as	discontinued	operations. (b)

Includes	crude	oil,	condensate	and	natural	gas	liquids.	The	amounts	correspond	with	the	basis	for	fiscal	settlements	with	governments,	representing	equity	tanker	liftings	and	direct	deliveries	of	liquid	hydrocarbons. U.S.	natural	gas	volumes	exclude	volumes	produced	in	Alaska	that	are	stored	for	later	sale	in	response	to	seasonal	demand,	although	our	reserves	have	been	reduced	by	those	volumes. (c) (d)

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

# Average	Sales	Price	per	Unit

|  |  | North	America |  |  | Africa |  | Europe |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | \t\tUnited |  |  |  |  |  |  | Disc. |  |
| (Dollars\tper\tunit) | \t\tStates | \t Canada^(a) | Total | EG | Other | Total | Total | Ops^(b) | Total |
| Year\tEnded\tDecember\t31,\t2011 |  |  |  |  |  |  |  |  |  |
| 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 | 0.70 | 0.24 | 9.75 | - | 2.96 |
| Synthetic\tcrude\toil\t(bbl) | - | 91.65 | \t 91.65 | - | - | - | - | - | \t 91.65 |
| Year\tEnded\tDecember\t31,\t2010 |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(bbl) | $72.30 | - | $72.30 | $50.57 | $89.15 | $71.71 | $81.95 | $- | $75.73 |
| Natural\tgas\t(mcf) | 4.71 | - | 4.71 | 0.24 | 0.70 | 0.25 | 7.04 | - | 2.82 |
| Synthetic\tcrude\toil\t(bbl) | - | 71.06 | \t 71.06 | - | - | - | - | - | \t 71.06 |
| Year\tEnded\tDecember\t31,\t2009 |  |  |  |  |  |  |  |  |  |
| Liquid\thydrocarbons\t(bbl) | $54.67 | - | $54.67 | $38.06 | $68.41 | $53.91 | $64.46 | $56.47 | $58.06 |
| Natural\tgas\t(mcf) | 4.14 | - | 4.14 | 0.24 | 0.70 | 0.25 | 4.84 | 8.54 | 2.52 |
| (a) |  |  |  |  |  |  |  |  |  |

Before	December	31,	2009,	OSM	was	not	included	in	the	SEC's	definition	of	oil	and	gas	producing	activities;	therefore,	synthetic	crude	oil	prices	are	not	reported	for	2009. (a)

# Average	Production	Cost	per	Unit^(a)

|  |  | North	America |  |  | Africa |  | Europe |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | \t\tUnited |  |  |  |  |  |  | Disc. | Grand |
| (Dollars\tper\tboe) | \t\tStates | Canada^(b) | \t\tTotal | EG | Other^(c) | \t\tTotal | Total | Ops^(d) | Total |
| Years\tended\tDecember\t31: |  |  |  |  |  |  |  |  |  |
| 2011 | $16.42 | $55.65 | $25.68 | $2.87 | $ 17.16 | $3.53 | $8.24 | $- | $14.26 |
| 2010 | 14.16 | 65.15 | 22.36 | \t 2.81 | 4.18 | 3.23 | 7.49 | - | \t 11.54 |
| 2009 | 14.03 | - | 14.03 | \t 2.63 | 3.64 | 2.93 | 6.99 | \t 19.14 | 7.80 |
| (a) |  |  |  |  |  |  |  |  |  |

Production,	severance	and	property	taxes	are	excluded	from	the	production	costs	used	in	the	calculation	of	this	metric. (a)

Before	December	31,	2009	OSM	was	not	included	in	the	SEC's	definition	of	oil	and	gas	producing	activities;	therefore,	production	costs	are	not	reported	for	2009.	Production	costs	in	2010	include	costs	associated with	a	major	turnaround	and	$64	million	for	a	water	abatement	accrual	in	2011. (b)

Production	operations	ceased	in	Libya	in	February	2011,	but	fixed	costs	continued	to	be	incurred. (c)

Our	businesses	in	Ireland	and	Gabon	were	sold	in	2009	and	were	reported	as	discontinued	operations. (d)

# Integrated	Gas

Our	 integrated	 gas	 operations	 include	 natural	 gas	 liquefaction	 operations	 and	 methanol	 production	 operations.	Also	 included	 in	 the	 financial	 results	 of the Integrated	Gas	segment	are	the	costs	associated	with	ongoing	development	of	projects	to	link	stranded	natural	gas	resources	with	key	demand	areas.

We	hold	a	60	percent	interest	in	EGHoldings,	which	is	accounted	for	under	the	equity	method	of	accounting.	EGHoldings	has	a	3.7	mmta	LNG	production	facility on	Bioko	Island	in	EG.	LNG	from	the	production	facility	is	sold	under	a	3.4	mmta,	or	460	mmcfd,	sales	and	purchase	agreement	with	a	17-year	term	ending	in	2024. 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.	This production	facility	allows	us	to	monetize	our	natural	gas	reserves	from	the	Alba	field,	as	natural	gas	for	the	facility	is	purchased	from	the	Alba	field	participants	under	a long-term	natural	gas	supply	agreement.	Gross	sales	of	LNG	from	this	production	facility	totaled	4.1	mmt	in	2011.	Planned	maintenance	at	the	LNG	production	facility is	scheduled	for	a	30	day	period	from	late	first	quarter	through	early	second	quarter	2012,	with	operations	expected	to	be	completely	shut	down	for	10	of	those	days.	In 2011,	we	continued	discussions	with	the	government	of	EG	and	our	partners	regarding	a	potential	second	LNG	production	train	on	Bioko	Island.

We	own	a	45	percent	interest	in	AMPCO,	which	is	accounted	for	under	the	equity	method	of	accounting.	AMPCO	owns	a	methanol	plant	located	on	Bioko	Island in	Equatorial	Guinea.	Feedstock	for	the	plant	is	supplied	from	our	natural	gas	production	from	the	Alba	field.	Gross	sales	of	methanol	from	the	plant	totaled	1.04,	0.85 and	0.96	mmt	in	2011,	2010	and	2009.	Production	from	the	plant	is	used	to	supply	customers	in	Europe	and	the	U.S.

We	sold	our	30	percent	outside-operated	interest	in	a	natural	gas	liquefaction	plant	in	Kenai	Alaska	in	the	third	quarter	of	2011	at	which	time	our	sales	from	this facility	ceased.

The	above	discussion	of	the	Integrated	Gas	segment	contains	forward-looking	statements	with	respect	to	the	planned	maintenance	and	possible	expansion	of	the LNG	 production	 facility	 in	 Equatorial	 Guinea.	 Factors	 that	 could	 potentially	 affect	 the	 possible	 expansion	 of	 the	 LNG	 production	 facility	 include	 partner	 and government	approvals,	access	to	sufficient	natural	gas	volumes	through	exploration	or	commercial	negotiations	with	other	resource	owners	and	access	to	sufficient regasification	capacity.	Predicted	planned	maintenance	and	downtime	are	good	faith	estimates	and	preliminary,	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.

# 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.	We	compete with	these	companies	for	the	equipment	and	labor	required	to	develop	and	operate	those	properties	and	in	the	marketing	of	oil	and	natural	gas	to	end-users.	Many	of	our competitors	have	financial	and	other	resources	greater	than	those	available	to	us.	Acquiring	exploration	opportunities	frequently	requires	competitive	bids	involving front-end	 bonus	 payments	 or	 commitments-to-work	 programs.	We	 also	 compete	 in	 attracting	 and	 retaining	 personnel,	 including	 petroleum	 engineers,	 geologists, geophysicists	and	other	specialists.	Based	upon	statistics	compiled	in	the	"2011	Global	Upstream	Performance	Review"	published	by	IHS	Herold	Inc.,	we	rank	tenth among	U.S.-based	petroleum	companies	on	the	basis	of	2010	worldwide	liquid	hydrocarbon	and	natural	gas	production.

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	in	conventional	and	synthetic	crude	oil,	natural	gas	and	petroleum	products,	as	well	as	changes	in	competitive conditions	in	the	markets	we	serve.	Generally,	results	from	production	and	oil	sands	mining	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	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	where	we	operate	have	their	own	similar	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	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	 2011,	 the	 U.S.	 Environmental	 Protection	Agency	 ("U.S.	 EPA")	 published	 proposed	 New	 Source	 Performance	 Standards	 ("NSPS")	 and	 National Emissions	Standards	for	Hazardous	Air	Pollutants	("NESHAP")	that	will	both	amend	existing	NSPS	and	NESHAP	standards	for	oil	and	gas	facilities	as	well	as	create	a new	NSPS	for	oil	and	gas	production,	transmission	and	distribution	facilities.	If	the	proposed	rules	are	finalized	without	substantial	modification,	compliance	with	the rules	will	result	in	an	increase	in	costs	of	control,	equipment	and	labor	and	require	additional	notification,	monitoring,	reporting	and	recordkeeping.	The	U.S.	EPA	is required	to	finalize	this	rule	by	April,	2012.

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.	To	 minimize	 pre-construction	 delays	 in	 the	 near	 term,	 we	 entered	 into	 an	Administrative Compliance	and	Consent	Agreement	("Agreement")	that	temporarily	suspended	the	requirement	for	pre-construction	permits	for	facilities	on	Trial	Lands	in	North Dakota	as	long	as	permit	applications	were	filed	in	accordance	with	the	Agreement.	We	cannot	reasonably	estimate	the	financial	impact	of	these	permitting	requirements until	the	U.S.	EPA	finalizes	its	internal	permitting	procedures.	The	U.S.	EPA	has	indicated	that	this	rule	will	be	finalized	during	the	first	half	of	2012.

# Climate	Change

In	2010,	the	U.S.	EPA	promulgated	rules	that	required	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	cased	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	regulation affecting	the	hydraulic	fracturing	process.	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	has	begun	preparation	for	the	study	and	expects	to	issue	an	interim	report	in 2012	followed	by	a	final	report	in	2014.

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	an	open-pit	mine,	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	tailing	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	Alberta	Energy	Resources	Conservation	Board	("ERCB")	issued	a	Directive	which	more	clearly defines	criteria	for	managing	oil	sands	tailings.	The	AOSP	joint	venture	operator	submitted	tailings	management	papers	to	the	ERCB	for	both	mines	setting	forth	plans to	comply	with	the	Directive	which	received	approval,	with	conditions,	in	the	second	half	of	2010.	Further	new	regulations	or	failure	to	comply	in	a	timely	manner	could result	in	additional	cost	to	us.

# 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	the	years 2011,	2010	and	2009,	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.	In	addition,	for	the	years	2010	and	2009,	sales	of	crude	oil	to	the	Libyan	National	Oil	Company	accounted	for	more	than	10	percent	of	our annual	revenues.	These	transactions	were	restricted	to	sales	of	crude	oil	produced	in	Libya	during	those	periods.

# 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	3,322	active,	full-time	employees	as	of	December	31,	2011.	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,	2012,	are	as	follows:

Michael	K.	Stewart 	54 Vice	President,	Finance	and	Accounting,	Controller	and	Treasurer

Howard	J.	Thill 	52 Vice	President,	Investor	Relations	and	Public	Affairs

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.	Cazalot	was	appointed	chairman	of	the	board	of	directors	effective	July	2011	and	was	appointed	president	and	chief	executive	officer	effective	January 2002.

•	 Ms.	Clark	was	appointed	executive	vice	president	effective	January	2007.	Ms.	Clark	joined	Marathon	Oil	in	January	2004	as	senior	vice	president	and	chief financial	officer.

•	 Mr.	Roberts	was	appointed	executive	vice	president	and	chief	operating	officer	effective	July	2011.	Mr.	Roberts	joined	Marathon	in	June	2006	as	senior	vice president,	business	development	and	was	appointed	executive	vice	president,	upstream	in	April	2008.

•	 Ms.	Campbell	was	appointed	vice	president,	public	policy	effective	June	2010.	Prior to this	appointment,	Ms.	Campbell	was	Vice	President,	Human Resources	since	October	2000.

•	 Mr.	Guidry	was	appointed	vice	president,	business	development	effective	July	2011.	Mr.	Guidry	previously	served	as	regional	vice	president	for	our	Libya operations	from	November	2008	to	June	2011.	Prior	to	the	Libya	assignment,	Mr.	Guidry	was	regional	vice	president	for	Marathon's	North	American Production	Operations	from	August	2006	to	November	2008.

•	 Ms.	Kerrigan	was	appointed	vice	president,	general	counsel	and	secretary	effective	November	1,	2009.	Prior	to	this	appointment,	Ms.	Kerrigan	was	assistant general	counsel	since	January	1,	2003.

•	 Mr.	Stewart	was	appointed	vice	president,	finance	and	accounting,	controller	and	treasurer	effective	December	2011.	Mr.	Stewart	previously	served	as	vice president,	accounting	and	controller	from	May	2006	to	December	2011	and	as	controller	from	July	2005	to	April	2006.

•	 Mr.	Thill	was	appointed	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://www.marathonoil.com/Investor_Center/.

Our	Annual	Report	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.

# A	substantial	or	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	gas;

•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	tornados;

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

•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	Report	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,	on	a	selected	basis,	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	period	ended	December	31,	2011,	as	well	as	other	conditions	in existence	at	the	date.	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	net	revenues	from	our	proved	 liquid	hydrocarbon,	natural	gas	and	synthetic	crude	oil	reserves	reflected	 in	 this	Report	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	net revenues	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	period	ended	December	31,	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	net	revenues	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,	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;	and

•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	and	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;

•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	ongoing	capital	projects.

We	may	incur	substantial	capital	expenditures	and	operating	costs	as	a	result	of	compliance	with,	and	changes	in	environmental	health,	safety	and	security laws	and	regulations,	and,	as	a	result,	our	business,	financial	condition,	results	of	operation	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,	as	well	as laws	and	regulations	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	and	regulations.	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	and	regulations	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	cleanups	or	curtail	operations	that	could	materially	and	adversely	affect	business,	financial	condition,	results	of	operation	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	or	regulations	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	2011,	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	2011	at	the	Durban	Climate	Change	Conference,	countries	such	as	the	U.S.,	China	and	India,	and	the	European	Union	agreed	in	principal	to	replace	the	Kyoto Protocol	(which	expires	in	2012)	with	a	new	legally	binding	agreement.	However,	at	this	time	it	is	not	certain	whether	a	legally	binding	resolution	will	be	reached,	what the	terms	of	any	agreement	would	be,	or	whether	the	U.S.	Senate	would	ratify	such	an	agreement.	These	actions	could	result	in	increased:	(1)	costs	to	operate	and maintain	our	facilities,	(2)	capital	expenditures	to	install	new	emission	controls	at	our	facilities,	and	(3)	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	announced	in	the	first	quarter	of	2010	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	has	begun	preparation	for	the	study	and	expects	to	issue	an	interim	report	in	2012	followed	by	a	final	report	in	2014.	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	oil	and natural	gas,	including	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.

# Worldwide	political	and	economic	developments	could	damage	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	64	percent	of	our	liquid	hydrocarbon	and	natural	gas sales	volumes	in	2011	was	derived	from	production	outside	the	U.S.	and	64	percent	of	our	proved	liquid	hydrocarbon	and	natural	gas	reserves	as	of	December	31,	2011, 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	with	suppliers	located	within	or	outside	of	the	U.S.	There	are	many	risks	associated	with operations	in	countries	and	in	global	markets,	such	as	Equatorial	Guinea,	Indonesia,	Libya	and	the	Iraqi	Kurdistan	Region,	including:

•changes	in	governmental	policies	relating	to	liquid	hydrocarbon,	natural	gas,	bitumen	or	synthetic	crude	oil	pricing	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,	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	and	other	legislation,	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.

# 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	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	exploration	and	production	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	oil	sands	mining	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	crude	oil	from our	facilities.	A	prolonged	disruption	in	the	ability	of	any	pipeline	or	vessels	to	transport	crude	oil	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.	Except	for	oil	and	gas	producing	properties,	including	oil	sands	mines,	which	generally	are leased,	or	as	otherwise	stated,	such	properties	are	held	in	fee.	The	plants	and	facilities	have	been	constructed	or	acquired	over	a	period	of	years	and	vary	in	age	and operating	efficiency.	At	the	date	of	acquisition	of	important	properties,	titles	were	examined	and	opinions	of	counsel	obtained,	but	no	title	examination	has	been	made specifically	for	the	purpose	of	this	document.	The	properties	classified	as	owned	in	fee	generally	have	been	held	for	many	years	without	any	material	unfavorably adjudicated	claim.

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.	Noble	is	seeking	an	unspecified	amount	of	damages.	We	are	vigorously	defending	this	litigation.	The	ultimate	outcome	of	this	lawsuit, including	any	financial	effect	on	us,	remains	uncertain.	We	do	not	believe	an	estimate	of	a	reasonably	probable	loss	(or	range	of	loss)	can	be	made	for	this	lawsuit	at	this time.

# Environmental	Proceedings

The	following	is	a	summary	of	proceedings	involving	us	that	were	pending	or	contemplated	as	of	December	31,	2011,	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.

Claims	under	CERCLA	and	related	state	acts	have	been	raised	with	respect	to	the	clean-up	of	various	waste	disposal	and	other	sites.	CERCLA	is	intended	to facilitate	the	clean-up	of	hazardous	substances	without	regard	to	fault.	Potentially	responsible	parties	("PRP")	for	each	site	include	present	and	former	owners	and operators	of,	transporters	to	and	generators	of	the	substances	at	the	site.	We	had	been	identified	as	a	PRP	at	five	CERCLA	waste	sites,	however,	after	the	June	30,	2011 spin-off	of	our	downstream	business,	MPC	has	indemnified	Marathon	and	retained	liability	for	all	of	these	sites.

As	of	December	31,	2011,	we	have	identified	20	sites	where	remediation	is	being	sought	under	other	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	liability	for	clean-up	and	remediation	costs	in	connection	with	these	sites	will	be	less	than	$25	million.

We	have	been	working	with	the	North	Dakota	Department	of	Health	to	resolve	voluntary	disclosures	we	made	in	2009	relating	to	potential	Clean	Air	Act	violations relating	to	our	operations	on	state	lands	in	the	Bakken	shale.	The	amount	of	the	potential	fine	is	estimated	to	be	$100,000.

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.

# SEC	Investigation	Relating	to	Libya

On	May	25,	2011,	we	received	a	subpoena	issued	by	the	SEC	requiring	production	of	documents	related	to	payments	made	to	the	government	of	Libya,	or	to officials	and	persons	affiliated	with	officials	of	the	government	of	Libya.	We	have	been	and	intend	to	continue	cooperating	with	the	SEC	in	its	investigation.

# 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,	2012,	there	were	46,783 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:

|  |  | 2011* |  |  | 2010 |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Dollars\tper\tshare | \t\tHigh\tPrice | Low\tPrice | \t\tDividends | \t\tHigh\tPrice | Low\tPrice | \t\tDividends |
| Quarter\t1 | $\t\t\t\t53.31 | $\t\t\t\t37.34 | $\t\t\t\t0.25 | $\t\t\t\t32.85 | $\t\t\t\t\t\t\t\t28.04 | $\t\t\t\t\t\t\t\t0.24 |
| Quarter\t2 | 54.17 | 49.06 | 0.25 | 34.11 | 30.19 | 0.25 |
| Quarter\t3 | 34.07 | 21.58 | 0.15 | 34.98 | 30.21 | 0.25 |
| Quarter\t4 | 29.34 | 20.27 | 0.15 | 37.03 | 33.07 | 0.25 |
| Full\tYear | $54.17 | $20.27 | $0.80 | $37.03 | $28.04 | $0.99 |
| * |  |  |  |  |  |  |

* On	June	30,	2011,	we	completed	the	spin-off	our	downstream	business.	The	June	30,	2011	closing	price	of	our	common	stock	on	the	NYSE	was	$52.68.	On	July	1,	2011,	the	opening	price	of	our	common	stock	on the	NYSE	was	$32.95.	Our	quarterly	dividend	was	also	adjusted	to	$0.15	per	share.

# 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	Corporation,	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.

On	January	27,	2012,	we	announced	a	13	percent	increase	in	our	quarterly	dividend	to	$0.17	per	share.

# 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,	2011,	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) |
| :--- | :--- | :--- | :--- | :--- |
|  |  |  | Total\tNumber\tof | Approximate |
|  |  |  | Shares\tPurchased | Dollar\tValue\tof |
|  |  |  | as\tPart\tof | Shares\tthat\tMay |
|  | Total\tNumber\tof | Average | Publicly | Yet\tBe\tPurchased |
|  | Shares | Price\tPaid | Announced\tPlans | Under\tthe\tPlans |
| Period | Purchased^(a) | per\tShare | or\tPrograms^(c) | or\tPrograms^(c) |
| 10/01/11\t–\t10/31/11 | 6,217 | $20.84 | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t- | $\t\t\t\t1,780,609,536 |
| 11/01/11\t–\t11/30/11 | 12,748 | $25.03 | - | $1,780,609,536 |
| 12/01/11\t–\t12/31/11 | 40,420^(b) | $27.21 | - | $1,780,609,536 |
| Total | 59,385 | $26.08 | - |  |

26,396	shares	of	restricted	stock	were	delivered	by	employees	to	Marathon	Oil,	upon	vesting,	to	satisfy	tax	withholding	requirements.

32,989	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.

We	announced	a	share	repurchase	program	in	January	2006,	and	amended	it	several	times	in	2007	for	a	total	authorized	program	of	$5	billion.	As	of	December	31,	2011,	78	million	common	shares	had	been acquired	at	a	cost	of	$3,222	million,	which	includes	transaction	fees	and	commissions	that	are	not	reported	in	the	table	above.	Of	this	total,	66	million	shares	had	been	acquired	at	a	cost	of	$2,922	million	prior	the spin-off	of	the	downstream	business	(see	Item	8.	Financial	Statements	and	Supplementary	Data—Note	3	to	the	consolidated	financial	statements).

# Item	6.			Selected	Financial	Data

| (Dollars	in	millions,	except	as	noted) | 2011^(b) | 2010^(c) | 2009^(d) | 2008^(d)(e) | 2007^(d)(f)(g) |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Statement\tof\tIncome\tData^(a) |  |  |  |  |  |
| Revenues | $\t\t\t\t14,663 | $\t\t\t\t11,690 | $8,524 | $13,162 | $8,569 |
| Income\tfrom\tcontinuing\toperations | 1,707 | 1,882 | 716 | 2,192 | 1,699 |
| Net\tincome | 2,946 | 2,568 | 1,463 | 3,528 | 3,956 |
| Per\tShare\tData |  |  |  |  |  |
| Basic\t: |  |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $2.40 | $2.65 | $1.01 | $3.09 | $2.46 |
| Net\tincome | $4.15 | $3.62 | $2.06 | $4.97 | $5.73 |
| Diluted\t: |  |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $2.39 | $2.65 | $1.01 | $3.08 | $2.44 |
| Net\tincome | $4.13 | $3.61 | $2.06 | $4.95 | $5.69 |
| Statement\tof\tCash\tFlows\tData^(a) |  |  |  |  |  |
| Additions\tto\tproperty,\tplant\tand\tequipment\trelated\tto\tcontinuing\toperations | $3,295 | $3,536 | $3,349 | $4,202 | $2,354 |
| Dividends\tpaid | 567 | 704 | 679 | 681 | 637 |
| Dividends\tper\tshare | $0.80 | $0.99 | $0.96 | $0.96 | $0.92 |
| Balance\tSheet\tData\tas\tof\tDecember\t31: |  |  |  |  |  |
| Total\tassets | $31,371 | $50,014 | $\t\t\t\t47,052 | $\t\t\t\t42,686 | $\t\t\t\t42,746 |
| Total\tlong-term\tdebt,\tincluding\tcapitalized\tleases | 4,674 | 7,601 | 8,436 | 7,087 | 6,084 |

Our	downstream	business	was	spun-off	on	June	30,	2011.	Previous	periods	have	been	recast	to	reflect	the	business	in	discontinued	operations	(see	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	3	to the	consolidated	financial	statements).

Includes	impairments	of	$310	million	primarily	related	to	E&P	segment	assets	(see	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	15	to	the	consolidated	financial	statements).

Includes	impairments	of	$447	million	primarily	related	to	E&P	segment	assets	(see	Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	15	to	the	consolidated	financial	statements).

Our	businesses	in	Ireland	and	Gabon	were	sold	in	2009.	Previous	periods	have	been	recast	to	reflect	these	businesses	in	discontinued	operations.

Includes	a	$1,412	million	impairment	of	goodwill	related	to	the	OSM	reporting	unit.

On	October	18,	2007,	we	completed	the	acquisition	of	all	the	outstanding	shares	of	Western	Oil	Sands	Inc.

Effective	May	1,	2007,	we	no	longer	consolidate	EGHoldings	and	our	investment	in	EGHoldings	is	accounted	for	under	the	equity	method	of	accounting;	therefore,	EGHoldings'	additions	to	property,	plant	and equipment	subsequent	to	April	2007	are	not	included	in	our	additions	to	property,	plant	and	equipment	related	to	continuing	operations.

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

We	are	an	international	energy	company	with	operations	in	the	U.S.,	Canada,	Africa, the	Middle	East	and	Europe.	Our	operations	are	organized into three reportable	segments:

•E&P	which	explores	for,	produces	and	markets	liquid	hydrocarbons	and	natural	gas	on	a	worldwide	basis.

•	 OSM	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.

•IG	which	produces	and	markets	products	manufactured	from	natural	gas,	such	as	LNG	and	methanol,	in	EG.

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	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 shareholders	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.	Fractional	shares	of	MPC	common	stock	were	not	distributed	and	any	fractional	share	of	MPC	common	stock	otherwise	issuable	to	a	Marathon	shareholder	was sold	in	the	open	market	on	such	shareholder's	behalf,	and	such	shareholder	received	a	cash	payment	with	respect	to	that	fractional	share.	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	in	all	periods	presented	in	this	Annual	Report	on	Form	10-K	(see	Item	8.	Financial	Statements	and	Supplementary	Data—Note	3	to	the	consolidated	financial statements	for	additional	information).

# Overview	–	Market	Conditions

# Exploration	and	Production

Prevailing	prices	for	the	various	grades	of	crude	oil	and	natural	gas	that	we	produce	significantly	impact	our	revenues	and	cash	flows.	Prices	of	crude	oil	have	been volatile	in	recent	years.	In	2011,	crude	prices	increased	over	2010	levels,	with	increases	in	Brent	averages	outstripping	those	in	WTI.	During	much	of	2010,	both	WTI and	Brent	crude	oil	monthly	average	prices	remained	in	the	$75	to	$85	per	barrel	range.	Crude	oil	prices	reached	a	low	of	$33.98	in	February	2009,	following	global demand	declines	in	an	economic	recession,	but	recovered	quickly	ending	2009	at	$79.36.	The	following	table	lists	benchmark	crude	oil	and	natural	gas	price	annual averages	for	the	past	three	years.

Settlement	date	average. (a)

Our	U.S.	crude	oil	production	was	approximately	58	percent	sour	in	2011	and	68	percent	in	2010.	Sour	crude	contains	more	sulfur	than	light	sweet	WTI	does.	Sour crude	oil	also	tends	to	be	heavier	than	light	sweet	crude	oil	and	sells	at	a	discount	to	light	sweet	crude	oil	because	of	higher	refining	costs	and	lower	refined	product values.	Our	international	crude	oil	production	is	relatively	sweet	and	is	generally	sold	in	relation	to	the	Brent	crude	benchmark.	The	differential	between	WTI	and	Brent average	prices	widened	significantly	in	2011	to	$16.15	in	comparison	to	differentials	of	less	than	$1.00	in	2010	and	2009.

A	significant	portion	of	our	natural	gas	production	in	the	lower	48	states	of	the	U.S.	is	sold	at	bid-week	prices	or	first-of-month	indices	relative	to	our	specific producing	areas.	Average	settlement	date	Henry	Hub	natural	gas	prices	have	been	relatively	stable	for	the	periods	of	this	report;	however,	a	decline	began	in	September 2011	which	has	continued	in	2012	with	February	averaging	$2.68	per	mmbtu.	Should	U.S.	natural	gas	prices	remain	depressed,	an	impairment	charge	related	to	our natural	gas	assets	may	be	necessary.

Our	other	major	natural	gas-producing	regions	are	Europe	and	EG.	Natural	gas	prices	in	Europe	have	been	significantly	higher	than	in	the	U.S.	In	the	case	of	EG our	natural	gas	sales	are	subject	to	term	contracts,	making	realized	prices	less	volatile.	The	natural	gas	sales	from	EG	are	at	fixed	prices;	therefore,	our	worldwide reported	average	natural	gas	realized	prices	may	not	fully	track	market	price	movements.

# Oil	Sands	Mining

OSM	segment	revenues	correlate	with	prevailing	market	prices	for	the	various	qualities	of	synthetic	crude	oil	we	produce.	Roughly	two-thirds	of	the	normal	output mix	will	track	movements	in	WTI	and	one-third	will	track	movements	in	the	Canadian	heavy	sour	crude	oil	marker,	primarily	Western	Canadian	Select.	Output	mix	can be	impacted	by	operational	problems	or	planned	unit	outages	at	the	mines	or	the	upgrader.

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	Canadian	Alberta	Energy	Company	("AECO")	natural	gas	sales	index	and	crude	oil	prices,	respectively.	Recently	AECO	prices	have	declined,	much	as	Henry	Hub prices	have.	We	would	expect	a	significant,	continued	declined	in	natural	gas	prices	to	have	a	favorable	impact	on	OSM	operating	costs.

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

| Benchmark | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| WTI\tcrude\toil\t(Dollars\tper\tbbl) | $\t\t\t\t95.11 | $\t\t\t\t79.61 | $\t\t\t\t62.09 |
| Western\tCanadian\tSelect\t(Dollars\tper\tbbl)^(a) | 77.97 | 65.31 | 52.13 |
| AECO\tnatural\tgas\tsales\tindex\t(Dollars\tper\tmmbtu)^(b) | $3.68 | $3.89 | $3.49 |
| (a) |  |  |  |

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

Monthly	average	day	ahead	index. (b)

Our	integrated	gas	operations	include	production	and	marketing	of	products	manufactured	from	natural	gas,	such	as	LNG	and	methanol,	in	EG.

World	LNG	trade	in	2011	has	been	estimated	to	be	241	mmt.	Long-term,	LNG	continues	to	be	in	demand	as	markets	seek	the	benefits	of	clean	burning	natural	gas. Market	prices	for	LNG	are	not	reported	or	posted.	In	general,	LNG	delivered	to	the	U.S.	is	tied	to	Henry	Hub	prices	and	will	track	with	changes	in	U.S.	natural	gas prices,	while	LNG	sold	in	Europe	and	Asia	is	indexed	to	crude	oil	prices	and	will	track	the	movement	of	those	prices.	We	have	a	60	percent	ownership	in	an	LNG production	facility	in	Equatorial	Guinea,	which	sells	LNG	under	a	long-term	contract	at	prices	tied	to	Henry	Hub	natural	gas	prices.	Gross	sales	from	the	plant	were	4.1 mmt,	3.7	mmt	and	3.9	mmt	in	2011,	2010	and	2009.

We	own	a	45	percent	interest	in	a	methanol	plant	located	in	Equatorial	Guinea	through	our	investment	in	AMPCO.	Gross	sales	of	methanol	from	the	plant	totaled 1,039,657,	850,605	and	960,374	metric	tonnes	in	2011,	2010	and	2009.	Methanol	demand	has	a	direct	impact	on	AMPCO's	earnings.	Because	global	demand	for methanol	is	rather	limited,	changes	in	the	supply-demand	balance	can	have	a	significant	impact	on	sales	prices.	World	demand	for	methanol	in	2011	has	been	estimated to	be	55.4	mmt.	Our	plant	capacity	of	1.1	mmt	is	about	2	percent	of	total	demand.

# Operating	and	Financial	Highlights

Significant	operating	and	financial	highlights	during	2011	include:

•	 Completed	the	spin-off	of	our	downstream	business	on	June	30,	2011

•	 Acquired	a	significant	operated	position	in	the	Eagle	Ford	shale	play	in	south	Texas

•	 Added	net	proved	reserves,	for	the	E&P	and	OSM	segments	combined,	of	307	mmboe,	excluding	dispositions,	for	a	212	percent	reserve	replacement	ratio

•Increased	proved	liquid	hydrocarbon,	including	synthetic	crude	oil,	reserves	to	78	percent	from	75	percent	of	proved	reserves

•Increased	E&P	net	sales	volumes,	excluding	Libya,	by	7	percent

•	 Recorded	96	percent	average	operational	availability	for	all	major	company-operated	E&P	assets,	compared	to	94	percent	in	2010

•	 Completed	debottlenecking	work	that	increased	crude	oil	production	capacity	at	the	Alvheim	FPSO	in	Norway	to	150,000	gross	bbld	from	the	previous capacity	of	142,000	gross	bbld	and	the	original	2008	capacity	of	120,000	gross	bbld

•	 Announced	two	non-operated	discoveries	in	the	Iraqi	Kurdistan	Region	and	began	drilling	in	Poland

•	 Completed	AOSP	Expansion	1,	including	the	start-up	of	the	expanded	Scotford	upgrader,	realizing	an	increase	in	net	synthetic	crude	oil	sales	volumes	of	48 percent

•	 Completed	dispositions	of	non-core	assets	and	interests	in	acreage	positions	for	net	proceeds	of	$518	million

•	 Repurchased	12	million	shares	of	our	common	stock	at	a	cost	of	$300	million

•	 Retired	$2,498	million	principal	of	our	long-term	debt

•	 Resumed	limited	production	in	Libya	in	the	fourth	quarter	of	2011	following	the	February	2011	temporary	suspension	of	operations

# Consolidated	Results	of	Operations:	2011	compared	to	2010

Due	to	the	spin-off	of	our	downstream	business	on	June	30,	2011,	which	is	reported	as	discontinued	operations,	income	from	continuing	operations	is	more representative	of	Marathon	Oil	as	an	independent	energy	company.	Consolidated	income	from	continuing	operations	before	income	taxes	was	9	percent	higher	in	2011 than	in	2010,	largely	due	to	higher	liquid	hydrocarbon	prices.	This	improvement	was	offset	by	increased	income	taxes	primarily	the	result	of	excess	foreign	tax	credits generated	during	2011	that	we	do	not	expect	to	utilize	in	the	future.	The	effective	income	tax	rate	for	continuing	operations	was	61	percent	in	2011	compared	to	54 percent	in	2010.

Revenues	are	summarized	in	the	following	table:

| (In	millions) | 2011 | 2010 |
| :--- | :--- | :--- |
| E&amp;P | $\t\t\t\t13,029 | $\t\t\t\t10,782 |
| OSM | 1,588 | 833 |
| IG | 93 | 150 |
| Segment\trevenues | 14,710 | 11,765 |
| Elimination\tof\tintersegment\trevenues | (47) | (75) |
| Total\trevenues | $14,663 | $11,690 |

E&P	segment	revenues	increased	$2,247	million	from	2010	to	2011,	primarily	due	to	higher	average	liquid	hydrocarbon	realizations,	which	were	$99.37	per	bbl	in 2011,	a	31	percent	increase	over	2010.	Revenues	in	2010	included	net	pre-tax	gains	of	$95	million	on	derivative	instruments	intended	to	mitigate	price	risk	on	future sales	of	liquid	hydrocarbons	and	natural	gas.

Included	in	our	E&P	segment	are	supply	optimization	activities	which	include	the	purchase	of	commodities	from	third	parties	for	resale.	Supply	optimization serves	to	aggregate	volumes	in	order	to	satisfy	transportation	commitments	and	to	achieve	flexibility	within	product	types	and	delivery	points.	See	the	Cost	of	revenues discussion	as	revenues	from	supply	optimization	approximate	the	related	costs.	Higher	average	crude	oil	prices	in	2011	compared	to	2010	increased	revenues	related	to supply	optimization.

Revenues	from	the	sale	of	our	U.S.	production	are	higher	in	2011	primarily	as	a	result	of	higher	liquid	hydrocarbon	and	natural	gas	price	realizations,	but	sales volumes	declined.

The	following	table	gives	details	of	net	sales	and	average	realizations	of	our	U.S.	operations.

|  | 2011 | 2010 |
| :--- | :--- | :--- |
| United\tStates\tOperating\tStatistics |  |  |
| Net\tliquid\thydrocarbon\tsales\t(mbbld)^(a) | 75 | 70 |
| Liquid\thydrocarbon\taverage\trealizations\t(per\tbbl)^(b) | $92.55 | $72.30 |
| Net\tnatural\tgas\tsales\t(mmcfd) | 326 | 364 |
| Natural\tgas\taverage\trealizations\t(per\tmcf)^(b) | $4.95 | $4.71 |
| (a)\nIncludes\tcrude\toil,\tcondensate\tand\tnatural\tgas\tliquids. |  |  |

Includes	crude	oil,	condensate	and	natural	gas	liquids. (a)

Excludes	gains	and	losses	on	derivative	instruments. (b)

Increased	liquid	hydrocarbon	sales	volumes	in	2011	were	a	result	of	new	wells	in	the	Bakken	shale,	new	production	from	acreage	acquired	in	the	Eagle	Ford	shale and	increased	production	from	the	Droshky	development	in	the	Gulf	of	Mexico,	which	commenced	operations	in	July	2010.	Natural	gas	sales	volumes	were	lower	in 2011	as	compared	to	2010	due	to	the	sale	of	a	portion	of	our	Powder	River	Basin	asset	in	2010,	decreased	demand	in	Alaska	and	natural	field	declines,	partly	offset	by increased	natural	gas	production	from	the	Droshky	development.

The	following	table	gives	details	of	net	sales	and	average	realizations	of	our	international	operations.

|  | 2011 | 2010 |
| :--- | :--- | :--- |
| International\tOperating\tStatistics |  |  |
| Net\tliquid\thydrocarbon\tsales\t(mbbld)^(a) |  |  |
| Europe | 101 | 92 |
| Africa | 43 | 83 |
| Total\tInternational | 144 | 175 |
| Liquid\thydrocarbon\taverage\trealizations\t(per\tbbl)^(b) |  |  |
| Europe | $115.55 | $81.95 |
| Africa | 73.21 | \t 71.71 |
| Total\tInternational | $102.96 | $77.11 |
| Net\tnatural\tgas\tsales\t(mmcfd) |  |  |
| Europe^(c) | 97 | 105 |
| Africa | 443 | 409 |
| Total\tInternational | 540 | 514 |
| Natural\tgas\taverage\trealizations\t(per\tmcf)^(b) |  |  |
| Europe | $9.84 | $7.10 |
| Africa | 0.24 | 0.25 |
| Total\tInternational | $1.97 | $1.65 |

Includes	crude	oil,	condensate	and	natural	gas	liquids.	The	amounts	correspond	with	the	basis	for	fiscal	settlements	with	governments,	representing	equity	tanker	liftings	and	direct	deliveries	of	liquid	hydrocarbons. (a)

Includes	natural	gas	acquired	for	injection	and	subsequent	resale	of	16	mmcfd	and	18	mmcfd	in	2011	and	2010. (c)

Compared	to	2010,	international	liquid	hydrocarbon	sales	volumes	are	lower	due	to	the	temporary	cessation	of	production	from	Libya	in	February	2011.	In	the fourth	quarter	of	2011,	limited	production	resumed	from	the	Waha	concessions,	but	we	made	no	deliveries	of	hydrocarbons.	Sales	are	planned	to	resume	in	the	first quarter	of	2012.	Partially	offsetting	the	impact	of	Libya,	were	higher	liquid	hydrocarbon	sales	from	Norway	due	to	increasing	capacity	of	the	Alvheim	FPSO	and	from two	new	West	Brae	wells	in	the	U.K.	Natural	gas	sales	volumes	from	EG	were	higher	in	2011	due	to	a	turnaround	in	2010,	while	natural	gas	sales	volumes	from	Europe were	down	primarily	related	to	2011	planned	turnarounds	and	normal	production	declines	in	the	U.K.

OSM	segment	revenues	increased	$755	million	from	2010	to	2011.	Revenues	were	impacted	by	net	pre-tax	gains	of	$25	million	on	derivative	instruments	in	2010. The	increase	in	revenue	is	due	to	higher	synthetic	crude	oil	sales	volumes	and	realizations	as	shown	on	the	table	below.

Includes	blendstocks. (a)

The	2011	sales	volumes	improved	as	a	result	of	the	Jackpine	mine,	which	commenced	operations	in	late	2010,	and	the	upgrader	expansion	which	was	completed and	commenced	operations	in	the	second	quarter	of	2011.	Sales	volumes	in	2010	were	impacted	by	a	turnaround	that	commenced	in	late	March	2010	that	caused production	to	be	completely	shut	down	in	April,	with	a	staged	resumption	in	May	2010.

IG	segment	revenues	decreased	$57	million	in	2011	from	2010	because	sales	of	LNG	from	our	Alaska	operations	declined	throughout	2011	as	we	planned	to	shut down	the	LNG	facility.	In	the	third	quarter	of	2011,	sales	from	the	LNG	facility	ceased	completely	because	we	sold	our	equity	interest	in	the	facility.

Income	from	equity	method	investments	increased	$118	million	in	2011	from	2010	primarily	due	to	the	impact	of	higher	liquid	hydrocarbon	prices	on	the earnings	of	certain	of	our	equity	method	investees	in	2011.

Net	gain	on	disposal	of	assets	in	2011	is	primarily	related	to	sales	of	non-core	assets,	such	as	the	Burns	Point	gas	plant	and	the	Alaska	LNG	facility,	and	the assignment	of	interests	in	our	DJ	Basin	and	Poland	acreage	positions.	The	2010	gain	is	primarily	related	to	the	pretax	gain	of	$811	million	on	the	sale	of	a	20	percent outside-operated	interest	in	our	Production	Sharing	Contract	and	Joint	Operating	Agreement	in	Block	32	offshore	Angola.	See	Item	8.	Financial	Statements	and Supplementary	Data	–	Note	6	to	the	consolidated	financial	statements	for	discussion	of	significant	dispositions.

Cost	of	revenues	increased	$1,439	million	from	2010	to	2011	primarily	due	to	the	impact	of	higher	crude	oil	prices	on	our	supply	optimization	activities.	Costs related	to	supply	optimization	were	$3,599	million	in	2011	compared	to	$2,530	million	in	2010.

Additionally,	total	OSM	segment	costs	increased	for	2011	primarily	because	the	Jackpine	mine	commenced	production	in	late	2010	and	the	upgrader	expansion came	online	in	2011.	Although	gross	costs	are	up	due	to	the	increased	volumes	from	the	expansion,	per	barrel	costs	have	been	declining	in	comparison	with	2010.	OSM segment	costs	also	increased	in	2011	when	compared	to	2010	due	to	the	expansion's	operation	start-up	costs.	These	increases	were	partially	offset	by	no	turnaround	costs in	2011.	We	incurred	$99	million	in	2010	associated	with	the	turnaround.	Additionally,	estimated	net	costs	of	$64	million	were	recorded	in	2011	to	address	water	flow	in a	previously	mined	and	contained	area	of	the	Muskeg	River	mine.

Purchases	from	related	parties	increased	$78	million	from	2010	as	a	result	of	purchases	from	the	Alba	LPG	plant	in	EG,	in	which	we	own	an	equity	interest. Higher	liquid	hydrocarbon	prices	in	2011	increased	the	value	of	those	purchases.

Depreciation,	depletion	and	amortization	increased	$210	million	in	2011	from	2010.	Since	both	our	E&P	and	OSM	segments	apply	the	units-of-production method	to	the	majority	of	their	assets,	the	previously	discussed	increases	or	decreases	in	sales	volumes	generally	result	in	similar	changes	in	DD&A.	Increased	DD&A expense	in	2011	reflects	the	impact	of	higher	OSM	segment	sales	volumes,	partially	offset	by	decreases	in	E&P	segment	sales	volumes.	The	DD&A	rate	(expense	per barrel	of	oil	equivalent),	which	is	impacted	by	changes	in	proved	reserves	and	capitalized	costs,	can	also	cause	changes	in	our	DD&A.	The	following	table	provides DD&A	rates	for	our	E&P	and	OSM	segments.

| ($	per	boe) | 2011 | 2010 |
| :--- | :--- | :--- |
| DD&amp;A\trate |  |  |
| E&amp;P\tSegment |  |  |
| United\tStates | $\t\t\t\t\t\t\t\t25 | $\t\t\t\t\t\t\t\t22 |
| International | 10 | 9 |
| OSM\tSegment | $\t\t\t\t\t\t\t\t18 | $\t\t\t\t\t\t\t\t16 |

Impairments	in	2011	related	primarily	to	our	Droshky	development	in	the	Gulf	of	Mexico	for	$273	million	and	an	intangible	asset	for	an	LNG	delivery	contract	at Elba	Island.	Impairments	in	2010	include	$423	million	related	to	our	Powder	River	Basin	field	in	the	first	quarter,	as	well	as	smaller	impairments	to	other	E&P	segment fields	due	to	reductions	in	estimated	reserves,	reduced	drilling	expectations	and	declining	natural	gas	prices.	See	Item	8.	Financial	Statements	and	Supplementary	Data —Note	15	to	the	consolidated	financial	statements	for	further	information	about	the	impairments.

General	and	administrative	expenses	increased	$53	million	in	2011	compared	to	2010	primarily	due	to	additional	compensation	expense	related	to	performance units	and	stock	based	compensation	expense.

Other	taxes	increased	$31	million	in	2011	compared	to	2010.	With	the	increase	in	revenues,	particularly	related	to	higher	prices,	production	and	ad	valorem	taxes increased.

Exploration	expenses	were	higher	in	2011	than	2010	primarily	due	to	higher	dry	well	costs.	Dry	wells	primarily	related	to	Indonesia,	the	Gulf	of	Mexico,	Norway and	various	U.S.	onshore	properties	in	both	2011	and	2010.	In	addition,	costs	related	to	some	suspended	exploratory	wells	in	Equatorial	Guinea	were	expensed	in	2010. Geologic	and	seismic	costs	have	increased	in	2011	over	2010	primarily	related	to	the	U.S.	shale	plays,	Poland	and	the	Iraqi	Kurdistan	Region.

The	following	table	summarizes	components	of	exploration	expenses:

| (In	millions) | 2011 | 2010 |
| :--- | :--- | :--- |
| Dry\twell\tand\tunproved\tproperty\timpairment | $\t\t\t\t357 | $\t\t\t\t223 |
| Geological,\tgeophysical,\tseismic | 120 | 116 |
| Other | 167 | 159 |
| Total\texploration\texpenses | $644 | $498 |

Loss	on	early	extinguishment	of	debt	relates	to	debt	retirements	in	February	and	March	of	2011	and	in	April	of	2010.	See	Item	8.	Financial	Statements	and Supplementary	Data—Note	17	to	the	consolidated	financial	statements	for	additional	discussion	of	these	transactions.

Provision	for	income	taxes	increased	$545	million	from	2010	to	2011	in	part	due	to	the	increase	in	pretax	income.	In	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	2011.	A	higher	price	and production	outlook	over	the	next	several	years	for	Norway	due	to	better	than	expected	performance	contributed	to	generating	these	excess	foreign	tax	credits.	The following	is	an	analysis	of	the	effective	income	tax	rates	for	2011	and	2010:

|  | 2011 | 2010 |
| :--- | :--- | :--- |
| Statutory\trate\tapplied\tto\tincome\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | \t\t\t\t\t35% | \t\t\t\t\t\t\t\t\t35% |
| Effects\tof\tforeign\toperations,\tincluding\tforeign\ttax\tcredits | 6 | 20 |
| Change\tin\tpermanent\treinvestment\tassertion | 5 | - |
| Adjustments\tto\tvaluation\tallowances | 14 | (2) |
| Tax\tlaw\tchanges | 1 | 1 |
| Effective\tincome\ttax\trate\ton\tcontinuing\toperations | 61% | 54% |

The	effective	tax	rate	is	influenced	by	a	variety	of	factors	including	the	geographical	and	functional	sources	of	income,	the	relative	magnitude	of	these	sources	of income,	foreign	currency	remeasurement	effects,	and	tax	legislation	changes.	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	and	to individual	items	not	allocated	to	segments	is	reported	in	"Corporate	and	other	unallocated	items"	shown	in	Item	8.	Financial	Statements	and	Supplementary	Data—Note 8	to	the	consolidated	financial	statements.

Effects	of	foreign	operations	–	The	effects	of	foreign	operations	on	our	effective	tax	rate	decreased	in	2011	as	compared	to	2010,	primarily	due	to	the	suspension	of all	production	operations	in	Libya	in	the	first	quarter	of	2011,	where	the	statutory	tax	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	recognized	deferred	U.S.	tax	on	previously	undistributed	earnings.

Adjustments	to	valuation	allowance	–	In	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	2011.

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

Discontinued	operations	reflect	the	June	30,	2011	spin-off	of	our	downstream	business	and	the	historical	results	of	those	operations,	net	of	tax,	for	all	periods presented.	See	Item	8.	Financial	Statements	and	Supplementary	Data—Note	3	to	the	consolidated	financial	statements.

Segment	income	for	2011	and	2010	is	summarized	and	reconciled	to	net	income	in	the	following	table.

| (In	millions) | 2011 | 2010 |
| :--- | :--- | :--- |
| E&amp;P |  |  |
| United\tStates | $366 | $251 |
| International | 1,791 | 1,690 |
| E&amp;P\tsegment | 2,157 | 1,941 |
| OSM | 256 | (50) |
| IG | 178 | 142 |
| Segment\tincome | 2,591 | 2,033 |
| Items\tnot\tallocated\tto\tsegments,\tnet\tof\tincome\ttaxes: |  |  |
| Corporate\tand\tother\tunallocated\titems | (326) | (202) |
| Foreign\tcurrency\tremeasurement\tof\ttaxes | 9 | 32 |
| Impairments | (195) | (286) |
| Loss\ton\tearly\textinguishment\tof\tdebt | (176) | (57) |
| Tax\teffect\tof\tsubsidiary\trestructuring | (122) | - |
| Deferred\tincome\ttaxes | (61) | (45) |
| Water\tabatement\t–\tOil\tSands | (48) | - |
| Eagle\tFord\ttransaction\tcosts | (10) | - |
| Gain\ton\tdispositions | 45 | 407 |
| Income\tfrom\tcontinuing\toperations | 1,707 | 1,882 |
| Discontinued\toperations | 1,239 | 686 |
| Net\tincome | $\t\t2,946 | $\t\t2,568 |

United	States	E&P	income	increased	$115	million	from	2010	to	2011.	The	majority	of	the	income	increase	was	due	to	higher	liquid	hydrocarbon	realizations	in 2011,	along	with	higher	liquid	hydrocarbon	sales	volumes,	partially	offset	by	higher	DD&A	in	the	Gulf	of	Mexico	and	increased	exploration	and	operating	costs.

International	E&P	income	increased	$101	million	from	2010	to	2011.	This	increase	was	primarily	related	to	higher	liquid	hydrocarbon	realizations,	partially	offset by	lower	liquid	hydrocarbon	sales	volumes	and	higher	income	taxes.

OSM	 segment	income	increased	$306	million	from	2010	to	2011.	The	increase	in	segment	income	was	primarily	the	result	of	higher	synthetic	crude	oil	sales volumes	and	higher	price	realizations.

IG	segment	income	increased	$36	million	from	2010	to	2011.	The	increase	in	income	was	primarily	the	result	of	higher	LNG	and	methanol	sales	volumes, somewhat	offset	by	lower	Henry	Hub	gas	prices.

# Consolidated	Results	of	Operations:	2010	compared	to	2009

| (In	millions) | 2010 | 2009 |
| :--- | :--- | :--- |
| E&amp;P | $\t\t\t\t10,782 | $\t\t\t\t7,738 |
| OSM | 833 | 692 |
| IG | 150 | 50 |
| Segment\trevenues | 11,765 | 8,480 |
| Elimination\tof\tintersegment\trevenues | (75) | (28) |
| Gain\ton\tU.K.\tnatural\tgas\tcontracts | - | 72 |
| Total\trevenues | \t $\t\t\t\t11,690 | \t $\t\t\t\t8,524 |

E&P	segment	revenues	increased	$3,044	million	from	2009	to	2010,	primarily	due	to	higher	average	liquid	hydrocarbon	and	natural	gas	realizations,	slightly	offset by	lower	natural	gas	sales	volumes.	On	average,	our	worldwide	liquid	hydrocarbon	realizations	were	30	percent	higher	in	2010	than	in	2009	and	our	worldwide	natural gas	realizations	were	18	percent	higher.

E&P	segment	revenues	included	net	derivative	gains	of	$95	million	and	losses	of	$13	million	in	2010	and	2009.	Excluded	from	E&P	segment	revenues	were	gains of	$72	million	in	2009	related	to	natural	gas	sales	contracts	in	the	U.K.	that	were	accounted	for	as	derivative	instruments.	These	U.K.	contracts	expired	in	September 2009.

Included	in	our	E&P	segment	are	supply	optimization	activities	which	include	the	purchase	of	commodities	from	third	parties	for	resale.	Supply	optimization serves	to	aggregate	volumes	in	order	to	satisfy	transportation	commitments	and	to	achieve	flexibility	within	product	types	and	delivery	points.	See	the	Cost	of	revenues discussion	as	revenues	from	supply	optimization	are	approximately	equal	to	those	costs.	Higher	average	crude	oil	prices	in	2010	compared	to	2009	increased	revenues related	to	supply	optimization.

|  | 2010 | 2009 |
| :--- | :--- | :--- |
| United\tStates\tOperating\tStatistics |  |  |
| Net\tliquid\thydrocarbon\tsales\t(mbbld)^(a) | 70 | 64 |
| Liquid\thydrocarbon\taverage\trealizations\t(per\tbbl)^(b) | $\t\t\t\t72.30 | $\t\t\t\t54.67 |
| Net\tnatural\tgas\tsales\t(mmcfd) | 364 | 373 |
| Natural\tgas\taverage\trealizations\t(per\tmcf)^(b) | $4.71 | $4.14 |

Liquid	hydrocarbon	sales	volumes	in	2010	benefited	from	the	Droshky	development	in	the	Gulf	of	Mexico,	which	commenced	production	mid-year	2010.

|  | 2010 | 2009 |
| :--- | :--- | :--- |
| International\tOperating\tStatistics |  |  |
| Net\tliquid\thydrocarbon\tsales\t(mbbld)^(a) |  |  |
| Europe | 92 | 92 |
| Africa | 83 | 87 |
| Total\tInternational | 175 | 179 |
| Liquid\thydrocarbon\taverage\trealizations\t(per\tbbl)^(b) |  |  |
| Europe | $81.95 | $64.46 |
| Africa | 71.71 | 53.91 |
| Total\tInternational | $\t\t\t\t77.11 | $\t\t\t\t59.31 |
| Net\tnatural\tgas\tsales\t(mmcfd) |  |  |
| Europe^(c) | 105 | 138 |
| Africa | 409 | 430 |
| Total\tInternational | 514 | 568 |
| Natural\tgas\taverage\trealizations\t(per\tmcf)^(b) |  |  |
| Europe | $7.10 | $4.90 |
| Africa | 0.25 | 0.25 |
| Total\tInternational | $1.65 | $1.38 |

Excludes	gains	and	losses	on	derivative	instruments	and	the	unrealized	effects	of	U.K.	natural	gas	contracts	that	were	accounted	for	as	derivatives. (b)

Includes	natural	gas	acquired	for	injection	and	subsequent	resale	of	18	mmcfd	and	22	mmcfd	in	2010	and	2009. (c)

Compared	to	2009,	international	natural	gas	sales	volumes	are	lower	primarily	due	to	a	turnarounds	in	2010	in	EG	and	the	U.K.

OSM	segment	revenues	increased	$141	million	from	2009	to	2010.	Revenues	were	impacted	by	net	gains	of	$25	million	and	$13	million	on	derivative	instruments in	2010	and	2009.	Excluding	the	derivatives	impact,	the	increase	in	revenue	reflects	the	26	percent	increase	in	synthetic	crude	oil	realizations.	Synthetic	crude	oil	sales volumes	were	lower	in	2010	due	to	the	impact	of	the	planned	turnaround	at	the	Muskeg	River	mine	and	upgrader	that	began	in	late	March	2010	and	halted	production	in April	before	a	staged	resumption	of	operations	in	May	2010.

IG	segment	revenues	increased	$100	million	from	2009	to	2010	primarily	due	to	higher	commodity	prices.

Income	from	equity	method	investments	increased	$76	million	in	2010	from	2009	primarily	due	to	the	impact	of	higher	commodity	prices	on	the	earnings	of many	of	our	equity	method	investees	in	2010.

Net	gain	on	disposal	of	assets	in	2010	is	primarily	related	to	the	pretax	gain	of	$811	million	on	the	sale	of	a	20	percent	outside-operated	interest	in	our	Production Sharing	Contract	and	Joint	Operating	Agreement	in	Block	32	offshore	Angola.	In	2009,	we	sold	our	operated	and	a	portion	of	our	outside-operated	Permian	Basin producing	assets	in	New	Mexico	and	west	Texas,	plus	sales	of	other	oil	and	gas	properties.

Cost	of	revenues	increased	$1,616	million	from	2009	to	2010	primarily	due	the	impact	of	higher	crude	oil	prices	on	our	supply	optimization	activities.	Costs related	to	supply	optimization	were	$2,530	million	in	2010	compared	to	$1,445	million	in	2009.	Additionally,	OSM	segment	costs	were	higher	in	2010	due	to	the planned	turnaround	at	the	Muskeg	River	mine	and	the	upgrader.

Purchases	from	related	parties	increased	$26	million	from	2009	as	a	result	of	purchases	from	the	Alba	LPG	plant	in	EG,	in	which	we	own	an	equity	interest. Higher	liquid	hydrocarbon	prices	in	2010	increased	the	value	of	those	purchases.

Depreciation,	depletion	and	amortization	increased	$122	million	in	2010	from	2009.	Since	both	our	E&P	and	OSM	segments	apply	the	units-of-production method	to	the	majority	of	their	assets,	the	previously	discussed	increases	or	decreases	in	sales	volumes	generally	result	in	similar	changes	in	DD&A.	Increased	DD&A	in 2010	reflects	the	impact	of	higher	sales	volumes	at	a	higher	rate	of	DD&A	per	barrel	on	our	U.S.	E&P	assets.	The	DD&A	rate	(expense	per	barrel	of	oil	equivalent), which	is	impacted	by	changes	in	proved	reserves	and	capitalized	costs,	can	also	cause	changes	in	our	DD&A.	The	following	table	provides	DD&A	rates	for	our	E&P and	OSM	segments.

| ($	per	boe) | 2010 | 2009 |
| :--- | :--- | :--- |
| DD&amp;A\trate |  |  |
| E&amp;P\tSegment |  |  |
| United\tStates | $\t\t\t\t22 | $\t\t\t\t18 |
| International | 9 | 9 |
| OSM\tSegment | $16 | $12 |

Impairments	in	2010	includes	$423	million	related	to	our	Powder	River	Basin	field	in	the	first	quarter,	as	well	as	smaller	impairments	to	other	E&P	segment	fields due	to	reductions	in	estimated	reserves,	reduced	drilling	expectations	and	declining	natural	gas	prices.	See	Item	8.	Financial	Statements	and	Supplementary	Data—Note 15	to	the	consolidated	financial	statements	for	further	information	about	the	impairments.

General	and	administrative	expenses	increased	$40	million	in	2010	compared	to	2009	primarily	due	to	additional	compensation	expense	and	higher	defined benefit	costs	(see	Item	8.	Financial	Statements	and	Supplementary	Data—Note	20	to	the	consolidated	financial	statements	for	further	information	about	defined	benefit costs).

Other	taxes	increased	$26	million	in	2010	compared	to	2009.	With	the	increase	in	revenues,	particularly	related	to	higher	prices,	production	and	ad	valorem	taxes increased.

Exploration	expenses	were	higher	in	2010	than	2009	primarily	due	to	higher	dry	well	costs.	Dry	wells	primarily	related	to	Gulf	of	Mexico,	Indonesia,	Norway	and various	U.S.	onshore	properties	in	2010	and	to	Europe	and	Africa	in	2009.	The	following	table	summarizes	the	components	of	exploration	expenses.

| (In	millions) | 2010 | 2009 |
| :--- | :--- | :--- |
| Dry\twell\tand\tunproved\tproperty\timpairment | $\t\t\t\t223 | $83 |
| Geological,\tgeophysical,\tseismic | 116 | 105 |
| Other | 159 | 119 |
| Total\texploration\texpenses | $498 | $\t\t\t\t307 |

Loss	on	early	extinguishment	of	debt	relates	to	debt	retirements	in	April	of	2010.	See	Item	8.	Financial	Statements	and	Supplementary	Data—Note	17	to	the consolidated	financial	statements	for	additional	discussion	of	these	transactions.

Provision	for	income	taxes	increased	$128	million	from	2009	to	2010	primarily	due	to	the	increase	in	pretax	income.	The	effective	rate,	however,	decreased	from 74	percent	in	2009	to	54	percent	in	2010.	In	2009	more	income	was	generated	in	high	tax	jurisdictions	than	in	2010.	In	addition,	in	2009,	it	was	determined	that	we	may not	be	able	to	realize	all	recorded	foreign	tax	benefits	and	therefore	a	valuation	allowance	was	recorded	against	these	benefits.

The	following	is	an	analysis	of	the	effective	income	tax	rates	for	2010	and	2009:

|  | 2010 | 2009 |
| :--- | :--- | :--- |
| Statutory\trate\tapplied\tto\tincome\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | 35% | 35% |
| Effects\tof\tforeign\toperations,\tincluding\tforeign\ttax\tcredits | 20 | 16 |
| Foreign\tcurrency\tremeasurement\tloss | - | 11 |
| Adjustments\tto\tvaluation\tallowances | (2) | 10 |
| Tax\tlaw\tchange | 1 | - |
| Other | - | 2 |
| Effective\tincome\ttax\trate\ton\tcontinuing\toperations | \t\t\t\t\t54% | \t\t\t\t\t74% |

The	effective	tax	rate	is	influenced	by	a	variety	of	factors	including	the	geographical	and	functional	sources	of	income,	the	relative	magnitude	of	these	sources	of income,	foreign	currency	remeasurement	effects,	and	tax	legislation	changes.	See	Item	8.	Financial	Statements	and	Supplementary	Data—Note	10	to	the	consolidated financial	statements	for	further	information	about	income	taxes.

Discontinued	operations	reflect	the	June	30,	2011	spin-off	of	our	downstream	business	and	the	2009	disposals	of	our	E&P	businesses	in	Ireland	and	Gabon	and their	historical	operating	results,	net	of	tax,	for	all	periods	presented.	See	Item	8.	Financial	Statements	and	Supplementary	Data—Notes	3	and	6	to	the	consolidated financial	statements.

Segment	income	for	2010	and	2009	is	summarized	and	reconciled	to	net	income	in	the	following	table.

| (In	millions) | 2010 | 2009 |
| :--- | :--- | :--- |
| E&amp;P |  |  |
| United\tStates | $251 | $52 |
| International | 1,690 | 1,166 |
| E&amp;P\tsegment | 1,941 | 1,218 |
| OSM | (50) | 44 |
| IG | 142 | 90 |
| Segment\tincome | 2,033 | 1,352 |
| Items\tnot\tallocated\tto\tsegments,\tnet\tof\tincome\ttaxes: |  |  |
| Corporate\tand\tother\tunallocated\titems | (202) | (431) |
| Foreign\tcurrency\tremeasurement\tof\ttaxes | 32 | (319) |
| Impairments | (286) | (45) |
| Loss\ton\tearly\textinguishment\tof\tdebt | (57) | - |
| Deferred\tincome\ttaxes | (45) | - |
| Gain\ton\tdispositions | 407 | 122 |
| Gain\ton\tU.K.\tnatural\tgas\tcontracts^(a) | - | 37 |
| Income\tfrom\tcontinuing\toperations | 1,882 | 716 |
| Discontinued\toperations | 686 | 747 |
| Net\tincome | $\t\t\t\t2,568 | $\t\t\t\t1,463 |
| (a) |  |  |

Amounts	relate	to	natural	gas	contracts	in	the	U.	K.	that	were	accounted	for	as	derivative	instruments	and	recorded	at	fair	value. (a)

United	States	E&P	income	increased	$199	million	from	2009	to	2010.	The	majority	of	the	income	increase	was	due	to	higher	liquid	hydrocarbon	and	natural	gas realizations	in	2010,	along	with	higher	liquid	hydrocarbon	sales	volumes,	partially	offset	by	higher	DD&A	and	higher	exploration	and	operating	costs.	Exploration expenses	were	$275	million	for	2010,	compared	 to	$153	million	for	2009,	reflecting	 increased	geological	and	geophysical	spending	focused	on	shale	plays	and exploration	dry	well	expense,	primarily	the	Flying	Dutchman	well	in	the	Gulf	of	Mexico.

International	E&P	income	increased	$524	million	from	2009	to	2010.	This	increase	was	primarily	related	to	higher	liquid	hydrocarbon	and	natural	gas	realizations, partially	offset	by	higher	exploration	expenses	and	income	taxes.	Exploration	expenses	were	$223	million	for	2010,	compared	to	$154	million	for	2009,	reflecting	higher dry	well	expense	with	dry	wells	in	Indonesia,	Norway	and	EG.

OSM	segment	income	decreased	$94	million	from	2009	to	2010.	Cost	increases	in	2010	associated	with	the	planned	turnaround	at	the	Muskeg	River	mine	and	the Jackpine	mine	start-up	were	in	excess	of	the	revenue	increase	previously	discussed.	Results	for	2010	included	after-tax	gains	on	crude	oil	derivative	instruments	of	$19 million,	while	the	impact	of	derivatives	on	2009	was	not	significant.

IG	segment	income	increased	$52	million	from	2009	to	2010.	The	increase	in	income	was	primarily	the	result	of	higher	realizations	for	LNG	and	methanol.

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

# Cash	Flows

Net	cash	used	in	investing	activities	related	to	continuing	operations	totaled	$7,174	million	in	2011	compared	to	$2,157	million	in	2010	and	$2,359	million	in 2009.	Significant	investing	activities	include	acquisitions,	additions	to	property,	plant	and	equipment	and	asset	disposals.

Acquisitions	in	2011	included	proved	and	unproved	assets	in	the	Eagle	Ford	shale	play	in	south	Texas.	See	Item	8.	Financial	Statements	and	Supplementary	Data	– Note	5	to	the	consolidated	financial	statements	for	further	information	about	the	transactions.

The	most	significant	additions	to	property,	plant	and	equipment	relate	to	our	long-term	projects,	which	cross	several	years.	In	our	E&P	segment,	exploration	and development	projects	 in	Angola	 impacted	all	 three	years.	Development	of	fields	 tied	back	 to	 the	Alvheim	FPSO	occurred	 in	2009	and	2010.	Spending	on	U.S. exploration	and	development	projects	has	been	increasing	over	the	years,	related	to	unconventional	resource	plays	and	Gulf	of	Mexico	exploration	when	drilling	was allowed.	In	the	OSM	segment,	the	AOSP	Expansion	1,	which	began	in	2008,	was	substantially	complete	in	2010.

Disposal	of	assets	totaled	$518	million,	$1,368	million	and	$812	million	in	2011,	2010	and	2009.	Several	sales	of	non-core	assets	in	2011	and	acreage	farmouts resulted	in	net	proceeds	of	$518	million.	In	2010,	we	closed	the	sale	of	our	20	percent	outside-operated	undivided	interest	in	the	Production	Sharing	Contract	and	Joint Operating	Agreement	in	Block	32	offshore	Angola	for	$1.3	billion.	In	2009,	we	sold	all	of	our	operated	and	outside-operated	interests	in	Ireland	and	Gabon,	reporting the	disposals	as	discontinued	operations.	We	also	sold	our	operated	and	a	portion	of	our	outside-operated	Permian	Basin	producing	assets	in	New	Mexico	and	west Texas.	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	$5,211	million	in	2011,	but	provided	cash	of	$1,343	million	in	2010	and	$737 million	2009.	In	connection	with	the	spin-off,	we	distributed	$1.6	billion	to	MPC	in	the	second	quarter	of	2011.	Early	debt	repayments	of	$2,498	million	and	$500 million	occurred	in	2011	and	2010.	Purchases	of	common	stock	used	$300	million	in	cash	during	2011.	Sources	of	cash	in	2009	included	the	issuance	of	$1.5	billion	in senior	notes.	Dividend	payments	were	uses	of	cash	in	every	year.

# 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	$3.0	billion	committed revolving	credit	facility	and	sales	of	non-core	assets.	Because	of	the	alternatives	available	to	us,	including	internally	generated	cash	flow	and	access	to	capital	markets, 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,	2011,	we	had	$4,815	million	in	long-term	debt	outstanding,	$141	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,	2011,	we	had	no	borrowings	outstanding	against	our	$3	billion	revolving	credit	facility,	the	vast	majority	of	which	has	a	termination	date	of	May 2013,	and	no	commercial	paper	outstanding	under	our	U.S.	commercial	paper	program	that	is	backed	by	the	revolving	credit	facility.

# Shelf	Registration

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

# 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	20	percent	and	14	percent	at	December	31,	2011	and	2010.

| (Dollars	in	millions) | 2011 | 2010 |
| :--- | :--- | :--- |
| Long-term\tdebt\tdue\twithin\tone\tyear | $141 | $295 |
| Long-term\tdebt | 4,674 | 7,601 |
| Total\tdebt | $4,815 | $7,896 |
| Cash | $493 | $3,951 |
| Equity | $\t\t\t\t17,159 | $\t\t\t\t23,771 |
| Calculation: |  |  |
| Total\tdebt | $4,815 | $7,896 |
| Minus\tcash | 493 | 3,951 |
| Total\tdebt\tminus\tcash | 4,322 | 3,945 |
| Total\tdebt | 4,815 | 7,896 |
| Plus\tequity | 17,159 | 23,771 |
| Minus\tcash | 493 | 3,951 |
| Total\tdebt\tplus\tequity\tminus\tcash | $21,481 | $27,716 |
| Cash-adjusted\tdebt-to-capital\tratio | 20% | 14% |

# Capital	Requirements

# Capital	Spending

Our	approved	capital,	investment	and	exploration	budget	for	2012	is	$4,822	million.	Additional	details	related	to	the	2012	budget	are	discussed	in	Outlook.

# Other	Expected	Cash	Outflows

We	plan	to	make	contributions	of	up	to	$113	million	to	our	pension	plans	during	2012.	As	of	December	31,	2011,	$141	million	of	our	long-term	debt	is	due	in	the next	twelve	months.

Dividends	of	$0.80	per	common	share	or	$567	million	were	paid	during	2011	reflecting	quarterly	dividends	of	$0.25	per	share	in	the	first	two	quarters	and	$0.15 per	share	in	the	two	quarters	after	the	spin-off	of	our	downstream	business.	On	January	27,	2012,	we	announced	that	our	Board	of	Directors	had	declared	a	dividend	of $0.17	cents	per	share	on	Marathon	Oil	common	stock,	payable	March	12,	2012,	to	stockholders	of	record	at	the	close	of	business	on	February	16,	2012.	This	is	a	13 percent	increase	over	the	dividend	paid	in	the	preceding	quarter.

# Share	Repurchase	Program

Since	January	2006,	our	Board	of	Directors	has	authorized	a	common	share	repurchase	program	totaling	$5	billion.	As	of	December	31,	2011,	we	had	repurchased 78	million	common	shares	at	a	cost	of	$3,222	million,	with	66	million	shares	purchased	for	$2,922	million	prior	to	the	spin-off	of	our	downstream	business	and 12	million	shares	acquired	at	a	cost	of	$300	million	in	the	third	quarter	of	2011.	Purchases	under	the	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.

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	expected capital,	investment	and	exploration	spending	and	planned	funding	of	our	pension	plans.	The	forward-looking	statements	about	our	capital,	investment	and	exploration budget	are	based	on	current	expectations,	estimates	and	projections	and	are	not	guarantees	of	future	performance.	The	forward-looking	statements	about	our	common share	repurchase	program	are

based	on	current	expectations,	estimates	and	projections	and	are	not	guarantees	of	future	performance.	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	are	difficult	to	predict.	Some	factors that	could	cause	actual	results	to	differ	materially	include	prices	of	and	demand	for	liquid	hydrocarbons,	natural	gas	and	synthetic	crude	oil,	actions	of	competitors, disruptions	or	interruptions	of	our	production	or	oil	sands	mining	and	bitumen	upgrading	operations	due	to	the	shortage	of	skilled	labor	and	unforeseen	hazards	such	as weather	conditions,	acts	of	war	or	terrorist	acts	and	the	governmental	or	military	response,	and	other	operating	and	economic	considerations.

# Contractual	Cash	Obligations

The	table	below	provides	aggregated	information	on	our	consolidated	obligations	to	make	future	payments	under	existing	contracts	as	of	December	31,	2011.

|  |  |  | 2013- | 2015- | Later |
| :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Total | 2012 | 2014 | 2016 | Years |
| Long-term\tdebt\t(excludes\tinterest)^(a) | $4,794 | $141 | $274 | $69 | $4,310 |
| Lease\tobligations | 275 | 64 | 69 | 53 | 89 |
| Purchase\tobligations: |  |  |  |  |  |
| Oil\tand\tgas\tactivities^(b) | 2,709 | 541 | 814 | 549 | 805 |
| Service\tand\tmaterials\tcontracts^(c) | 1,044 | 169 | 198 | 129 | 548 |
| Transportation\tand\trelated\tcontracts | 1,303 | 322 | 174 | 129 | 678 |
| Drilling\trigs\tand\tfracturing\tcrews | 1,079 | 506 | 551 | 22 |  |
| Other | 276 | 108 | 85 | 28 | 55 |
| Total\tpurchase\tobligations | 6,411 | 1,646 | 1,822 | 857 | 2,086 |
| Other\tlong-term\tliabilities\treported |  |  |  |  |  |
| in\tthe\tconsolidated\tbalance\tsheet^(d) | 1,231 | 176 | 273 | 251 | 531 |
| Total\tcontractual\tcash\tobligations^(e) | $\t\t\t\t12,711 | $\t\t\t\t2,027 | $\t\t\t\t2,438 | $\t\t\t\t1,230 | $\t\t\t\t7,016 |

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.

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

Primarily	includes	obligations	for	pension	and	other	postretirement	benefits	including	medical	and	life	insurance.	We	have	estimated	projected	funding	requirements	through	2021.	Also	includes	amounts	for uncertain	tax	positions.

This	table	does	not	include	the	estimated	discounted	liability	for	dismantlement,	abandonment	and	restoration	costs	of	oil	and	gas	properties	of	$1,510	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	Equatorial	Guinea.	Onshore	Equatorial	Guinea,	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.	The	methanol	that	is	produced	is	then	sold	through another	equity	method	investee.

# 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,	2011,	2010	and	2009	aggregated $231	million,	$439	million	and	$224	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,	future	abandonment	liabilities	and	prior	to	June	30,	2011,	crude	purchases	by	our downstream	business	which	we	spun-off	on	that	date.	The	decline	in	the	level	of	our	outstanding	letters	of	credit	in	2011	is	primarily	related	to	the	spin-off	of	our downstream	business.

# Outlook

Our	Board	of	Directors	approved	a	capital,	investment	and	exploration	budget	of	$4,822	million	for	2012,	including	budgeted	capital	expenditures	of	$4,402 million	which	represented	a	29	percent	increase	from	2011	spending.	Our	focus	in	2012	continues	to	be	our	U.S.	liquids-rich	growth	assets,	which	account	for	almost	65 percent	of	the	2012	budget.	Further	detail	of	our	budget	by	segment	and	asset	lifecycle	is	presented	below.	For	additional	information	about	expected	exploration	and development	activities	on	specific	assets	see	Item	1.	Business.

The	worldwide	exploration	and	production	budget	for	2012	is	$4,387	million,	a	44	percent	increase	over	2011	capital	spending.	The	exploration	and	production strategy	is	based	on	three	key	elements:	a	solid	portfolio	of	base	assets,	growth	assets	and	impact	exploration.	Almost	two	thirds,	or	$3,041	million	of	the	budget	is allocated	to	our	growth	assets	and	almost	one	half	of	that	is	targeted	to	ramp	up	our	operations	in	the	Eagle	Ford	shale	play	in	Texas.	We	will	also	continue	to	build	on our	substantial	positions	in	the	Bakken	and	Anadarko	Woodford	shale	plays	and	to	establish	our	business	in	the	emerging	Niobrara	shale	play	of	the	DJ	Basin. Approximately	$2.7	billion	of	our	budget	is	concentrated	in	these	four	U.S.	liquids-rich	resource	plays.

Spending	 on	 our	 base	 E&P	 assets	 is	 budgeted	 at	 $913	 million	 for	 2012.	These	 assets	 include	 production	 operations	 in	 the	 Gulf	 of	 Mexico,	 Norway,	 U.S. conventional	oil	and	gas	plays,	Equatorial	Guinea,	the	U.K.	and	Libya	which	generate	much	of	the	cash	that	will	be	available	for	investment	in	our	growth	assets	and exploration	projects.

Impact	exploration	projects	account	for	9	percent,	or	$433	million	of	the	2012	budget	and	include	conducting	seismic	surveys	and	drilling	12	–	18	gross	(6	–	10	net) wells	on	prospects	in	the	deepwater	Gulf	of	Mexico,	the	Iraqi	Kurdistan	Region	and	Poland.

The	above	discussion	includes	forward-looking	statements	with	respect	to	anticipated	future	exploratory	and	development	drilling	activity,	investments	in	new	and existing	resource	plays	and	potential	development	projects.	Some	factors	which	could	potentially	affect	these	forward-looking	statements	include	pricing,	supply	and demand	for	petroleum	products,	the	amount	of	capital	available	for	exploration	and	development,	regulatory	constraints,	drilling	rig	availability,	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.	The foregoing	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	offshore	developments	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.

The	Oil	Sands	Mining	segment	budget	for	2012	is	$275	million.	The	2012	budget	includes	funds	for	the	initiation	of	debottlenecking	projects,	continued	evaluation of	Quest	CCS	and	other	capital	expenditures.	A	final	investment	decision	on	Quest	CCS	is	expected	to	be	made	in	2012,	and	is	subject	to	regulatory	approvals, stakeholder	engagement,	detailed	engineering	studies,	as	well	as	a	final	joint	venture	partner	agreement.

# Corporate	and	Other

The	remaining	$160	million	of	our	2012	budget	is	split	roughly	in	half	between	capitalized	interest	on	ongoing	projects	and	other	corporate	activities.	Additionally, $1	million	is	budgeted	for	our	Integrated	Gas	segment.

The	forward-looking	statements	about	our	capital,	investment	and	exploration	budget	are	based	on	current	expectations,	estimates	and	projections	and	are	not guarantees	of	future	performance.	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	are	difficult	to	predict.	Some	factors	that	could	cause	actual	results	to	differ	materially	include	prices	of	and demand	for	crude	oil	and	natural	gas,	actions	of	competitors,	disruptions	or	interruptions	of	our	production	or	bitumen	mining	and	upgrading	operations	due	to	the shortage	of	skilled	labor	and	unforeseen	hazards	such	as	weather	conditions,	acts	of	war	or	terrorist	acts	and	the	governmental	or	military	response,	and	other	operating and	economic	considerations.

# 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.

Our	environmental	expenditures^(a) 	related	to	continuing	operations	for	each	of	the	last	three	years	were:

| (In	millions) | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| Capital | $122 | $82 | $91 |
| Compliance |  |  |  |
| Operating\tand\tmaintenance | 35 | 26 | 23 |
| Remediation^(b) | 5 | 1 | 2 |
| Total | $\t\t\t\t162 | $\t\t\t\t109 | $\t\t\t\t116 |

Amounts	are	determined	based	on	American	Petroleum	Institute	survey	guidelines	regarding	the	definition	of	environmental	expenditures.

These	amounts	include	spending	charged	against	remediation	reserves,	where	permissible,	but	exclude	non-cash	provisions	recorded	for	environmental	remediation.

Our	environmental	capital	expenditures	accounted	for	four	percent	of	capital	expenditures	for	continuing	operations	in	2011,	two	percent	in	2010	and	three	percent in	2009.

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

New	or	expanded	environmental	requirements,	which	could	increase	our	environmental	costs,	may	arise	in	the	future.	We	comply	with	all	legal	requirements regarding	the	environment,	but	since	not	all	of	them	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.

Our	environmental	capital	expenditures	related	 to	continuing	operations	are	expected	 to	 be	 $167	 million,	 or	 three	 percent,	 of	 capital	 expenditures	 in	 2012. Predictions	 beyond	 2012	 can	 only	 be	 broad-based	 estimates,	 which	 have	 varied,	 and	 will	 continue	 to	 vary,	 due	 to	 the	 ongoing	 evolution	 of	 specific	 regulatory requirements,	the	possible	imposition	of	more	stringent	requirements	and	the	availability	of	new	technologies,	among	other	matters.	Based	on	currently	identified projects,	we	anticipate	that	environmental	capital	expenditures	will	be	approximately	$205	million	in	2013;	however,	actual	expenditures	may	vary	as	the	number	and scope	of	environmental	projects	are	revised	as	a	result	of	improved	technology	or	changes	in	regulatory	requirements	and	could	increase	if	additional	projects	are identified	or	additional	requirements	are	imposed.

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

# Critical	Accounting	Estimates

The	preparation	of	financial	statements	 in	accordance	with	accounting	principles	generally	accepted	 in	 the	United	States	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	either	our	E&P	or	our	OSM	segments.	However,	during	2009,	the	change	to	presenting	oil	sands	mining	reserves	as synthetic	crude	oil	under	the	SEC's	revised	regulations	caused	our	reported	revisions	to	previous	estimates	to	be	near	50	percent	of	the	beginning	of	the	year	reserve estimate.	This	presentation	change	did	not	have	a	significant	impact	upon	the	calculation	of	depreciation,	depletion	and	amortization	for	our	OSM	segment.	For	our E&P	segment,	on	average,	a	five	percent	increase	in	the	amount	of	proved	liquid	hydrocarbon	and	natural	gas	reserves	would	lower	the	depreciation	and	depletion	rate by	approximately	$0.66	per	barrel,	which	would	increase	pretax	income	by	approximately	$87	million	annually,	based	on	2011	production.	Conversely,	on	average,	a five	percent	decrease	in	the	amount	of	proved	liquid	hydrocarbon	and	natural	gas	reserves	would	increase	the	depreciation	and	depletion	rate	by	approximately	$0.72	per barrel	and	would	result	in	a	decrease	in	pretax	income	of	approximately	$96	million	annually,	based	on	2011	production.	For	our	OSM	segment,	on	average,	a	five percent	increase	in	estimated	proved	synthetic	crude	oil	reserves	would	lower	the	depreciation	and	depletion	rate	by	approximately	$0.62	per	barrel	and	would	result	in an	increase	in	pretax	income	of	approximately	$9	million	annually,	based	on	2011	production.	On	average,	a	five	percent	decrease	in	estimated	proved	synthetic	crude oil	reserves	would	increase	the	depreciation	and	depletion	rate	by	approximately	$0.69	per	barrel	and	would	result	in	a	decrease	in	pretax	income	of	approximately	$9 million	annually,	based	on	2011	production.

# 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	amount	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	does	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.	We	use	a	market	or	income	approach	for	recurring	fair	value	measurements and	endeavor	to	use	the	best	information	available.	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	in	those	acquisitions;	and

•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	used	in	operations	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	E&P	assets	and	project	level	for	oil	sands	mining	assets.	If	the	sum	of	the	undiscounted	estimated	pretax	cash	flows	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	expected	present	value	of	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	proved	and	probable	reserves such	that	the	combined	volumes	represent	the	most	likely	expectation	of	recovery.	By	definition,	probable	reserve	estimates	are	less	precise	than	proved reserve	estimates.

•Expected	timing	of	production.	Production	forecasts	are	the	outcome	of	engineer	studies	which	estimate	proved	and	probable	reserves.	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	on	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	2011,	we	completed	a business	combination	in	the	Eagle	Ford	shale	with	an	aggregate	purchase	price	of	$4.5	billion	that	was	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.	A	large	volume	of	our	commodity	derivatives	are	exchange-traded	and	require	few	assumptions	in	arriving	at	fair value.	Fair	value	estimation	for	all	our	derivative	instruments	is	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 proved	and,	in	some	cases,	probable	and	possible	reserves	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	prevailing	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	funded	U.S.	pension	plan	and	our	unfunded	U.S.	retiree	health	care	plan	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	AA	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 issuance	within	each	defined	maturity	group.

Of	the	assumptions	used	to	measure	the	yearend	obligations	and	estimated	annual	net	periodic	benefit	cost,	the	discount	rate	has	the	most	significant	effect	on	the periodic	benefit	cost	reported	for	the	plans.	Decreasing	the	discount	rates	of	4.45	percent	for	our	U.S.	pension	plan	and	4.90	percent	for	our	other	U.S.	postretirement benefit	plan	by	0.25	would	increase	pension	obligations	and	other	postretirement	benefit	plan	obligations	by	$43	million	and	$9	million	and	would	increase	annual defined	benefit	pension	expense	by	$5	million	and	would	not	have	a	significant	impact	on	other	postretirement	benefit	plan	expense.

The	asset	rate	of	return	assumption	considers	the	asset	mix	of	the	plans	(targeted	at	approximately	75	percent	equity	securities	and	25	percent	debt	securities	for	the U.S.	funded	pension	plan	through	2011,	65	percent	equity	securities	and	35	percent	debt	securities	for	the	U.S.	funded	pension	plan	beginning	in	2012	and	70	percent equity	securities	and	30	percent	debt	securities	for	the	international	funded	pension	plans),	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	7.75	percent	asset	rate	of	return	assumption	by	0.25	would	not	have	a	significant	impact	on our	defined	benefit	pension	expense.

Compensation	change	assumptions	are	based	on	historical	experience,	anticipated	future	management	actions	and	demographics	of	the	benefit	plans.

Health	care	cost	trend	assumptions	are	developed	based	on	historical	cost	data,	the	near-term	outlook	and	an	assessment	of	likely	long-term	trends.

Item	8.	Financial	Statements	and	Supplementary	Data	–	Note	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	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	cost	of	revenues	or	selling,	general	and	administrative	expenses	in	the	consolidated	statements of	income,	except	for	tax	contingencies	unrelated	to	income	taxes,

which	are	recorded	as	other	taxes.	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

The	FASB	and	the	IASB	issued	joint	disclosure	requirements	in	December	2011	designed	to	enhance	disclosures	about	offsetting	assets	and	liabilities	that	will 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	financial	instruments	and	derivative	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.	These	disclosures	are	effective	for	us	beginning	the	first	quarter	of 2013	and	must	be	made	retrospectively	for	comparable	periods.	Adoption	of	this	amendment	will	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.	The	amendment	is	effective	for our	interim	and	annual	periods	beginning	with	the	first	quarter	of	2012.	Early	adoption	is	permitted,	but	we	were	unable	to	do	so	because	our	2011	annual	goodwill impairment	testing	was	completed	prior	to	the	issuance	of	the	amendment.	Adoption	of	this	amendment	will	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	Other	Comprehensive Income	("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	the	total	of 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	are	effective	for	us	beginning	with	the	first	quarter of	2012,	except	for	the	presentation	of	reclassifications,	which	has	been	deferred.	Adoption	of	this	amendment	will	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.	The	 amendments	 are	 to	 be	 applied prospectively	and	will	be	effective	for	our	interim	and	annual	periods	beginning	with	the	first	quarter	of	2012.	Early	application	is	not	permitted.	We	do	not	expect adoption	of	these	amendments	to	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	statement	for	more	information	about	the	fair	value measurement	of	our	derivatives,	as	well	as	the	amounts	recorded	in	our	consolidated	balance	sheets	and	statements	of	income	for	those	which	qualify	as	hedges	and those	not	designated	as	hedges.

# 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	occasionally	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.

We	regularly	use	commodity	derivative	instruments	in	the	E&P	segment	to	manage	natural	gas	price	risk	during	the	time	that	the	natural	gas	is	held	in	storage before	it	is	sold	or	related	to	our	supply	optimization	activities.

The	fair	value	of	commodity	derivatives	outstanding	at	December	31,	2011	was	less	than	$1	million.	For	these	derivatives,	hypothetical	10	percent	and	25	percent increases	and	decreases	in	commodity	prices	would	not	significantly	impact	income	from	operations	("IFO").	We	evaluate	our	portfolio	of	commodity	derivative instruments	on	an	ongoing	basis	and	add	or	revise	strategies	in	anticipation	of	changes	in	market	conditions	and	in	risk	profiles.

# 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,	2011,	we	had	multiple	interest	rate	swap	agreements	with	a	total	notional	amount	of	$600	million	at	a	weighted- average,	LIBOR-based,	floating	rate	of	4.76	percent.	These	interest	rate	swaps	are	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.

Sensitivity	analysis	of	the	projected	incremental	effect	of	a	hypothetical	10	percent	change	in	interest	rates	on	financial	assets	and	liabilities	as	of	December	31, 2011,	is	provided	in	the	following	table.

| (In	millions) | Fair	Value | Fair	Value |
| :--- | :--- | :--- |
| Financial\tassets\t(liabilities)^(a) |  |  |
| Interest\trate\tswap\tagreements | $\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t5^\t(b) | $\t\t\t\t\t\t\t\t\t\t\t\t4 |
| Long-term\tdebt,\tincluding\tamounts\tdue\twithin\tone\tyear | $(5,479)^\t(b) | $(231) |

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

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

At	December	31,	2011,	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.

# 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.	There	were	no	foreign	currency	forward	or	option	contracts	open	at	December	31, 2011.

# 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

|  | Page |
| :--- | :--- |
| Management's\tResponsibilities\tfor\tFinancial\tStatements | 54 |
| Management's\tReport\ton\tInternal\tControl\tover\tFinancial\tReporting | 54 |
| Report\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm | 55 |
| Audited\tConsolidated\tFinancial\tStatements |  |
| Consolidated\tStatements\tof\tIncome | 56 |
| Consolidated\tStatements\tof\tComprehensive\tIncome | 57 |
| Consolidated\tBalance\tSheets | 58 |
| Consolidated\tStatements\tof\tCash\tFlows | 59 |
| Consolidated\tStatements\tof\tStockholders'\tEquity | 60 |
| Notes\tto\tConsolidated\tFinancial\tStatements | 61 |
| Select\tQuarterly\tFinancial\tData\t(Unaudited) | 96 |
| Supplementary\tInformation\ton\tOil\tand\tGas\tProducing\tActivities\t(Unaudited) | 97 |
| Supplemental\tStatistics\t(Unaudited) | \t 104 |

# 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	Unites	States	of	America.	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/	Clarence	P.	Cazalot,	Jr.

Chairman,	President	and

Chief	Executive	Officer

/s/	Janet	F.	Clark

Executive	Vice	President	and

Chief	Financial	Officer

/s/	Michael	K.	Stewart

Vice	President,	Finance	and

Accounting,	Controller	and	Treasurer

# 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	Rule	13a	–	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	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,	2011.

The	effectiveness	of	Marathon	Oil's	internal	control	over	financial	reporting	as	of	December	31,	2011	has	been	audited	by	PricewaterhouseCoopers	LLP,	an independent	public	accounting	firm,	as	stated	in	their	report	which	is	included	herein.

Executive	Vice	President

and	Chief	Financial	Officer

# 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,	2011,	and	2010,	and	the	results	of	their	operations	and	their	cash	flows	for	each	of	the	three	years	in the	period	ended	December	31,	2011,	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States	of	America.	Also	in	our	opinion,	the	Company maintained,	in	all	material	respects,	effective	internal	control	over	financial	reporting	as	of	December	31,	2011,	based	on	criteria	established	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	29,	2012

# Consolidated	Statements	of	Income

| (In	millions,	except	per	share	data) | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| Revenues\tand\tother\tincome: |  |  |  |
| Sales\tand\tother\toperating\trevenues | $\t\t\t\t\t\t14,603 | $\t\t\t\t\t\t11,634 | $\t\t\t\t\t\t8,465 |
| Sales\tto\trelated\tparties | 60 | 56 | 59 |
| Income\tfrom\tequity\tmethod\tinvestments | 462 | 344 | 268 |
| Net\tgain\ton\tdisposal\tof\tassets | 103 | 766 | 202 |
| Other\tincome | 54 | 73 | 90 |
| Total\trevenues\tand\tother\tincome | 15,282 | 12,873 | 9,084 |
| Costs\tand\texpenses: |  |  |  |
| Cost\tof\trevenues\t(excludes\titems\tbelow) | 6,225 | 4,786 | 3,170 |
| Purchases\tfrom\trelated\tparties | 250 | 172 | 146 |
| Depreciation,\tdepletion\tand\tamortization | 2,266 | 2,056 | 1,934 |
| Impairments | 310 | 447 | 18 |
| General\tand\tadministrative\texpenses | 544 | 491 | 451 |
| Other\ttaxes | 230 | 199 | 173 |
| Exploration\texpenses | 644 | 498 | 307 |
| Total\tcosts\tand\texpenses | 10,469 | 8,649 | 6,199 |
| Income\tfrom\toperations | 4,813 | 4,224 | 2,885 |
| Net\tinterest\tand\tother | (107) | (75) | (122) |
| Loss\ton\tearly\textinguishment\tof\tdebt | (279) | (92) | - |
| Income\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | 4,427 | 4,057 | 2,763 |
| Provision\tfor\tincome\ttaxes | 2,720 | 2,175 | 2,047 |
| Income\tfrom\tcontinuing\toperations | 1,707 | 1,882 | 716 |
| Discontinued\toperations | 1,239 | 686 | 747 |
| Net\tincome | $2,946 | $2,568 | $1,463 |
| Per\tShare\tData |  |  |  |
| Basic: |  |  |  |
| Income\tfrom\tcontinuing\toperations | $2.40 | $2.65 | $1.01 |
| Discontinued\toperations | $1.75 | $0.97 | $1.05 |
| Net\tincome | $4.15 | $3.62 | $2.06 |
| Diluted: |  |  |  |
| Income\tfrom\tcontinuing\toperations | $2.39 | $2.65 | $1.01 |
| Discontinued\toperations | $1.74 | $0.96 | $1.05 |
| Net\tincome | $4.13 | $3.61 | $2.06 |
| Dividends | $0.80 | $0.99 | $0.96 |
| Weighted\taverage\tshares: |  |  |  |
| Basic | 710 | 710 | 709 |
| Diluted | 714 | 712 | 711 |

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

# Consolidated	Statements	of	Comprehensive	Income

| (In	millions) | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| Net\tincome | $\t\t\t\t2,946 | $\t\t\t\t2,568 | $\t\t\t\t1,463 |
| Other\tcomprehensive\tincome\t(loss) |  |  |  |
| Postretirement\tand\tpost-employment\tplans |  |  |  |
| Change\tin\tactuarial\tgain\t(loss) | 16 | (76) | (564) |
| Spin-off\tdownstream\tbusiness | 968 | - | - |
| Income\ttax\tbenefit\t(provision)\ton\tpostretirement\tand\tpost-employment\tplans | (357) | 7 | 208 |
| Postretirement\tand\tpost-employment\tplans,\tnet\tof\ttax | 627 | (69) | (356) |
| Derivative\thedges |  |  |  |
| Net\tunrecognized\tgain | 9 | 5 | 24 |
| Spin-off\tdownstream\tbusiness | (7) | - | - |
| Income\ttax\tbenefit\t(provision)\ton\tderivative\thedges | (1) | 1 | (12) |
| Derivative\thedges,\tnet\tof\ttax | 1 | 6 | 12 |
| Foreign\tcurrency\ttranslation\tand\tother |  |  |  |
| Unrealized\tgain\t(loss) | (1) | - | 4 |
| Income\ttax\tprovision\ton\tforeign\tcurrency\ttranslation\tand\tother | - | - | (1) |
| Foreign\tcurrency\ttranslation\tand\tother,\tnet\tof\ttax | (1) | - | 3 |
| Other\tcomprehensive\tincome\t(loss) | 627 | (63) | (341) |
| Comprehensive\tincome | $3,573 | $2,505 | $1,122 |

# Consolidated	Balance	Sheets

|  | December	31, |  |
| :--- | :--- | :--- |
| (In\tmillions,\texcept\tper\tshare\tdata) | \t\t\t\t2011 | \t\t\t\t2010 |
| Assets |  |  |
| Current\tassets: |  |  |
| Cash\tand\tcash\tequivalents | $493 | $3,951 |
| Receivables,\tless\tallowance\tfor\tdoubtful\taccounts\tof\t$0\tand\t$7 | 1,917 | 5,972 |
| Receivables\tfrom\trelated\tparties | 35 | 58 |
| Inventories | 361 | 3,453 |
| Prepayments | 96 | 92 |
| Deferred\ttax\tassets | 99 | - |
| Other\tcurrent\tassets | 223 | 303 |
| Total\tcurrent\tassets | 3,224 | 13,829 |
| Equity\tmethod\tinvestments | 1,383 | 1,802 |
| Property,\tplant\tand\tequipment,\tless\taccumulated\tdepreciation, |  |  |
| depletion\tand\tamortization\tof\t$17,248\tand\t$19,805 | 25,324 | 32,222 |
| Goodwill | 536 | 1,380 |
| Other\tnoncurrent\tassets | 904 | 781 |
| Total\tassets | $\t\t\t\t\t\t31,371 | $\t\t\t\t\t\t50,014 |
| Liabilities |  |  |
| Current\tliabilities: |  |  |
| Accounts\tpayable | $1,864 | $8,000 |
| Payables\tto\trelated\tparties | 18 | 49 |
| Payroll\tand\tbenefits\tpayable | 193 | 418 |
| Accrued\ttaxes | 2,015 | 1,447 |
| Deferred\ttax\tliabilities | 5 | 324 |
| Other\tcurrent\tliabilities | 158 | 580 |
| Long-term\tdebt\tdue\twithin\tone\tyear | 141 | 295 |
| Total\tcurrent\tliabilities | 4,394 | 11,113 |
| Long-term\tdebt | 4,674 | 7,601 |
| Deferred\tincome\ttaxes | 2,544 | 3,569 |
| Defined\tbenefit\tpostretirement\tplan\tobligations | 789 | 2,171 |
| Asset\tretirement\tobligations | 1,510 | 1,354 |
| Deferred\tcredits\tand\tother\tliabilities | 301 | 435 |
| Total\tliabilities | 14,212 | 26,243 |
| Commitments\tand\tcontingencies |  |  |
| Stockholders'\tEquity |  |  |
| Preferred\tstock\t-\tno\tshares\tissued\tor\toutstanding\t(no\tpar\tvalue,\t26\tmillion\tshares\tauthorized) | - | - |
| Common\tstock: |  |  |
|  | 770 | 770 |
| Securities\texchangeable\tinto\tcommon\tstock\t–\tno\tshares\tissued\tor\toutstanding |  |  |
| (no\tpar\tvalue,\t29\tmillion\tshares\tauthorized) | - | - |
| Held\tin\ttreasury,\tat\tcost\t–\t66\tmillion\tand\t60\tmillion\tshares | (2,716) | (2,665) |
| Additional\tpaid-in\tcapital | 6,680 | 6,756 |
| Retained\tearnings | 12,788 | 19,907 |
| Accumulated\tother\tcomprehensive\tloss | (370) | (997) |
| Total\tequity\tof\tMarathon\tOil's\tstockholders | 17,152 | 23,771 |
| Noncontrolling\tinterest | 7 | - |
| Total\tequity | 17,159 | 23,771 |
| Total\tliabilities\tand\tequity | $31,371 | $50,014 |

# Consolidated	Statements	of	Cash	Flows

| (In	millions) | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| Increase\t(decrease)\tin\tcash\tand\tcash\tequivalents |  |  |  |
| Operating\tactivities: |  |  |  |
| Net\tincome | $2,946 | $2,568 | $1,463 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tprovided\tby\toperating\tactivities: |  |  |  |
| Discontinued\toperations | (1,239) | (686) | (747) |
| Loss\ton\tearly\textinguishment\tof\tdebt | 279 | 92 | - |
| Deferred\tincome\ttaxes | (182) | (489) | 546 |
| Depreciation,\tdepletion\tand\tamortization | 2,266 | 2,056 | 1,934 |
| Impairments | 310 | 447 | 18 |
| Pension\tand\tother\tpostretirement\tbenefits,\tnet | 64 | 31 | (17) |
| Exploratory\tdry\twell\tcosts\tand\tunproved\tproperty\timpairments | 357 | 225 | 81 |
| Net\tgain\ton\tdisposal\tof\tassets | (103) | (766) | (202) |
| Equity\tmethod\tinvestments,\tnet | 47 | 56 | 34 |
| Changes\tin: |  |  |  |
| Current\treceivables | 8 | (409) | (188) |
| Inventories | 33 | (71) | (104) |
| Current\taccounts\tpayable\tand\taccrued\tliabilities | 485 | 1,018 | 308 |
| All\tother\toperating,\tnet | 163 | 122 | 46 |
| Net\tcash\tprovided\tby\tcontinuing\toperations | \t\t\t\t5,434 | \t\t\t\t4,194 | \t\t\t\t3,172 |
| Net\tcash\tprovided\tby\tdiscontinued\toperations | 1,090 | 1,676 | 2,096 |
| Net\tcash\tprovided\tby\toperating\tactivities | 6,524 | 5,870 | 5,268 |
| Investing\tactivities: |  |  |  |
| Acquisitions | (4,470) | - | - |
| Additions\tto\tproperty,\tplant\tand\tequipment | (3,295) | (3,536) | (3,349) |
| Disposal\tof\tassets | 518 | 1,368 | 812 |
| Investments\t-\treturn\tof\tcapital | 59 | 58 | 59 |
| Investing\tactivities\tof\tdiscontinued\toperations | (493) | (464) | (2,879) |
| All\tother\tinvesting,\tnet | 14 | (47) | 119 |
| Net\tcash\tused\tin\tinvesting\tactivities | (7,667) | (2,621) | (5,238) |
| Financing\tactivities: |  |  |  |
| Borrowings | - | - | 1,491 |
| Debt\tissuance\tcosts | - | - | (11) |
| Debt\trepayments | (2,877) | (653) | (68) |
| Purchases\tof\tcommon\tstock | (300) | - | - |
| Issuance\tof\tcommon\tstock | 77 | 12 | 4 |
| Dividends\tpaid | (567) | (704) | (679) |
| Financing\tactivities\tof\tdiscontinued\toperations | 2,916 | (12) | (13) |
| Distribution\tin\tspin-off | (1,622) | - | - |
| All\tother\tfinancing,\tnet | 78 | 2 | - |
| Net\tcash\tprovided\tby\t(used\tin)\tfinancing\tactivities | (2,295) | (1,355) | 724 |
| Effect\tof\texchange\trate\tchanges\ton\tcash | (20) | - | 18 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (3,458) | 1,894 | 772 |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 3,951 | 2,057 | 1,285 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $493 | $3,951 | $2,057 |

# Consolidated	Statements	of	Stockholders'	Equity

# Equity	Attributable	to	Marathon	Oil	Stockholders

|  |  |  | Securities |  |  |  | Accumulated |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | Exchangeable |  | Additional |  | Other | Non- | Total |
|  | Preferred | Common | into\tCommon | Treasury | Paid-in | Retained | Comprehensive | controlling | Stockholders' |
| (In\tmillions) | Stock | Stock | Stock | Stock | Capital | Earnings | Income\t(Loss) | Interest | Equity |
| January\t1,\t2009\tBalance | $\t\t\t\t\t\t\t\t\t\t\t\t- | $ \t\t\t\t\t\t767 | $\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t- | $(2,720) | $6,696 | $ 17,259 | $(593) | $- | $21,409 |
| Shares\tissued\t-\tstock\tbased\tcompensation | - | - | - | 20 | (9) | - | - | - | 11 |
| Shares\texchanged | - | 2 | - | - | (2) | - | - | - | - |
| Shares\trepurchased | - | - | - | (6) | - | - | - | - | (6) |
| Stock-based\tcompensation | - | - | - | - | 53 | - | - | - | 53 |
| Net\tincome | - | - | - | - | - | 1,463 | - | - | 1,463 |
| Other\tcomprehensive\tloss | - | - | - | - | - | - | (341) | - | (341) |
| Dividends\tpaid | - | - | - | - | - | (679) | - | - | (679) |
| December\t31,\t2009\tBalance | $- | $769 | $- | $(2,706) | $6,738 | $ 18,043 | $(934) | $- | $21,910 |
| Shares\tissued\t-\tstock\tbased\tcompensation | - | - | - | 46 | (12) | - | - | - | 34 |
| Shares\texchanged | - | 1 | - | - | (1) | - | - | - | - |
| Shares\trepurchased | - | - | - | (5) | - | - | - | - | (5) |
| Stock-based\tcompensation | - | - | - | - | 31 | - | - | - | 31 |
| Net\tincome | - | - | - | - | - | 2,568 | - | - | 2,568 |
| Other\tcomprehensive\tloss | - | - | - | - | - | - | (63) | - | (63) |
| Dividends\tpaid | - | - | - | - | - | (704) | - | - | (704) |
| December\t31,\t2010\tBalance | $- | $770 | $- | $(2,665) | $6,756 | $ 19,907 | $(997) | $- | $23,771 |
| Shares\tissued\t-\tstock\tbased\tcompensation | - | - | - | 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\tshares\tfrom\tnon-controlling\tinterest | - | - | - | - | - | - | - | 7 | 7 |
| Spin-off\tof\tdownstream\tbusiness | - | - | - | - | 5 | (9,498) | 587 | - | (8,906) |
| December\t31,\t2011\tBalance | $- | $770 | $- | $(2,716) | $6,680 | $ 12,788 | $(370) | $7 | $17,159 |

| (Shares	in	millions) | Preferred<br>Stock | Common<br>Stock | Securities<br>Exchangeable<br>into	Common<br>Stock | Treasury<br>Stock |
| :--- | :--- | :--- | :--- | :--- |
| January\t1,\t2009\tBalance | 3 | 767 | 3 | (61) |
| Shares\texchanged | (2) | 2 | (2) | - |
| December\t31,\t2009\tBalance | 1 | 769 | 1 | (61) |
| Shares\tissued\t-\tstock\tbased\tcompensation | - | - | - | 1 |
| Shares\texchanged | (1) | 1 | (1) | - |
| December\t31,\t2010\tBalance | - | 770 | - | (60) |
| Shares\tissued\t-\tstock\tbased\tcompensation | - | - | - | 6 |
| Shares\trepurchased | - | - | - | (12) |
| December\t31,\t2011\tBalance | - | 770 | - | (66) |

# 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;	oil	sands	mining	and	bitumen	transportation	and upgrading	in	Canada;	and	production	and	marketing	of	products	manufactured	from	natural	gas,	such	as	LNG	and	methanol	in	EG.

Principles	applied	in	consolidation	–	These	consolidated	financial	statements	include	the	accounts	of	our	majority-owned,	controlled	subsidiaries	and	variable interest	entities	for	which	we	are	the	primary	beneficiary.

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	shareholders	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.

Investments	in	unincorporated	joint	ventures	and	undivided	interests	in	certain	operating	assets	are	consolidated	on	a	pro	rata	basis.

As	a	result	of	the	spin-off	of	our	downstream	business	(see	Note	3),	the	results	of	operations	and	cash	flows	for	the	downstream	business	have	been	classified	as discontinued	operations	for	all	periods	presented.	The	disclosures	in	this	report	related	to	results	of	operations	and	cash	flows	are	presented	on	the	basis	of	continuing operations	unless	otherwise	stated.

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.

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.	Costs	associated	with	revenues	are	recorded	in	cost	of	revenues.

In	the	lower	48	states	of	the	U.S.,	production	volumes	of	liquid	hydrocarbons	and	natural	gas	are	sold	immediately	and	transported	to	market.	In	Alaska	and international	locations,	liquid	hydrocarbon	and	natural	gas	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.

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.

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	purchasers	of	liquid	hydrocarbons,	are	recorded	at invoiced	amounts	and	do	not	bear	interest.	We	determine	the	allowance	for	doubtful	accounts	based	on	historical	write-off	experience.	Past-due	balances	over	180	days are	reviewed	individually	for	collectability.

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	domestic	natural	gas	inventory.

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	are	reflected	on	our	consolidated	balance	sheet	on	a	net	basis	by	brokerage	firm,	as they	are	governed	by	master	netting	agreements.	Cash	flows	related	to	derivatives	used	to	manage	commodity	price	risk,	interest	rate	risk	and	foreign	currency	exchange rate	risk	related	to	operating	expenditures	are	classified	in	operating	activities	with	the	underlying	transactions.	Cash	flows	related	to	derivatives	used	to	manage exchange	rate	risk	related	to	capital	expenditures	denominated	in	foreign	currencies	are	classified	in	investing	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,	primarily expenditures	for	capital	projects	denominated	in	certain	foreign	currencies,	and	designate	them	as	cash	flow	hedges.	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,	2011	and	2010.

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	and	we	may use	commodity	derivative	instruments	to	manage	the	price	risk	on	natural	gas	that	we	purchase	to	be	marketed	with	our	natural	gas	production.	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.

Property,	plant	and	equipment	–	We	use	the	successful	efforts	method	of	accounting	for	oil	and	gas	producing	activities,	which	include	our	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 that	find	proved	reserves,	to	drill	and	equip	development	wells	and	to	construct	or	expand	oil	sand	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	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	our	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	43	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.	 Impairment	 of	 proved	 properties	 is	 required	 when	 the	 carrying	 value	 exceeds	 the	 related undiscounted	future	net	cash	flows	based	on	proved	and	probable	reserves.	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	in	addition	to	the	use	of	an	undiscounted	future	net	cash	flow	approach.	Information	such	as	drilling	results,	reservoir	performance, seismic	interpretation	or	future	plans	to	develop	acreage	are	also	considered.	Unproved	property	investments	deemed	to	be	impaired	are	written	down	to	their	fair	value, as	determined	by	discounted	future	net	cash	flows.	Impairment	expense	for	unproved	oil	and	natural	gas	properties	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	operating	expense.

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

Environmental	costs	–	Environmental	expenditures	are	capitalized	if	the	costs	mitigate	or	prevent	future	contamination	or	if	the	costs	improve	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	and 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.

Current	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.	Deferred	tax	assets	are recorded	when	it	is	more	likely	than	not	that	they	will	be	realized.	The	realization	of	deferred	tax	assets	is	assessed	periodically	based	on	several

interrelated	factors.	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,	stock	options	with	tandem	stock	appreciation	rights	("SARs")	and	stock-settled	SARs ("stock	 option	 awards")	 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	fair	market	value	of	our	common	stock	on	the	date	of	grant.

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.	 Unearned	 stock-based	 compensation	 is	 charged	 to	 stockholders'	 equity	 when	 restricted	 stock	 awards	 are	 granted. Compensation	expense	is	recognized	over	the	vesting	period	and	is	adjusted	if	conditions	of	the	restricted	stock	award	are	not	met.	Options	with	tandem	SARs	are classified	as	a	liability	and	are	remeasured	at	fair	value	each	reporting	period	until	settlement.

# 2. Accounting	Standards

# Not	Yet	Adopted

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	the	total	of	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	are	effective	for	us	beginning	with	the	first	quarter	of	2012,	except for	 the	presentation	of	reclassifications,	which	has	been	deferred.	Adoption	of	 this	amendment	will	not	have	a	significant	 impact	on	our	consolidated	results	of operations,	financial	position	or	cash	flows.

# Recently	Adopted

Oil	and	Gas	Reserve	Estimation	and	Disclosure	standards	were	issued	by	the	FASB	in	January	2010,	which	align	the	FASB's	reporting	requirements	with	the below	requirements	of	the	SEC.	The	FASB	also	addressed	the	impact	of	changes	in	the	SEC's	rules	and	definitions	on	accounting	for	oil	and	gas	producing	activities. Similar	to	the	SEC	requirements,	the	FASB	requirements	were	effective	for	periods	ending	on	or	after	December	31,	2009.	Initial	adoption	did	not	have	an	impact	on our	consolidated	results	of	operations,	financial	position	or	cash	flows.	The	effect	on	depreciation,	depletion	and	amortization	expense	subsequent	to	adoption,	as compared	to	prior	periods,	was	not	significant.	The	required	disclosures	are	presented	in	Supplementary	Information	on	Oil	and	Gas	Producing	Activities	(Unaudited).

In	December	2008,	the	SEC	announced	that	it	had	approved	revisions	to	its	oil	and	gas	reporting	disclosures.	The	new	disclosure	requirements	include	provisions that:

•Introduce	 a	 new	 definition	 of	 oil	 and	 gas	 producing	 activities.	This	 new	 definition	 allows	 companies	 to	 include	 volumes	 in	 their	 reserve	 base	 from unconventional	resources.	Such	unconventional	resources	include	bitumen	extracted	from	oil	sands	and	oil	and	gas	extracted	from	coal	beds	and	shale formations.

•	 Report	oil	and	gas	reserves	using	an	unweighted	average	price	using	the	prior	12-month	period,	based	on	the	closing	prices	on	the	first	day	of	each	month, rather	than	year-end	prices.

•Permit	companies	to	disclose	their	probable	and	possible	reserves	on	a	voluntary	basis.

•	 Require	companies	to	provide	additional	disclosure	regarding	the	aging	of	proved	undeveloped	reserves.

•Permit	the	use	of	reliable	technologies	to	determine	proved	reserves	if	those	technologies	have	been	demonstrated	empirically	to	lead	to	reliable	conclusions about	reserves	volumes.

•	 Replace	the	existing	"certainty"	test	for	areas	beyond	one	offsetting	drilling	unit	from	a	productive	well	with	a	"reasonable	certainty"	test.

•	 Require	additional	disclosures	regarding	the	qualifications	of	the	chief	technical	person	who	oversees	the	company's	overall	reserve	estimation	process. Additionally,	disclosures	regarding	internal	controls	surrounding	reserve	estimation,	as	well	as	a	report	addressing	the	independence	and	qualifications	of	its reserves	preparer	or	auditor	are	required.

•	 Require	separate	disclosure	of	reserves	in	foreign	countries	if	they	represent	15	percent	or	more	of	total	proved	reserves,	based	on	barrels	of	oil	equivalent.

As	with	the	FASB	standards	described	above,	adoption	did	not	have	an	impact	on	our	consolidated	results	of	operations,	financial	position	or	cash	flows.	The additional	disclosures	required	by	the	SEC	can	be	found	in	Item	1.	Business	–	Reserves.

# 3. Spin-off	of	Downstream	Business

On	June	30,	2011,	the	spin-off	of	the	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	affect	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,	 an	 Employee	 Matters	Agreement	 and	 a	Transition	 Services	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	oil	and	gas	exploration	and	production	operations,	oil	sands	mining	operations	and	integrated	gas	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	is	working	post-separation.	For	vested	equity-based	compensation	awards,	employees	received	both	Marathon	Oil	and	MPC	awards.

Under	the	Transition	Services	Agreement,	Marathon	Oil	and	MPC	are	providing	and/or	making	available	various	administrative	services	and	assets	to	each	other, for	up	to	a	one-year	period	beginning	on	the	distribution	date	of	the	spin-off.	The	services	include:	administrative	services;	accounting	services;	audit	services;	health, environmental	and	safety	services;	human	resource	services;	information	technology	services;	legal	services;	natural	gas	administration	services;	tax	services;	and treasury	services.	In	consideration	for	such	services,	the	companies	are	paying	fees	to	the	other	for	the	services	provided,	and	these	fees	are	generally	in	amounts intended	to	allow	the	party	providing	services	to	recover	all	of	its	direct	and	indirect	costs	incurred	in	providing	these	services.

The	following	table	presents	the	carrying	value	of	assets	and	liabilities	of	MPC,	immediately	preceding	the	June	30,	2011	spin-off.

The	results	of	operations	of	our	downstream	business	have	been	reported	as	discontinued	operations.	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	mine,	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,	2011.	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.	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	$715	million	as	of December	31,	2011.	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	the	fourth	quarter	of	2011,	we	closed	a	series	of	transactions	in	the	Eagle	Ford	shale	formation	in	south	Texas	that	were	accounted	for	as	a	business combination.	The	most	significant	of	these	transactions	was	the	acquisition	of	Hilcorp	Resources,	LLC.	The	total	consideration	paid	for	all	the	transactions	including approximately	167,000	net	acres	and	a	gathering	system,	was	$4.5	billion	which	was	funded	from	existing	cash.	All	Eagle	Ford	properties	are	included	in	our	E&P segment.

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

| Other	current	assets | 30 |
| :--- | :--- |
| Total\tcurrent\tassets\tacquired\nProperty,\tplant\tand\tequipment\nOther\tnoncurrent\tassets | 74\n4,501\n21 |
| Total\tassets\tacquired | $\t\t\t\t\t\t\t\t4,596 |
| Current\tliabilities: |  |
| Accounts\tpayable\nOther\tcurrent\tliabilities | $101\n20 |
| Total\tcurrent\tliabilities\tassumed\nAsset\tretirement\tobligations | 121\n5 |
| Total\tliabilities\tassumed | 126 |
| Net\tassets\tacquired | $4,470 |

The	fair	values	of	assets	acquired	and	liabilities	assumed	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.	A discount	rate	of	approximately	11	percent	was	used	in	the	discounted	cash	flow	analysis.	The	accounting	for	this	transaction	is	complete.

The	pro	forma	impact	of	this	business	combination	is	not	material	to	our	consolidated	statement	of	income	for	2011	and	2010.

In	addition,	during	2011,	we	acquired	approximately	108,000	net	acres	in	the	Eagle	Ford	shale	for	approximately	$265	million.	These	transactions	were	funded from	existing	cash	and	were	accounted	for	as	asset	acquisitions.

# 6. Dispositions

2012	pipelines		–		In	October	2011,	we	entered	into	definitive	agreements	to	sell	our	E&P	segment's	interests	in	several	Gulf	of	Mexico	crude	oil	pipeline	systems. This	includes	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.	The	value	of	this	transaction is	approximately	$205	million,	net	of	debt	assumed	by	the	buyer.	The	carrying	value	of	these	assets	was	$38	million	as	of	December	31,	2011.	This	transaction	closed	on January	3,	2012.

Burns	Point	gas	plant		–		During	the	fourth	quarter	of	2011,	we	sold	our	E&P	segment's	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	was	booked.

Alaska	LNG	facility		–		During	the	third	quarter	of	2011,	we	sold	our	Integrated	Gas	segment's	equity	interest	in	a	LNG	processing	facility	in	Alaska	and	a	pretax gain	on	the	transaction	of	$8	million	was	recorded.

DJ	Basin		–		In	April	2011,	we	assigned	a	30	percent	undivided	working	interest	in	our	E&P	segment's	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.	We	remain operator	of	this	jointly	owned	leasehold.

Angola		–		During	2010,	we	closed	the	sale	of	a	20	percent	outside-operated	interest	in	our	E&P	segment's	Production	Sharing	Contract	and	Joint	Operating Agreement	in	Block	32	offshore	Angola.	We	received	net	proceeds	of	$1.3	billion	and	recorded	a	pretax	gain	on	the	sale	of	$811	million.	We	retained	a	10	percent outside-operated	interest	in	Block	32.

Gudrun		–		In	March	2011,	we	closed	the	sale	of	our	outside-operated	interests	in	the	Gudrun	field	development	and	the	Brynhild	and	Eirin	exploration	areas offshore	Norway	for	net	proceeds	of	$85	million,	excluding	working	capital	adjustments.	A	$64	million	pretax	loss	on	this	disposition	was	recorded	in	the	fourth	quarter 2010.

Gabon		–		In	December	2009,	we	closed	the	sale	of	our	operated	fields	offshore	Gabon,	receiving	net	proceeds	of	$269	million,	after	closing	adjustments.	A	$232 million	pretax	gain	on	this	disposition	was	reported	in	discontinued	operations	for	2009.

Permian	Basin		–		In	June	2009,	we	closed	the	sale	of	our	E&P	segment's	operated	and	a	portion	of	our	outside-operated	Permian	Basin	producing	assets	in	New Mexico	and	west	Texas	for	net	proceeds	after	closing	adjustments	of	$293	million.	A	$196	million	pretax	gain	on	the	sale	was	recorded.

Ireland		–		In	April	2009,	we	closed	the	sale	of	our	operated	properties	in	Ireland	for	net	proceeds	of	$84	million,	after	adjusting	for	cash	held	by	the	sold subsidiary.	A	$158	million	pretax	gain	on	the	sale	was	recorded.	As	a	result	of	this	sale,	we	terminated	our	pension	plan	in	Ireland,	incurring	a	charge	of	$18	million.

In	June	2009,	we	entered	into	an	agreement	to	sell	the	subsidiary	holding	our	19	percent	outside-operated	interest	in	the	Corrib	natural	gas	development	offshore Ireland.	An	initial	$100	million	payment	was	received	at	closing.	Additional	fixed	proceeds	of	$135	million	will	be	received	at	the	earlier	of	first	commercial	gas	or December	31,	2012.	A	$154	million	impairment	was	recognized	in	discontinued	operations	in	the	second	quarter	of	2009.

Our	Irish	and	our	Gabonese	businesses,	which	had	been	reported	in	our	E&P	segment,	have	been	reported	as	discontinued	operations	in	the	consolidated	statements of	income	and	the	consolidated	statements	of	cash	flows.	Revenues	and	pretax	income	related	to	these	businesses	are	shown	in	the	table	below.

# 7. Income	per	Common	Share

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

|  | 2011 |  | 2010 |  | 2009 |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions,\texcept\tper\tshare\tdata) | Basic | Diluted | Basic | Diluted | Basic | Diluted |
| Income\tfrom\tcontinuing\toperations | $\t\t\t\t1,707 | $\t\t\t\t1,707 | $\t\t\t\t1,882 | $\t\t\t\t1,882 | $716 | $716 |
| Discontinued\toperations | 1,239 | 1,239 | 686 | 686 | 747 | 747 |
| Net\tincome | $2,946 | $2,946 | $2,568 | $2,568 | $\t\t\t\t1,463 | $\t\t\t\t1,463 |
| Weighted\taverage\tcommon\tshares\toutstanding | 710 | 710 | 710 | 710 | 709 | 709 |
| Effect\tof\tdilutive\tsecurities | - | 4 | - | 2 | - | 2 |
| Weighted\taverage\tcommon\tshares,\tincluding\tdilutive\teffect | 710 | 714 | 710 | 712 | 709 | 711 |
| Per\tshare: |  |  |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $2.40 | $2.39 | $2.65 | $2.65 | $1.01 | $1.01 |
| Discontinued\toperations | $1.75 | $1.74 | $0.97 | $0.96 | $1.05 | $1.05 |
| Net\tincome | $4.15 | $4.13 | $3.62 | $3.61 | $2.06 | $2.06 |

The	per	share	calculations	above	exclude	7	million,	13	million	and	10	million	stock	options	and	stock	appreciation	rights	in	2011,	2010	and	2009	that	were antidilutive.

# 8. Segment	Information

We	have	three	reportable	operating	segments:	Exploration	and	Production;	Oil	Sands	Mining;	and	Integrated	Gas.	Each	of	these	segments	is	organized	and managed	based	upon	the	nature	of	the	products	and	services	they	offer.

•E&P	–	explores	for,	produces	and	markets	liquid	hydrocarbons	and	natural	gas	on	a	worldwide	basis.

•	 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.

•IG	–	produces	and	markets	products	manufactured	from	natural	gas,	such	as	LNG	and	methanol,	in	EG.

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,	net	of	income	taxes,	attributable	to	the	operating	segments.	Our	corporate	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	activities,	net	of	associated	income	tax	effects.	Foreign	currency	remeasurement	and	transaction	gains	or	losses	are	not	allocated	to	operating	segments.	Non- cash	gains	and	losses	on	two	natural	gas	sales	contracts	in	the	United	Kingdom	that	were	accounted	for	as	derivative	instruments,	impairments,	gains	or	losses	on disposal	of	assets	or	other	items	that	affect	comparability	(as	determined	by	the	CODM)	also	are	not	allocated	to	operating	segments.

As	discussed	in	Note	3,	our	downstream	business	was	spun-off	on	June	30,	2011	and	has	been	reported	as	discontinued	operations	in	all	periods	presented.	Sales	to MPC	previously	reported	as	Intersegment	revenues	are	now	reported	as	Customer	revenues	because	such	sales	are	expected	to	continue	subsequent	to	the	spin-off.	Such sales	were	$1.4	billion	in	the	first	six	months	of	2011,	$1.8	billion	in	2010	and	$534	million	in	2009.

In	2011	and	2010,	MPC	accounted	for	approximately	18	percent	and	16	percent	of	total	revenues.	In	2010	and	2009,	the	Libyan	National	Oil	Company	accounted for	approximately	13	percent	and	13	percent	of	total	revenues.

Differences	between	segment	totals	for	income	from	equity	method	investments,	taxes	and	depreciation,	depletion	and	amortization	and	our	consolidated	totals represent	amounts	related	to	corporate	administrative	activities	and	other	unallocated	items	and	are	included	in	"Items	not	allocated	to	segments,	net	of	income	taxes"	in the	reconciliation	below.	Capital	expenditures	include	accruals	but	not	corporate	administrative	activities.	As	discussed	in	Notes	3	and	6,	discontinued	operations	for	our downstream	business	in	all	periods	and	our	Irish	and	Gabonese	businesses	in	2009	have	been	excluded	from	segment	results.

The	U.K.	natural	gas	contracts	expired	in	September	2009. (a)

The	following	reconciles	segment	income	to	net	income	as	reported	in	the	consolidated	statements	of	income.

| (In	millions) | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| Segment\tincome | $\t\t\t\t\t\t\t\t2,591 | $\t\t\t\t\t\t\t\t2,033 | $\t\t\t\t\t\t\t\t1,352 |
| Items\tnot\tallocated\tto\tsegments,\tnet\tof\tincome\ttaxes: |  |  |  |
| Corporate\tand\tother\tunallocated\titems | (326) | (202) | (431) |
| Foreign\tcurrency\tremeasurement\tof\ttaxes | 9 | 32 | (319) |
| Impairments^(a) | (195) | (286) | (45) |
| Loss\ton\tearly\textinguishment\tof\tdebt | (176) | (57) | - |
| Tax\teffect\tof\tsubsidiary\trestructuring | (122) | - | - |
| Deferred\tincome\ttaxes | (61) | (45) | - |
| Water\tabatement\t–\tOil\tSands | (48) | - | - |
| Eagle\tFord\ttransaction\tcosts | (10) | - | - |
| Gain\ton\tdispositions^(b) | 45 | 407 | 122 |
| Gain\ton\tU.K.\tnatural\tgas\tcontracts | - | - | 37 |
| Income\tfrom\tcontinuing\toperations | 1,707 | 1,882 | 716 |
| Discontinued\toperations | 1,239 | 686 | 747 |
| Net\tincome | $2,946 | $2,568 | $1,463 |
| (a) |  |  |  |

Significant	impairments	are	further	discussed,	on	a	pretax	basis,	in	Note	15. (a)

Significant	dispositions	are	further	discussed,	on	a	pretax	basis,	in	Note	6. (b)

The	following	reconciles	total	revenues	to	sales	and	other	operating	revenues	reported	in	continuing	operations	in	the	consolidated	statements	of	income.

| (In	millions) | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| Total\trevenues | $\t\t\t\t14,663 | $\t\t\t\t11,690 | $\t\t\t\t8,524 |
| Less:\tSales\tto\trelated\tparties | 60 | 56 | 59 |
| Sales\tand\tother\toperating\trevenues | $14,603 | $11,634 | $8,465 |

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

| (In	millions) | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| United\tStates | $\t\t\t\t\t\t\t\t6,971 | $\t\t\t\t\t\t\t\t5,363 | $\t\t\t\t\t\t\t\t3,326 |
| United\tKingdom | 1,546 | 1,063 | 1,143 |
| Libya^(a) | 216 | 1,473 | 1,139 |
| Norway | 3,386 | 2,243 | 1,617 |
| Canada | 1,588 | 833 | 692 |
| Other\tinternational | 956 | 715 | 607 |
| Total\trevenues | $14,663 | $11,690 | $8,524 |

See	Note	13	for	discussion	of	Libya	operations.

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

| (In	millions) | 2011 | 2010 |
| :--- | :--- | :--- |
| United\tStates | $10,928 | $18,415 |
| Canada | 9,711 | 9,564 |
| Equatorial\tGuinea | 2,214 | 2,389 |
| Norway | 1,133 | 1,353 |
| Other\tinternational | 2,721 | 2,399 |
| Total\tlong-lived\tassets | $\t\t\t\t\t\t\t\t26,707 | $\t\t\t\t\t\t\t\t34,120 |

Revenues	by	product	line	were:

A	portion	of	the	contingent	proceeds	from	the	sale	of	the	Corrib	natural	gas	development	was	written	off	in	the	fourth	quarter	of	2009	on	the	basis	of	new	public	information	regarding	the	pipeline	that	would transport	gas	from	the	Corrib	development.	The	remaining	carrying	value	of	this	contingent	receivable	was	written	off	in	2010. (b)

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

| (In	millions) | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| Net\tinterest\tand\tother | $\t\t\t\t\t\t\t\t\t\t\t\t24 | $\t\t\t\t\t\t\t\t\t\t\t\t(21) | $\t\t\t\t\t\t\t\t\t\t\t\t(28) |
| Provision\tfor\tincome\ttaxes | (57) | (1) | (319) |
| Aggregate\tforeign\tcurrency\tlosses | $(33) | $(22) | $(347) |

# 10. Income	Taxes

Income	tax	provisions	(benefits)	related	to	continuing	operations	were:

|  | 2011 | 2011 | 2011 | 2010 | 2010 | 2010 | 2009 | 2009 | 2009 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Current | Deferred | Total | Current | Deferred | Total | Current | Deferred | Total |
| Federal | $(210) | $(206) | $(416) | $(279) | $(267) | $(546) | $40 | $(329) | $(289) |
| State\tand\tlocal | 24 | 82 | 106 | 2 | (10) | (8) | (19) | 5 | (14) |
| Foreign | 3,088 | (58) | \t 3,030 | 2,941 | (212) | \t 2,729 | 1,480 | 870 | \t 2,350 |
| Total | $2,902 | $(182) | $2,720 | $2,664 | $(489) | $2,175 | $1,501 | $546 | $2,047 |

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:

|  | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| Statutory\trate\tapplied\tto\tincome\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | 35% | 35% | 35% |
| Effects\tof\tforeign\toperations,\tincluding\tforeign\ttax\tcredits | 6 | 20 | 16 |
| Change\tin\tpermanent\treinvestment\tassertion | 5 | - | - |
| Foreign\tcurrency\tremeasurement | - | - | 11 |
| Adjustments\tto\tvaluation\tallowances | 14 | (2) | 10 |
| Tax\tlaw\tchanges | 1 | 1 | - |
| Other | \t\t\t\t\t\t\t\t\t- | \t\t\t\t\t\t\t\t\t\t\t\t\t- | \t\t\t\t\t\t\t\t\t2 |
| Effective\tincome\ttax\trate\ton\tcontinuing\toperations | 61% | 54% | 74% |

Effects	of	foreign	operations	–	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 and	to	individual	items	not	allocated	to	segments	is	reported	in	"Corporate	and	other	unallocated	items"	shown	in	Note	8.

The	effects	of	foreign	operations	on	our	effective	tax	rate	decreased	in	2011	as	compared	to	2010,	primarily	due	to	the	suspension	of	all	production	operations	in Libya	in	the	first	quarter	of	2011,	where	the	statutory	tax	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.

Adjustments	to	valuation	allowances	–	In	2009,	it	was	determined	that	we	may	not	be	able	to	realize	all	recorded	foreign	tax	credit	benefits	and	therefore	a valuation	allowance	was	recorded	against	these	benefits.	In	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	2011.

Tax	law	changes	–	In	July	2011,	the	U.K.	enacted	the	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	new	CIT	legislation	eliminates	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.

The	Patient	Protection	and	Affordable	Care	Act	("PPACA")	and	the	Health	Care	and	Education	Reconciliation	Act	of	2010	("HCERA"),	(together,	the	"Acts") were	signed	in	to	law	in	March	2010.	The	Acts	effectively	change	the	tax	treatment	of	federal	subsidies	paid	to	sponsors	of	retiree	health	benefit	plans	that	provide prescription	drug	benefits	that	are	at	least	actuarially	equivalent	to	the	corresponding	benefits	provided	under	Medicare	Part	D.	The	federal	subsidy	paid	to	employers was	introduced	as	part	of	the	Medicare	Prescription	Drug,	Improvement,	and	Modernization	Act	of	2003	(the	"MPDIMA").	Under	the	MPDIMA,	the	federal	subsidy does	not	reduce	our	income	tax	deduction	for	the	costs	of	providing	such	prescription	drug	plans	nor	is	it	subject	to	income	tax	individually.	Beginning	in	2013,	under the	Acts,	our	income	tax	deduction	for	the	costs	of	providing	Medicare	Part	D-equivalent	prescription	drug	benefits	to	retirees	will	be	reduced	by	the	amount	of	the federal	subsidy.	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,	we	recorded	deferred	tax	expense	of	$45	million	in	the	first	quarter	of	2010	for	the	write-off	of	deferred	tax	assets	to reflect	the	change	in	the	tax	treatment	of	the	federal	subsidy.

Deferred	tax	assets	and	liabilities	resulted	from	the	following:

| (In	millions) | 2011 | 2010 |
| :--- | :--- | :--- |
| Deferred\ttax\tassets: |  |  |
| Employee\tbenefits | $\t\t\t\t\t\t\t\t413 | $\t\t\t\t\t\t\t\t1,079 |
| Operating\tloss\tcarryforwards^(a) | 376 | 285 |
| Foreign\ttax\tcredits | 3,005 | 2,045 |
| Other | 88 | 141 |
| Valuation\tallowances |  |  |
| Federal | (791) | (206) |
| State | (61) | (48) |
| Foreign^(a) | (194) | (142) |
| Total\tdeferred\ttax\tassets | 2,836 | 3,154 |
| Deferred\ttax\tliabilities |  |  |
| Property,\tplant\tand\tequipment^(a) | 3,283 | 5,292 |
| Inventories | - | 597 |
| Investments\tin\tsubsidiaries\tand\taffiliates | 1,286 | 1,116 |
| Other | 43 | 42 |
| Total\tdeferred\ttax\tliabilities | 4,612 | 7,047 |
| Net\tdeferred\ttax\tliabilities | $1,776 | $3,893 |
| (a) |  |  |

Certain	2010	amounts	were	reclassified	to	conform	to	the	current	period's	presentation. (a)

Operating	loss	carryforwards	–	At	December	31,	2011,	our	operating	loss	carryforwards	include	$811	million	of	Canadian	operating	loss	carryforwards	that	expire from	2013	through	2031	and	$245	million	of	Indonesian	operating	loss	carryforwards	that	do	not	have	expiration	dates.	State	operating	loss	carryforwards	of	$915 million	expire	in	2012	through	2031.

Valuation	allowances	–	The	ability	to	realize	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	$585	million	in	2011,	decreased	$74	million	in	2010	and	increased	$280 million	in	2009	due	to	changes	in	the	expected	realizability	of	foreign	tax	credits.

Foreign	valuation	allowances	increased	$52	million	and	$40	million	in	2011	and	2010,	primarily	due	to	net	operating	loss	carryforwards	generated	in	Indonesia. Foreign	valuation	allowances	decreased	$79	million	 in	2009,	primarily	due	 to	 the	reduction	of	net	operating	 loss	carryforwards	as	a	result	of	 the	disposition	of exploration	and	production	businesses	in	Ireland.

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

| (In	millions) | December	31,<br>2011 | 2010 |
| :--- | :--- | :--- |
| Assets: |  |  |
| Current\tdeferred\ttax\tassets | $\t\t\t\t\t\t\t\t\t\t\t\t99 | $\t\t\t\t\t\t\t\t\t\t\t\t- |
| Other\tnoncurrent\tassets | 674 | - |
| Liabilities: |  |  |
| Current\tdeferred\ttax\tliabilities | 5 | 324 |
| Noncurrent\tdeferred\ttax\tliabilities | 2,544 | 3,569 |
| Net\tdeferred\ttax\tliabilities | $1,776 | $3,893 |

We	are	continuously	undergoing	examination	of	our	U.S.	federal	income	tax	returns	by	the	Internal	Revenue	Service.	Such	audits	have	been	completed	through	the 2007	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,	2011,	our	income	tax	returns	remain	subject	to	examination	in	the	following	major	tax	jurisdictions	for	the	tax	years	indicated:

The	following	table	summarizes	the	activity	in	unrecognized	tax	benefits:

| (In	millions) | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| Beginning\tbalance | $103 | $75 | $39 |
| Additions\tfor\ttax\tpositions\trelated\tto\tthe\tcurrent\tyear | 4 | 28 | 30 |
| Reductions\tfor\ttax\tpositions\trelated\tto\tthe\tcurrent\tyear | - | (1) | (2) |
| Additions\tfor\ttax\tpositions\tof\tprior\tyears | 87 | 25 | 30 |
| Reductions\tfor\ttax\tpositions\tof\tprior\tyears | (29) | (12) | (15) |
| Settlements | (8) | (12) | (7) |
| Ending\tbalance | $\t\t\t\t\t\t\t\t157 | $\t\t\t\t\t\t\t\t103 | $\t\t\t\t\t\t\t\t75 |

If	the	unrecognized	tax	benefits	as	of	December	31,	2011	were	recognized,	$103	million	would	affect	our	effective	income	tax	rate.	There	were	$19	million	of uncertain	tax	positions	as	of	December	31,	2011	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	related	to	unrecognized	tax	benefits	were	$13	million,	$5	million	and	less	than	$1	million	in 2011,	2010	and	2009.	As	of	December	31,	2011	and	2010,	$27	million	and	$15	million	of	interest	and	penalties	were	accrued	related	to	income	taxes.

Pretax	income	from	continuing	operations	included	amounts	attributable	to	foreign	sources	of	$4,869	million,	$4,563	million	and	$2,947	million	in	2011,	2010	and 2009.

Undistributed	income	of	certain	consolidated	foreign	subsidiaries	at	December	31,	2011	amounted	to	$235	million	for	which	no	U.S.	deferred	income	tax	provision has	been	recorded	because	we	intend	to	permanently	reinvest	such	income	in	those	foreign	operations.	If	such	income	was	not	permanently	reinvested,	income	tax expense	of	approximately	$82	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.	A	significant	portion	of	our	inventories	at	December	31,	2010	were	related	to	our	downstream	business (see	Note	3).

| (In	millions) | 2011 | 2010 |
| :--- | :--- | :--- |
| Liquid\thydrocarbons,\tnatural\tgas\tand\tbitumen | $147 | $1,275 |
| Refined\tproducts\tand\tmerchandise | - | 1,774 |
| Supplies\tand\tsundry\titems | 214 | 404 |
| Inventories\tat\tcost | $\t\t\t\t\t\t\t\t361 | $\t\t\t\t\t\t\t\t3,453 |

The	LIFO	method	accounted	for	16	percent	and	85	percent	of	total	inventory	value	at	December	31,	2011	and	2010.	Current	acquisition	costs	were	estimated	to exceed	the	LIFO	inventory	value	at	December	31,	2011	and	2010	by	$74	million	and	$4,166	million.

# 12. Equity	Method	Investments	and	Related	Party	Transactions

During	2011,	2010	and	2009	only	our	equity	method	investees	were	considered	related	parties.	The	following	were	included	in	continuing	operations:

•	 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	activities.

Our	equity	method	investments	are	summarized	in	the	following	table:

|  | Ownership	as	of | December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | December\t31,\t2011 | 2011 | 2010 |
| EGHoldings | 60% | $\t\t\t\t\t\t\t\t875 | $\t\t\t\t\t\t\t\t927 |
| Alba\tPlant\tLLC | 52% | 272 | 303 |
| AMPCO | 45% | 191 | 210 |
| Downstream\tbusiness\tinvestments |  | - | 311 |
| Other\tinvestments |  | 45 | 51 |
| Total |  | $1,383 | $1,802 |

As	of	December	31,	2011,	the	carrying	value	of	our	equity	method	investments	was	$155	million	higher	than	the	underlying	net	assets	of	investees.	This	basis difference	is	being	amortized	into	net	income	over	the	remaining	estimated	useful	lives	of	the	underlying	net	assets.

Dividends	and	partnership	distributions	received	from	equity	method	investees	(excluding	distributions	that	represented	a	return	of	capital	previously	contributed) reported	in	continuing	operations	were	$509	million	in	2011,	$400	million	in	2010	and	$302	million	in	2009.

Summarized	financial	information	for	equity	method	investees	is	as	follows:

| (In	millions) | 2011^(a) | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| Income\tdata\t–\tyear: |  |  |  |
| Revenues\tand\tother\tincome | $\t\t\t\t\t\t\t\t1,544 | $\t\t\t\t\t\t\t\t2,243 | $\t\t\t\t\t\t\t\t1,916 |
| Income\tfrom\toperations | 942 | 999 | 677 |
| Net\tincome | 820 | 841 | 576 |
| Balance\tsheet\tdata\t–\tDecember\t31: |  |  |  |
| Current\tassets | $688 | $898 |  |
| Noncurrent\tassets | 2,079 | 3,371 |  |
| Current\tliabilities | 504 | 513 |  |
| Noncurrent\tliabilities | 115 | 832 |  |
| (a) |  |  |  |

(a) Values	in	2011	are	lower	than	in	previous	years	due	to	the	spin-off	of	our	downstream	business	on	June	30,	2011.

Almost	all	of	our	related	party	purchases	are	liquid	hydrocarbons	acquired	from	Alba	Plant	LLC.	Approximately	75	percent	of	our	sales	to	related	parties	in	all periods	are	associated	with	sales	of	natural	gas	to	EGHoldings.

# 13. Property,	Plant	and	Equipment

| (In	millions) | 2011 | 2010 |
| :--- | :--- | :--- |
| E&amp;P |  |  |
| United\tStates | $19,679 | $13,532 |
| International | 12,579 | 11,736 |
| Total\tE&amp;P | 32,258 | 25,268 |
| OSM | 9,936 | 9,631 |
| IG | 37 | 47 |
| Downstream\tbusiness | - | 16,624 |
| Corporate | 341 | 457 |
| Total\tproperty,\tplant\tand\tequipment | $42,572 | $52,027 |
| Less\taccumulated\tdepreciation,\tdepletion\tand\tamortization | (17,248) | (19,805) |
| Net\tproperty,\tplant\tand\tequipment | $25,324 | $32,222 |

During	the	first	quarter	2011,	all	production	operations	in	Libya	were	suspended.	In	the	fourth	quarter	of	2011,	limited	production	resumed	from	the	Waha concessions,	but	we	made	no	deliveries	of	hydrocarbons.	Sales	are	expected	in	the	first	quarter	of	2012.	The	return	of	our	operations	in	Libya	to	pre-conflict	levels	is unknown	at	this	time;	however,	we	and	our	partners	in	the	Waha	concession	are	assessing	the	condition	of	our	assets	and	determining	when	the	full	resumption	of operations	will	be	viable.	As	of	December	31,	2011,	our	net	property,	plant	and	equipment	investment	in	Libya	is	approximately	$756	million	and	our	net	proved reserves	in	Libya	are	239	mmboe.

Property,	plant	and	equipment	includes	gross	assets	acquired	under	capital	leases	of	$13	million	and	$272	million	at	December	31,	2011	and	2010,	with	related amounts	in	accumulated	depreciation,	depletion	and	amortization	of	$1	million	and	$48	million	at	December	31,	2011	and	2010.

Deferred	exploratory	well	costs	were	as	follows:

Exploratory	well	costs	capitalized	greater	than	one	year	after	completion	of	drilling	as	of	December	31,	2011	are	summarized	by	geographical	area	below:

Well	costs	that	have	been	suspended	for	longer	than	one	year	are	associated	with	five	projects.	Exploration	on	Angola	Block	31	began	in	2004,	with	costs accumulating	through	2009.	Development	alternatives	are	being	evaluated	and	optimization	efforts	continue	for	this	block.	Costs	for	two	offshore	Gulf	of	Mexico projects	were	incurred	in	2009	and	2010.	Drilling	is	expected	to	resume	on	the	Innsbruck	prospect	in	the	second	half	of	2012,	while	evaluation	of	the	outside-operated Shenandoah	prospect	is	ongoing	with	an	appraisal	well	expected	in	2012.	Two	international	projects	had	costs	incurred	in	2004	and	2009	and	have	the	potential	to	tie- back	to	current	production	facilities.	Development	will	be	pursued	when	the	additional	production	is	required	to	feed	our	Equatorial	Guinea	and	Norway	operations. Management	believes	these	projects	with	suspended	exploratory	drilling	costs	exhibit	sufficient	quantities	of	hydrocarbons	to	justify	potential	development.

# 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	the	carrying	value.	We	performed	our	annual	impairment	tests	during	2011,	2010	and	2009	and	no	impairment	was	required.	The	fair	value	of	each	of	our reporting	units	exceeded	the	book	value	appreciably;	however,	should	market	conditions	deteriorate	or	commodity	prices	decline	significantly,	an	impairment	may	be necessary.

The	changes	in	the	carrying	amount	of	goodwill	for	the	years	ended	December	31,	2011,	and	2010	were	as	follows:

| (In	millions) | E&amp;P | OSM | business | Total |
| :--- | :--- | :--- | :--- | :--- |
| 2010 |  |  |  |  |
| Beginning\tbalance,\tgross | $537 | $\t\t\t\t\t\t\t\t1,412 | $\t\t\t\t\t\t\t\t\t\t\t\t885 | $\t\t\t\t\t\t\t\t2,834 |
| Less:\taccumulated\timpairment | - | (1,412) | - | (1,412) |
| Beginning\tbalance,\tnet | 537 | - | 885 | 1,422 |
| Contingent\tconsideration\tadjustment | - | - | (1) | (1) |
| Purchase\tprice\tadjustment | - | - | (7) | (7) |
| Dispositions | - | - | (34) | (34) |
| Ending\tbalance,\tnet | 537 | - | 843 | 1,380 |
| 2011 |  |  |  |  |
| Beginning\tbalance,\tgross | 537 | 1,412 | 843 | 2,792 |
| Less:\taccumulated\timpairments | - | (1,412) | - | (1,412) |
| Beginning\tbalance,\tnet | 537 | - | 843 | 1,380 |
| Dispositions | (1) | - | (2) | (3) |
| Contingent\tconsideration\tadjustment | - | - | (3) | (3) |
| Purchase\tprice\tadjustment | - | - | 9 | 9 |
| Spin-off\tdownstream\tbusiness | - | - | (847) | (847) |
| Ending\tbalance,\tnet | $\t\t\t\t\t\t\t\t\t\t\t\t536 | $- | $- | $536 |

# 15. Fair	Value	Measurements

# Fair	Values	–	Recurring

As	of	December	31,	2011,	balances	related	to	interest	rate	swaps	accounted	for	at	fair	value	on	a	recurring	basis	were	noncurrent	assets	of	$5	million	measured	at fair	value	using	actionable	broker	quotes	which	are	Level	2	inputs.	There	were	no	other	significant	recurring	fair	value	measurements	as	of	December	31,	2011.

The	following	table	presents	assets	and	liabilities	accounted	for	at	fair	value	on	a	recurring	basis	as	of	December	31,	2010	by	fair	value	hierarchy	level.	The majority	of	commodity	derivatives	outstanding	at	December	31,	2010	related	to	our	downstream	business.

|  |  |  | December	31,	2010 |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Level\t1 | Level\t2 | Level\t3 | Collateral | Total |
| Derivative\tinstruments,\tassets |  |  |  |  |  |
| Commodity | $58 | $- | $1 | $81 | $140 |
| Interest\trate | - | 32 | - | - | 32 |
| Derivative\tinstruments,\tassets | \t\t\t\t\t\t\t\t\t\t\t\t58 | \t\t\t\t\t\t\t\t\t\t\t\t32 | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t1 | 81 | \t\t\t\t\t\t\t\t\t\t\t\t172 |
| Derivative\tinstruments,\tliabilities\nCommodity | $(102) | $- | $(3) | $- | $(105) |
| Derivative\tinstruments,\tliabilities | (102) | - | (3) | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t- | (105) |

As	of	December	31,	2010,	commodity	derivatives	in	Level	1	were	exchange-traded	contracts	for	crude	oil,	natural	gas	and	refined	products	measured	at	fair	value with	a	market	approach	using	the	close-of-day	settlement	prices	for	the	market.	Interest	rate	swaps	were	in	Level	2	of	the	fair	value	hierarchy	because	they	were measured	at	fair	value	with	a	market	approach	using	market	price	quotes	or	a	price	obtained	from	third-party	services	such	as	Bloomberg	L.P.	which	were	corroborated with	data	from	active	markets	for	similar	assets	and	liabilities.	Collateral	deposits	related	to	commodity	derivatives	are	in	broker	accounts	covered	by	master	netting agreements.

Commodity	derivatives	in	Level	3	are	measured	at	fair	value	with	a	market	approach	using	prices	obtained	from	third-party	services	such	as	Platt's	and	price assessments	from	other	independent	brokers.

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

| (In	millions) | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| Beginning\tbalance | $(2) | $9 | $(26) |
| Total\trealized\tand\tunrealized\tgains\t(losses): |  |  |  |
| Included\tin\tnet\tincome | - | 23 | 68 |
| Included\tin\tother\tcomprehensive\tincome | - | 4 | (1) |
| Transfers\tto\tLevel\t2 | - | (30) | - |
| Purchases | - | 2 | 5 |
| Sales | - | - | (23) |
| Issuances | - | - | (44) |
| Settlements | - | (10) | 30 |
| Spin-off\tof\tdownstream\tbusiness | 2 | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t- | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t- |
| Ending\tbalance |  |  |  |
|  | $- | $(2) | $9 |

Net	income	for	2010	and	2009	included	unrealized	losses	of	$1	million,	and	$7	million	related	to	the	derivatives	in	Level	3.	See	Note	16	for	income	statement impacts	of	our	derivative	instruments.

# 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 for	continuing	operations.

|  | 2011 |  | 2010 |  | 2009 |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Fair\tValue | Impairment | Fair\tValue | Impairment | Fair\tValue | Impairment |
| Long-lived\tassets\theld\tfor\tuse | $\t\t\t\t\t\t\t\t\t\t\t\t226 | $\t\t\t\t\t\t\t\t\t\t\t\t282 | $\t\t\t\t\t\t\t\t\t\t\t\t147 | $\t\t\t\t\t\t\t\t\t\t\t\t447 | $5 | $15 |
| Long-lived\tassets\theld\tfor\tsale | - | - | 85 | 64 | \t\t\t\t\t\t\t\t\t\t\t\t311 | \t\t\t\t\t\t\t\t\t\t\t\t154 |
| Intangible\tassets | - | 25 | - | - | - | - |
| Equity\tmethod\tinvestments | - | - | - | 25 | - | - |

In	May	2011,	significant	water	production	and	reservoir	pressure	declines	occurred	at	our	E&P	segment's	Droshky	development	in	the	Gulf	of	Mexico.	Plans	for	a waterflood	were	cancelled	and	the	field	will	be	produced	to	abandonment	pressures,	which	are	expected	in	the	first	half	of	2012.	Consequently,	3.4	million	barrels	of	oil equivalent	of	proved	reserves	were	written	off	and	a	$273	million	impairment	of	this	long-lived	asset	to	fair	value	was	recorded	in	the	second	quarter	of	2011.	The	$226 million	fair	value	of	the	Droshky	development	was	determined	using	an	income	approach	based	upon	internal	estimates	of	future	production	levels,	prices	and	discount rate,	all	Level	3	inputs.

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	held	in our	Integrated	Gas	segment.

In	the	fourth	quarter	of	2010,	due	to	the	pending	sale	of	our	E&P	segment's	outside-operated	interest	in	the	Gudrun	field	development,	located	offshore	Norway, we	recorded	a	loss	for	this	asset	held	for	sale.	The	fair	value	of	$85	million	was	based	upon	the	pending	transaction,	which	is	a	Level	3	market	input.

In	the	third	quarter	of	2010,	we	fully	impaired	our	Integrated	Gas	segment's	equity	method	investment	in	an	entity	engaged	in	gas-to-fuels	related	technology.	This investment	was	determined	to	have	sustained	an	other	than	temporary	loss	in	value.	Based	upon	recent	financial	information,	the	fair	value	was	measured	with	an income	approach	using	internally	developed	estimates	of	future	cash	flows.	These	cash	flows	are	Level	3	inputs.

In	March	2010,	we	completed	a	reservoir	study	which	resulted	in	a	portion	of	our	Powder	River	Basin	field	being	removed	from	plans	for	future	development	in	our E&P	segment.	The	field's	fair	value	was	measured	at	$144	million,	using	an	income	approach	based	upon	internal	estimates	of	future	production	levels,	prices	and discount	rate	which	are	Level	3	inputs.	This	resulted	in	an	impairment	of	$423	million.

The	impairment	charge	recorded	on	assets	held	for	sale	in	2009	related	to	the	sale	of	the	Corrib	natural	gas	development	offshore	Ireland	and	was	based	on	the	fair value	of	anticipated	sale	proceeds	(see	Note	6).	Fair	value	of

anticipated	sale	proceeds	included	cash	received	at	closing,	a	minimum	amount	due	at	the	earlier	of	first	gas	or	December	31,	2012,	and	a	range	of	contingent	proceeds subject	to	the	timing	of	first	commercial	gas.	The	fair	value	of	the	total	proceeds	was	measured	using	an	income	method	that	incorporated	a	probability-weighted approach	with	respect	to	timing	of	first	commercial	gas	and	an	associated	sliding	scale	on	the	amount	of	corresponding	consideration	specified	in	the	sales	agreement: the	longer	it	takes	to	achieve	first	gas,	the	lower	the	amount	of	the	consideration.	Because	a	portion	of	the	proceeds	is	variable	in	timing	and	amount	depending	upon timing	of	first	commercial	gas,	the	inputs	to	the	fair	value	calculation	were	classified	as	Level	3	inputs.

Impairments	of	several	other	long-lived	assets	held	for	use	in	our	E&P	segment	that	were	evaluated	in	2011,	2010	and	2009	were	a	result	of	reduced	drilling expectations,	reduction	of	estimated	reserves	or	declining	natural	gas	prices,	and	are	also	reported	above.	The	fair	values	of	those	assets	were	measured	using	an	income approach	based	upon	internal	estimates	of	future	production	levels,	commodity	prices	and	discount	rate,	which	are	Level	3	inputs.	Natural	gas	prices	began	declining	in September	2011	and	have	continued	to	decline	in	2012.	Should	natural	gas	prices	remain	depressed,	an	impairment	charge	related	to	our	natural	gas	assets	may	be necessary.

# Fair	Values	–	Financial	Instruments

The	following	table	summarizes	financial	instruments,	excluding	the	derivative	financial	instruments	reported	above,	by	individual	balance	sheet	line	item	at December	31,	2011	and	2010.

|  | 2011^(a) |  | 2010 |  |
| :--- | :--- | :--- | :--- | :--- |
|  | Fair | Carrying | Fair | Carrying |
| (In\tmillions) | Value | Amount | Value | Amount |
| Financial\tassets |  |  |  |  |
| Other\tcurrent\tassets | $146 | $148 | $226 | $220 |
| Other\tnoncurrent\tassets | 68 | 68 | 396 | 231 |
| Total\tfinancial\tassets | 214 | 216 | 622 | 451 |
| Financial\tliabilities |  |  |  |  |
| Long-term\tdebt,\tincluding\tcurrent\tportion^(b) | 5,479 | 4,753 | 8,364 | 7,527 |
| Deferred\tcredits\tand\tother\tliabilities | 36 | 38 | 66 | 67 |
| Total\tfinancial\tliabilities | $\t\t\t\t5,515 | $\t\t\t\t4,791 | $\t\t\t\t8,430 | $\t\t\t\t7,594 |
| (a)\nFinancial\tassets\tand\tliabilities\thave\tdecreased\tfrom\t2010\tdue\tto\tthe\tspin-off\tof\tour\tdownsteam\tbusiness,\tearly\tretirement\tof\tlong-term\tdebt\tand\tUnited\tStates\tSteel's\tredemption\tof\tthe\tbonds\tfor\twhich\tthey |  |  |  |  |

Financial	assets	and	liabilities	have	decreased	from	2010	due	to	the	spin-off	of	our	downsteam	business,	early	retirement	of	long-term	debt	and	United	States	Steel's	redemption	of	the	bonds	for	which	they retained	responsibilty. (a)

Excludes	capital	leases. (b)

Our	current	assets	and	liabilities	include	financial	instruments,	the	most	significant	of	which	are	trade	accounts	receivables	and	payables.	We	believe	the	carrying values	of	these	current	assets	and	liabilities	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	current	portion	of	our	long-term	debt,	which	is	reported	with	long-term	debt	above	and	discussed	below,	is	an exception	to	this	assessment.

Fair	values	of	our	remaining	financial	assets	included	in	other	noncurrent	assets	and	of	our	financial	liabilities	included	in	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.

Over	90	percent	of	our	long-term	debt	instruments	are	publicly-traded.	A	market	approach,	based	upon	quotes	from	major	financial	institutions	is	used	to	measure the	fair	value	of	such	debt.	Because	such	quotes	cannot	be	independently	verified	to	the	market	they	are	considered	Level	3	inputs.	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.	As	of	December	30,	2011,	our	only	derivatives	outstanding	are	interest	rate	swaps	that	are	fair	value	hedges,	which	have	an	asset	value	of	$5 million	and	are	located	on	the	consolidated	balance	sheet	in	Other	noncurrent	assets.

The	following	table	presents	the	gross	fair	values	of	derivative	instruments,	excluding	cash	collateral,	and	where	they	appear	on	the	consolidated	balance	sheet	as	of December	31,	2010.	The	majority	of	our	2010	commodity	derivatives	were	related	to	our	downstream	business.

# Derivatives	Designated	as	Fair	Value	Hedges

As	of	December	31,	2011,	we	had	multiple	interest	rate	swap	agreements	with	a	total	notional	amount	of	$600	million	at	a	weighted-average,	LIBOR-based, floating	rate	of	4.76	percent.	As	of	December	31,	2010,	we	had	multiple	interest	rate	swap	agreements	with	a	total	notional	amount	of	$1,450	million	at	a	weighted- average,	LIBOR-based,	floating	rate	of	4.43	percent.	The	interest	rate	swaps	have	no	hedge	ineffectiveness.

In	connection	with	the	debt	retired	in	February	and	March	2011	discussed	in	Note	17,	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.

The	following	table	summarizes	the	pretax	effect	related	to	continuing	operations	of	derivative	instruments	designated	as	hedges	of	fair	value	in	our	consolidated statements	of	income.

|  |  |  | Gain	(Loss) |  |
| :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Income\tStatement\tLocation | 2011 | 2010 | 2009 |
| Derivative |  |  |  |  |
| Commodity | Sales\tand\tother\toperating\trevenues | $\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t- | $(1) | $(16) |
| Interest\trate | Net\tinterest\tand\tother | 28 | 26 | - |
|  |  | 28 | \t\t\t\t25 | (16) |
| Hedged\tItem |  |  |  |  |
| Commodity | Sales\tand\tother\toperating\trevenues | - | 1 | \t\t\t\t16 |
| Long-term\tdebt | Net\tinterest\tand\tother | (28) | (26) | - |
|  |  | $(28) | $(25) | $16 |

# Derivatives	Not	Designated	as	Hedges

The	following	table	summarizes	the	effect	related	to	continuing	operations	of	all	derivative	instruments	not	designated	as	hedges	in	our	consolidated	statements	of income.

| (In	millions) | Income	Statement	Location | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- | :--- |
| Commodity | Sales\tand\tother\toperating\trevenues | $\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t5 | $\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t121 | $\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t90 |
| Foreign\tcurrency | Net\tinterest\tand\tother | - | - | 3 |
|  |  | $5 | $121 | $93 |

As	of	December	31,	2011,	we	had	no	borrowings	against	our	$3	billion	revolving	credit	facility	and	no	commercial	paper	outstanding	under	our	U.S.	commercial paper	program	that	is	backed	by	the	revolving	credit	facility.

|  | December	31, |  |
| :--- | :--- | :--- |
| (In\tmillions) | 2011 | 2010 |
| Marathon\tOil\tCorporation: |  |  |
| Revolving\tcredit\tfacility | $\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t- | $\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t- |
| 6.125%\tnotes\tdue\t2012 | - | 450 |
| 6.000%\tnotes\tdue\t2012 | - | 400 |
| 5.900%\tnotes\tdue\t2018^(a) | 854 | 894 |
| 6.800%\tnotes\tdue\t2032^(a) | 550 | 550 |
| 9.375%\tdebentures\tdue\t2012 | 53 | 53 |
| 9.125%\tdebentures\tdue\t2013 | 114 | 114 |
| 6.500%\tdebentures\tdue\t2014 | - | 700 |
| 7.500%\tdebentures\tdue\t2019^(a) | 228 | 688 |
| 6.000%\tdebentures\tdue\t2017^(a) | 682 | 682 |
| 9.375%\tdebentures\tdue\t2022 | 32 | 32 |
| 8.500%\tdebentures\tdue\t2023 | 70 | 70 |
| 8.125%\tdebentures\tdue\t2023 | 131 | 131 |
| 6.600%\tdebentures\tdue\t2037 | 750 | 750 |
| 4.550%\tpromissory\tnote,\tsemi-annual\tpayments\tdue\t2012\t–\t2015 | 272 | 340 |
| Series\tA\tmedium\tterm\tnotes\tdue\t2022 | 3 | 3 |
| 2033 | - | 198 |
| 5.375%\tobligation\trelating\tto\trevenue\tbonds\tdue\t2013 | 23 | 23 |
| 5.125%\tobligation\trelating\tto\trevenue\tbonds\tdue\t2037 | 1,000 | 1,000 |
| Sale-leaseback\tfinancing\tdue\t2012 | 11 | 20 |
| Capital\tlease\tobligation\tdue\t2012 | 9 | 17 |
| Consolidated\tsubsidiaries |  |  |
| 8.375%\tsecured\tnotes\tdue\t2012^(a) | - | 448 |
| Capital\tlease\tobligations\tdue\t2012\t–\t2034 |  |  |
| Downstream\tbusiness | - | 279 |
| Other | 11 | 12 |
| Total^(b) | 4,793 | 7,854 |
| Unamortized\tfair\tvalue\tdifferential\tfor\tdebt\tassumed\tin\tacquisitions | - | 16 |
| Unamortized\tdiscount | (10) | (16) |
| Fair\tvalue\tadjustments^(c) | 32 | 42 |
| Amounts\tdue\twithin\tone\tyear | (141) | (295) |
| Total\tlong-term\tdebt\tdue\tafter\tone\tyear | $4,674 | $7,601 |
| (a) |  |  |

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

In	the	event	of	a	change	in	control,	as	defined	in	the	related	agreements,	debt	obligations	totaling	$431	million	at	December	31,	2011,	may	be	declared	immediately	due	and	payable. (b)

See	Note	15	for	information	on	interest	rate	swaps. (c)

The	termination	date	on	$2,625	million	of	our	revolving	credit	facility	is	May	2013.	The	remaining	$375	million	has	a	termination	date	of	May	2012.	The	facility requires	a	representation	at	an	initial	borrowing	that	there	has	been	no	change	in	our	consolidated	financial	position	or	operations,	considered	as	a	whole	which	would materially	and	adversely	affect	our	ability	to	perform	our	obligations	under	the	revolving	credit	facility.	Interest	on	the	facility	is	based	on	defined	short-term	market rates.	During	the	term	of	the	agreement,	we	are	obligated	to	pay	a	variable	facility	fee	on	the	total	commitment,	which	at	December	31,	2011	was	0.10	percent.

# Our	long-term	debt	agreements	do	not	contain	restrictive	financial	covenants.

On	 December	 31,	 2010,	 we	 were	 obligated	 (primarily	 or	 contingently)	 for	 $221	 million	 of	 debt	 for	 which	 United	 States	 Steel	 assumed	 responsibility	 for repayment.	During	the	fourth	quarter	of	2011,	United	States	Steel	called	all	industrial	development	and	environmental	improvement	bonds	and	notes	for	which	they	had assumed	responsibility.

The	following	table	shows	five	years	of	debt	payments:

In	February	and	March	2011,	we	retired	 the	following	debt	at	a	weighted	average	price	equal	 to	112	percent	of	face	value.	A	$279	million	 loss	on	early extinguishment	of	debt	was	recognized	in	the	first	quarter	of	2011.	The	loss	includes	related	deferred	financing	and	premium	costs	partially	offset	by	the	gain	on	settled interest	rate	swaps.

# (In	millions)

These	notes	were	senior	secured	notes	of	Marathon	Oil	Canada	Corporation. (a)

In	April	2010,	we	retired	$500	million	in	aggregate	principal	of	our	debt	under	two	tender	offers	at	a	weighted	average	price	equal	to	117	percent	of	face	value.	As a	result,	we	recorded	a	loss	on	early	extinguishment	of	debt	of	$92	million,	including	the	transaction	premium	as	well	as	the	expensing	of	related	deferred	financing	costs on	the	debt	in	the	second	quarter	of	2010.

# 18. Asset	Retirement	Obligations

The	following	summarizes	the	changes	in	asset	retirement	obligations:

| (In	millions) | 2011 | 2010 |
| :--- | :--- | :--- |
| Beginning\tbalance | $1,355 | $1,102 |
| Incurred,\tincluding\tacquisitions | 37 | 49 |
| Settled | (39) | (28) |
| Accretion\texpense\t(included\tin\tdepreciation,\tdepletion\tand\tamortization) | 81 | 70 |
| Revisions\tto\tprevious\testimates | 126 | 162 |
| Spin-off\tdownstream\tbusiness | (50) | - |
| Ending\tbalance^(a) | $\t\t\t\t1,510 | $\t\t\t\t1,355 |

Includes	asset	retirement	obligation	of	$1	million	classified	as	short-term	at	December	31,	2010.

# 19. Supplemental	Cash	Flow	Information

| 19.<br>Supplemental	Cash	Flow	Information |  |  |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | 2011 | 2010 | 2009 |
| Net\tcash\tprovided\tfrom\toperating\tactivities\tincluded: |  |  |  |
| Interest\tpaid\t(net\tof\tamounts\tcapitalized) | $268 | $107 | $19 |
| Income\ttaxes\tpaid\tto\ttaxing\tauthorities | \t\t\t\t2,893 | \t\t\t\t2,155 | \t\t\t\t1,663 |
| Commercial\tpaper\tand\trevolving\tcredit\tarrangements,\tnet: |  |  |  |
| Commercial\tpaper\t-\tissuances | $421 | $- | $897 |
| -\trepayments | (421) | - | (897) |
| Total | $- | $- | $- |
| Noncash\tinvesting\tand\tfinancing\tactivities\trelated\tto\tcontinuing\toperations: |  |  |  |
| Additions\tto\tproperty,\tplant\tand\tequipment |  |  |  |
| Asset\tretirement\tcosts\tcapitalized,\texcluding\tacquisitions | $151 | $207 | $135 |
| Change\tin\tcapital\texpenditure\taccrual | 104 | (140) | (28) |
| Debt\tpayments\tmade\tby\tUnited\tStates\tSteel | 214 | 105 | 144 |
| Capital\tlease\tand\tsale-leaseback\tfinancing\tobligations\tincrease | - | - | 9 |

# 20. Defined	Benefit	Postretirement	Plans

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

We	also	have	defined	benefit	plans	for	other	postretirement	benefits	covering	most	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.

Summary	information	for	our	defined	benefit	pension	plans	follows.	In	2011,	both	our	U.S.	and	international	plans	have	accumulated	benefit	obligations	in	excess of	plan	assets,	while	in	2010	only	our	U.S.	plans	had	accumulated	benefit	obligations	in	excess	of	plan	assets.

|  |  | 2011 |  | 2010 |
| :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | U.S. |  | Int'l | U.S. |
| Projected\tbenefit\tobligation | $(986) |  | $(465) | $(3,221) |
| Accumulated\tbenefit\tobligation | (813) |  | (418) | (2,365) |
| Fair\tvalue\tof\tplan\tassets | \t\t\t\t\t\t\t\t516 |  | \t\t\t\t\t\t\t\t412 | \t\t\t\t\t\t\t\t1,798 |

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

|  | 2011 | Pension	Benefits | 2010 |  | Other	Benefits<br>2011 | 2010 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | U.S. | Int'l | U.S. | Int'l |  |  |
| Change\tin\tbenefit\tobligations: |  |  |  |  |  |  |
| Benefit\tobligations\tat\tJanuary\t1 | $3,221 | $\t\t\t\t415 | $\t\t\t\t2,989 | $\t\t\t\t395 | $\t\t\t\t779 | $\t\t\t\t685 |
| Spin-off\tdownstream\tbusiness | (2,308) | - | - | - | (483) | - |
| Service\tcost | 28 | 19 | 92 | 19 | 4 | 18 |
| Interest\tcost | 44 | 22 | 153 | 22 | 16 | 39 |
| Plan\tamendment | - | 11 | - | - | - | - |
| Actuarial\tloss | 84 | 13 | 287 | 6 | 1 | 69 |
| Foreign\tcurrency\texchange\trate\tchanges | - | (2) | - | (18) | - | - |
| Other | - | - | - | 6 | - | - |
| Benefits\tpaid | (83) | (13) | (300) | (15) | (16) | (32) |
| Benefit\tobligations\tat\tDecember\t31 | $986 | $465 | $3,221 | $415 | $301 | $779 |
| Change\tin\tplan\tassets: |  |  |  |  |  |  |
| Fair\tvalue\tof\tplan\tassets\tat\tJanuary\t1 | $\t\t\t\t1,798 | $389 | $1,623 | $348 | $- | $- |
| Spin-off\tdownstream\tbusiness | (1,268) | - | - | - | - | - |
| Actual\treturn\ton\tplan\tassets | 30 | 15 | 214 | 47 | - | - |
| Employer\tcontributions | 39 | 23 | 267 | 20 | - | - |
| Foreign\tcurrency\texchange\trate\tchanges | - | (2) | - | (14) | - | - |
| Other | - | - | (6) | 3 | - | - |
| Benefits\tpaid | (83) | (13) | (300) | (15) | - | - |
| Fair\tvalue\tof\tplan\tassets\tat\tDecember\t31 | $516 | $412 | $1,798 | $389 | $- | $- |
| Funded\tstatus\tof\tplans\tat\tDecember\t31 | $(470) | $(53) | $(1,423) | $(26) | $(301) | $(779) |
| Amounts\trecognized\tin\tthe\tconsolidated\tbalance\tsheet: |  |  |  |  |  |  |
| Current\tliabilities | (17) | - | (21) | - | (18) | (36) |
| Noncurrent\tliabilities | (453) | (53) | (1,402) | (26) | (283) | (743) |
| Accrued\tbenefit\tcost | $(470) | $(53) | $(1,423) | $(26) | $(301) | $(779) |
| Pretax\tamounts\tin\taccumulated\tother |  |  |  |  |  |  |
| comprehensive\tincome: |  |  |  |  |  |  |
| Net\tloss | $432 | $63 | $1,382 | $41 | $16 | $18 |
| Prior\tservice\tcost\t(credit) | 27 | 11 | 81 | - | (18) | (24) |

Components	of	net	periodic	benefit	cost	and	other	comprehensive	income	–	The	following	summarizes	the	net	periodic	benefit	costs	and	the	amounts	recognized as	other	comprehensive	income	for	our	defined	benefit	pension	and	other	postretirement	plans.

|  | 2011 |  | 2010 | 2010 | 2009 | 2009 | Other	Benefits | Other	Benefits |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | U.S. | Int'l | U.S.\tInt'l |  | U.S.\tInt'l | U.S.\tInt'l | 2011 | 2010 | 2009 |
| Components\tof\tnet\tperiodic\tbenefit\tcost\trelated\tto\tcontinuing\toperations: |  |  |  |  |  |  |  |  |  |
| Service\tcost | $28 | $19 | $30 | $19 | $36 | $14 | $4 | $3 | $3 |
| Interest\tcost | 44 | 22 | 47 | 22 | 46 | 22 | 16 | 16 | 18 |
| Expected\treturn\ton\tplan\tassets | (43) | (23) | (44) | (22) | (47) | (21) | - | - | - |
| -\tprior\tservice\tcost\t(credit) | 6 | - | 6 | - | 6 | 1 | (7) | (7) | (6) |
| -\tactuarial\tloss | 47 | 2 | 48 | 5 | 20 | 2 | - | - | - |
| Other | - | - | - | 2 | - | - | - | - | - |
| Net\tsettlement/curtailment\tloss^(a) | 30 | - | 56 | - | 4 | 18 | - | - | - |
| Net\tperiodic\tbenefit\tcost^(b) | $112 | $20 | $143 | $26 | $65 | $36 | $13 | $12 | $15 |
| Other\tchanges\tin\tplan\tassets\tand\tbenefit\tobligations\trecognized\tin\tother |  |  |  |  |  |  |  |  |  |
| comprehensive\tincome\t(pretax): |  |  |  |  |  |  |  |  |  |
| Actuarial\tloss\t(gain) | $97 | $24 | $211 | $(25) | $587 | $52 | $1 | $69 | $(34) |
| Amortization\tof\tactuarial\t(loss)\tgain | (77) | (2) | (167) | (5) | (33) | (7) | - | 2 | 5 |
| Prior\tservice\tcost | - | (11) | - | - | - | - | - | - | - |
| Amortization\tof\tprior\tservice\tcredit\t(cost) | (6) | - | (13) | - | (13) | (1) | 7 | 6 | 5 |
| Spin\toff\tdownstream\tbusiness | (24) | - | - | - | - | - | - | - | - |
| Total\trecognized\tin\tother\tcomprehensive\tincome | $ (10) | $11 | $31 | $(30) | $541 | $44 | $8 | $77 | $(24) |
| Total\trecognized\tin\tnet\tperiodic\tbenefit\tcost\tand\tother\tcomprehensive\tincome | $102 | $31 | $174 | $(4) | $606 | $80 | $21 | $89 | $(9) |
| (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	2011 and	2010.	Additionally,	in	2009	a	curtailment	and	settlement	was	recorded	related	to	our	discontinued	operations	in	Ireland	as	discussed	in	Note	6. (a)

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

The	estimated	net	loss	and	prior	service	cost	for	our	defined	benefit	pension	plans	that	will	be	amortized	from	accumulated	other	comprehensive	income	into	net periodic	benefit	cost	in	2012	are	$46	million	and	$7	million.	The	estimated	prior	service	credit	for	our	other	defined	benefit	postretirement	plans	that	will	be	amortized from	accumulated	other	comprehensive	income	into	net	periodic	benefit	cost	in	2012	is	$7	million.

Plan	assumptions	–	The	following	summarizes	the	assumptions	used	to	determine	the	benefit	obligations	at	December	31,	and	net	periodic	benefit	cost	for	the defined	benefit	pension	and	other	postretirement	plans	for	2011,	2010	and	2009.

|  | 2011 |  | 2010 |  | 2009 |  | Other	Benefits | Other	Benefits |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | U.S. | Int'l | U.S. | Int'l | U.S. | Int'l | 2011 | 2010 | 2009 |
| Weighted\taverage\tassumptions\tused\tto\tdetermine\tbenefit\tobligation: |  |  |  |  |  |  |  |  |  |
| Discount\trate | \t4.45% | \t4.70% | \t5.05% | \t5.40% | \t5.50% | \t5.70% | \t4.90% | \t5.55% | \t5.95% |
| Rate\tof\tcompensation\tincrease | \t5.00% | \t4.30% | \t5.00% | \t5.10% | \t4.50% | \t5.55% | \t5.00% | \t5.00% | \t4.50% |
| Weighted\taverage\tassumptions\tused\tto\tdetermine\tnet\tperiodic\tbenefit |  |  |  |  |  |  |  |  |  |
| cost: |  |  |  |  |  |  |  |  |  |
| Discount\trate | \t5.05% | \t5.40% | \t5.23% | \t5.70% | \t6.90% | \t6.70% | \t5.55% | \t6.85% | \t6.85% |
| Expected\tlong-term\treturn\ton\tplan\tassets | \t8.50%^(a) | \t5.86% | \t8.50% | \t6.40% | \t8.50% | \t6.10% | - | - | - |
| Rate\tof\tcompensation\tincrease | \t5.00% | \t5.10% | \t4.50% | \t5.55% | \t4.50% | \t4.75% | \t5.00% | \t4.50% | \t4.50% |
| (a) |  |  |  |  |  |  |  |  |  |

(a) Due	to	the	revised	targeted	asset	allocation	as	discussed	under	the	plan	investment	policies	and	strategies,	effective	January	1,	2012,	the	expected	long	term	rate	of	return	on	plan	assets	was	changed	from	8.50 percent	to	7.75	percent.

# Expected	long-term	return	on	plan	assets

U.S.	plan	–	The	overall	expected	long-term	return	on	plan	assets	assumption	for	our	U.S.	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	overall	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

|  | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| Health\tcare\tcost\ttrend\trate\tassumed\tfor\tthe\tfollowing\tyear: |  |  |  |
| Medical |  |  |  |
| Pre-65 | \t 7.50% | \t 7.50% | \t7.00% |
| Post-65 | \t 7.00% | \t 7.00% | \t6.75% |
| Prescription\tdrugs | \t 7.50% | \t 7.50% | \t7.50% |
| Rate\tto\twhich\tthe\tcost\ttrend\trate\tis\tassumed\tto\tdecline\t(the\tultimate\ttrend\trate): |  |  |  |
| Medical |  |  |  |
| Pre-65 | \t 5.00% | \t 5.00% | \t5.00% |
| Post-65 | \t 5.00% | \t 5.00% | \t5.00% |
| Prescription\tdrugs | \t 5.00% | \t 5.00% | \t5.00% |
| Year\tthat\tthe\trate\treaches\tthe\tultimate\ttrend\trate: |  |  |  |
| Medical |  |  |  |
| Pre-65 | \t2018 | \t2018 | 2014 |
| Post-65 | \t2017 | \t2017 | 2015 |
| Prescription\tdrugs | \t2018 | \t2018 | 2015 |

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:

|  | 1-Percentage- | 1-Percentage- |
| :--- | :--- | :--- |
| (In\tmillions) | Point\tIncrease | Point\tDecrease |
| Effect\ton\ttotal\tof\tservice\tand\tinterest\tcost\tcomponents | $2 | $2 |
| Effect\ton\tother\tpostretirement\tbenefit\tobligations | 33 | 27 |

# 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.	As	such,	for	2011	and	prior,	the plan's	targeted	asset	allocation	was	comprised	of	75	percent	equity	securities	and	25	percent	fixed	income	securities.	Effective	January	1,	2012,	the	U.S.	plan's	targeted asset	allocation	is	comprised	of	65	percent	equity	securities	and	35	percent	fixed	income	securities	but	may	be	adjusted	accordingly	to	better	match	the	plan's	liabilities over	time	as	the	funded	ratio	(as	defined	by	the	investment	policy)	changes.

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	six	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.

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, 2011	and	2010.

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	in	the	fair	value	hierarchy.	The	money	market	mutual	fund	is	valued at	the	net	asset	value	("NAV")	of	shares	held.

Equity	securities	–	Investments	in	public	investment	trusts	and	S&P	500	exchange-traded	funds	are	valued	using	a	market	approach	at	the	closing	price	reported	in an	active	market	and	are	therefore	considered	Level	1.	During	the	fourth	quarter	2011,	Level	1	investment	trust	holdings	were	liquidated	and	the	proceeds	were	re- invested	in	an	exchange	traded	fund.	Non-public	investment	trusts	are	valued	using	a	market	approach	based	on	the	underlying	investments	in	the	trust,	which	are publicly-traded	securities,	and	are	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.	During	the	fourth	quarter	2011,	the	U.S.	plan's	ownership interest	held	in	the	fixed	income	pooled	fund	was	liquidated	and	the	proceeds	were	re-invested	in	U.S.	treasuries.	Further,	the	U.S.	plan's	ownership	interest	held	in	the equity	based	pooled	fund	was	liquidated	and	the	proceeds	were	re-invested	in	an	exchange	traded	fund.	The	majority	of	the	pooled	funds	held	by	our	international pension	plans	are	benchmarked	against	a	relative	public	index.	These	are	considered	Level	2.

U.S.	treasuries	–	U.S.	treasury	notes	are	valued	at	the	closing	price	reported	in	an	active	market.	These	notes	are	considered	Level	1	investments.

Real	estate	–	Real	estate	investments	are	valued	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	and	is considered	Level	2.	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.	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	investors.	The	contract	is	valued	using	a	market	approach	based	on	the	underlying	investments	within	the	portfolio	and	is considered	Level	2.	The	majority	of	the	underlying	investments	consists	of	a	well-diversified	mix	of	non-U.S.	publicly	traded	equity	and	fixed	income	securities.	The values	of	the	LLCs	are	determined	using	an	income	approach	based	on	discounted	cash	flows	and	are	considered	Level	3.

The	following	table	presents	the	fair	values	of	our	defined	benefit	pension	plans'	assets,	by	level	within	the	fair	value	hierarchy,	as	of	December	31,	2011	and	2010.

| (In	millions) | Level	1 |  | Level	2 | December	31,	2011 | Level	3 |  | Total |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | U.S. | Int'l | U.S. | Int'l | U.S. | Int'l | U.S. | Int'l |
| Cash\tand\tcash\tequivalents | $12 | $2 | $- | $- | $- | $- | $12 | $2 |
| Equity\tsecurities: |  |  |  |  |  |  |  |  |
| Investment\ttrusts | - | - | 7 | - | - | - | 7 | - |
| Exchange\ttraded\tfunds | 324 | - | - | - | - | - | 324 | - |
| Private\tequity | - | - | - | - | 23 | - | 23 | - |
| Investment\tfunds |  |  |  |  |  |  |  |  |
| Mutual\tfunds\t–\tequity^(a) | - | 159 | - | - | - | - | - | 159 |
| Pooled\tfunds\t–\tequity^(b) | - | - | - | 96 | - | - | - | 96 |
| Pooled\tfunds\t–\tfixed\tincome^(c) | - | - | - | 149 | - | - | - | 149 |
| U.S.\ttreasuries | 92 | - | - | - | - | - | 92 | - |
| Real\testate^(d) | - | - | - | - | 21 | - | 21 | - |
| Other | - | - | 30\t^(e) | 6 | 7 | - | 37 | 6 |
| Total\tinvestments,\tat\tfair\tvalue | $428 | $161 | $37 | $251 | $\t\t51 | $\t\t\t\t- | $516 | $412 |

| (In	millions) | Level	1 |  | Level	2 | December	31,	2010 | Level	3 |  | Total |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | U.S. | Int'l | U.S. | Int'l | U.S. | Int'l | U.S. | Int'l |
| Cash\tand\tcash\tequivalents | $8 | $1 | $- | $- | $- | $- | $8 | $1 |
| Equity\tsecurities: |  |  |  |  |  |  |  |  |
| Investment\ttrusts | 25 | - | 137 | - | - | - | 162 | - |
| Exchange\ttraded\tfunds | 56 | - | - | - | - | - | 56 | - |
| Private\tequity | - | - | - | - | 67 | - | 67 | - |
| Investment\tfunds |  |  |  |  |  |  |  |  |
| Mutual\tfunds\t–\tequity^(a) | - | 161 | - | - | - | - | - | 161 |
| Pooled\tfunds\t–\tequity^(b) | - | - | 1,072 | 97 | - | - | 1,072 | 97 |
| Pooled\tfunds\t–\tfixed\tincome^(c) | - | - | 350 | 126 | - | - | 350 | 126 |
| Real\testate^(d) | - | - | - | - | 54 | - | 54 | - |
| Other | - | - | 5 | 4 | 24 | - | 29 | 4 |
| Total\tinvestments,\tat\tfair\tvalue | $\t\t\t\t89 | $\t\t\t\t162 | $\t\t\t\t1,564 | $\t\t\t\t227 | $\t\t\t\t145 | $\t\t\t\t\t\t- | $\t\t\t\t1,798 | $\t\t\t\t389 |

Includes	approximately	70	percent	of	investments	held	in	U.S.	and	non-U.S.	common	stocks	in	the	financial	services,	consumer	staples,	health	care,	energy	and	basic	material	sectors	and	30	percent	of	investments held	among	various	other	sectors.	The	funds	objective	is	to	outperform	their	respective	benchmark	indexes	FTSE	All	Share,	MSCI	World	Free,	and	MSCI	Europe	(excluding	the	U.K.)	as	defined	by	the	investment policy. (a)

U.S.	–	At	December	31,	2010,	includes	approximately	70	percent	of	investments	held	in	U.S.	and	non-U.S.	publicly	traded	common	stocks	in	the	consumer	staples,	consumer	discretionary,	technology,	health	and energy	sectors	and	30	percent	of	investments	held	among	various	other	sectors.	Int'l	–	Includes	approximately	70	percent	of	investments	held	in	non-U.S.	common	stocks	(specifically	Asia	Pacific,	except	Japan, and	the	U.K.)	in	the	financials,	energy,	consumer	staples,	industrials,	and	telecommunication	services	sectors	and	the	30	percent	of	investments	held	amongst	various	other	sectors.	The	funds	objective	is	to outperform	their	respective	benchmark	indexes,	MSCI	AC	Asia	and	FTSE	All-Share,	as	defined	by	the	investment	policy. (b)

U.S.	–	At	December	31,	2010,	includes	approximately	80	percent	of	investments	held	in	U.S.	and	non-U.S.	publicly	traded	investment	grade	government	and	corporate	bonds	which	include	treasuries,	mortgage- backed	securities	and	industrials	and	20	percent	of	investments	held	among	various	other	sectors.	Int'l	–	Includes	approximately	80	percent	of	investments	held	in	U.S.	and	non-U.S.	publicly	traded	investment grade	government	and	corporate	bonds	which	include	gilts,	treasuries,	financials,	sovereigns	and	collateralized	asset	backed	securities	and	20	percent	of	investments	held	among	various	other	sectors.	The	funds objective	is	to	outperform	their	respective	benchmark	indexes,	as	defined	by	the	investment	policy. (c)

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	land	with	the greatest	percentage	of	investments	made	in	the	U.S.	and	Asia,	which	includes	the	emerging	markets	of	China	and	India. (d)

Includes	an	$18	million	receivable	for	the	sale	of	an	investment	that	closed	as	of	December	31,	2011	but	did	not	cash	settle	until	the	next	business	day. (e)

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

|  | Private | Real |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Equity | Estate | Other | Total |
| Beginning\tbalance | $\t\t\t\t67 | $\t\t\t\t54 | $\t\t\t\t24 | $\t\t\t\t145 |
| Spin-off\tdownstream\tbusiness | (46) | (37) | (17) | (100) |
| Actual\treturn\ton\tplan\tassets | 3 | 2 | - | 5 |
| Purchases | 3 | 4 | - | 7 |
| Sales | (4) | (2) | - | (6) |
| Ending\tbalance | $23 | $21 | $7 | $51 |

|  | Private | Real |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Equity | Estate | Other | Total |
| Beginning\tbalance | $42 | $36 | $23 | $101 |
| Actual\treturn\ton\tplan\tassets | 13 | 4 | 1 | 18 |
| Purchases | 15 | 17 | - | 32 |
| Sales | (3) | (3) | - | (6) |
| Ending\tbalance | $67 | $54 | $24 | $145 |

Contributions	to	defined	benefit	plans	–	We	expect	to	make	contributions	to	the	funded	pension	plans	of	up	to	$113	million	in	2012.	Cash	contributions	to	be	paid from	our	general	assets	for	the	unfunded	pension	and	postretirement	plans	are	expected	to	be	approximately	$18	million	and	$21	million	in	2012.

Estimated	future	benefit	payments	–	The	following	gross	benefit	payments,	which	reflect	expected	future	services,	as	appropriate,	are	expected	to	be	paid	in	the years	indicated.

|  | Pension	Benefits | Pension	Benefits | Other |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | U.S. | Int'l | Benefits^(a) |
| 2012 | $ \t\t\t\t104 | $\t\t\t\t12 | $21 |
| 2013 | 100 | 13 | 22 |
| 2014 | 102 | 15 | 22 |
| 2015 | 101 | 16 | 23 |
| 2016 | 104 | 18 | 24 |
| 2017\tthrough\t2021 | 482 | 105 | 121 |
| (a) |  |  |  |

Expected	Medicare	reimbursements	for	2012	through	2013	total	$5	million.	Effective	2013,	as	a	result	of	the	PPACA,	future	Medicare	reimbursements	will	no	longer	be	tax	deductible	and	must	be	used	to	reduce the	costs	of	providing	Medicare	Part	D	equivalent	prescription	drug	benefits	to	retirees.	The	total	of	these	future	reimbursements	from	2014	through	2021	is	$22	million. (a)

Contributions	to	defined	contribution	plans	–	We	contribute	to	several	defined	contribution	plans	for	eligible	employees.	Contributions	to	these	plans	related	to continuing	operations	totaled	$50	million	in	2011,	$75	million	in	2010	and	$59	million	in	2009.

# 21. Incentive	Based	Compensation

# Description	of	Stock	Based	Compensation	Plans

The	 Marathon	 Oil	 Corporation	 2007	 Incentive	 Compensation	 Plan	 (the	 "2007	 Plan")	 was	 approved	 by	 our	 stockholders	 in	April	 2007	 and	 authorizes	 the Compensation	Committee	of	the	Board	of	Directors	to	grant	stock	options,	stock	appreciation	rights,	stock	awards	(including	restricted	stock	and	restricted	stock	unit awards)	and	performance	awards	to	employees.	The	2007	Plan	also	allows	us	to	provide	equity	compensation	to	our	non-employee	directors.	No	more	than	34	million shares	of	our	common	stock	may	be	issued	under	the	2007	Plan	and	no	more	than	12	million	of	those	shares	may	be	used	for	awards	other	than	stock	options	or	stock appreciation	rights.

Shares	subject	to	awards	under	the	2007	Plan	that	are	forfeited,	are	terminated	or	expire	unexercised	become	available	for	future	grants.	If	a	stock	appreciation	right is	settled	upon	exercise	by	delivery	of	shares	of	common	stock,	the	full	number	of	shares	with	respect	to	which	the	stock	appreciation	right	was	exercised	will	count against	the	number	of	shares	of	our	common	stock	reserved	for	issuance	under	the	2007	Plan	and	will	not	again	become	available	under	the	2007	Plan.	In	addition,	the number	of	shares	of	our	common	stock	reserved	for	issuance	under	the	2007	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	2007	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	2007	Plan,	no	new	grants	were	or	will	be	made	from	the	2003	Incentive	Compensation	Plan	(the	"2003	Plan").	The	2003	Plan	replaced	the 1990	Stock	Plan,	the	Non-Officer	Restricted	Stock	Plan,	the	Non-Employee	Director	Stock	Plan,	the	deferred	stock	benefit	provision	of	the	Deferred	Compensation Plan	for	Non-Employee	Directors,	the	Senior	Executive	Officer	Annual	Incentive	Compensation	Plan	and	the	Annual	Incentive	Compensation	Plan	(the	"Prior	Plans"). No	new	grants	will	be	made	from	the	Prior	Plans.	Any	awards	previously	granted	under	the	2003	Plan	or	the	Prior	Plans	shall	continue	to	be	exercisable	in	accordance with	their	original	terms	and	conditions.

# Stock	based	awards	under	the	Plan

Stock	options	–	We	grant	stock	options	under	the	2007	Plan.	Our	stock	options	represent	the	right	to	purchase	shares	of	our	common	stock	at	its	fair	market	value on	the	date	of	grant.	Through	2004,	certain	stock	options	were	granted	under	the	2003	Plan	with	a	tandem	stock	appreciation	right,	which	allows	the	recipient	to	instead elect	to	receive	cash	or	our	common	stock	equal	to	the	excess	of	the	fair	market	value	of	shares	of	common	stock,	as	determined	in	accordance	with	the	2003	Plan,	over the	option	price	of	the	shares.	In	general,	stock	options	granted	under	the	2007	Plan	and	the	2003	Plan	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	stock	appreciation	rights	have	been	granted	under	the	2007	Plan.	Similar	to stock	options,	stock	appreciation	rights	represent	the	right	to	receive	a	payment	equal	to	the	excess	of	the	fair	market	value	of	shares	of	common	stock	on	the	date	the right	is	exercised	over	the	grant	price.	Under	the	2003	Plan,	certain	SARs	were	granted	as	stock-settled	SARs	and	others	were	granted	in	tandem	with	stock	options.	In general,	SARs	granted	under	the	2003	Plan	vest	ratably	over	a	three-year	period	and	have	a	maximum	term	of	ten	years	from	the	date	they	are	granted.

Restricted	stock	–	We	grant	restricted	stock	and	restricted	stock	units	under	the	2007	Plan	and	previously	granted	such	awards	under	the	2003	Plan.	In	2005,	the Compensation	Committee	began	granting	time-based	restricted	stock	to	certain	of	our	U.S.-based	officers	as	part	of	their	annual	long-term	incentive	package.	The restricted	stock	awards	to	officers	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	("restricted	stock	awards"),	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,	however,	certain	restricted	stock	awards	will	vest	over	a	four-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.

Common	stock	units	–	We	maintain	an	equity	compensation	program	for	our	non-employee	directors	under	the	2007	Plan	and	previously	maintained	such	a program	under	the	2003	Plan.	All	non-employee	directors	receive	annual	grants	of	common	stock	units,	and	they	are	required	to	hold	units	granted	prior	to	2012	until they	leave	the	Board	of	Directors.	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	related	to	continuing	operations	was	$65	million,	$51	million	and	$59	million	in	2011,	2010	and	2009,	while	the total	related	income	tax	benefits	were	$23	million,	$19	million	and	$22	million	in	the	same	years.	In	2011,	2010	and	2009	cash	received	upon	exercise	of	stock	option awards	related	was	$77	million,	$12	million	and	$4	million.	Tax	benefits	realized	for	deductions	for	stock	awards	exercised	during	2011,	2010	and	2009	totalled	$32 million,	$11	million	and	$10	million.

# Stock	option	awards

During	2011,	2010	and	2009,	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	Black-Scholes	assumptions:

|  | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| Weighted\taverage\texercise\tprice\tper\tshare | $32.30 | $30.00 | $27.62 |
| Expected\tannual\tdividend\tyield | 2.1\t% | 3.2\t% | 3.5\t% |
| Expected\tlife\tin\tyears | 5.3 | 5.1 | 4.9 |
| Expected\tvolatility | 40\t% | 43\t% | 41\t% |
| Risk-free\tinterest\trate | 1.7\t% | 2.2\t% | 2.3\t% |
| Weighted\taverage\tgrant\tdate\tfair\tvalue\tof\tstock\toption\tawards\tgranted | $10.44 | $8.70 | $7.67 |

The	following	is	a	summary	of	stock	option	award	activity	in	2011.

|  | Number | Average |
| :--- | :--- | :--- |
|  | of\tShares | Exercise\tprice |
| Outstanding\tat\tbeginning\tof\tyear | \t24,912,261 | $24.85 |
| Granted | 7,676,544 | 32.30 |
| Exercised | \t (3,576,373) | 15.12 |
| Cancelled | (652,607) | 25.88 |
| Spin-off\tdownstream\tbusiness | \t (6,989,110) | 30.94 |
| Outstanding\tat\tend\tof\tyear | \t21,370,715 | $24.41 |

The	intrinsic	value	of	stock	option	awards	exercised	during	2011,	2010	and	2009	was	$59	million,	$8	million	and	$3	million.

The	following	table	presents	information	related	to	stock	option	awards	at	December	31,	2011.

| Range	of | Number | Average | Weighted | Number | Weighted |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Exercise | of\tShares | Remaining | Average | of\tShares | Average |
| Prices | Under\tOption | Contractual\tLife | Exercise\tPrice | Under\tOption | Exercise\tPrice |
| $\t\t\t\t\t7.99-12.75 | 1,272,745 | 2 | $10.23 | 1,272,745 | $10.23 |
| \t\t\t\t\t\t\t12.76-16.81 | 2,850,590 | 5 | 15.21 | 2,354,373 | 15.28 |
| \t\t\t\t\t\t\t16.82-23.20 | 6,642,268 | 8 | 18.60 | 2,810,120 | 18.52 |
| \t\t\t\t\t\t\t23.21-29.24 | 2,021,400 | 4 | 23.92 | 1,955,767 | 23.82 |
| \t\t\t\t\t\t\t29.25-30.36 | 22,388 | 7 | 29.56 | 22,388 | 29.56 |
| \t\t\t\t\t\t\t30.37-47.91 | 8,561,324 | 7 | 34.20 | 4,690,067 | 35.75 |
| \t\t\t\t\t\t\tTotal | 21,370,715 | 6 | 24.41 | 13,105,460 | 24.11 |

As	of	December	31,	2011,	the	aggregate	intrinsic	value	of	stock	option	awards	outstanding	was	$146	million.	The	aggregate	intrinsic	value	and	weighted	average remaining	contractual	life	of	stock	option	awards	currently	exercisable	were	$98	million	and	5	years.

As	of	December	31,	2011,	the	number	of	fully-vested	stock	option	awards	and	stock	option	awards	expected	to	vest	was	21,142,660.	The	weighted	average	exercise price	and	weighted	average	remaining	contractual	life	of	these	stock	option	awards	were	$24.38	and	6	years	and	the	aggregate	intrinsic	value	was	$145	million.	As	of December	31,	2011,	unrecognized	compensation	cost	related	to	stock	option	awards	was	$36	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

|  | Awards | Fair	Value |
| :--- | :--- | :--- |
| Unvested\tat\tbeginning\tof\tyear | \t2,084,680 | $23.03 |
| Granted | \t3,066,978^(a) | 27.74 |
| Vested | (993,949) | 27.34 |
| Forfeited | (163,806) | 23.88 |
| Spin-off\tdownstream\tbusiness | (289,925) | 21.30 |
| Unvested\tat\tend\tof\tyear | \t3,703,978 | 25.88 |
| (a) |  |  |

Beginning	in	August,	2011,	most	employees	on	the	U.S.,	U.K.,	Canadian	and	Norwegian	payrolls	are	eligible	for	a	restricted	stock	grant,	based	on	performance. (a)

As	of	December	31,	2011,	there	was	$78	million	of	unrecognized	compensation	cost	related	to	restricted	stock	awards	which	is	expected	to	be	recognized	over	a weighted	average	period	of	2.5	years.

# Performance	unit	awards

Performance	units	provide	for	named	executive	officers	to	receive	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	total	shareholder	return	("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	the	actual	payout	varying	from	$0	to	$2	per	unit	(capped	at	a maximum	payout	of	$2	per	unit).	Because	performance	units	are	to	be	settled	in	cash	at	the	end	of	the	performance	period,	they	are	accounted	for	as	liability	awards. Compensation	expense	related	to	continuing	operations	associated	with	performance	units	was	$32	million	and	$2	million	in	2011	and	2009,	but	was	not	significant	in 2010.	Expense	for	2011	included	$14	million	paid	on	three	groups	of	performance	unit	grants	outstanding	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.

During	the	third	quarter	of	2011,	we	granted	15	million	performance	units	to	named	executive	officers.	A	portion	of	these	units	have	an	18-month	performance period	and	a	portion	have	a	30-month	performance	period	to	reflect	the	remaining	periods	of	the	original	2011	and	2010	performance	unit	grants	outstanding	prior	to	the spinoff.

# 22. Stockholders'	Equity

Securities	 exchangeable into	 Marathon	 common	 stock	 –	In	conjunction	with	our	acquisition	of	Western	Oil	Sands	Inc.	("Western")	on	October	18,	2007, Canadian	residents	were	able	to	receive,	at	their	election,	cash,	Marathon	common	stock	or	securities	exchangeable	into	Marathon	common	stock	(the	"Exchangeable Shares").	The	Exchangeable	Shares	were	shares	of	an	indirect	Canadian	subsidiary	of	Marathon	and	were	exchanged	into	Marathon	stock	based	upon	an	exchange	ratio that	began	at	one-for-one	and	adjusted	quarterly	to	reflect	cash	dividends.	The	Exchangeable	Shares	were	exchangeable	at	the	option	of	the	holder	at	any	time	and	were automatically	redeemable	on	October	18,	2011.	They	could	also	be	redeemed	prior	to	their	automatic	redemption	if	certain	conditions	were	met.	Those	conditions	were met	and	we	filed	notice	of	the	proposed	redemption	in	Canada	on	March	3,	2010.	On	April	7,	2010,	the	remaining	exchangeable	shares	were	redeemed.

Preferred	shares	–	Also	in	connection	with	our	acquisition	of	Western,	the	Board	of	Directors	authorized	a	class	of	voting	preferred	stock.	Upon	completion	of	the acquisition,	we	issued	shares	of	this	voting	preferred	stock	to	a	trustee,	who	held	the	shares	for	the	benefit	of	the	holders	of	the	Exchangeable	Shares	discussed	above. Each	share	of	voting	preferred	stock	was	entitled	to	one	vote	on	all	matters	submitted	to	the	holders	of	Marathon	common	stock.	Each	holder	of	Exchangeable	Shares could	direct	the	trustee	to	vote	the	number	of	shares	of	voting	preferred	stock	equal	to	the	number	of	shares	of	Marathon	common	stock	issuable	upon	the	exchange	of the	Exchangeable	Shares	held	by	that	holder.	In	no	event	would	the	aggregate	number	of	votes	entitled	to	be	cast	by	the	trustee	with	respect	to	the	outstanding	shares	of voting	preferred	stock	exceed	the	number	of	votes	entitled	to	be	cast	with	respect	to	the	outstanding	Exchangeable	Shares.	Except	as	otherwise	provided	in	our	restated certificate	of	incorporation	or	by	applicable	law,	the	common	stock	and	the

voting	preferred	stock	voted	together	as	a	single	class	in	the	election	of	directors	of	Marathon	and	on	all	other	matters	submitted	to	a	vote	of	stockholders	of	Marathon generally.	The	voting	preferred	stock	had	no	other	voting	rights	except	as	required	by	law.	Other	than	dividends	payable	solely	in	shares	of	voting	preferred	stock,	no dividend	or	other	distribution,	was	paid	or	payable	to	the	holder	of	the	voting	preferred	stock.	In	the	event	of	any	liquidation,	dissolution	or	winding	up	of	Marathon,	the holder	of	shares	of	the	voting	preferred	stock	would	not	be	entitled	to	receive	any	assets	of	Marathon	available	for	distribution	to	its	stockholders.	The	voting	preferred stock	was	not	convertible	into	any	other	class	or	series	of	the	capital	stock	of	Marathon	or	into	cash,	property	or	other	rights,	and	could	not	be	redeemed.	In	connection with	the	redemption	of	the	Exchangeable	Shares,	these	preferred	shares	were	eliminated	in	June	2010.

Share	repurchase	plan	–	The	Board	of	Directors	has	authorized	the	repurchase	of	up	to	$5	billion	of	our	common	stock.	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.	As	of	December	31,	2011,	we had	acquired	78	million	common	shares	at	a	cost	of	$3,222	million	under	this	authorized	share	repurchase	program,	including	12	million	common	shares	acquired during	2011	at	a	cost	of	$300	million.

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	 (including	 sale-leasebacks	 accounted	 for	 as financings)	and	for	operating	lease	obligations	having	initial	or	remaining	noncancelable	lease	terms	in	excess	of	one	year	are	as	follows:

|  | Capital | Operating |
| :--- | :--- | :--- |
|  | Lease | Lease |
| (In\tmillions) | Obligations | Obligations |
| 2012 | $\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t22 | $\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t42 |
| 2013 | 1 | 38 |
| 2014 | 1 | 29 |
| 2015 | 1 | 26 |
| 2016 | 1 | 25 |
| Later\tyears | 25 | 66 |
| Sublease\trentals | - | (2) |
| Total\tminimum\tlease\tpayments | $51 | $224 |
| Less\timputed\tinterest\tcosts | (20) |  |
| Present\tvalue\tof\tnet\tminimum\tlease\tpayments | $31 |  |

Operating	lease	rental	expense	related	to	continuing	operations	was	$74	million,	$77	million	and	$105	million	in	2011,	2010	and	2009,	which	excludes	$16	million and	$3	million	paid	by	United	States	Steel	on	assumed	leases	in	2010	and	2009.

# 24. 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.	Noble	is	seeking	an	unspecified	amount	of	damages.	We	are	vigorously	defending	this	litigation.	The	ultimate	outcome	of this	lawsuit,	including	any	financial	effect	on	us,	remains	uncertain.	We	do	not	believe	an	estimate	of	a	reasonably	probable	loss	(or	range	of	loss)	can	be	made	for	this lawsuit	at	this	time.

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,	2011	and	2010,	accrued	liabilities	for	remediation	totaled	$1	million	and	$119	million.	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	provided	certain	guarantees,	direct	and	indirect,	of	the	indebtedness	of	other	companies.	Under	the	terms	of	most	of	these	guarantee arrangements,	we	would	be	required	to	perform	should	the	guaranteed	party	fail	to	fulfill	its	obligations	under	the	specified	arrangements.	In	addition	to	these	financial guarantees,	we	also	have	various	performance	guarantees	related	to	specific	agreements.

United	States	Steel	was	the	sole	general	partner	of	Clairton	1314B	Partnership,	L.P.,	which	owned	certain	facilities	formerly	owned	by	United	States	Steel.	We	have agreed,	under	certain	circumstances,	to	indemnify	the	limited	partners	if	the	partnership's	product	sales	fail	to	qualify	for	the	credit	under	Section	29	of	the	Internal Revenue	Code.	The	Clairton	1314B	Partnership	was	terminated	on	October	31,	2008,	but	we	were	not	released	from	our	obligations.	United	States	Steel	has	estimated the	maximum	potential	amount	of	this	indemnity	obligation,	including	interest	and	tax	gross-up,	was	approximately	$110	million	as	of	December	31,	2011,	all	of	which is	related	to	our	continuing	operations.

We	 have	 entered	 into	 other	 guarantees	 related	 to	 our	 continuing	 operations	 with	 maximum	 potential	 undiscounted	 payments	 totaling	 $139	 million	 as	 of December	31,	2011,	which	consist	primarily	of	leases	of	corporate	assets	containing	general	lease	indemnities	and	guaranteed	residual	values,	a	performance	guarantee and	a	long-term	transportation	services	agreement.

In	October	2010,	upon	acquiring	a	position	in	four	exploration	blocks	in	the	Iraqi	Kurdistan	Region,	we	indemnified	the	KRG	against	any	negative	tax	effects related	to	certain	payments	we	are	obligated	to	make	to	the	KRG.	As	of	December	31,	2011,	some	of	those	payments	had	been	made,	no	related	taxes	have	been assessed,	and	neither	is	there	any	history	of	such	payments	being	taxed.	Given	the	lack	of	history	of	tax	assessment	against	such	payments,	and	because	certain	of	our future	payments	to	the	KRG	are	not	quantifiable,	a	maximum	potential	undiscounted	payments	cannot	be	calculated.

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,	2011	and	2010,	contractual	commitments	of	our	continuing	operations	to	acquire	property,	plant	and	equipment	totaled $2,683	million	and	$1,881	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	cost	of	revenues.	At December	31,	2011,	the	remaining	liability	is	$49	million.

# Selected	Quarterly	Financial	Data	(Unaudited)

| (In	millions,	except	per	share	data) | 1st	Qtr. | 2nd	Qtr. | 3rd	Qtr. | 4th	Qtr. | 1st	Qtr. | 2nd	Qtr. | 3rd	Qtr. | 4th	Qtr. |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Revenues | $\t\t3,671 | $\t\t3,694 | $\t\t3,649 | $\t\t3,649 | $\t\t2,667 | $\t\t2,807 | $\t\t2,854 | $\t\t3,362 |
| Income\tfrom\toperations\tbefore\tincome\ttaxes | 1,289 | 928 | 1,333 | 1,263 | 1,389 | 922 | 1,050 | 863 |
| Income\tfrom\tcontinuing\toperations | 455 | 298 | 405 | 549 | 617 | 374 | 467 | 424 |
| Discontinued\toperations | 541 | 698 | - | - | (160) | 335 | 229 | 282 |
| Net\tincome | $996 | $996 | $405 | $549 | $457 | $709 | $696 | $706 |
| Net\tincome\tper\tshare: |  |  |  |  |  |  |  |  |
| Basic: |  |  |  |  |  |  |  |  |
| Continuing\toperations | $0.64 | $0.42 | $0.57 | $0.78 | $0.87 | $0.53 | $0.66 | $0.60 |
| Discontinued\toperations | 0.76 | 0.98 | - | - | (0.23) | 0.47 | 0.32 | 0.39 |
| Net\tincome | 1.40 | 1.40 | 0.57 | 0.78 | 0.64 | 1.00 | 0.98 | 0.99 |
| Diluted: |  |  |  |  |  |  |  |  |
| Continuing\toperations | 0.64 | 0.42 | 0.57 | 0.78 | 0.87 | 0.53 | 0.66 | 0.60 |
| Discontinued\toperations | 0.75 | 0.97 | - | - | (0.23) | 0.47 | 0.32 | 0.39 |
| Net\tincome | 1.39 | 1.39 | 0.57 | 0.78 | 0.64 | 1.00 | 0.98 | 0.99 |
| Dividends\tpaid\tper\tshare | $0.25 | $0.25 | $0.15 | $0.15 | $0.24 | $0.25 | $0.25 | $0.25 |

Our	downstream	business	was	spun-off	on	June	30,	2011.	All	quarters	have	been	recast	to	reflect	the	business	in	discontinued	operations.

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

The	supplementary	 information	 is	disclosed	by	 the	following	geographic	areas:	 the	United	States;	Europe,	which	primarily	 includes	activities	 in	 the	United Kingdom,	Norway	and	Poland;	EG;	Other	Africa,	which	primarily	includes	activities	in	Angola	and	Libya;	Canada;	and	Other	International	("Other	Int'l"),	which includes	activities	in	Indonesia	and	the	Iraqi	Kurdistan	Region.	Discontinued	operations	("Disc	Ops")	represent	our	Irish	and	Gabonese	oil	exploration	and	production businesses	that	were	sold	in	2009.

# 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.

|  | United |  |  | Other |  | Continuing | Disc |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (mmbbl) | States | \tCanada^(a) | \t EG^(b) | Africa | \tEurope | Operations | Ops |
| Liquid\tHydrocarbons |  |  |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2009 | 178 | - | \t139 | 211 | 104 | 632 | 4 |
| Revisions\tof\tprevious\testimates | - | - | (2) | 3 | 19 | 20 | 2 |
| Extensions,\tdiscoveries\tand\tother\tadditions | 21 | - | - | 31 | 12 | 64 | - |
| Production | (23) | - | \t (15) | (17) | (33) | (88) | (2) |
| Sales\tof\treserves\tin\tplace | (6) | - | - | - | - | (6) | (4) |
| End\tof\tyear\t–\t2009 | 170 | - | \t122 | 228 | 102 | 622 | - |
| Revisions\tof\tprevious\testimates | (3) | - | 10 | - | 23 | 30 | - |
| Purchases\tof\treserves\tin\tplace | 1 | - | - | - | - | 1 | - |
| Extensions,\tdiscoveries\tand\tother\tadditions | 30 | - | - | 28 | 8 | 66 | - |
| Production | (25) | - | \t (13) | (17) | (34) | (89) | - |
| End\tof\tyear\t–\t2010 | 173 | - | \t119 | 239 | 99 | 630 | - |
| Revisions\tof\tprevious\testimates | 16 | - | 11 | 2 | 21 | 50 | - |
| Improved\trecovery | 1 | - | - | - | - | 1 | - |
| Purchases\tof\treserves\tin\tplace | 89 | - | - | - | - | 89 | - |
| Extensions,\tdiscoveries\tand\tother\tadditions | 27 | - | - | 1 | 14 | 42 | - |
| Production | (27) | - | \t (13) | (2) | (37) | (79) | - |
| End\tof\tyear\t–\t2011 | 279 | - | \t117 | 240 | 97 | 733 | - |
| Proved\tdeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2009 | 137 | - | 99 | 193 | 81 | 510 | 4 |
| End\tof\tyear\t–\t2009 | 120 | - | 83 | 186 | 87 | 476 | - |
| End\tof\tyear\t–\t2010 | 124 | - | 86 | 180 | 89 | 479 | - |
| End\tof\tyear\t–\t2011 | 141 | - | 78 | 179 | 84 | 482 | - |
| Proved\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2009 | 41 | - | 40 | 18 | 23 | 122 | - |
| End\tof\tyear\t–\t2009 | 50 | - | 39 | 42 | 15 | 146 | - |
| End\tof\tyear\t–\t2010 | 49 | - | 33 | 59 | 10 | 151 | - |
| End\tof\tyear\t–\t2011 | 138 | - | 39 | 61 | 13 | 251 | - |

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

|  | United<br>States | Canada^(a) | EG^(b) | Other<br>Africa | Europe | Continuing<br>Operations | Disc<br>Ops |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Natural\tGas\t(bcf) |  |  |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2009 | \t 1,085 | - | \t1,866 | 109 | 159 | 3,219 | \t 132 |
| Revisions\tof\tprevious\testimates | (139) | - | (23) | - | (10) | (172) | - |
| Extensions,\tdiscoveries\tand\tother\tadditions | 80 | - | - | - | 2 | 82 | - |
| Production^(c) | (146) | - | (155) | (2) | (42) | (345) | (6) |
| Sales\tof\treserves\tin\tplace | (60) | - | - | - | - | (60) | \t(126) |
| End\tof\tyear\t–\t2009 | 820 | - | \t1,688 | 107 | 109 | 2,724 | - |
| Revisions\tof\tprevious\testimates | 16 | - | 111 | (1) | 35 | 161 | - |
| Purchases\tof\treserves\tin\tplace | 1 | - | - | - | - | 1 | - |
| Extensions,\tdiscoveries\tand\tother\tadditions | 61 | - | - | - | 4 | 65 | - |
| Production^(c) | (133) | - | (148) | (1) | (32) | (314) | - |
| Sales\tof\treserves\tin\tplace | (20) | - | - | - | - | (20) | - |
| End\tof\tyear\t–\t2010 | 745 | - | \t1,651 | 105 | 116 | 2,617 | - |
| Revisions\tof\tprevious\testimates | 18 | - | 81 | (1) | 22 | 120 | - |
| Purchases\tof\treserves\tin\tplace | 119 | - | - | - | - | 119 | - |
| Extensions,\tdiscoveries\tand\tother\tadditions | 109 | - | - | - | 11 | 120 | - |
| Production^(c) | (119) | - | (161) | - | (30) | (310) | - |
| End\tof\tyear\t–\t2011 | 872 | - | \t1,571 | 104 | 119 | 2,666 | - |
| Proved\tdeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2009 | 839 | - | \t1,273 | 109 | 95 | 2,316 | 34 |
| End\tof\tyear\t–\t2009 | 652 | - | \t1,102 | 107 | 50 | 1,911 | - |
| End\tof\tyear\t–\t2010 | 591 | - | \t1,186 | 104 | 43 | 1,924 | - |
| End\tof\tyear\t–\t2011 | 551 | - | \t1,104 | 104 | 40 | 1,799 | - |
| Proved\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2009 | 246 | - | 593 | - | 64 | 903 | 98 |
| End\tof\tyear\t–\t2009 | 168 | - | 586 | - | 59 | 813 | - |
| End\tof\tyear\t–\t2010 | 154 | - | 465 | 1 | 73 | 693 | - |
| End\tof\tyear\t–\t2011 | 321 | - | 467 | - | 79 | 867 | - |
| Synthetic\tcrude\toil\t(mmbbl) |  |  |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2009 | - | - | - | - | - | - | - |
| Revisions\tof\tprevious\testimates^(d) | - | 603 | - | - | - | 603 | - |
| End\tof\tyear\t–\t2009 | - | 603 | - | - | - | 603 | - |
| Revisions\tof\tprevious\testimates | - | (22) | - | - | - | (22) | - |
| Production | - | (9) | - | - | - | (9) | - |
| End\tof\tyear\t–\t2010 | - | 572 | - | - | - | 572 | - |
| Revisions\tof\tprevious\testimates | - | 17 | - | - | - | 17 | - |
| Production | - | (14) | - | - | - | (14) | - |
| Extensions,\tdiscoveries\tand\tother\tadditions | - | 48 | - | - | - | 48 | - |
| End\tof\tyear\t–\t2011 | - | 623 | - | - | - | 623 | - |
| Proved\tdeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2009 | - | - | - | - | - | - | - |
| End\tof\tyear\t–\t2009 | - | 392 | - | - | - | 392 | - |
| End\tof\tyear\t–\t2010 | - | 433 | - | - | - | 433 | - |
| End\tof\tyear\t–\t2011 | - | 623 | - | - | - | 623 | - |
| Proved\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2009 | - | - | - | - | - | - | - |
| End\tof\tyear\t–\t2009 | - | 211 | - | - | - | 211 | - |
| End\tof\tyear\t–\t2010 | - | 139 | - | - | - | 139 | - |
| End\tof\tyear\t–\t2011 | - | - | - | - | - | - | - |

|  | United |  |  | Other |  | Continuing | Disc |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (mmboe) | States | Canada^(a) | EG^(b) | Africa | Europe | Operations | Ops |
| Total\tProved\tReserves |  |  |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2009 | 359 | - | \t 450 | 229 | 131 | 1,169 | 26 |
| Revisions\tof\tprevious\testimates^(d) | (22) | 603 | (6) | 3 | 17 | 595 | 1 |
| Extensions,\tdiscoveries\tand\tother\tadditions | 34 | - | - | 31 | 13 | 78 | - |
| Production^(c) | (48) | - | (41) | (17) | (41) | (147) | (2) |
| Sales\tof\treserves\tin\tplace | (16) | - | - | - | - | (16) | (25) |
| End\tof\tyear\t–\t2009 | 307 | 603 | \t 403 | 246 | 120 | 1,679 | - |
| Revisions\tof\tprevious\testimates | (1) | (22) | 29 | - | 28 | 34 | - |
| Purchases\tof\treserves\tin\tplace | 1 | - | - | - | - | 1 | - |
| Extensions,\tdiscoveries\tand\tother\tadditions | 40 | - | - | 28 | 9 | 77 | - |
| Production^(c) | (47) | (9) | (38) | (17) | (39) | (150) | - |
| Sales\tof\treserves\tin\tplace | (3) | - | - | - | - | (3) | - |
| End\tof\tyear\t–\t2010 | 297 | 572 | \t 394 | 257 | 118 | 1,638 | - |
| Revisions\tof\tprevious\testimates | 19 | 17 | 25 | 1 | 25 | 87 | - |
| Improved\trecovery | 1 | - | - | - | - | 1 | - |
| Purchases\tof\treserves\tin\tplace | 109 | - | - | - | - | 109 | - |
| Extensions,\tdiscoveries\tand\tother\tadditions | 45 | 48 | - | 1 | 16 | 110 | - |
| Production^(c) | (47) | (14) | (40) | (2) | (42) | (145) | - |
| End\tof\tyear\t–\t2011 | 424 | 623 | \t 379 | 257 | 117 | 1,800 | - |
| Proved\tdeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2009 | 277 | - | \t 312 | 211 | 96 | 896 | 10 |
| End\tof\tyear\t–\t2009 | 229 | 392 | \t 267 | 204 | 95 | 1,187 | - |
| End\tof\tyear\t–\t2010 | 222 | 433 | \t 284 | 198 | 96 | 1,233 | - |
| End\tof\tyear\t–\t2011 | 233 | 623 | \t 262 | 196 | 91 | 1,405 | - |
| Proved\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2009 | 82 | - | \t 138 | 18 | 35 | 273 | 16 |
| End\tof\tyear\t–\t2009 | 78 | 211 | \t 136 | 42 | 25 | 492 | - |
| End\tof\tyear\t–\t2010 | 75 | 139 | \t 110 | 59 | 22 | 405 | - |
| End\tof\tyear\t–\t2011 | 191 | - | \t 117 | 61 | 26 | 395 | - |

Synthetic	crude	oil	proved	reserves	were	added	as	of	December	31,	2009.

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

Excludes	the	resale	of	purchased	natural	gas	utilized	in	reservoir	management.

Volumes	for	Canada	are	after	10	million	barrels	of	synthetic	crude	oil	production	in	2009.

# Capitalized	Costs	and	Accumulated	Depreciation,	Depletion	and	Amortization

|  |  |  |  | December	31, |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | United |  |  | Other |  | Other |  |
| (In\tmillions) | States | \tCanada | EG | Africa | \tEurope | Int'l | \t Total |
| 2011\tCapitalized\tcosts: |  |  |  |  |  |  |  |
| Proved\tproperties | $15,288 | $9,209 | $1,545 | $1,678 | $8,342 | $33 | $36,095 |
| Unproved\tproperties | 4,344 | 1,473 | 23 | 303 | 51 | 179 | 6,373 |
| Total | 19,632 | 10,682 | \t 1,568 | 1,981 | 8,393 | 212 | \t 42,468 |
| \tAccumulated\tdepreciation,\tdepletion\tand\tamortization: |  |  |  |  |  |  |  |
| Proved\tproperties | 8,499 | 572 | 729 | 134 | 6,593 | 1 | \t 16,528 |
| Unproved\tproperties | 359 | - | - | 9 | - | 12 | 380 |
| Total | 8,858 | 572 | 729 | 143 | 6,593 | 13 | \t 16,908 |
| Net\tcapitalized\tcosts | $10,774 | $10,110 | $839 | $1,838 | $1,800 | $199 | $25,560 |
| 2010\tCapitalized\tcosts: |  |  |  |  |  |  |  |
| Proved\tproperties | $12,008 | $8,362 | $1,518 | $1,437 | $8,032 | $24 | $31,381 |
| Unproved\tproperties | 1,450 | 1,626 | 24 | 277 | 46 | 122 | 3,545 |
| Total | 13,458 | 9,988 | \t 1,542 | 1,714 | 8,078 | 146 | \t 34,926 |
| \tAccumulated\tdepreciation,\tdepletion\tand\tamortization: |  |  |  |  |  |  |  |
| Proved\tproperties | 7,049 | 381 | 625 | 122 | 5,927 | 1 | \t 14,105 |
| Unproved\tproperties | 325 | - | - | 9 | - | 8 | 342 |
| Total | 7,374 | 381 | 625 | 131 | 5,927 | 9 | \t 14,447 |
| Net\tcapitalized\tcosts | $6,084 | $9,607 | $917 | $1,583 | $2,151 | $137 | $20,479 |

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

|  |  | United |  |  | Other |  | Other | Continuing | Disc |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | (In\tmillions) | States | Canada | EG | Africa | Europe | Int'l | Operations | Ops | Total |
| 2011 | Property\tacquisition: |  |  |  |  |  |  |  |  |  |
| Proved | Proved | $1,782 | $5 | $1 | $- | $- | $- | $1,788 | $- | $1,788 |
| Unproved | Unproved | 3,271 | - | - | 1 | 7 | 57 | 3,336 | - | 3,336 |
| Exploration | Exploration | 782 | 42 | - | 33 | 109 | 168 | 1,134 | - | 1,134 |
| Development | Development | 889 | 293 | 18 | 294 | 388 | - | 1,882 | - | 1,882 |
| Total | Total | $6,724 | $340 | $19 | $328 | $504 | $\t\t\t\t225 | $8,140 | $- | $8,140 |
| 2010 | Property\tacquisition: |  |  |  |  |  |  |  |  |  |
| Proved | Proved | $1 | $- | $- | $- | $- | $- | $1 | $- | $1 |
| Unproved | Unproved | 400 | - | - | 1 | 2 | 103 | 506 | - | 506 |
| Exploration | Exploration | 520 | 10 | 1 | 41 | 43 | 153 | 768 | - | 768 |
| Development | Development | 855 | 889 | 13 | 315 | 465 | - | 2,537 | - | 2,537 |
| Total | Total | $1,776 | $\t\t\t\t899 | $14 | $357 | $510 | $256 | $3,812 | $- | $3,812 |
| 2009 | Property\tacquisition: |  |  |  |  |  |  |  |  |  |
| Proved | Proved | $- | $11 | $- | $- | $- | $- | $11 | $\t\t\t\t\t\t15 | $26 |
| Unproved | Unproved | 127 | 1 | - | 6 | - | 2 | 136 | - | 136 |
| Exploration | Exploration | 271 | 11 | - | 127 | 81 | 29 | 519 | - | 519 |
| Development | Development | 1,150 | 976 | 23 | 266 | 354 | - | 2,769 | 64 | 2,833 |
| Total | Total | $\t\t1,548 | $999 | $\t\t\t\t23 | $\t\t399 | $\t\t\t\t435 | $31 | $3,435 | $79 | $\t\t\t\t3,514 |

Includes	costs	incurred	whether	capitalized	or	expensed.

# Results	of	Operations	for	Oil	and	Gas	Producing	Activities

|  |  |  | United |  |  | Other |  | Other |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | (In\tmillions) |  | States | Canada | EG | Africa | Europe | Int'l | Total |
| 2011 | Revenues\tand\tother\tincome: | Revenues\tand\tother\tincome: |  |  |  |  |  |  |  |
| Sales | Sales | Sales | $ \t\t3,063 | $\t\t\t\t1,388 | $29 | $\t\t216 | $1,010 | $- | $5,706 |
| Transfers | Transfers | Transfers | 63 | - | \t\t905 | - | \t\t3,560 | - | 4,528 |
|  | Other\tincome^(a) | Other\tincome^(a) | 41 | - | - | - | 15 | - | 56 |
| Total\trevenues\tand\tother\tincome | Total\trevenues\tand\tother\tincome | Total\trevenues\tand\tother\tincome | 3,167 | 1,388 | 934 | 216 | 4,585 | - | \t 10,290 |
| Expenses: | Expenses: |  |  |  |  |  |  |  |  |
| Production\tcosts | Production\tcosts | Production\tcosts | (954) | (814)^(b) | (117) | (33) | (350) | - | (2,268) |
|  | Exploration\texpenses | Exploration\texpenses | (378) | (10) | (1) | (10) | (81) | (164) | (644) |
| Depreciation,\tdepletion\tand\tamortization^(c) | Depreciation,\tdepletion\tand\tamortization^(c) | Depreciation,\tdepletion\tand\tamortization^(c) | (1,471) | (196) | (104) | (11) | (685) | - | (2,467) |
|  | Administrative\texpenses | Administrative\texpenses | (67) | (10) | (2) | (1) | (19) | (15) | (114) |
| Total\texpenses | Total\texpenses | Total\texpenses | (2,870) | (1,030) | (224) | (55) | (1,135) | (179) | (5,493) |
| Results\tbefore\tincome\ttaxes | Results\tbefore\tincome\ttaxes |  | 297 | 358 | 710 | 161 | 3,450 | (179) | 4,797 |
| Income\ttax\t(provision)\tbenefit | Income\ttax\t(provision)\tbenefit | Income\ttax\t(provision)\tbenefit | (104) | (90) | (254) | (168) | (2,203) | 63 | (2,756) |
| Results\tof\tcontinuing\toperations | Results\tof\tcontinuing\toperations |  | $193 | $268 | $456 | $(7) | $1,247 | $(116) | $2,041 |
| 2010 | Revenues\tand\tother\tincome: |  |  |  |  |  |  |  |  |
| Sales | Sales | Sales | $2,429 | $692 | $11 | $1,473 | $697 | $- | $5,302 |
|  | Transfers | Transfers | 93 | - | 701 | - | 2,319 | - | 3,113 |
| Other\tincome^(a) | Other\tincome^(a) | Other\tincome^(a) | 17 | - | - | 812 | (64) | - | 765 |
| Total\trevenues\tand\tother\tincome | Total\trevenues\tand\tother\tincome | Total\trevenues\tand\tother\tincome | 2,539 | 692 | 712 | 2,285 | 2,952 | - | 9,180 |
| Expenses: | Expenses: |  |  |  |  |  |  |  |  |
| Production\tcosts | Production\tcosts | Production\tcosts | (815) | (596) | (108) | (70) | (297) | - | (1,886) |
| Exploration\texpenses | Exploration\texpenses | Exploration\texpenses | (275) | (5) | (21) | (47) | (32) | (118) | (498) |
|  | Depreciation,\tdepletion\tand\tamortization^(c) | Depreciation,\tdepletion\tand\tamortization^(c) | (1,463) | (109) | (110) | (36) | (687) | - | (2,405) |
| Administrative\texpenses | Administrative\texpenses | Administrative\texpenses | (52) | (9) | (1) | 2 | (20) | (10) | (90) |
| Total\texpenses | Total\texpenses | Total\texpenses | (2,605) | (719) | (240) | (151) | (1,036) | (128) | (4,879) |
| Results\tbefore\tincome\ttaxes | Results\tbefore\tincome\ttaxes | Results\tbefore\tincome\ttaxes | (66) | (27) | 472 | 2,134 | 1,916 | (128) | 4,301 |
| Income\ttax\t(provision)\tbenefit | Income\ttax\t(provision)\tbenefit |  | 26 | 7 | (187) | (1,647) | (658) | \t\t\t\t46 | (2,413) |
| Results\tof\tcontinuing\toperations | Results\tof\tcontinuing\toperations | Results\tof\tcontinuing\toperations | $(40) | $(20) | $285 | $487 | $1,258 | $(82) | $1,888 |
| 2009 | Revenues\tand\tother\tincome: |  |  |  |  |  |  |  |  |
| Sales | Sales | (d) | $1,839 | $599 | $23 | $1,146 | $699 | $- | $4,306 |
|  | Transfers | Transfers | 24 | - | 587 | - | 1,678 | - | 2,289 |
|  | (a)\nOther\tincome | (a)\nOther\tincome | 185 | - | - | - | 13 | - | 198 |
| Total\trevenues\tand\tother\tincome | Total\trevenues\tand\tother\tincome | Total\trevenues\tand\tother\tincome | 2,048 | 599 | 610 | \t\t1,146 | 2,390 | - | 6,793 |
| Expenses: | Expenses: |  |  |  |  |  |  |  |  |
| Production\tcosts | Production\tcosts | Production\tcosts | (763) | (371) | (108) | (62) | (289) | - | (1,593) |
| Exploration\texpenses | Exploration\texpenses | Exploration\texpenses | (153) | (16) | - | (73) | (37) | (28) | (307) |
|  | (c)\nDepreciation,\tdepletion\tand\tamortization | (c)\nDepreciation,\tdepletion\tand\tamortization | (846) | (126) | (115) | (37) | (736) | - | (1,860) |
| Administrative\texpenses | Administrative\texpenses | Administrative\texpenses | (53) | (9) | (1) | (3) | (13) | (22) | (101) |
| Total\texpenses | Total\texpenses | Total\texpenses | (1,815) | (522) | (224) | (175) | (1,075) | (50) | (3,861) |
| Results\tbefore\tincome\ttaxes | Results\tbefore\tincome\ttaxes | Results\tbefore\tincome\ttaxes | 233 | 77 | 386 | 971 | 1,315 | (50) | 2,932 |
| Income\ttax\t(provision)\tbenefit | Income\ttax\t(provision)\tbenefit |  | (76) | (17) | (112) | (770) | (678) | 14 | (1,639) |
| Results\tof\tcontinuing\toperations | Results\tof\tcontinuing\toperations | Results\tof\tcontinuing\toperations | $157 | $60 | $274 | $201 | $637 | $(36) | $\t\t1,293 |
| Results\tof\tdiscontinued\toperations | Results\tof\tdiscontinued\toperations |  | $- | $- | $- | $194 | $79 | $- | $273 |
| (a) | Includes\tnet\tgain\ton\tdisposal\tof\tassets. |  |  |  |  |  |  |  |  |

Includes	net	gain	on	disposal	of	assets. (a)

2011	Canada	production	costs	include	$64	million	for	the	OSM	water	abatement. (b)

Includes	long-lived	asset	impairments. (c)

Excludes	noncash	effects	of	changes	in	the	fair	value	of	certain	natural	gas	sales	contracts	in	the	United	Kingdom	which	expired	September	2009. (d)

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

| (In	millions) | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| Results\tof\tcontinuing\toperations | $2,041 | $1,888 | $1,293 |
| Items\tnot\tincluded\tin\tresults\tof\tcontinuing\toil\tand\tgas\toperations,\tnet\tof\ttax: |  |  |  |
| Marketing\tincome\tand\ttechnology\tcosts | (53) | (11) | (24) |
| Income\tfrom\tequity\tmethod\tinvestments | 213 | 167 | 110 |
| Other\tthird-party\tincome^(a) | 10 | (5) | 9 |
| Other | (1) | (2) | (4) |
| Items\tnot\tallocated\tto\tsegment\tincome,\tnet\tof\ttax: |  |  |  |
| Gain\ton\tasset\tdisposition | (23) | (449) | (122) |
| Long-lived\tasset\timpairments | 178 | 303 | - |
| Water\tabatement-OSM | 48 | - | - |
| Segment\tincome\tnot\tincluded\tin\tresults\tof\tcontinuing\toil\tand\tgas\toperations: |  |  |  |
| Integrated\tGas | 178 | 142 | 90 |
| Segment\tincome | $2,591 | $2,033 | $1,352 |

Includes	revenues,	net	of	associated	costs	and	income	taxes,	from	activities	that	support	our	production	operations,	which	may	include	processing	or	transportation	of	third-party	production	and	the	purchase	and subsequent	resale	of	natural	gas	utilized	for	reservoir	management. (a)

# Standardized	Measure	of	Discounted	Future	Net	Cash	Flows

|  |  |  | December	31, |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | United\nStates | Canada | EG | Other\nAfrica | Europe | Total |
| 2011 |  |  |  |  |  |  |
| Future\tcash\tinflows | $ 28,108 | $ 59,365 | $ 7,318 | $ 30,007 | $12,120 | $136,918 |
| Future\tproduction\tand\tadministrative\tcosts | (10,751) | (28,048) | (1,931) | (1,269) | (2,752) | (44,751) |
| Future\tdevelopment\tcosts | (6,341) | (10,346) | (435) | (874) | (1,702) | (19,698) |
| Future\tincome\ttax\texpenses | (2,740) | (4,490) | (1,368) | (25,821) | (5,147) | (39,566) |
| Future\tnet\tcash\tflows | $8,276 | $ 16,481 | $ 3,584 | $2,043 | $2,519 | $32,903 |
| 10\tpercent\tannual\tdiscount\tfor\testimated\ttiming\tof\tcash\tflows | (4,539) | (11,845) | (1,330) | (733) | (528) | (18,975) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tproved\toil\tand\tgas\treserves | $3,737 | $4,636 | $ 2,254 | $1,310 | $1,991 | $13,928 |
| 2010 |  |  |  |  |  |  |
| Future\tcash\tinflows | $ 15,349 | $ 41,901 | $ 5,366 | $ 20,815 | $8,800 | $92,231 |
| Future\tproduction\tand\tadministrative\tcosts | (6,878) | (21,675) | (1,469) | (996) | (2,275) | (33,293) |
| Future\tdevelopment\tcosts | (2,084) | (9,688) | (441) | (907) | (1,535) | (14,655) |
| Future\tincome\ttax\texpenses | (1,726) | (1,821) | (1,208) | (17,201) | (2,956) | (24,912) |
| Future\tnet\tcash\tflows | $4,661 | $8,717 | $ 2,248 | $1,711 | $2,034 | $19,371 |
| 10\tpercent\tannual\tdiscount\tfor\testimated\ttiming\tof\tcash\tflows | (2,008) | (6,168) | (795) | (825) | (295) | (10,091) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tproved\toil\tand\tgas\treserves | $2,653 | $2,549 | $ 1,453 | $886 | $1,739 | $9,280 |
| 2009 |  |  |  |  |  |  |
| Future\tcash\tinflows | $ 12,094 | $ 32,207 | $ 4,620 | $ 14,974 | $6,901 | $70,796 |
| Future\tproduction\tand\tadministrative\tcosts | (6,796) | (21,044) | (1,514) | (876) | (2,373) | (32,603) |
| Future\tdevelopment\tcosts | (1,362) | (6,715) | (462) | (677) | (1,752) | (10,968) |
| Future\tincome\ttax\texpenses | (923) | (60) | (935) | (12,419) | (1,253) | (15,590) |
| Future\tnet\tcash\tflows | $3,013 | $4,388 | $ 1,709 | $1,002 | $1,523 | $11,635 |
| 10\tpercent\tannual\tdiscount\tfor\testimated\ttiming\tof\tcash\tflows | (1,041) | (3,658) | (625) | (571) | (85) | (5,980) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tproved\toil\tand\tgas\treserves | $1,972 | $730 | $ 1,084 | $431 | $1,438 | $5,655 |

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

| (In	millions) | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| Sales\tand\ttransfers\tof\toil\tand\tgas\tproduced,\tnet\tof\tproduction\tand\tadministrative\tcosts | $(7,922) | $(6,330) | $(4,876) |
| Net\tchanges\tin\tprices\tand\tproduction\tand\tadministrative\tcosts\trelated\tto\tfuture\tproduction | \t 12,313 | 9,843 | 4,840 |
| Extensions,\tdiscoveries\tand\timproved\trecovery,\tless\trelated\tcosts | 1,454 | 1,268 | 1,399 |
| Development\tcosts\tincurred\tduring\tthe\tperiod | 1,899 | 2,546 | 2,786 |
| Changes\tin\testimated\tfuture\tdevelopment\tcosts | (1,349) | (2,153) | (3,773) |
| Revisions\tof\tprevious\tquantity\testimates | 2,526 | 1,117 | 5,110 |
| Net\tchanges\tin\tpurchases\tand\tsales\tof\tminerals\tin\tplace | 233 | (20) | (159) |
| Accretion\tof\tdiscount | 2,040 | 1,335 | 787 |
| Net\tchange\tin\tincome\ttaxes | (6,676) | (4,231) | (4,345) |
| Timing\tand\tother | 130 | 250 | (149) |
| Net\tchange\tfor\tthe\tyear | 4,648 | 3,625 | 1,620 |
| Beginning\tof\tthe\tyear | 9,280 | 5,655 | 4,035 |
| End\tof\tyear | $13,928 | $9,280 | $5,655 |

# Supplemental	Statistics	(Unaudited)

| (In	millions) | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| Segment\tIncome\t(Loss) |  |  |  |
| Exploration\tand\tProduction |  |  |  |
| United\tStates | $366 | $251 | $52 |
| International | 1,791 | 1,690 | 1,166 |
| E&amp;P\tsegment | 2,157 | 1,941 | 1,218 |
| Oil\tSands\tMining | 256 | (50) | 44 |
| Integrated\tGas | 178 | 142 | 90 |
| Segment\tincome | 2,591 | 2,033 | 1,352 |
| Items\tnot\tallocated\tto\tsegments,\tnet\tof\tincome\ttaxes | (884) | (151) | (636) |
| Income\tfrom\tcontinuing\toperations | 1,707 | 1,882 | 716 |
| Discontinued\toperations^(a) | 1,239 | 686 | 747 |
| Net\tincome | $2,946 | $2,568 | $1,463 |
| Capital\tExpenditures^(b) |  |  |  |
| Exploration\tand\tProduction |  |  |  |
| United\tStates | $2,145 | $1,528 | $1,420 |
| International | 893 | 946 | 742 |
| E&amp;P\tsegment | 3,038 | 2,474 | 2,162 |
| Oil\tSands\tMining | 308 | 874 | 1,115 |
| Integrated\tGas | 2 | 2 | 2 |
| Corporate | 51 | 46 | 42 |
| Total | $3,399 | $3,396 | $3,321 |
| Exploration\tExpenses |  |  |  |
| United\tStates | $379 | $275 | $153 |
| International | 265 | 223 | 154 |
| Total | $644 | $498 | $307 |

The	spin-off	of	our	downstream	business	was	completed	on	June	30,	2011	and	all	periods	have	been	recast	to	reflect	the	downstream	business	as	discontinued	operations.	In	addition,	our	businesses	in	Ireland	and Gabon	were	sold	in	2009	and	are	reflected	as	discontinued	operations	in	2009.

Capital	expenditures	include	changes	in	accruals. (b)

|  | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| E&amp;P\tOperating\tStatistics |  |  |  |
| Net\tLiquid\tHydrocarbon\tSales\t(mbbld) |  |  |  |
| United\tStates | 75 | 70 | 64 |
| Europe | 101 | 92 | 92 |
| Africa | 43 | 83 | 87 |
| Total\tInternational | 144 | 175 | 179 |
| Worldwide\tcontinuing\toperations | 219 | 245 | 243 |
| Discontinued\toperations | - | - | 5 |
| Worldwide | 219 | 245 | 248 |
| Natural\tgas\tliquids\tincluded\tin\tabove | 17 | 16 | 19 |
| Natural\tGas\tSales\t(mmcfd)^(c) |  |  |  |
| United\tStates | 326 | 364 | 373 |
| Europe | 97 | 105 | 138 |
| Africa | 443 | 409 | 430 |
| Total\tInternational | 540 | 514 | 568 |
| Worldwide\tcontinuing\toperations | 866 | 878 | 941 |
| Discontinued\toperations | - | - | 17 |
| Worldwide | 866 | 878 | 958 |
| Total\tWorldwide\tSales\t(mboed) |  |  |  |
| Continuing\toperations | 363 | 391 | 400 |
| Discontinued\toperations | - | - | 7 |
| Worldwide | 363 | 391 | 407 |
| Average\tRealizations^(d) |  |  |  |
| Liquid\tHydrocarbons\t(per\tbbl) |  |  |  |
| United\tStates | $92.55 | $72.30 | $54.67 |
| Europe | 115.55 | 81.95 | 64.46 |
| Africa | 73.21 | 71.71 | 53.91 |
| Total\tInternational | 102.96 | 77.11 | 59.31 |
| Worldwide\tcontinuing\toperations | 99.37 | 75.73 | 58.09 |
| Discontinued\toperations | - | - | 56.47 |
| Worldwide | $99.37 | $75.73 | $58.06 |
| Natural\tGas\t(per\tmcf) |  |  |  |
| United\tStates | $4.95 | $4.71 | $4.14 |
| Europe | 9.84 | 7.10 | 4.90 |
| Africa^(e) | 0.24 | 0.25 | 0.25 |
| Total\tInternational | 1.97 | 1.65 | 1.38 |
| Worldwide\tcontinuing\toperations | 3.09 | 2.91 | 2.47 |
| Discontinued\toperations | - | - | 8.54 |
| Worldwide | $3.09 | $2.91 | $2.58 |
| (c) |  |  |  |

Includes	natural	gas	acquired	for	injection	and	subsequent	resale	of	16	mmcfd,	18	mmcfd	and	22	mmcfd	for	the	years	2011,	2010	and	2009. (c)

Excludes	gains	and	losses	on	derivative	instruments.

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	income	in	our	E&P	segment	and we	include	our	share	of	AMPCO's	and	EGHoldings'	income	in	our	Integrated	Gas	segment. (e)

| (In	millions,	except	as	noted) | 2011 | 2010 | 2009 |
| :--- | :--- | :--- | :--- |
| OSM\tOperating\tStatistics |  |  |  |
| Net\tSynthetic\tCrude\tOil\tSales\t(mbbld)^(f) | 43 | 29 | 32 |
| Synthetic\tCrude\tAverage\tOil\tRealizations\t(per\tbbl)^(d) | $91.65 | $71.06 | $56.44 |
| IG\tOperating\tStatistics |  |  |  |
| Net\tSales\t(mtd) |  |  |  |
| LNG^(g) | 7,086 | 6,859 | 6,642 |
| Methanol | 1,282 | 1,049 | 1,192 |
| Proved\tReserves |  |  |  |
| Net\tProved\tReserves\tat\tyear-end\t(developed\tand\tundeveloped) |  |  |  |
| Liquid\tHydrocarbons\t(mmbbl) |  |  |  |
| United\tStates | 279 | 173 | 170 |
| International | 454 | 457 | 452 |
| Worldwide | 733 | 630 | 622 |
| Natural\tGas\t(bcf) |  |  |  |
| United\tStates | 872 | 745 | 820 |
| International | 1,794 | 1,872 | 1,904 |
| Worldwide | 2,666 | 2,617 | 2,724 |
| Synthetic\tCrude\tOil\t(mmbbl) |  |  |  |
| Canada | 623 | 572 | 603 |
| Total\tProved\tReserves\t(mmboe) | 1,800 | 1,638 | 1,679 |
| (f)\nIncludes\tblendstocks. |  |  |  |

Includes	blendstocks. (f)

Includes	both	consolidated	sales	volumes	and	our	share	of	the	sales	volumes	of	equity	method	investees.	LNG	sales	from	Alaska,	conducted	through	a	consolidated	subsidiary,	ceased	when	these	operations	were sold	in	the	third	quarter	of	2011.	LNG	and	methanol	sales	from	Equatorial	Guinea	are	conducted	through	equity	method	investees. (g)

# 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	13(a)-15(e)	and	15(d)-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.

# 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.	During	the	fourth	quarter	of	2011,	there	were	no	changes	in	our	internal	control	over	financial	reporting	that	have	materially affected,	or	were	reasonably	likely	to	materially	affect,	our	internal	control	over	financial	reporting.

# Item	9B.	Other	Information

# PART	III

# Item	10.	Directors,	Executive	Officers	and	Corporate	Governance

Information	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	2012	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	2012	Annual	Meeting	of	Stockholders.

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

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	Securities and	Exchange	Commission.	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,	2011.

# 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	2012	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	2012	Annual	Meeting	of	stockholders.

# Securities	Authorized	for	Issuance	Under	Equity	Compensation	Plans

The	following	table	provides	information	as	of	December	31,	2011	with	respect	to	shares	of	Marathon	Oil	common	stock	that	may	be	issued	under	our	existing equity	compensation	plans:

•2003	Incentive	Compensation	Plan	(the	"2003	Plan")	–	No	additional	awards	will	be	granted	under	this	plan.

•1990	Stock	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 securities	to be	issued upon exercise	of outstanding options, warrants and	rights Weighted- average exercise price	of outstanding options, warrants and	rights^(c) Number	of securities remaining available	for future issuance under	equity compensation plans Equity	compensation	plans	approved	by	stockholders 	20,776,749	^(a) $24.41 11,994,866	^(d) Equity	compensation	plans	not	approved	by	stockholders 20,984	^(b) N/A — Total 	20,797,733 N/A 11,994,866

Includes	the	following:

•2,835,382	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,	2011	of	$29.27	per	share;

•54,578	stock	options	and	SARs	outstanding	under	the	1990	Stock	Plan;

•238,083	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	2007	Plan	and	the	2003	Plan;	common	stock	units	credited	under	the	2007	Plan	and	the	2003	Plan	were	186,822	and	51,261;

•846,163	restricted	stock	units	granted	to	non-officers	under	the	2007	Plan	and	outstanding	as	of	December	31,	2011.

In	addition	to	the	awards	reported	above	2,863,487	shares	of	restricted	stock	were	issued	and	outstanding	as	of	December	31,	2011,	but	subject	to	forfeiture	restrictions	under	the	2007	Plan.

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. (b)

Weighted-average	exercise	prices	do	not	take	the	restricted	stock	units	or	common	stock	units	into	account	as	these	awards	have	no	exercise	price. (c)

Reflects	the	shares	available	for	issuance	under	the	2007	Plan.	No	more	than	7,765,713	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,	cancelled	or	expire	unexercised	shall	again	immediately	become	available	for	issuance. (d)

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 2012	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	2012	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:

Any	reference	made	to	USX	Corporation	in	the	exhibit	listing	that	follows	is	a	reference	to	the	former	name	of	Marathon	Oil	Corporation,	a	Delaware corporation	and	the	registrant,	and	is	made	because	the	exhibit	being	listed	and	incorporated	by	reference	was	originally	filed	before	July	2001,	the	date	of	the change	 in	 the	registrant's	name.	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 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Number | Exhibit\tDescription | Exhibit\tDescription | Exhibit\tDescription | Exhibit\tDescription | Exhibit\tDescription | Form | Exhibit | Filing\tDate |
| 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 | 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\t and\t Distribution\t dated\t May | Separation\t and\t Distribution\t dated\t May | Separation\t and\t Distribution\t dated\t May | Separation\t and\t Distribution\t dated\t May | 25,\n2011\t among | 8-K | 2.1 | 5/26/2011 |
|  | Marathon\t Oil\t Corporation,\t Marathon\t Oil\t Company\t and | Marathon\t Oil\t Corporation,\t Marathon\t Oil\t Company\t and | Marathon\t Oil\t Corporation,\t Marathon\t Oil\t Company\t and | Marathon\t Oil\t Corporation,\t Marathon\t Oil\t Company\t and | Marathon\t Oil\t Corporation,\t Marathon\t Oil\t Company\t and |  |  |  |
|  | Marathon\tPetroleum\tCorporation | Marathon\tPetroleum\tCorporation | Marathon\tPetroleum\tCorporation | Marathon\tPetroleum\tCorporation |  |  |  |  |
| 2.2++ | Purchase\t and\t Sale\tAgreement\t between\t Hilcorp\t Resources | Purchase\t and\t Sale\tAgreement\t between\t Hilcorp\t Resources | Purchase\t and\t Sale\tAgreement\t between\t Hilcorp\t Resources | Purchase\t and\t Sale\tAgreement\t between\t Hilcorp\t Resources | Purchase\t and\t Sale\tAgreement\t between\t Hilcorp\t Resources | 10-Q/A | 2.2 | \t10/18/2011 |
|  | Holding,\tLP\tand\tMarathon\tOil\tCompany\tdated\tMay\t31,\t2011 | Holding,\tLP\tand\tMarathon\tOil\tCompany\tdated\tMay\t31,\t2011 | Holding,\tLP\tand\tMarathon\tOil\tCompany\tdated\tMay\t31,\t2011 | Holding,\tLP\tand\tMarathon\tOil\tCompany\tdated\tMay\t31,\t2011 | Holding,\tLP\tand\tMarathon\tOil\tCompany\tdated\tMay\t31,\t2011 |  |  |  |
| 3 | Articles\tof\tIncorporation\tand\tBylaws | Articles\tof\tIncorporation\tand\tBylaws | Articles\tof\tIncorporation\tand\tBylaws | Articles\tof\tIncorporation\tand\tBylaws |  |  |  |  |
| 3.1 | Restated | Certificate | of | Incorporation | of\t Marathon\nOil | 8-K | 3.1 | 4/25/2007 |
|  | Corporation |  |  |  |  |  |  |  |
| 3.2 | By-Laws\tof\tMarathon\tOil\tCorporation | By-Laws\tof\tMarathon\tOil\tCorporation | By-Laws\tof\tMarathon\tOil\tCorporation | By-Laws\tof\tMarathon\tOil\tCorporation |  | 10-Q/A | 3.1 | 5/13/2011 |
| 3.3 | Specimen\tof\tCommon\tStock\tCertificate | Specimen\tof\tCommon\tStock\tCertificate | Specimen\tof\tCommon\tStock\tCertificate | Specimen\tof\tCommon\tStock\tCertificate |  | 8-K | 3.3 | 5/14/2007 |
| 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 | 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 | Five\t Year\t Credit\t Agreement\t dated\t as\t of\t May\t 20,\t 2004 | Five\t Year\t Credit\t Agreement\t dated\t as\t of\t May\t 20,\t 2004 | Five\t Year\t Credit\t Agreement\t dated\t as\t of\t May\t 20,\t 2004 | Five\t Year\t Credit\t Agreement\t dated\t as\t of\t May\t 20,\t 2004 | Five\t Year\t Credit\t Agreement\t dated\t as\t of\t May\t 20,\t 2004 | 10-K | 4.1 | 2/26/2010 |
|  | among\tMarathon\tOil\tCorporation,\tthe\tCo-Agents\tand\tother | among\tMarathon\tOil\tCorporation,\tthe\tCo-Agents\tand\tother | among\tMarathon\tOil\tCorporation,\tthe\tCo-Agents\tand\tother | among\tMarathon\tOil\tCorporation,\tthe\tCo-Agents\tand\tother | among\tMarathon\tOil\tCorporation,\tthe\tCo-Agents\tand\tother |  |  |  |
|  | Lenders\t party\t thereto,\t Bank\t of\t America,\t N.A.,\t as | Lenders\t party\t thereto,\t Bank\t of\t America,\t N.A.,\t as | Lenders\t party\t thereto,\t Bank\t of\t America,\t N.A.,\t as | Lenders\t party\t thereto,\t Bank\t of\t America,\t N.A.,\t as | Lenders\t party\t thereto,\t Bank\t of\t America,\t N.A.,\t as |  |  |  |
|  | Syndication\tAgent,\tABN\tAmbro\tBank\tN.V.,\tCitibank,\tN.A. | Syndication\tAgent,\tABN\tAmbro\tBank\tN.V.,\tCitibank,\tN.A. | Syndication\tAgent,\tABN\tAmbro\tBank\tN.V.,\tCitibank,\tN.A. | Syndication\tAgent,\tABN\tAmbro\tBank\tN.V.,\tCitibank,\tN.A. | Syndication\tAgent,\tABN\tAmbro\tBank\tN.V.,\tCitibank,\tN.A. |  |  |  |
|  | and\tMorgan\tStanley\tBank,\tas\tDocumentation\tAgent | and\tMorgan\tStanley\tBank,\tas\tDocumentation\tAgent | and\tMorgan\tStanley\tBank,\tas\tDocumentation\tAgent | and\tMorgan\tStanley\tBank,\tas\tDocumentation\tAgent |  |  |  |  |
| 4.2 |  |  |  |  |  | 10-Q | 4.1 | 5/8/2006 |
|  | Credit\tAgreement\tdated\tas\tof\tMay\t20,\t2004\tamong\tMarathon | Credit\tAgreement\tdated\tas\tof\tMay\t20,\t2004\tamong\tMarathon | Credit\tAgreement\tdated\tas\tof\tMay\t20,\t2004\tamong\tMarathon | Credit\tAgreement\tdated\tas\tof\tMay\t20,\t2004\tamong\tMarathon | Credit\tAgreement\tdated\tas\tof\tMay\t20,\t2004\tamong\tMarathon |  |  |  |
|  | Oil\t Corporation,\t the\t Co-Agents\t and\t other\t Lenders\t party | Oil\t Corporation,\t the\t Co-Agents\t and\t other\t Lenders\t party | Oil\t Corporation,\t the\t Co-Agents\t and\t other\t Lenders\t party | Oil\t Corporation,\t the\t Co-Agents\t and\t other\t Lenders\t party | Oil\t Corporation,\t the\t Co-Agents\t and\t other\t Lenders\t party |  |  |  |
|  | thereto,\t Bank\t of\t America,\t N.A.,\t as\t Syndication\t Agent, | thereto,\t Bank\t of\t America,\t N.A.,\t as\t Syndication\t Agent, | thereto,\t Bank\t of\t America,\t N.A.,\t as\t Syndication\t Agent, | thereto,\t Bank\t of\t America,\t N.A.,\t as\t Syndication\t Agent, | thereto,\t Bank\t of\t America,\t N.A.,\t as\t Syndication\t Agent, |  |  |  |
|  | Citibank,\tN.A.\tand\tMorgan\tStanley\tBank,\tas\tDocumentation | Citibank,\tN.A.\tand\tMorgan\tStanley\tBank,\tas\tDocumentation | Citibank,\tN.A.\tand\tMorgan\tStanley\tBank,\tas\tDocumentation | Citibank,\tN.A.\tand\tMorgan\tStanley\tBank,\tas\tDocumentation | Citibank,\tN.A.\tand\tMorgan\tStanley\tBank,\tas\tDocumentation |  |  |  |
|  | Agent |  |  |  |  |  |  |  |
| 4.3 |  |  |  |  |  | 10-Q | 4.1 | 8/7/2007 |

| Exhibit |  |  |  |  | Incorporated	by	Reference | Incorporated	by	Reference |  | Filed |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Number | Exhibit\tDescription | Exhibit\tDescription | Exhibit\tDescription | Form | Exhibit | Filing\tDate | SEC\tFile\tNo. | Herewith |
| 10.7 | Form\tof\tNon-Qualified\tStock\tOption\tAward\tAgreement\tfor | Form\tof\tNon-Qualified\tStock\tOption\tAward\tAgreement\tfor | Form\tof\tNon-Qualified\tStock\tOption\tAward\tAgreement\tfor | 10-K | 10.5 | \t 2/28/2011 |  |  |
|  | Officers\t granted\t under\t Marathon\t Oil\t Corporation's\t 2007 | Officers\t granted\t under\t Marathon\t Oil\t Corporation's\t 2007 | Officers\t granted\t under\t Marathon\t Oil\t Corporation's\t 2007 |  |  |  |  |  |
|  | Incentive\tCompensation\tPlan,\teffective\tFebruary\t24,\t2010 | Incentive\tCompensation\tPlan,\teffective\tFebruary\t24,\t2010 | Incentive\tCompensation\tPlan,\teffective\tFebruary\t24,\t2010 |  |  |  |  |  |
| 10.8 | Form\tof\tOfficer\tRestricted\tStock\tAward\tAgreement\tgranted | Form\tof\tOfficer\tRestricted\tStock\tAward\tAgreement\tgranted | Form\tof\tOfficer\tRestricted\tStock\tAward\tAgreement\tgranted |  |  |  |  | X |
|  | under\nMarathon\nOil | Corporation's | 2007\nIncentive |  |  |  |  |  |
|  | Compensation\tPlan,\teffective\tMay\t30,\t2007 | Compensation\tPlan,\teffective\tMay\t30,\t2007 | Compensation\tPlan,\teffective\tMay\t30,\t2007 |  |  |  |  |  |
| 10.9 | Form\tof\tOfficer\tRestricted\tStock\tAward\tAgreement\tgranted | Form\tof\tOfficer\tRestricted\tStock\tAward\tAgreement\tgranted | Form\tof\tOfficer\tRestricted\tStock\tAward\tAgreement\tgranted | 10-K | 10.7 | \t 2/28/2011 |  |  |
|  | under\nMarathon\nOil | Corporation's | 2007\nIncentive |  |  |  |  |  |
|  | Compensation\tPlan,\teffective\tFebruary\t24,\t2010 | Compensation\tPlan,\teffective\tFebruary\t24,\t2010 | Compensation\tPlan,\teffective\tFebruary\t24,\t2010 |  |  |  |  |  |
| 10.10 | Form\t of\t Performance\t Unit\t Award\t Agreement | Form\t of\t Performance\t Unit\t Award\t Agreement | (18\t month |  |  |  |  | X |
|  | Performance\tCycle)\tfor\tSection\t 16\t Officers\t granted\t under | Performance\tCycle)\tfor\tSection\t 16\t Officers\t granted\t under | Performance\tCycle)\tfor\tSection\t 16\t Officers\t granted\t under |  |  |  |  |  |
|  | Marathon\t Oil\t Corporation's\t 2007 | Marathon\t Oil\t Corporation's\t 2007 | Incentive\t Compensation |  |  |  |  |  |
|  | Plan,\teffective\tJuly\t27,\t2011 |  |  |  |  |  |  |  |
| 10.11 | Form\t of\t Performance\t Unit\t Award\t Agreement | Form\t of\t Performance\t Unit\t Award\t Agreement | (18\t month |  |  |  |  | X |
|  | Performance\tCycle)\tfor\tOfficers\tgranted\tunder\tMarathon\tOil | Performance\tCycle)\tfor\tOfficers\tgranted\tunder\tMarathon\tOil | Performance\tCycle)\tfor\tOfficers\tgranted\tunder\tMarathon\tOil |  |  |  |  |  |
|  | Corporation's\t2007\tIncentive\tCompensation\tPlan,\teffective | Corporation's\t2007\tIncentive\tCompensation\tPlan,\teffective | Corporation's\t2007\tIncentive\tCompensation\tPlan,\teffective |  |  |  |  |  |
|  | July\t27,\t2011 |  |  |  |  |  |  |  |
| 10.12 | Form\t of\t Performance\t Unit\t Award\t Agreement | Form\t of\t Performance\t Unit\t Award\t Agreement | (30\t month |  |  |  |  | X |
|  | Performance\tCycle)\tfor\tSection\t 16\t Officers\t granted\t under | Performance\tCycle)\tfor\tSection\t 16\t Officers\t granted\t under | Performance\tCycle)\tfor\tSection\t 16\t Officers\t granted\t under |  |  |  |  |  |
|  | Marathon\t Oil\t Corporation's\t 2007 | Marathon\t Oil\t Corporation's\t 2007 | Incentive\t Compensation |  |  |  |  |  |
|  | Plan,\teffective\tJuly\t27,\t2011 |  |  |  |  |  |  |  |
| 10.13 | Form\t of\t Performance\t Unit\t Award\t Agreement | Form\t of\t Performance\t Unit\t Award\t Agreement | (30\t month |  |  |  |  | X |
|  | Performance\tCycle)\tfor\tOfficers\tgranted\tunder\tMarathon\tOil | Performance\tCycle)\tfor\tOfficers\tgranted\tunder\tMarathon\tOil | Performance\tCycle)\tfor\tOfficers\tgranted\tunder\tMarathon\tOil |  |  |  |  |  |
|  | Corporation's\t2007\tIncentive\tCompensation\tPlan,\teffective | Corporation's\t2007\tIncentive\tCompensation\tPlan,\teffective | Corporation's\t2007\tIncentive\tCompensation\tPlan,\teffective |  |  |  |  |  |
|  | July\t27,\t2011 |  |  |  |  |  |  |  |
| 10.14 | Marathon\tOil\tCorporation\tPolicy\tfor\tRepayment\tof\tAnnual | Marathon\tOil\tCorporation\tPolicy\tfor\tRepayment\tof\tAnnual | Marathon\tOil\tCorporation\tPolicy\tfor\tRepayment\tof\tAnnual | 10-K | 10.10 | \t 2/28/2011 |  |  |
|  | Cash\tBonus\tAmounts |  |  |  |  |  |  |  |
| 10.15 | Marathon\t Oil\t Corporation | 2003 | Incentive\t Compensation | 10-K | 10.9 | \t 2/26/2010 |  |  |
|  | Plan,\tEffective\tJanuary\t1,\t2003 | Plan,\tEffective\tJanuary\t1,\t2003 |  |  |  |  |  |  |
| 10.16 | Marathon\tOil\tCorporation\t1990\tStock\tPlan\t(as\tAmended\tand | Marathon\tOil\tCorporation\t1990\tStock\tPlan\t(as\tAmended\tand | Marathon\tOil\tCorporation\t1990\tStock\tPlan\t(as\tAmended\tand | 10-Q | 10.1 | \t 11/7/2008 |  |  |
|  | Restated)\tEffective\tJanuary\t1,\t2002 | Restated)\tEffective\tJanuary\t1,\t2002 |  |  |  |  |  |  |
| 10.17 | First\tAmendment\tto\tMarathon\tOil\tCorporation\t1990\tStock | First\tAmendment\tto\tMarathon\tOil\tCorporation\t1990\tStock | First\tAmendment\tto\tMarathon\tOil\tCorporation\t1990\tStock | 10-Q | 10.2 | \t 11/7/2008 |  |  |
|  | Plan\t(as\tAmended\tand\tRestated)\tEffective\tJanuary\t1,\t2002 | Plan\t(as\tAmended\tand\tRestated)\tEffective\tJanuary\t1,\t2002 | Plan\t(as\tAmended\tand\tRestated)\tEffective\tJanuary\t1,\t2002 |  |  |  |  |  |
| 10.18 | Marathon\tOil\tCorporation\tDeferred\tCompensation\tPlan\tfor | Marathon\tOil\tCorporation\tDeferred\tCompensation\tPlan\tfor | Marathon\tOil\tCorporation\tDeferred\tCompensation\tPlan\tfor | 10-K | 10.14 | \t 2/27/2009 |  |  |

| Exhibit<br>Number | Exhibit	Description | Exhibit	Description | Exhibit	Description | Form | Exhibit | Incorporated	by	Reference<br>Filing	Date | SEC	File	No. |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 10.19 | Form\t of\t Non-Qualified\t Stock\t Option\t with\t Tandem\t Stock | Form\t of\t Non-Qualified\t Stock\t Option\t with\t Tandem\t Stock | Form\t of\t Non-Qualified\t Stock\t Option\t with\t Tandem\t Stock | 10-K | 10.14 | \t 2/26/2010 |  |
|  | Appreciation\t Right\t Award\t Agreement | for\t Chief\t Executive | for\t Chief\t Executive |  |  |  |  |
|  | Officer | granted\nunder\t Marathon\t Oil\nCorporation's | 2003 |  |  |  |  |
|  | Incentive\tCompensation\tPlan,\teffective\tJanuary\t1,\t2003 | Incentive\tCompensation\tPlan,\teffective\tJanuary\t1,\t2003 |  |  |  |  |  |
| 10.20 | Form\t of\t Non-Qualified\t Stock\t Option\t with\t Tandem\t Stock | Form\t of\t Non-Qualified\t Stock\t Option\t with\t Tandem\t Stock | Form\t of\t Non-Qualified\t Stock\t Option\t with\t Tandem\t Stock | 10-K | 10.15 | \t 2/26/2010 |  |
|  | Appreciation | Right\nAward\nAgreement\nfor | Executive |  |  |  |  |
|  | Committee | members\ngranted\nunder\nMarathon | Oil |  |  |  |  |
|  | Corporation's\t 2003 | Incentive\t Compensation\t Plan,\t effective | Incentive\t Compensation\t Plan,\t effective |  |  |  |  |
|  | January\t1,\t2003 | January\t1,\t2003 |  |  |  |  |  |
| 10.21 | Form\t of\t Non-Qualified\t Stock\t Option\t with\t Tandem\t Stock | Form\t of\t Non-Qualified\t Stock\t Option\t with\t Tandem\t Stock | Form\t of\t Non-Qualified\t Stock\t Option\t with\t Tandem\t Stock | 10-K | 10.16 | \t 2/26/2010 |  |
|  | Appreciation\t Right\t Award\t Agreement | for\t Officers\t granted | for\t Officers\t granted |  |  |  |  |
|  | under | Marathon\nOil\nCorporation's\n2003 | Incentive |  |  |  |  |
|  | Compensation\tPlan,\teffective\tJanuary\t1,\t2003 | Compensation\tPlan,\teffective\tJanuary\t1,\t2003 |  |  |  |  |  |
| 10.22 | Form | of\t Stock\t Appreciation\t Right\t Award\t Agreement | for | 10-K | 10.18 | \t 2/26/2010 |  |
|  | Chief | Executive\nOfficer\ngranted\nunder\nMarathon | Oil |  |  |  |  |
|  | Corporation's\t 2003 | Incentive\t Compensation\t Plan,\t effective | Incentive\t Compensation\t Plan,\t effective |  |  |  |  |
|  | January\t1,\t2003 | January\t1,\t2003 |  |  |  |  |  |
| 10.23 | Form | of\t Stock\t Appreciation\t Right\t Award\t Agreement | for | 10-K | 10.19 | \t 2/26/2010 |  |
|  | Executive\tCommittee\tmembers\tgranted\tunder\tMarathon\tOil | Executive\tCommittee\tmembers\tgranted\tunder\tMarathon\tOil | Executive\tCommittee\tmembers\tgranted\tunder\tMarathon\tOil |  |  |  |  |
|  | Corporation's\t 2003 | Incentive\t Compensation\t Plan,\t effective | Incentive\t Compensation\t Plan,\t effective |  |  |  |  |
|  | January\t1,\t2003 | January\t1,\t2003 |  |  |  |  |  |
| 10.24 | Form | of\t Stock\t Appreciation\t Right\t Award\t Agreement | for | 10-K | 10.2 | \t 2/26/2010 |  |
|  | Officers | granted\nunder\t Marathon\t Oil\t Corporation's | 2003 |  |  |  |  |
|  | Incentive\tCompensation\tPlan,\teffective\tJanuary\t1,\t2003 | Incentive\tCompensation\tPlan,\teffective\tJanuary\t1,\t2003 |  |  |  |  |  |
| 10.25 | Form | of\t Non-Qualified\nStock\t Option\t Award\t Agreement | of\t Non-Qualified\nStock\t Option\t Award\t Agreement | 10-K | 10.21 | \t 2/26/2010 |  |
|  | granted\t under\t Marathon\t Oil\t Corporation's | 2003 | Incentive |  |  |  |  |
|  | Compensation\tPlan | Compensation\tPlan |  |  |  |  |  |
| 10.26 | Form\tof\tOfficer\tRestricted\tStock\tAward\tAgreement\tgranted | Form\tof\tOfficer\tRestricted\tStock\tAward\tAgreement\tgranted | Form\tof\tOfficer\tRestricted\tStock\tAward\tAgreement\tgranted | 10-K | 10.22 | \t 2/26/2010 |  |
|  | under | Marathon\nOil\nCorporation's\n2003 | Incentive |  |  |  |  |
|  | Compensation\tPlan | Compensation\tPlan |  |  |  |  |  |
| 10.27 | Form\t of\t Performance\t Unit\t Award\t Agreement | Form\t of\t Performance\t Unit\t Award\t Agreement | (2005-2007 | 10-K | 10.23 | \t 2/26/2010 |  |
|  | Performance | Cycle)\ngranted\nunder\nMarathon | Oil |  |  |  |  |
|  | Corporation's\t2003\tIncentive\tCompensation\tPlan | Corporation's\t2003\tIncentive\tCompensation\tPlan |  |  |  |  |  |
| 10.28 | Form | of\t Non-Qualified\nStock\t Option\t Award\t Agreement | of\t Non-Qualified\nStock\t Option\t Award\t Agreement | 10-K | 10.24 | \t 2/26/2010 |  |

| Exhibit<br>Number | Exhibit	Description | Form | Exhibit | Incorporated	by	Reference<br>Filing	Date | SEC	File	No. | Filed<br>Herewith |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 10.29 | Form\tof\tPerformance\tUnit\tAward\tAgreement\t(2010-2012 | 10-K | 10.25 | \t 2/26/2010 |  |  |
|  | Performance\nCycle)\ngranted\nunder\nMarathon\nOil |  |  |  |  |  |
|  | Corporation's\t2007\tIncentive\tCompensation\tPlan |  |  |  |  |  |
| 10.30 | Form\t of\t Non-Qualified\t Stock\t Option\t Award\t Agreement | 10-K | 10.26 | \t 2/26/2010 |  |  |
|  | granted\tunder\tMarathon\tOil\tCorporation's\t2007\tIncentive |  |  |  |  |  |
|  | Compensation\tPlan |  |  |  |  |  |
| 10.31 | Marathon\tOil\tCompany\tExcess\tBenefit\tPlan\tAmended\tand |  |  |  |  | X |
|  | Restated |  |  |  |  |  |
| 10.32 | Marathon\t Oil\t Company\t Deferred\t Compensation\nPlan |  |  |  |  | X |
|  | Amended\tand\tRestated\tEffective\tJune\t30,\t2011 |  |  |  |  |  |
| 10.33 | Executive\tTax,\tEstate,\tand\tFinancial\tPlanning\tProgram | 10-K | 10.32 | \t 2/27/2009 |  |  |
| 10.34 | Executive\tChange\tin\tControl\tSeverance\tBenefits\tPlan | 10-K | 10.35 | \t 2/27/2009 |  |  |
| 12.1 | Computation\tof\tRatio\tof\tEarnings\tto\tFixed\tCharges |  |  |  |  | X |
| 14.1 | Code\tof\tEthics\tfor\tSenior\tFinancial\tOfficers | 10-K | 14.1 | \t 2/26/2010 |  |  |
| 21.1 | List\tof\tSignificant\tSubsidiaries |  |  |  |  | X |
| 23.1 | Consent\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm |  |  |  |  | X |
| 23.2 | Consent\tof\tGLJ\tPetroleum\tConsultants\tLTD.,\tindependent |  |  |  |  | X |
|  | petroleum\tengineers\tand\tgeologists |  |  |  |  |  |
| 23.3 | Consent\t of\t Ryder\t Scott\t Company,\nL.P.,\nindependent |  |  |  |  | X |
|  | petroleum\tengineers\tand\tgeologists |  |  |  |  |  |
| 23.4 | Consent\t of\t Netherland,\t Sewell\t &amp;\t Associates,\nInc., |  |  |  |  | X |
|  | independent\tpetroleum\tengineers\tand\tgeologists |  |  |  |  |  |
| 31.1 | Certification\t of\t Chairman,\t President\t and\t Chief\t Executive |  |  |  |  | X |
|  | Officer\tpursuant\t to\tRule\t13(a)-14\tand\t15(d)-14\tunder\t the |  |  |  |  |  |
|  | Securities\tExchange\tAct\tof\t1934 |  |  |  |  |  |
| 31.2 | Certification\t of\t Executive\t Vice\t President\t and\t Chief |  |  |  |  | X |
|  | Financial\t Officer\t pursuant\t to\t Rule\t 13(a)-14\t and\t 15(d)-14 |  |  |  |  |  |
|  | under\tthe\tSecurities\tExchange\tAct\tof\t1934 |  |  |  |  |  |
| 32.1 | Certification\t of\t Chairman,\t President\t and\t Chief\t Executive |  |  |  |  | X |
|  | Officer\tpursuant\tto\t18\tU.S.C.\tSection\t1350 |  |  |  |  |  |
| 32.2 | Certification\t of\t Executive\t Vice\t President\t and\nChief |  |  |  |  | X |
|  | Financial\tOfficer\tpursuant\tto\t18\tU.S.C.\tSection\t1350 |  |  |  |  |  |
| 99.1 | Report\t of\t GLJ\t Petroleum\t Consultants\t LTD.,\nindependent |  |  |  |  | X |
|  | petroleum\tengineers\tand\tgeologists\tfor\t2011 |  |  |  |  |  |
| 99.2 | Report\t of\t GLJ\t Petroleum\t Consultants\t LTD.,\nindependent | 10-K | 99.1 | \t 2/28/2011 |  |  |

# 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	29,	2012 		MARATHON	OIL	CORPORATION

																Vice	President,	Finance	and	Accounting,	Controller

Pursuant	to	the	requirements	of	the	Securities	Exchange	Act	of	1934,	this	report	has	been	signed	below	by	the	following	persons	on	February	29,	2012	on	behalf	of the	registrant	and	in	the	capacities	indicated.



Question: what were total development costs in millions for the three year period?
Calculation:    table_row = [1899, 2546, 2786] # row labeled development costs incurred during the period
 a = sum(table_row) 
Answer: 7231