# Table	of	Contents

# Index	to	Financial	Statements

# 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,	2008

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)

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	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,	2008:	$36,559	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.	However,	the	registrant	has	made	no	determination	that	such	individuals	are	"affiliates"	within	the	meaning	of	Rule	405 of	the	Securities	Act	of	1933.

There	were	707,524,845	shares	of	Marathon	Oil	Corporation	Common	Stock	outstanding	as	of	January	31,	2009.

# Documents	Incorporated	By	Reference:

Portions	of	the	registrant's	proxy	statement	relating	to	its	2009	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,"	"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	exerts	significant	influence	by	virtue	of	its	ownership	interest).

# 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	and	Section	21E	of	the	Securities	Exchange	Act	of	1934.	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,	gross	margins,	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,	sales,	throughput	or	shipments	of	liquid	hydrocarbons,	natural	gas,	bitumen	and	refined	products;	levels	of	worldwide prices	of	liquid	hydrocarbons,	natural	gas	and	refined	products;	levels	of	reserves	of	liquid	hydrocarbons,	natural	gas	and	bitumen;	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	originally	organized	in	2001	as	USX	HoldCo,	Inc.,	a	wholly-owned	subsidiary	of	the	former	USX	Corporation.	As	a	result	of	a reorganization	completed	in	July	2001,	USX	HoldCo,	Inc.	(1)	became	the	parent	entity	of	the	consolidated	enterprise	(the	former	USX	Corporation	was	merged	into	a subsidiary	of	USX	HoldCo,	Inc.)	and	(2)	changed	its	name	to	USX	Corporation.	In	connection	with	the	transaction	described	in	the	next	paragraph	(the	"USX Separation"),	USX	Corporation	changed	its	name	to	Marathon	Oil	Corporation.

Before	December	31,	2001,	Marathon	had	two	outstanding	classes	of	common	stock:	USX-Marathon	Group	common	stock,	which	was	intended	to	reflect	the performance	of	our	energy	business,	and	USX-U.S.	Steel	Group	common	stock	("Steel	Stock"),	which	was	intended	to	reflect	the	performance	of	our	steel	business.	On December	31,	2001,	we	disposed	of	our	steel	business	through	a	tax-free	distribution	of	the	common	stock	of	our	wholly-owned	subsidiary	United	States	Steel Corporation	("United	States	Steel")	to	holders	of	Steel	Stock	in	exchange	for	all	outstanding	shares	of	Steel	Stock	on	a	one-for-one	basis.

In	connection	with	the	USX	Separation,	our	certificate	of	incorporation	was	amended	on	December	31,	2001,	and	Marathon	has	had	only	one	class	of	common stock	authorized	since	that	date.

On	June	30,	2005,	we	acquired	the	38	percent	ownership	interest	in	Marathon	Ashland	Petroleum	LLC	("MAP")	previously	held	by	Ashland	Inc.	("Ashland").	In addition,	we	acquired	a	portion	of	Ashland's	Valvoline	Instant	Oil	Change	business,	its	maleic	anhydride	business,	its	interest	in	LOOP	LLC	which	owns	and	operates the	only	U.S.	deepwater	oil	port,	and	its	interest	in	LOCAP	LLC	which	owns	a	crude	oil	pipeline.	As	a	result	of	the	transactions,	MAP	is	wholly	owned	by	Marathon	and its	name	was	changed	to	Marathon	Petroleum	Company	LLC	("MPC")	effective	September	1,	2005.

On	October	18,	2007,	we	acquired	all	the	outstanding	shares	of	Western	Oil	Sands	Inc.	("Western").	Western's	primary	asset	was	a	20	percent	outside-operated interest	in	the	Athabasca	Oil	Sands	Project	("AOSP"),	an	oil	sands	mining	joint	venture	located	in	the	province	of	Alberta,	Canada.	The	acquisition	was	accounted	for under	the	purchase	method	of	accounting	and,	as	such,	our	results	of	operations	include	Western's	results	from	October	18,	2007.	Western's	oil	sands	mining	and bitumen	upgrading	operations	are	reported	as	a	separate	Oil	Sands	Mining	segment,	while	its	ownership	interests	in	leases	where	in-situ	recovery	techniques	are expected	to	be	utilized	are	included	in	the	Exploration	and	Production	segment.

# Segment	and	Geographic	Information

Our	operations	consist	of	four	reportable	operating	segments:	1)	Exploration	and	Production	("E&P")	–	explores	for,	produces	and	markets	liquid	hydrocarbons	and natural	gas	on	a	worldwide	basis;	2)	Oil	Sands	Mining	("OSM")	–	mines,	extracts	and	transports	bitumen	from	oil	sands	deposits	in	Alberta,	Canada,	and	upgrades	the bitumen	to	produce	and	market	synthetic	crude	oil	and	by-products;	3)	Refining,	Marketing	and	Transportation	("RM&T")	–	refines,	markets	and	transports	crude	oil and	petroleum	products,	primarily	in	the	Midwest,	upper	Great	Plains,	Gulf	Coast	and	southeastern	regions	of	the	United	States;	and	4)	Integrated	Gas	("IG")	–	markets and	transports	products	manufactured	from	natural	gas,	such	as	liquefied	natural	gas	("LNG")	and	methanol,	on	a	worldwide	basis,	and	is	developing	other	projects	to link	stranded	natural	gas	resources	with	key	demand	areas.	For	operating	segment	and	geographic	financial	information,	see	Note	10	to	the	consolidated	financial statements.

# Exploration	and	Production

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	conduct	exploration,	development	and	production	activities	in	ten	countries:	the	United	States,	Angola,	Canada,	Equatorial	Guinea,	Gabon,	Indonesia,	Ireland, Libya,	Norway	and	the	United	Kingdom.

Our	2008	worldwide	net	liquid	hydrocarbon	sales	averaged	211	thousand	barrels	per	day	("mbpd").	Our	2008	worldwide	net	natural	gas	sales,	including	natural	gas acquired	for	injection	and	subsequent	resale,	averaged	1,016	million	cubic	feet	per	day	("mmcfd").	In	total,	our	2008	worldwide	net	sales	averaged	381	thousand	barrels of	oil	equivalent	per	day	("mboepd").	For	purposes	of	determining	barrels	of	oil	equivalent	("boe"),	natural	gas	volumes	are	converted	to	approximate	liquid hydrocarbon	barrels	by	dividing	the	natural	gas	volumes	expressed	in	thousands	of	cubic	feet	("mcf")	by	six.	The	liquid	hydrocarbon	volume	is	added	to	the	barrel equivalent	of	natural	gas	volume	to	obtain	boe.

# Exploration

In	the	United	States	during	2008,	we	drilled	71	gross	(48	net)	exploratory	wells	of	which	60	gross	(42	net)	wells	encountered	commercial	quantities	of hydrocarbons.	Of	these	60	wells,	3	were	temporarily	suspended	or	in	the	process	of	being	completed	at	year	end.	Internationally,	we	drilled	12	gross	(3	net)	exploratory wells	of	which	11	gross	(3	net)	wells	encountered	commercial	quantities	of	hydrocarbons.	Of	these	11	wells,	5	gross	(1	net)	wells	were	temporarily	suspended	or	were	in the	process	of	being	completed	at	December	31,	2008.

United	States	–	The	Gulf	of	Mexico	continues	to	be	a	core	area.	At	the	end	of	2008,	we	had	interests	in	103	blocks	in	the	Gulf	of	Mexico,	including	97	in	the deepwater	area.	We	have	been	awarded	42	blocks	on	which	we	were	the	high	bidder	in	the	federal	Outer	Continental	Shelf	Lease	Sales	No.	205	and	206	conducted	by the	U.S.	Minerals	Management	Service	("MMS")	in	late	2007	and	early	2008.	Our	initial	net	investment	in	these	blocks	was	$343	million.	We	own	100	percent	of	fifteen of	the	blocks.	We	acquired	the	remaining	blocks	in	conjunction	with	partners.	Our	plans	call	for	initial	drilling	on	some	of	these	leases	in	2009	and	2010.

In	2008,	a	successful	appraisal	well	was	drilled	on	the	Stones	prospect	located	on	Walker	Ridge	Block	508	after	a	2005	discovery.	We	hold	a	25	percent	outside- operated	interest	in	the	Stones	prospect.	In	the	third	quarter	of	2008,	we	announced	a	Gulf	of	Mexico	deepwater	discovery	on	the	Gunflint	prospect	located	on Mississippi	Canyon	Block	948.	We	own	a	13	percent	outside-operated	interest	in	the	prospect.	In	the	first	quarter	of	2009,	we	participated	in	a	deepwater	discovery	on the	Shenandoah	prospect	located	on	Walker	Ridge	Block	52.	We	own	a	20	percent	outside-operated	interest	in	the	prospect.

In	2008,	we	successfully	completed	our	first	horizontal	well	in	the	Woodford	Shale	resource	play	in	the	Anadarko	Basin	of	Oklahoma.	We	are	currently participating	in	additional	horizontal	wells	in	the	area	where	we	hold	30,000	net	acres.

We	hold	acreage	in	two	additional	emerging	shale	resource	plays	in	the	U.S.	In	the	Appalachian	Basin	we	hold	65,000	net	acres	in	the	Marcellus	Shale	resource play	in	Pennsylvania	and	West	Virginia.	We	hold	25,000	net	acres,	primarily	in	Texas,	in	the	Haynesville	Shale	resource	play	located	in	north	Louisiana	and	east	Texas. Initial	drilling	on	some	of	these	leases	is	planned	for	2009.

Angola	–	Offshore	Angola,	we	hold	a	10	percent	outside-operated	interest	in	Block	31	and	a	30	percent	outside-operated	interest	in	Block	32.	Through	December 2008,	28	discoveries	on	these	blocks	have	been	announced,	including	the	Portia	and	Dione	discoveries	on	Angola	Block	31	in	2008.

Norway	–	We	hold	interests	in	over	510,000	gross	acres	offshore	Norway,	including	production	license	505	("PL	505")	that	was	awarded	in	January	2009.	In	2009, exploration	drilling	is	expected	to	commence	on	additional	prospects	with	the	potential	to	be	tied	back	to	the	Alvheim	complex.

Indonesia	–	We	are	the	operator	and	hold	a	70	percent	interest	in	the	Pasangkayu	Block	offshore	Indonesia.	The	1.2	million	acre	block	is	located	mostly	in	deep water,	predominantly	offshore	of	the	island	of	Sulawesi	in	the	Makassar	Strait,	directly	east	of	the	Kutei	Basin	production	region.	The	production	sharing	contract	with the	Indonesian	government	was	signed	in	2006	and	we	completed	3D	seismic	acquisition	in	May	2008.	We	expect	to	begin	exploratory	drilling	in	early	2010. Additionally,	in	October	2008,	we	were	granted	a	49	percent	interest	and	operatorship	in	the	Bone	Bay	Block	offshore	Indonesia.	The	Bone	Bay	Block	is	200	miles southeast	of	our	Pasangkayu	Block.	Current	exploration	plans	for	Bone	Bay	call	for	the	acquisition	of	seismic	data	starting	in	2010,	followed	by	drilling	in	2011.

We	are	the	operator	of	a	drilling	rig	consortium	that	has	secured	a	two-year	contract	for	a	deepwater	exploration	drilling	rig.	The	rig	will	be	used	for	deepwater exploration	activities	by	us	and	by	five	other	companies	in	Indonesia.	The	participants	have	the	right	to	extend	this	rig	commitment.

We	continue	to	participate	in	joint	study	agreements	in	Indonesia,	which	provide	a	right	of	first	refusal	in	future	bid	rounds.	We	completed	two	joint	study agreements	in	2008.

Equatorial	Guinea	–	During	2004,	we	announced	the	Deep	Luba	and	Gardenia	discoveries	on	the	Alba	Block,	in	which	we	hold	a	63	percent	operated	interest,	and the	Corona	well	on	Block	D,	where	we	are	the	operator	with	a	90	percent	interest.	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.

Libya	–	We	hold	a	16	percent	outside-operated	interest	in	the	Waha	concessions,	which	encompass	almost	13	million	acres	located	in	the	Sirte	Basin.	Our exploration	program	in	2008	included	the	drilling	of	three	wells,	all	of	which	were	successful.	Most	of	these	discoveries	extended	previously	defined	hydrocarbon accumulations.

Canada	–	We	hold	interests	in	both	operated	and	outside-operated	exploration-stage	in-situ	oil	sand	leases	as	a	result	of	the	acquisition	of	Western	in	2007.	Initial test	drilling	on	the	100	percent	interest	Birchwood	prospect	positively	confirmed	bitumen	presence	with	additional	test	drilling	required	to	confirm	reservoir	quality.

United	Kingdom	–	We	have	a	45	percent	interest	in	five	exploratory	U.K.	onshore	coal	seam	gas	("CSG")	licenses.	Drilling	has	been	completed	in	five	exploration wells	in	three	of	the	licenses.	One	test	well	was	completed	in	2007	and	three	lateral	wells	for	production	testing	were	drilled	in	2008.	We	and	our	partners	were	awarded 11	new	blocks	for	CSG	exploration	and	potential	future	development	during	the	13th	Onshore	Licensing	Round	in	2008.	After	the	2008	licensing	our	interest	covers 520,000	acres.	We	are	the	operator	of	these	new	licenses	and	have	a	55	percent	working	interest.

# Production	(including	development	activities)

United	States	–	Our	U.S.	operations	accounted	for	30	percent	of	our	2008	worldwide	net	liquid	hydrocarbon	sales	volumes	and	44	percent	of	our	worldwide	net natural	gas	sales	volumes.

During	2008,	our	net	sales	in	the	Gulf	of	Mexico	averaged	23	mbpd	of	liquid	hydrocarbons,	representing	36	percent	of	our	total	U.S.	net	liquid	hydrocarbon	sales, and	20	mmcfd	of	natural	gas,	representing	five	percent	of	our	total	U.S.	net	natural	gas	sales.	At	year	end	2008,	we	held	interests	in	six	producing	fields	and	five platforms	in	the	Gulf	of	Mexico,	of	which	we	operate	one	platform.

Hurricanes	Gustav	and	Ike	impacted	Gulf	of	Mexico	operations	in	the	latter	part	of	the	third	quarter	of	2008,	resulting	in	approximately	9.5	net	mboepd	being	shut- in	during	the	quarter.	The	Ewing	Bank	development	resumed	production	in	October	2008,	but	the	outside-operated	Ursa	and	Troika	fields	were	shut-in	for	repairs	until November	2008	and	January	2009,	respectively,	impacting	fourth	quarter	sales	by	approximately	7	mboepd.	We	have	a	65	percent	working	interest	in	Ewing	Bank,	a four	percent	overriding	royalty	interest	in	Ursa	and	a	50	percent	working	interest	in	Troika.

We	own	a	50	percent	outside-operated	interest	in	the	Petronius	field	on	Viosca	Knoll	Blocks	786	and	830.	The	Petronius	platform	also	provides	processing	and transportation	services	to	adjacent	third-party	fields.	For	example,	Petronius	processes	liquid	hydrocarbons	from	our	Perseus	field	which	commenced	production	in April	2005	and	is	located	five	miles	from	the	platform.

The	Neptune	development	in	the	Gulf	of	Mexico	commenced	production	of	liquid	hydrocarbons	and	natural	gas	in	July	2008.	We	hold	a	30	percent	outside- operated	working	interest	in	this	development	located	on	Atwater	Valley	area	in	the	Gulf	of	Mexico,	120	miles	off	the	coast	of	Louisiana.	The	development	plan included	seven	subsea	wells	tied	back	to	a	stand-alone	platform	and	six	wells	have	been	drilled	and	completed.

In	October	2008,	development	of	the	Droshky	discovery,	located	in	the	Gulf	of	Mexico	on	Green	Canyon	Block	244,	was	authorized	by	our	board	of	directors.	The initial	Droshky	discovery	well	and	two	sidetracks	were	drilled	in	2007,	followed	in	2008	by	a	second	delineation	and	sidetrack	well.	The	project	will	consist	of development	wells,	which	will	be	tied	back	to	the	nearby	third-party	owned	and	operated	Bullwinkle	platform.	We	have	secured	a	rig	to	begin	drilling	in	2009,	and	first production	is	targeted	for	2010.	Net	sales	after	royalties	are	expected	to	peak	at	about	45	mbpd	of	liquid	hydrocarbons	and	43	mmcfd	of	natural	gas.	We	hold	a	100 percent	working	interest	in	Droshky.

Also	in	October	2008,	development	of	the	Ozona	prospect,	located	in	the	Gulf	of	Mexico	on	Garden	Banks	Block	515	was	authorized	by	our	board	of	directors.	We have	secured	a	rig	to	complete	the	previously	drilled	appraisal	well	and	tie	back	to	the	nearby	outside-operated	Auger	platform.	First	production	is	expected	in	2011.	We hold	a	68	percent	working	interest	in	Ozona.

We	produce	natural	gas	in	the	Cook	Inlet	and	adjacent	Kenai	Peninsula	of	Alaska.	In	2008,	our	net	natural	gas	sales	from	Alaska	averaged	126	mmcfd,	representing 28	percent	of	our	total	U.S.	net	natural	gas	sales	volumes.	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.

Net	liquid	hydrocarbon	and	natural	gas	sales	from	our	Wyoming	fields	averaged	19	mbpd	and	123	mmcfd	in	2008.	Our	Wyoming	net	natural	gas	sales	decreased from	the	prior	year	primarily	as	a	result	of	natural	field	declines,	partially	offset	by	new	wells	in	the	Wamsutter	Field	and	Powder	River	Basin	areas.	Development	of	the Powder	River	Basin	continued	in	2008	with	100	operated	wells	drilled,	which	was	down	from	the	170	wells	drilled	in	2007.	Additional	development	of	our	southwest Wyoming	interests	continued	in	2008	where	we	participated	in	the	drilling	of	six	wells.

We	also	have	domestic	natural	gas	operations	in	Oklahoma,	east	Texas	and	north	Louisiana,	with	combined	net	sales	of	137	mmcfd	in	2008,	and	liquid hydrocarbon	operations	in	the	Permian	Basin	of	southeast	New	Mexico	and	west	Texas,	with	net	sales	of	11	mbpd	in	2008.

We	hold	320,000	acres	in	the	Williston	Basin	(the	Bakken	Shale	resource	play).	The	majority	of	the	acreage	is	located	in	North	Dakota	with	the	remainder	in eastern	Montana.	This	represents	a	substantial	position	in	the	Bakken	Shale	where	approximately	225	locations	will	be	drilled	over	the	next	four	to	five	years.	We currently	have	four	operated	drilling	rigs	running	and	ended	2008	with	December	average	net	sales	of	8.2	mboepd.

We	hold	leases	with	natural	gas	production	in	the	Piceance	Basin	of	Colorado,	located	in	Garfield	County	in	the	Greater	Grand	Valley	field	complex.	Our	plans include	drilling	approximately	150	wells	over	the	next	five	years.	Drilling	and	production	commenced	in	late	2007.	We	currently	have	one	operated	drilling	rig	running and	ended	2008	with	December	average	net	sales	of	10	mmcfd.

United	Kingdom	–	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	38	percent	working	interest	in	the	East	Brae	field.	The	Brae	A	platform	and	facilities	host	the	underlying	South Brae	field	and	the	adjacent	Central	and	West	Brae	fields.	The	North	Brae	field,	which	is	produced	via	the	Brae	B	platform,	and	the	East	Brae	field,	which	is	produced via	the	East	Brae	platform,	are	natural	gas	condensate	fields.	The	East	Brae	platform	hosts	the	nearby	Braemar	field	in	which	we	have	a	26	percent	working	interest.	Net liquid	hydrocarbon	sales	from	the	Brae	area	averaged	12	mbpd	in	2008.	Net	Brae	natural	gas	sales	averaged	119	mmcfd,	or	21	percent,	of	our	international	natural	gas sales	volumes	in	2008.

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	28	third-party	fields	have	contracted	to	use	the	Brae	system.	In	addition	to	generating	processing	and	pipeline	tariff	revenue,	this	third- party	business	also	has	a	favorable	impact	on	Brae	area	operations	by	optimizing	infrastructure	usage	and	extending	the	economic	life	of	the	complex.

The	Brae	group	owns	a	50	percent	interest	in	the	outside-operated	Scottish	Area	Gas	Evacuation	("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	billion	cubic	feet	("bcf")	per	day.	The	SAGE	terminal	at	St.	Fergus	in	northeast	Scotland	processes	natural	gas	from	the	SAGE pipeline	and	has	the	capacity	for	almost	1	bcf	per	day	of	third-party	natural	gas	from	the	Britannia,	Atlantic	and	Cromarty	fields.

In	the	U.K.	Atlantic	Margin,	we	own	a	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.	Net	sales	from	the	Foinaven	fields	averaged 12	mbpd	of	liquid	hydrocarbons	and	6	mmcfd	of	natural	gas	in	2008.

Norway	–	Norway	is	a	strategic	and	growing	core	area,	which	complements	our	long-standing	operations	in	the	U.K.	sector	of	the	North	Sea	discussed	above.	We were	approved	for	our	first	operatorship	on	the	Norwegian	continental	shelf	in	2002,	where	today	we	operate	seven	licenses,	including	the	PL	505,	which	was	awarded	in January	2009.

The	operated	Alvheim	complex	located	on	the	Norwegian	continental	shelf	commenced	production	in	June	2008.	The	complex	consists	of	a	floating	production, storage	and	offloading	vessel	("FPSO")	with	subsea	infrastructure.	Produced	oil	is	transported	by	shuttle	tanker	and	produced	natural	gas	transported	to	the	SAGE system	using	a	new	14-inch	diameter,	24-mile	cross	border	pipeline.	First	production	to	the	complex	was	from	the	Alvheim	development	which	is	comprised	of	the Kameleon	and	Kneler	discoveries,	in	which	we	have	a	65	percent	working	interest,	and	the	Boa	discovery,	in	which	we	have	a	58	percent	working	interest.	At	the	end	of 2008,	the	Alvheim	development	included	ten	producing	wells	and	two	water	disposal	wells.	The	nearby	Vilje	discovery,	in	which	we	own	a	47	percent	outside-operated working	interest,	began	producing	through	the	Alvheim	complex	in	August	2008.	The	two	Vilje	development	wells	were	drilled	and	completed	in	2007.	Additionally,	in 2007,	the	Norwegian	government	approved	a	plan	for	development	and	operation	to	develop	the	Volund	field	as	a	subsea	tie-back	to	the	Alvheim	complex.	The	Volund development	will	consist	of	three	production	wells	and	one	water	disposal	well,	all	to	be	drilled	in	the	2009	and	2010.	The	Volund	development,	in	which	we	own	a	65 percent	working	interest	and	serve	as	operator,	is	expected	to	begin	production	in	late	2009.

In	addition,	we	hold	a	28	percent	outside-operated	interest	in	the	Gudrun	field,	located	120	miles	off	the	coast	of	Norway,	where	a	successful	appraisal	well	was drilled	in	2006.	In	January	2009,	the	operator	announced	a	development	concept	that	includes	a	fixed	processing	platform	with	seven	production	wells	that	would	be tied	to	existing	facilities	on	the	Sleipner	field.	A	final	investment	decision	is	expected	in	2009.

On	October	31,	2008,	we	closed	the	sale	of	our	non-core,	outside-operated	interests	(24	percent	of	Heimdal	field,	47	percent	of	Vale	field	and	20	percent	of	Skirne field)	and	associated	undeveloped	acreage	in	offshore	Norway.

Ireland	–	In	December	2008,	we	announced	an	agreement	to	sell	our	wholly-owned	subsidiary	which	owns	our	producing	properties	in	Ireland.	Closing	is	subject to	customary	closing	conditions.	Properties	included	in	the	sale	are	our	100	percent	working	interest	in	the	Kinsale	Head,	Ballycotton	and	Southwest	Kinsale	natural	gas fields	and	our	87	percent	operated	working	interest	in	the	Seven	Heads	natural	gas	field	in	the	Celtic	Sea	offshore	Ireland.	Also	included	is	a	100	percent	interest	in	our gas	storage	business	which	allows	us	to	provide	full	third-party	storage	services	from	the	Southwest	Kinsale	field.

We	own	a	19	percent	working	interest	in	the	outside-operated	Corrib	natural	gas	development	project,	located	40	miles	off	Ireland's	northwest	coast,	where	six	of the	seven	wells	necessary	to	develop	the	field	have	been	drilled.	Four	of	these	wells	were	completed	and	tested	at	the	end	of	2008.	Terminal	construction	and	offshore pipe	installation	are	currently	underway	and	onshore	pipeline	installation	is	planned	to	commence	in	2009.	The	operator	expects	first	production	from	the	field	in	late 2010	or	early	2011.

Equatorial	Guinea	–	We	own	a	63	percent	operated	working	interest	in	the	Alba	field	offshore	Equatorial	Guinea	During	2008,	net	liquid	hydrocarbon	sales average	41	mbpd	or	28	percent	of	our	international	liquid	hydrocarbon	sales	volumes,	and	net	natural	gas	sales	averaged	366	mmcfd,	or	64	percent	of	our	international natural	gas	sales.	Net	liquid	hydrocarbon	sales	volumes	in	2008	included	26	mbpd	of	condensate.

We	also	own	a	52	percent	interest	in	Alba	Plant	LLC,	an	equity	method	investee	that	operates	an	onshore	liquefied	petroleum	gas	("LPG")	processing	plant.	Alba field	natural	gas	is	supplied	to	the	LPG	plant	under	a	long-term	contract	at	a	fixed	price.	During	2008,	a	gross	883	mmcfd	of	natural	gas	was	supplied	to	the	LPG production	facility	and	our	net	liquid	hydrocarbon	sales	volumes	in	2008	included	11	mbpd	of	LPG	and	4	mbpd	of	secondary	condensate	produced	by	Alba	Plant	LLC.

As	part	of	our	Integrated	Gas	segment,	we	own	45	percent	of	Atlantic	Methanol	Production	Company	LLC	("AMPCO")	and	60	percent	of	Equatorial	Guinea	LNG Holdings	Limited	("EGHoldings").	AMPCO	operates	a	methanol	plant	and	EGHoldings	operates	an	LNG	production	facility,	both	located	on	Bioko	Island.	Alba	field dry	natural	gas,	which	remains	after	the	condensate	and	LPG	are	removed,	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	LPG	produced	by	Alba	Plant	LLC	is	reflected	in	our	E&P	segment.	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 2008,	a	gross	94	mmcfd	of	dry	natural	gas	was	supplied	to	the	methanol	plant	and	a	gross	565	mmcfd	of	dry	gas	was	supplied	to	the	LNG	production	facility.	Any remaining	dry	gas	is	returned	offshore	and	reinjected	into	the	Alba	reservoir	for	later	production.

Angola	–	The	discoveries	on	Blocks	31	and	32	represent	four	potential	development	hubs.	The	Plutao,	Saturno,	Venus	and	Marte	discoveries	and	one	successful appraisal	well	form	a	planned	development	area	in	the	northeastern	portion	of	Block	31.	In	2008,	we	received	approval	to	proceed	with	this	first	deepwater	development project,	called	the	PSVM	development.	Key	contracts	were	awarded	and	construction	work	commenced	in	the	second	half	of	2008.	A	total	of	48	production	and injection	wells	are	planned	for	the	PSVM	development.	Other	discoveries	on	Block	31	comprise	potential	development	areas	in	the	southeast	and	middle	portions	of	the block.	Seven	of	the	Block	32	discoveries	form	a	potential	development	in	the	eastern	area	of	that	block.

Libya	–	We	resumed	operations	in	Libya	in	2006,	holding	a	16	percent	outside-operated	interest	in	the	Waha	concessions.	Net	liquid	hydrocarbon	sales	in	Libya averaged	46	mbpd	in	2008	compared	to	45	mbpd	in	2007.	The	2008	net	liquid	hydrocarbon	sales	in	Libya	represented	31	percent	of	our	international	liquid	hydrocarbon sales	volumes.	Net	natural	gas	sales	in	Libya	averaged	4	mmcfd	in	2008.

Gabon	–	We	are	the	operator	of	the	Tchatamba	South,	Tchatamba	West	and	Tchatamba	Marin	fields	offshore	Gabon	with	a	56	percent	working	interest.	Net	sales in	Gabon	averaged	6	mbpd	of	liquid	hydrocarbons	in	2008.	Production	from	these	three	fields	is	processed	on	a	single	offshore	facility	at	Tchatamba	Marin,	with	the processed	oil	being	transported	through	an	offshore	and	onshore	pipeline	to	an	outside-operated	storage	facility.

# Other	Matters

During	the	first	quarter	of	2008,	we	relinquished	our	interest	in	an	exploration	and	production	license	in	Sudan,	and	as	a	result,	we	no	longer	have	any	interests	in Sudan.

We	ceased	efforts	to	pursue	exploration	opportunities	in	Ukraine	and	closed	our	Kiev	office	in	the	third	quarter	of	2008.

The	above	discussion	of	the	E&P	segment	includes	forward-looking	statements	with	respect	to	anticipated	future	exploratory	and	development	drilling,	Blocks	31 and	32	offshore	Angola,	the	Equatorial	Guinea	discoveries,	the	timing	of	production	from	the	Woodford	Shale	resource	play,	the	Droshky	and	Ozona	developments	in the	Gulf	of	Mexico,	the	Volund	development,	the	sale	of	a	subsidiary	which	owns	producing	properties	in	Ireland	and	the	Corrib	project.	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.	Except	for	the	Volund	development,	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	possible	developments	on	Blocks	31	and	32 offshore	Angola,	and	the	Equatorial	Guinea	discoveries	could	further	be	affected	by	presently	known	data	concerning	size	and	character	of	reservoirs,	economic recoverability,	future	drilling	success	and	production	experience.	Factors	that	could	affect	the	sale	of	the	subsidiary	include	customary	closing	conditions.	The	foregoing factors	(among	others)	could	cause	actual	results	to	differ	materially	from	those	set	forth	in	the	forward-looking	statements.

# Reserves

At	December	31,	2008,	our	net	proved	liquid	hydrocarbon	and	natural	gas	reserves	totaled	1,195	million	boe,	of	which	43	percent	were	located	in	Organization	for Economic	Cooperation	and	Development	("OECD")	countries.	The	following	table	sets	forth	estimated	quantities	of	net	proved	liquid	hydrocarbon	and	natural	gas reserves	at	the	end	of	each	of	the	last	three	years.

# Estimated	Quantities	of	Net	Proved	Liquid	Hydrocarbon	and	Natural	Gas	Reserves	at	December	31

|  | Developed | Developed | Developed | Developed	and<br>Undeveloped | Developed	and<br>Undeveloped |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2008 | 2007 | 2006 | 2008 | 2007 | 2006 |
| Liquid\tHydrocarbons\t(Millions\tof\tbarrels) |  |  |  |  |  |  |
| United\tStates | 137 | 135 | 150 | 178 | 166 | 172 |
| Europe | 81 | 32 | 35 | 104 | 115 | 108 |
| Africa | 296 | 304 | 381 | 354 | 369 | 397 |
| WORLDWIDE | 514 | 471 | 566 | 636 | 650 | 677 |
| Developed\treserves\tas\ta\tpercent\tof\ttotal\tnet\tproved\treserves | 81% | 72% | 84% |  |  |  |
| Natural\tGas\t(Billions\tof\tcubic\tfeet) |  |  |  |  |  |  |
| United\tStates | 839 | 761 | 857 | 1,085 | 1,007 | 1,069 |
| Europe | 129 | 173 | 238 | 291 | 382 | 444 |
| Africa | 1,382 | 1,515 | 648 | 1,975 | 2,061 | 1,997 |
| WORLDWIDE | 2,350 | 2,449 | 1,743 | 3,351 | 3,450 | 3,510 |
| Developed\treserves\tas\ta\tpercent\tof\ttotal\tnet\tproved\treserves | 70% | 71% | 50% |  |  |  |
| Total\tBOE\t(Millions\tof\tbarrels) |  |  |  |  |  |  |
| United\tStates | 277 | 262 | 293 | 359 | 334 | 350 |
| Europe | 103 | 61 | 75 | 153 | 179 | 182 |
| Africa | 526 | 556 | 489 | 683 | 712 | 730 |
| WORLDWIDE | 906 | 879 | 857 | 1,195 | 1,225 | 1,262 |
| Developed\treserves\tas\ta\tpercent\tof\ttotal\tnet\tproved\treserves | 76% | 72% | 68% |  |  |  |

The	following	table	sets	forth	changes	in	estimated	quantities	of	proved	liquid	hydrocarbon	and	natural	gas	reserves:

# Changes	in	Estimated	Quantities	of	Net	Proved	Liquid	Hydrocarbon	and	Natural	Gas	Reserves

(a) Additions	were	principally	in	Norway,	the	Gulf	of	Mexico	and	Libya.

(b) The	sale	of	outside-operated	properties	in	Norway	was	the	most	significant	disposition.

During	2008,	we	transferred	126	million	boe	from	proved	undeveloped	to	proved	developed	reserves.	Costs	incurred	for	the	periods	ended	December	31,	2008, 2007	and	2006	relating	to	the	development	of	proved	undeveloped	liquid	hydrocarbon	and	natural	gas	reserves,	were	$1,189	million,	$1,250	million	and	$1,010	million. Of	the	289	million	boe	of	proved	undeveloped	reserves	at	year-end	2008,	64	percent	of	the	volume	is	associated	with	projects	that	have	been	included	in	proved	reserves for	more	than	three	years	while	19	percent	of	the	proved	undeveloped	reserves	were	added	during	2008.	As	of	December	31,	2008,	estimated	future	development	costs relating	to	the	development	of	proved	undeveloped	liquid	hydrocarbon	and	natural	gas	reserves	for	the	years	2009	through	2011	are	projected	to	be	$1,244	million,	$508 million	and	$262	million.

The	above	estimated	quantities	of	net	proved	liquid	hydrocarbon	and	natural	gas	reserves	and	estimated	future	development	costs	relating	to	the	development	of proved	undeveloped	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.	To	the	extent	these	assumptions	prove	inaccurate,	actual	recoveries	and	development costs	could	be	different	than	current	estimates.

For	a	discussion	of	the	proved	liquid	hydrocarbon	and	natural	gas	reserve	estimation	process,	see	Item	7.	Management's	Discussion	and	Analysis	of	Financial Condition	and	Results	of	Operations	–	Critical	Accounting	Estimates	–	Estimated	Net	Recoverable	Reserve	Quantities	–	Proved	Liquid	Hydrocarbon	and	Natural	Gas Reserves,	and	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	–	Estimated	Quantities	of	Proved	Oil	and	Natural	Gas	Reserves.	We	filed	reports with	the	U.S.	Department	of	Energy	("DOE")	for	2007	disclosing	our	total	year-end	estimated	liquid	hydrocarbon	and	natural	gas	reserves.	The	year-end	estimates reported	to	the	DOE	are	the	same	estimates	reported	in	the	Supplementary	Information	on	Oil	and	Gas	Producing	Activities.

# Delivery	Commitments

We	sell	liquid	hydrocarbons	and	natural	gas	under	a	variety	of	contractual	arrangements,	some	of	which	specify	the	delivery	of	a	fixed	and	determinable	quantity. Worldwide,	we	are	contractually	committed	to	deliver	126	bcf	of	natural	gas	in	the	future.	These	contracts	have	various	expiration	dates	through	the	year	2018.	Our proved	reserves	in	Alaska,	the	United	Kingdom	and	other	locations,	are	sufficient	to	fulfill	these	delivery	commitments.

# Net	Liquid	Hydrocarbon	and	Natural	Gas	Sales

The	following	tables	set	forth	the	daily	average	net	sales	volumes	of	liquid	hydrocarbons	and	natural	gas	for	each	of	the	last	three	years.

(a) Includes	crude	oil,	condensate	and	natural	gas	liquids. (b) Represents	net	sales	from	leasehold	ownership,	after	royalties	and	interests	of	others.

(c) Represents	equity	tanker	liftings	and	direct	deliveries	of	liquid	hydrocarbons.	The	amounts	correspond	with	the	basis	for	fiscal	settlements	with	governments.	Crude	oil	purchases,	if	any,	from	host	governments	are excluded.

(d) Represents	the	Russian	oil	exploration	and	production	businesses	that	were	sold	in	June	2006.

(e) Represents	net	sales	after	royalties,	except	for	Ireland	where	amounts	are	before	royalties.

(f) Excludes	volumes	acquired	from	third	parties	for	injection	and	subsequent	resale	of	32	mmcfd,	47	mmcfd	and	46	mmcfd	in	2008,	2007	and	2006.

# Productive	and	Drilling	Wells

The	following	tables	set	forth	productive	wells	and	service	wells	as	of	December	31,	2008,	2007	and	2006	and	drilling	wells	as	of	December	31,	2008.

# Gross	and	Net	Wells

|  |  | Productive	Wells(a) | Productive	Wells(a) | Productive	Wells(a) | Productive	Wells(a) | Service |  | Drilling |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | Oil | Oil | Natural\tGas | Natural\tGas | Wells(b) |  | Wells(c) | Wells(c) |
|  |  | Gross | Net | Gross | Net | Gross | Net | Gross | Net |
| 2008 | United\tStates | 5,856 | 2,140 | 5,411 | 3,846 | 2,703 | 822 | 77 | 50 |
|  | Europe | 64 | 26 | 67 | 40 | 26 | 10 | 2 | 1 |
|  | Africa | 968 | 162 | 13 | 9 | 97 | 18 | 7 | 1 |
|  | \t\t\t\tWORLDWIDE | 6,888 | 2,328 | 5,491 | 3,895 | 2,826 | 850 | 86 | 52 |
| 2007 | United\tStates | 5,864 | 2,111 | 5,184 | 3,734 | 2,737 | 838 |  |  |
|  | Europe | 54 | 20 | 76 | 41 | 29 | 11 |  |  |
|  | Africa | 964 | 161 | 13 | 9 | 99 | 18 |  |  |
|  | \t\t\t\tWORLDWIDE | 6,882 | 2,292 | 5,273 | 3,784 | 2,865 | 867 |  |  |
| 2006 | United\tStates | 5,661 | 2,068 | 5,554 | 4,063 | 2,729 | 834 |  |  |
|  | Europe | 51 | 19 | 75 | 41 | 31 | 12 |  |  |
|  | Africa | 925 | 155 | 13 | 9 | 100 | 19 |  |  |
|  | \t\t\t\tWORLDWIDE | 6,637 | 2,242 | 5,642 | 4,113 | 2,860 | 865 |  |  |
| (a) |  |  |  |  |  |  |  |  |  |

(a) Includes	active	wells	and	wells	temporarily	shut-in.	Of	the	gross	productive	wells,	wells	with	multiple	completions	operated	by	Marathon	totaled	276,	303	and	294	as	of	December	31,	2008,	2007	and	2006. Information	on	wells	with	multiple	completions	operated	by	others	is	unavailable	to	us. (b) Consists	of	injection,	water	supply	and	disposal	wells.

(c) Consists	of	exploratory	and	development	wells.

# Drilling	Activity

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.

# Net	Productive	and	Dry	Wells	Completed (a)

|  |  | Development(b) | Development(b) | Development(b) | Development(b) | Exploratory | Exploratory | Exploratory | Exploratory | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | Natural |  |  |  | Natural |  |  |  |
|  |  | Oil | Gas | Dry | Total | Oil | Gas | Dry | Total |  |
| 2008 | United\tStates | 38 | 161 | — | 199 | 33 | 8 | 6 | 47 | 246 |
|  | International | 8 | 1 | — | 9 | 1 | 2 | 1 | 4 | 13 |
|  | \t\t\t\tWORLDWIDE | 46 | 162 | — | 208 | 34 | 10 | 7 | 51 | 259 |
| 2007 | United\tStates | 9 | 172 | — | 181 | 9 | 13 | 12 | 34 | 215 |
|  | International | 7 | — | — | 7 | 3 | 1 | 2 | 6 | 13 |
|  | \t\t\t\tWORLDWIDE | 16 | 172 | — | 188 | 12 | 14 | 14 | 40 | 228 |
| 2006 | United\tStates | 32 | 186 | 5 | 223 | 3 | 8 | 3 | 14 | 237 |
|  | International | 51 | 1 | — | 52 | 19 | — | 6 | 25 | 77 |
|  | \t\t\t\tWORLDWIDE | 83 | 187 | 5 | 275 | 22 | 8 | 9 | 39 | 314 |
| (a) |  |  |  |  |  |  |  |  |  |  |

(a) Includes	the	number	of	wells	completed	during	the	applicable	year	regardless	of	the	year	in	which	drilling	was	initiated.	Excludes	any	wells	where	drilling	operations	were	continuing	or	were	temporarily suspended	as	of	the	end	of	the	applicable	year.	A	dry	well	is	a	well	found	to	be	incapable	of	producing	hydrocarbons	in	sufficient	quantities	to	justify	completion.	A	productive	well	is	an	exploratory	or development	well	that	is	not	a	dry	well.

(b) Indicates	wells	drilled	in	the	proved	area	of	an	oil	or	natural	gas	reservoir.

# Acreage

The	following	tables	set	forth,	by	geographic	area,	the	developed	and	underdeveloped	exploration	and	production	acreage	that	we	hold	as	of	December	31,	2008.

# Gross	and	Net	Acreage

|  |  |  |  |  | Developed	and | Developed	and |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Developed | Developed | Undeveloped | Undeveloped | Undeveloped | Undeveloped |
| (Thousands\tof\tacres) | Gross | Net | Gross | Net | Gross | Net |
| United\tStates | 1,318 | 1,035 | 1,612 | 1,169 | 2,930 | 2,204 |
| Europe | 493 | 393 | 1,555 | 617 | 2,048 | 1,010 |
| Africa | 12,978 | 2,151 | 2,787 | 654 | 15,765 | 2,805 |
| Other\tInternational | — | — | 2,535 | 1,471 | 2,535 | 1,471 |
| WORLDWIDE | 14,789 | 3,579 | 8,489 | 3,911 | 23,278 | 7,490 |

# Oil	Sands	Mining

Through	our	acquisition	of	Western,	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	and	upgrades	the	bitumen	to	synthetic	crude	oil.	The	AOSP's	asset	is	the	mining	and extraction	operations	of	the	Muskeg	River	mine	located	near	Fort	McMurray,	Alberta,	which	began	bitumen	production	in	2003,	together	with	Scotford	upgrading infrastructure	located	northeast	of	Edmonton,	Alberta.	The	underlying	developed	leases	are	held	for	the	duration	of	the	project,	with	royalties	paid	to	the	province	of Alberta.	As	of	December	31,	2008,	we	have	rights	to	participate	in	developed	and	undeveloped	leases	totaling	approximately	215,000	gross	(45,000	net)	acres.	Prior	to December	6,	2009,	we	are	entitled	to	participate	in	any	new	land	acquisitions	by	either	of	the	other	AOSP	owners	within	a	defined	area	of	mutual	interest.

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. Bitumen	production	from	the	mine	is	taken	by	pipeline	to	the	Scotford	upgrader.

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	chunks	are	further	reduced	to	smaller	particles.	The	particles	are	combined	with	hot	water	to	create	slurry.	The	slurry	moves	through	a pipeline	where	it	separates	into	sand,	clay	and	bitumen.	Air	is	introduced	to	the	slurry	mixture,	which	creates	a	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,	referred	to	as	"dilbit",	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	hydro-treating	and	a	hydro-conversion	process	to	remove	sulfur	and	break	the heavy	carbon	molecules	into	lighter	products.	The	three	major	products	that	the	Scotford	upgrader	produces	are	Premium	Albian	synthetic	crude	oil,	Albian	Heavy synthetic	crude	oil	and	vacuum	gas	oil.	The	vacuum	gas	oil	is	sold	to	the	operator	under	a	long	term	contract	at	market-related	prices,	and	the	other	products	are	sold	in the	marketplace.

The	following	table	sets	forth	key	operating	statistics	for	the	last	two	years.

# OSM	Operating	Statistics

(b) Bitumen	production	is	before	royalties.

Proved	reserves	can	be	added	as	expansions	are	permitted,	funding	is	approved	and	certain	stipulations	of	the	joint	venture	agreement	are	satisfied.	The	following table	sets	forth	changes	in	estimated	quantities	of	net	proved	bitumen	reserves	for	the	year	2008.

# Estimated	Quantities	of	Proved	Bitumen	Reserves

(a) Revisions	were	driven	primarily	by	price	and	the	impact	of	the	new	royalty	regime	discussed	below.

The	above	estimated	quantity	of	net	proved	bitumen	reserves	is	a	forward-looking	statement	and	is	based	on	a	number	of	assumptions,	including	(among	others) commodity	prices,	volumes	in-place,	presently	known	physical	data,	recoverability	of	bitumen,	industry	economic	conditions,	levels	of	cash	flow	from	operations,	and other	operating	considerations.	To	the	extent	these	assumptions	prove	inaccurate,	actual	recoveries	could	be	different	than	current	estimates.	For	a	discussion	of	the proved	bitumen	reserves	estimation	process,	see	Item	7.	Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	–	Critical	Accounting Estimates	–	Estimated	Net	Recoverable	Reserve	Quantities	–	Proved	Bitumen	Reserves.	Operations	at	the	AOSP	are	not	within	the	scope	of	Statement	of	Financial Accounting	Standards	("SFAS")	No.	25,	"Suspension	of	Certain	Accounting	Requirements	for	Oil	and	Gas	Producing	Companies	(an	Amendment	of	Financial Accounting	Standards	Board	("FASB")	Statement	No.	19),"	SFAS	No.	69,	"Disclosures	about	Oil	and	Gas	Producing	Activities	(an	Amendment	of	FASB	Statements 19,	25,	33	and	39),"	and	Securities	and	Exchange	Commission	("SEC")	Rule	4-10	of	Regulation	S-X;	therefore,	bitumen	production	and	reserves	are	not	included	in	our Supplementary	Information	on	Oil	and	Gas	Producing	Activities.	The	SEC	has	recently	issued	a	release	amending	these	disclosure	requirements	effective	for	annual reports	on	Form	10-K	for	fiscal	years	ending	on	or	after	December	31,	2009,	see	Item	7.	Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of Operations	–	Accounting	Standards	Not	Yet	Adopted	for	additional	information.

Prior	to	our	acquisition	of	Western,	the	first	fully-integrated	expansion	of	the	existing	AOSP	facilities	was	approved	in	2006.	Expansion	1,	which	includes construction	of	mining	and	extraction	facilities	at	the	Jackpine	mine,	expansion	of	treatment	facilities	at	the	existing	Muskeg	River	mine,	expansion	of	the	Scotford upgrader	and	development	of	related	infrastructure,	is	anticipated	to	begin	operations	in	late	2010	or	2011.	When	Expansion	1	is	complete,	we	will	have	more	than 50,000	bpd	of	net	production	and	upgrading	capacity	in	the	Canadian	oil	sands.	The	timing	and	scope	of	future	expansions	and	debottlenecking	opportunities	on	existing operations	remain	under	review.

During	2008,	the	Alberta	government	accepted	the	project's	application	to	have	a	portion	of	the	Expansion	1	capital	costs	form	part	of	the	Muskeg	River	mine's allowable	cost	recovery	pool.	Due	to	commodity	price	declines	in	the	year,	royalties	for	2008	were	one	percent	of	the	gross	mine	revenue.

Commencing	January	1,	2009,	the	Alberta	Royalty	regime	has	been	amended	such	that	royalty	rates	will	be	based	on	the	Canadian	dollar	("CAD")	equivalent monthly	average	West	Texas	Intermediate	("WTI")	price.	Royalty	rates	will	rise	from	a	minimum	of	one	percent	to	a	maximum	of	nine	percent	under	the	gross	revenue method	and	from	a	minimum	of	25	percent	to	a	maximum	of	40	percent	under	the	net	revenue	method.	Under	both	methods,	the	minimum	royalty	is	based	on	a	WTI price	of	$55.00	CAD	per	barrel	and	below	while	the	maximum	royalty	is	reached	at	a	WTI	price	of	$120.00	CAD	per	barrel	and	above,	with	a	linear	increase	in	royalty between	the	aforementioned	prices.

The	above	discussion	of	the	Oil	Sands	Mining	segment	includes	forward-looking	statements	concerning	the	anticipated	completion	of	AOSP	Expansion	1.	Factors which	could	affect	the	expansion	project	include	transportation	logistics,	availability	of	materials	and	labor,	unforeseen	hazards	such	as	weather	conditions,	delays	in obtaining	or	conditions	imposed	by	necessary	government	and	third-party	approvals	and	other	risks	customarily	associated	with	construction	projects.

# Refining,	Marketing	and	Transportation

# Refining

We	own	and	operate	seven	refineries	in	the	Gulf	Coast,	Midwest	and	upper	Great	Plains	regions	of	the	United	States	with	an	aggregate	refining	capacity	of 1.016	million	barrels	per	day	("mmbpd")	of	crude	oil.	During	2008,

our	refineries	processed	944	mbpd	of	crude	oil	and	207	mbpd	of	other	charge	and	blend	stocks.	The	table	below	sets	forth	the	location	and	daily	crude	oil	refining capacity	of	each	of	our	refineries	as	of	December	31,	2008.

# Crude	Oil	Refining	Capacity

| Crude	Oil	Refining	Capacity |  |
| :--- | :--- |
| (Thousands\tof\tbarrels\tper\tday) | 2008 |
| Garyville,\tLouisiana | 256 |
| Catlettsburg,\tKentucky | 226 |
| Robinson,\tIllinois | 204 |
| Detroit,\tMichigan | 102 |
| Canton,\tOhio | 78 |
| Texas\tCity,\tTexas | 76 |
| St.\tPaul\tPark,\tMinnesota | 74 |
| TOTAL | 1,016 |

Our	refineries	include	crude	oil	atmospheric	and	vacuum	distillation,	fluid	catalytic	cracking,	catalytic	reforming,	desulfurization	and	sulfur	recovery	units.	The refineries	process	a	wide	variety	of	crude	oils	and	produce	numerous	refined	products,	ranging	from	transportation	fuels,	such	as	reformulated	gasolines,	blend-grade gasolines	intended	for	blending	with	fuel	ethanol	and	ultra-low	sulfur	diesel	fuel,	to	heavy	fuel	oil	and	asphalt.	Additionally,	we	manufacture	aromatics,	cumene, propane,	propylene,	sulfur	and	maleic	anhydride.

Our	refineries	are	integrated	with	each	other	via	pipelines,	terminals	and	barges	to	maximize	operating	efficiency.	The	transportation	links	that	connect	our refineries	allow	the	movement	of	intermediate	products	between	refineries	to	optimize	operations,	produce	higher	margin	products	and	utilize	our	processing	capacity efficiently.

Our	Garyville,	Louisiana,	refinery	is	located	along	the	Mississippi	River	in	southeastern	Louisiana.	The	Garyville	refinery	processes	heavy	sour	crude	oil	into products	such	as	gasoline,	distillates,	sulfur,	asphalt,	propane,	polymer	grade	propylene,	isobutane	and	coke.	In	2006,	we	approved	an	expansion	of	our	Garyville refinery	by	180	mbpd	to	436	mbpd,	with	a	currently	projected	cost	of	$3.35	billion	(excluding	capitalized	interest).	Construction	commenced	in	early	2007	and	is continuing	on	schedule.	We	estimate	that,	as	of	December	31,	2008,	this	project	is	approximately	75	percent	complete.	We	expect	to	complete	the	expansion	in	late 2009.

Our	Catlettsburg,	Kentucky,	refinery	is	located	in	northeastern	Kentucky	on	the	western	bank	of	the	Big	Sandy	River,	near	the	confluence	with	the	Ohio	River.	The Catlettsburg	refinery	processes	sweet	and	sour	crude	oils	into	products	such	as	gasoline,	asphalt,	diesel,	jet	fuel,	petrochemicals,	propane,	propylene	and	sulfur.

Our	Robinson,	Illinois,	refinery	is	located	in	the	southeastern	Illinois	town	of	Robinson.	The	Robinson	refinery	processes	sweet	and	sour	crude	oils	into	products such	as	multiple	grades	of	gasoline,	jet	fuel,	kerosene,	diesel	fuel,	propane,	propylene,	sulfur	and	anode-grade	coke.

Our	Detroit,	Michigan,	refinery	is	located	near	Interstate	75	in	southwest	Detroit.	The	Detroit	refinery	processes	light	sweet	and	heavy	sour	crude	oils,	including Canadian	crude	oils,	into	products	such	as	gasoline,	diesel,	asphalt,	slurry,	propane,	chemical	grade	propylene	and	sulfur.	In	2007,	we	approved	a	heavy	oil	upgrading and	expansion	project	at	our	Detroit,	Michigan,	refinery,	with	a	current	projected	cost	of	$2.2	billion	(excluding	capitalized	interest).	This	project	will	enable	the	refinery to	process	additional	heavy	sour	crude	oils,	including	Canadian	bitumen	blends,	and	will	increase	its	crude	oil	refining	capacity	by	about	15	percent.	Construction	began in	the	first	half	of	2008	and	is	presently	expected	to	be	complete	in	mid-2012.

Our	Canton,	Ohio,	refinery	is	located	approximately	60	miles	southeast	of	Cleveland,	Ohio.	The	Canton	refinery	processes	sweet	and	sour	crude	oils	into	products such	as	gasoline,	diesel	fuels,	kerosene,	propane,	sulfur,	asphalt,	roofing	flux,	home	heating	oil	and	No.	6	industrial	fuel	oil.

Our	Texas	City,	Texas,	refinery	is	located	on	the	Texas	gulf	coast	approximately	30	miles	south	of	Houston,	Texas.	The	refinery	processes	sweet	crude	oil	into products	such	as	gasoline,	propane,	chemical	grade	propylene,	slurry,	sulfur	and	aromatics.

Our	St.	Paul	Park,	Minnesota,	refinery	is	located	in	St.	Paul	Park,	a	suburb	of	Minneapolis-St.	Paul.	The	St.	Paul	Park	refinery	processes	predominantly	Canadian crude	oils	into	products	such	as	gasoline,	diesel,	jet	fuel,	kerosene,	asphalt,	propane,	propylene	and	sulfur.

The	above	discussion	includes	forward-looking	statements	concerning	the	expansion	of	the	Garyville	refinery	and	the	Detroit	refinery	heavy	oil	upgrading	and expansion	project.	Some	factors	that	could	affect	those	projects	include	transportation	logistics,	availability	of	materials	and	labor,	unforeseen	hazards	such	as	weather conditions,	delays	in	obtaining	or	conditions	imposed	by	necessary	government	and	third-party	approvals	and	other	risks	customarily	associated	with	construction projects.

Planned	maintenance	activities	requiring	temporary	shutdown	of	certain	refinery	operating	units,	or	turnarounds,	are	periodically	performed	at	each	refinery.	We performed	major	turnaround	activities	at	our	Robinson,	Catlettsburg,	Garyville	and	Canton	refineries	in	2008,	at	our	Catlettsburg,	Robinson	and	St.	Paul	Park	refineries in	2007	and	at	our	Catlettsburg	refinery	in	2006.

The	following	table	sets	forth	our	refinery	production	by	product	group	for	each	of	the	last	three	years.

# Refined	Product	Yields

| (Thousands	of	barrels	per	day) | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Gasoline | 609 | 646 | 661 |
| Distillates | 342 | 349 | 323 |
| Propane | 22 | 23 | 23 |
| Feedstocks\tand\tspecial\tproducts | 96 | 108 | 107 |
| Heavy\tfuel\toil | 24 | 27 | 26 |
| Asphalt | 75 | 86 | 89 |
| TOTAL | 1,168 | 1,239 | 1,229 |

Crude	oil	supply	–	We	obtain	most	of	the	crude	oil	we	refine	through	negotiated	contracts	and	purchases	or	exchanges	on	the	spot	market.	Our	crude	oil	supply contracts	are	generally	term	contracts	with	market	related	pricing	provisions.	The	following	table	provides	information	on	our	sources	of	crude	oil	for	each	of	the	last three	years.	The	crude	oil	sourced	outside	of	North	America	was	acquired	from	various	foreign	national	oil	companies,	producing	companies	and	trading	companies.	Of the	U.S.	and	Canadian	sourced	crude	processed	at	our	refineries,	27	mbpd,	or	5	percent,	was	supplied	by	a	combination	of	our	E&P	and	OSM	production	operations	for the	year	2008.

# Sources	of	Crude	Oil	Refined

| (Thousands	of	barrels	per	day) | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| United\tStates | 466 | 527 | 470 |
| Canada | 135 | 138 | 130 |
| Middle\tEast\tand\tAfrica | 244 | 253 | 266 |
| Other\tinternational | 99 | 92 | 114 |
| TOTAL | 944 | \t 1,010 | 980 |
| Average\tcost\tof\tcrude\toil\tthroughput\t(Dollars\tper\tbarrel) | $98.34 | $71.20 | $61.15 |

Our	refineries	receive	crude	oil	and	other	feedstocks	and	distribute	our	refined	products	through	a	variety	of	channels,	including	pipelines,	trucks,	railcars,	ships	and barges.

Refined	product	marketing	and	distribution	–	We	are	a	supplier	of	refined	products	to	resellers	and	consumers	within	our	23-state	market	area	in	the	Midwest, upper	Great	Plains,	Gulf	Coast	and	southeastern	regions	of	the	United	States.	Our	market	area	includes	approximately	4,600	Marathon	branded-retail	outlets concentrated	in	the	Midwest	and	southeastern	states.	We	currently	own	and	distribute	from	65	light	product	and	22	asphalt	terminals.	In	addition,	we	distribute	through 68	third-party	terminals	in	our	market	area.	Our	marine	transportation	operations	include	15	towboats	and	196	owned	and	5	leased	barges	that	transport	refined	products on	the	Ohio,	Mississippi	and	Illinois	rivers,	their	tributaries	and	the	Intercoastal	Waterway.	We	lease	or	own	2,500	railcars	of	various	sizes	and	capacities	for	movement and	storage	of	refined	products	and	over	140	transport	trucks.

The	following	table	sets	forth,	as	a	percentage	of	total	refined	product	sales,	sales	of	refined	products	to	our	different	customer	types	for	the	past	three	years.

| Refined	Product	Sales	by	Customer	Type | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Private-brand\tmarketers,\tcommercial\tand\tindustrial\tconsumers | 67% | 69% | 71% |
| Marathon-branded\toutlets | 18% | 16% | 14% |
| Speedway\tSuperAmerica\tLLC\t("SSA")\tretail\toutlets | 15% | 15% | 15% |

The	following	table	sets	forth	our	refined	products	sales	by	product	group	and	our	average	sales	price	for	each	of	the	last	three	years.

# Refined	Product	Sales

| (Thousands	of	barrels	per	day) | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Gasoline | 756 | 791 | 804 |
| Distillates | 375 | 377 | 375 |
| Propane | 22 | 23 | 23 |
| Feedstocks\tand\tspecial\tproducts | 100 | 103 | 106 |
| Heavy\tfuel\toil | 23 | 29 | 26 |
| Asphalt | 76 | 87 | 91 |
| TOTAL(a) | 1,352 | \t 1,410 | 1,425 |
| Average\tsales\tprice\t(Dollars\tper\tbarrel) | $109.49 | $86.53 | $77.76 |
| (a) |  |  |  |

(a) Includes	matching	buy/sell	volumes	of	24	mbpd	in	2006.	On	April	1,	2006,	we	changed	our	accounting	for	matching	buy/sell	arrangements	as	a	result	of	a	new	accounting	standard.	This	change	resulted	in	lower refined	products	sales	volumes	for	2008,	2007	and	the	remainder	of	2006	than	would	have	been	reported	under	our	previous	accounting	practices.	See	Note	2	to	the	consolidated	financial	statements.

Gasoline	and	distillates	–	We	sell	gasoline,	gasoline	blendstocks	and	No.	1	and	No.	2	fuel	oils	(including	kerosene,	jet	fuel,	diesel	fuel	and	home	heating	oil)	to wholesale	marketing	customers	in	the	Midwest,	upper	Great	Plains,	Gulf	Coast	and	southeastern	regions	of	the	United	States.	We	sold	47	percent	of	our	gasoline volumes	and	88	percent	of	our	distillates	volumes	on	a	wholesale	or	spot	market	basis	in	2008.	The	demand	for	gasoline	is	seasonal	in	many	of	our	markets,	with	demand typically	being	at	its	highest	levels	during	the	summer	months.

We	have	blended	fuel	ethanol	into	gasoline	for	over	15	years	and	began	increasing	our	blending	program	in	2007,	in	part	due	to	federal	regulations	that	require	us	to use	specified	volumes	of	renewable	fuels.	We	blended	57	mbpd	of	ethanol	into	gasoline	in	2008,	41	mbpd	in	2007	and	35	mbpd	in	2006.	The	future	expansion	or contraction	of	our	ethanol	blending	program	will	be	driven	by	the	economics	of	the	ethanol	supply	and	by	government	regulations.	We	sell	reformulated	gasoline,	which is	also	blended	with	ethanol,	in	parts	of	our	marketing	territory,	including:	Chicago,	Illinois;	Louisville,	Kentucky;	northern	Kentucky;	Milwaukee,	Wisconsin	and Hartford,	Illinois.	We	also	sell	biodiesel-blended	diesel	in	Minnesota,	Illinois	and	Kentucky.

In	2007,	we	acquired	a	35	percent	interest	in	an	entity	which	owns	and	operates	a	110-million-gallon-per-year	ethanol	production	facility	in	Clymers,	Indiana.	We also	own	a	50	percent	interest	in	an	entity	which	owns	a	110-million-gallon-per-year	ethanol	production	facility	in	Greenville,	Ohio.	The	Greenville	plant	began production	in	February	2008.	Both	of	these	facilities	are	managed	by	a	co-owner.

Propane	–	We	produce	propane	at	all	seven	of	our	refineries.	Propane	is	primarily	used	for	home	heating	and	cooking,	as	a	feedstock	within	the	petrochemical industry,	for	grain	drying	and	as	a	fuel	for	trucks	and	other	vehicles.	Our	propane	sales	are	typically	split	evenly	between	the	home	heating	market	and	industrial consumers.

Feedstocks	and	special	products	–	We	are	a	producer	and	marketer	of	petrochemicals	and	specialty	products.	Product	availability	varies	by	refinery	and	includes benzene,	cumene,	dilute	naphthalene	oil,	molten	maleic	anhydride,	molten	sulfur,	propylene,	toluene	and	xylene.	We	market	propylene,	cumene	and	sulfur	domestically to	customers	in	the	chemical	industry.	We	sell	maleic	anhydride	throughout	the	United	States	and	Canada.	We	also	have	the	capacity	to	produce	1,400	tons	per	day	of anode	grade	coke	at	our	Robinson	refinery,	which	is	used	to	make	carbon	anodes	for	the	aluminum	smelting	industry,	and	2,700	tons	per	day	of	fuel	grade	coke	at	the Garyville	refinery,	which	is	used	for	power	generation	and	in	miscellaneous	industrial	applications.	In	September	2008,	we	shut	down	our	lubes	facility	in	Catlettsburg, Kentucky,	and	sold	from	inventory	through	December	31,	2008;	therefore,	base	oils,	aromatic	extracts	and	slack	wax	are	no	longer	being	produced	and	marketed.	In addition,	we	have	recently	discontinued	production	and	sales	of	petroleum	pitch	and	aliphatic	solvents.

Heavy	fuel	oil	–	We	produce	and	market	heavy	oil,	also	known	as	fuel	oil,	residual	fuel	or	slurry	at	all	seven	of	our	refineries.	Another	product	of	crude	oil,	heavy oil	is	primarily	used	in	the	utility	and	ship	bunkering	(fuel)	industries,	though	there	are	other	more	specialized	uses	of	the	product.	We	also	sell	heavy	fuel	oil	at	our terminals	in	Wellsville,	Ohio,	and	Chattanooga,	Tennessee.

Asphalt	–	We	have	refinery	based	asphalt	production	capacity	of	up	to	102	mbpd.	We	market	asphalt	through	33	owned	or	leased	terminals	throughout	the	Midwest and	Southeast.	We	have	a	broad	customer	base,	including

approximately	710	asphalt-paving	contractors,	government	entities	(states,	counties,	cities	and	townships)	and	asphalt	roofing	shingle	manufacturers.	We	also	produce asphalt	cements,	polymerized	asphalt,	asphalt	emulsions	and	industrial	asphalts.

# Retail	Marketing

SSA,	our	wholly-owned	subsidiary,	sells	gasoline	and	merchandise	through	owned	and	operated	retail	outlets	primarily	under	the	Speedway®	and	SuperAmerica® brands.	Diesel	fuel	is	also	sold	at	a	number	of	these	outlets.	SSA	retail	outlets	offer	a	wide	variety	of	merchandise,	such	as	prepared	foods,	beverages,	and	non-food items,	as	well	as	a	significant	number	of	proprietary	items.	As	of	December	31,	2008,	SSA	had	1,617	retail	outlets	in	nine	states.	Sales	of	refined	products	through	these retail	outlets	accounted	for	15	percent	of	our	refined	product	sales	volumes	in	2008.	Revenues	from	sales	of	non-petroleum	merchandise	through	these	retail	outlets totaled	$2,838	million	in	2008,	$2,796	million	in	2007	and	$2,706	million	in	2006.	The	demand	for	gasoline	is	seasonal	in	a	majority	of	SSA	markets,	usually	with	the highest	demand	during	the	summer	driving	season.	Profit	levels	from	the	sale	of	merchandise	and	services	tend	to	be	less	volatile	than	profit	levels	from	the	retail	sale	of gasoline	and	diesel	fuel.

In	October	2008,	we	sold	our	interest	in	Pilot	Travel	Centers	LLC	("PTC"),	an	operator	of	travel	centers	in	the	United	States.

# Pipeline	Transportation

We	own	a	system	of	pipelines	through	Marathon	Pipe	Line	LLC	("MPL")	and	Ohio	River	Pipe	Line	LLC	("ORPL"),	our	wholly-owned	subsidiaries.	Our	pipeline systems	transport	crude	oil	and	refined	products	primarily	in	the	Midwest	and	Gulf	Coast	regions	to	our	refineries,	our	terminals	and	other	pipeline	systems.	Our	MPL and	ORPL	wholly-owned	and	undivided	interest	common	carrier	systems	consist	of	1,815	miles	of	crude	oil	lines	and	1,826	miles	of	refined	product	lines	comprising	34 systems	located	in	11	states.	The	MPL	common	carrier	pipeline	network	is	one	of	the	largest	petroleum	pipeline	systems	in	the	United	States,	based	on	total	barrels delivered.	Our	common	carrier	pipeline	systems	are	subject	to	state	and	Federal	Energy	Regulatory	Commission	regulations	and	guidelines,	including	published	tariffs for	the	transportation	of	crude	oil	and	refined	products.	Third	parties	generated	11	percent	of	the	crude	oil	and	refined	product	shipments	on	our	MPL	and	ORPL common	carrier	pipelines	in	2008.	Our	MPL	and	ORPL	common	carrier	pipelines	transported	the	volumes	shown	in	the	following	table	for	each	of	the	last	three	years.

# Pipeline	Barrels	Handled

| (Thousands	of	barrels	per	day) | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Crude\toil\ttrunk\tlines | 1,405 | 1,451 | 1,437 |
| Refined\tproducts\ttrunk\tlines | 960 | 1,049 | 1,101 |
| TOTAL | 2,365 | 2,500 | 2,538 |

We	also	own	176	miles	of	private	crude	oil	pipelines	and	850	miles	of	private	refined	products	pipelines,	and	we	lease	217	miles	of	common	carrier	refined	product pipelines.	We	have	partial	ownership	interests	in	several	pipeline	companies	that	have	approximately	780	miles	of	crude	oil	pipelines	and	3,000	miles	of	refined	products pipelines,	including	about	800	miles	operated	by	MPL.	In	addition,	MPL	operates	most	of	our	private	pipelines	and	985	miles	of	crude	oil	and	160	miles	of	natural	gas pipelines	owned	by	our	E&P	segment.

Our	major	refined	product	lines	include	the	Cardinal	Products	Pipeline	and	the	Wabash	Pipeline.	The	Cardinal	Products	Pipeline	delivers	refined	products	from Kenova,	West	Virginia,	to	Columbus,	Ohio.	The	Wabash	Pipeline	system	delivers	product	from	Robinson,	Illinois,	to	various	terminals	in	the	area	of	Chicago,	Illinois. Other	significant	refined	product	pipelines	owned	and	operated	by	MPL	extend	from:	Robinson,	Illinois,	to	Louisville,	Kentucky;	Garyville,	Louisiana,	to	Zachary, Louisiana;	and	Texas	City,	Texas,	to	Pasadena,	Texas.

In	addition,	as	of	December	31,	2008,	we	had	interests	in	the	following	refined	product	pipelines:

•65	percent	undivided	ownership	interest	in	the	Louisville-Lexington	system,	a	petroleum	products	pipeline	system	extending	from	Louisville	to	Lexington, Kentucky;

•60	percent	interest	in	Muskegon	Pipeline	LLC,	which	owns	a	refined	products	pipeline	extending	from	Griffith,	Indiana,	to	North	Muskegon,	Michigan;

•50	percent	interest	in	Centennial	Pipeline	LLC,	which	owns	a	refined	products	system	connecting	the	Gulf	Coast	region	with	the	Midwest	market;

•17	percent	interest	in	Explorer	Pipeline	Company,	a	refined	products	pipeline	system	extending	from	the	Gulf	Coast	to	the	Midwest;	and

•6	percent	interest	in	Wolverine	Pipe	Line	Company,	a	refined	products	pipeline	system	extending	from	Chicago,	Illinois,	to	Toledo,	Ohio.

Our	major	crude	oil	lines	run	from:	Patoka,	Illinois,	to	Catlettsburg,	Kentucky;	Patoka,	Illinois,	to	Robinson,	Illinois;	Patoka,	Illinois,	to	Lima,	Ohio;	Samaria, Michigan,	to	Detroit,	Michigan;	and	St.	James,	Louisiana,	to	Garyville,	Louisiana.

In	addition,	as	of	December	31,	2008,	we	had	interests	in	the	following	crude	oil	pipelines:

•51	percent	interest	in	LOOP	LLC,	the	owner	and	operator	of	LOOP,	which	is	the	only	U.S.	deepwater	oil	port,	located	18	miles	off	the	coast	of	Louisiana, and	a	crude	oil	pipeline	connecting	the	port	facility	to	storage	caverns	and	tanks	at	Clovelly,	Louisiana;

•59	percent	interest	in	LOCAP	LLC,	which	owns	a	crude	oil	pipeline	connecting	LOOP	and	the	Capline	system;

•37	percent	interest	in	the	Capline	system,	a	large-diameter	crude	oil	pipeline	extending	from	St.	James,	Louisiana,	to	Patoka,	Illinois;

•26	percent	undivided	ownership	interest	in	the	Maumee	Pipeline	System,	a	large	diameter	crude	oil	pipeline	extending	from	Lima,	Ohio,	to	Samaria, Michigan;	and

•17	percent	interest	in	Minnesota	Pipe	Line	Company,	LLC,	which	owns	crude	oil	pipelines	extending	from	Clearbrook,	Minnesota,	to	Cottage	Grove, Minnesota,	which	is	in	the	vicinity	of	our	St.	Paul	Park,	Minnesota	refinery.

We	plan	to	construct,	by	the	year	2012,	a	new	section	of	pipeline	connecting	with	the	existing	crude	line	from	Samaria,	Michigan,	to	Detroit,	Michigan.	This	new section	will	deliver	additional	supplies	of	Canadian	crude	to	our	Detroit	refinery.	The	above	discussion	includes	forward-looking	statements	concerning	the	construction of	a	new	section	of	pipeline	in	Michigan.	Some	factors	that	could	affect	this	project	include	transportation	logistics,	availability	of	materials	and	labor,	unforeseen hazards	such	as	weather	conditions,	delays	in	obtaining	or	conditions	imposed	by	government	or	third-party	approvals	and	other	risks	customarily	associated	with construction	projects.

# Integrated	Gas

Our	integrated	gas	operations	include	natural	gas	liquefaction	and	regasification	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.

# LNG	Operations

We	hold	a	60	percent	interest	in	EGHoldings,	which	is	accounted	for	under	the	equity	method	of	accounting.	In	May	2007,	EGHoldings	completed	construction	of	a 3.7	million	metric	tonnes	per	annum	("mmtpa")	LNG	production	facility	on	Bioko	Island	and	delivered	its	first	cargo	of	LNG.	LNG	from	the	production	facility	is	sold

under	a	3.4	mmtpa,	or	460	mmcfd,	sales	and	purchase	agreement	with	a	17-year	term.	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.	Sales	of	LNG	from	this	production facility	totaled	3.4	metric	tonnes	in	2008.	In	2008	we	continued	discussions	with	the	government	of	Equatorial	Guinea	and	partners	regarding	a	potential	second	LNG production	facility	on	Bioko	Island.

We	also	own	a	30	percent	interest	in	a	Kenai,	Alaska,	natural	gas	liquefaction	plant,	and	lease	two	87,500	cubic	meter	tankers	used	to	transport	LNG	to	customers	in Japan.	Feedstock	for	the	plant	is	supplied	from	a	portion	of	our	natural	gas	production	in	the	Cook	Inlet.	From	the	first	production	in	1969,	we	have	sold	our	share	of	the LNG	plant's	production	under	long-term	contract	with	two	of	Japan's	largest	utility	companies,	with	2008	LNG	deliveries	totaling	40	gross	bcf.	In	June	2008	we,	along with	our	partner,	received	approval	from	the	DOE	to	extend	the	export	license	for	this	natural	gas	liquefaction	plant	through	March	2011.

In	April	2004,	we	began	delivering	LNG	cargoes	at	the	Elba	Island,	Georgia,	LNG	regasification	terminal	pursuant	to	an	LNG	sales	and	purchase	agreement. Under	the	terms	of	the	agreement,	we	have	the	right	to	deliver	and	sell	up	to	58	bcf	of	natural	gas	(as	LNG)	per	year,	through	March	31,	2021,	with	a	possible	extension to	November	30,	2023.	In	September	2004,	we	signed	an	agreement	under	which	we	will	be	supplied	with	58	bcf	of	natural	gas	per	year,	as	LNG,	for	a	minimum	period of	five	years.	The	agreement	allows	for	delivery	of	LNG	at	the	Elba	Island	LNG	regasification	terminal	with	pricing	linked	to	the	Henry	Hub	index.	This	supply agreement	enables	us	to	fully	utilize	our	rights	at	Elba	Island	during	the	period	of	this	agreement,	while	affording	us	the	flexibility	to	commercialize	other	stranded natural	gas	resources	beyond	the	term	of	this	contract.	The	agreement	commenced	in	2005.

# Methanol	Operations

We	own	a	45	percent	interest	in	AMPCO,	which	is	accounted	for	under	the	equity	method	of	accounting.	AMPCO	owns	a	methanol	plant	located	in	Malabo, Equatorial	Guinea.	Feedstock	for	the	plant	is	supplied	from	our	natural	gas	production	from	the	Alba	field.	Sales	of	methanol	from	the	plant	totaled	792,794	metric tonnes	in	2008.	Production	from	the	plant	is	used	to	supply	customers	in	Europe	and	the	United	States.

# Natural	Gas	Technology

We	are	developing	a	range	of	natural	gas	conversion	technologies	that	can	connect	stranded	natural	gas	to	both	conventional	and	transportation	fuel	markets.	Our proprietary	Gas-to-Fuels	("GTF™")	process	offers	the	ability	to	convert	natural	gas	into	premium	fuels	while	bypassing	conventional	intermediate	synthetic	gasification technology.	The	base	patent	for	this	technology	was	awarded	in	2007.

During	2008,	we	entered	into	agreements	with	GRT,	Inc.,	a	Delaware	corporation,	to	cooperate	on	the	advancement	of	gas-to-fuels-related	technology.	This transaction	provides	us	with	access	to	additional	specialized	technical	and	research	personnel	and	lab	facilities,	and	significantly	expanded	the	portfolio	of	patents available	to	us	via	license	and	through	a	cooperative	development	program.	In	addition,	we	have	acquired	a	20	percent	interest	in	GRT,	Inc.

Also,	during	2008,	we	completed	construction	of	a	facility	to	demonstrate	operation	of	the	fully	integrated	GTF™	process	at	a	practical	scale.	We	are	evaluating	the commercialization	of	this	technology	and	have	engaged	an	engineering	contractor	to	provide	engineering	and	design	services	for	using	the	GTF™	technology	on	a commercial	scale.

In	addition	to	GTF™,	we	continue	to	evaluate	the	application	of	other	natural	gas	technologies,	including	LNG	technology	enhancements,	gas	hydrates	and	gas-to- liquids	technology.

The	above	discussion	of	the	Integrated	Gas	segment	contains	forward-looking	statements	with	respect	to	the	possible	expansion	of	the	LNG	production	facility	and expectations	for	a	GTF™	demonstration	facility.	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.	Factors	that	could	potentially	affect	the	GTF™	demonstration	facility	include	construction	delays,	start-up	difficulties	relating	to	scale-up	in	the process	and	unforeseen	difficulties	in	our	testing	program	related	to	moving	from	laboratory	to	practical	scale.	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	the	more	attractive	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	geologists,	geophysicists and	other	specialists.	Based	upon	statistics	compiled	in	the	"2008	Global	Upstream	Performance	Review"	published	by	IHS	Herold	Inc.,	we	rank	ninth	among	U.S.- based	petroleum	companies	on	the	basis	of	2007	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	in	North	America.	There	are	several additional	synthetic	crude	oil	projects	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.

We	must	also	compete	with	a	large	number	of	other	companies	to	acquire	crude	oil	for	refinery	processing	and	in	the	distribution	and	marketing	of	a	full	array	of petroleum	products.	Based	upon	the	"The	Oil	&	Gas	Journal	2009	Worldwide	Refinery	Survey",	we	rank	fifth	among	U.S.	petroleum	companies	on	the	basis	of	U.S. crude	oil	refining	capacity	as	of	December	31,	2008.	We	compete	in	four	distinct	markets	for	the	sale	of	refined	products	–	wholesale,	spot,	branded	and	retail distribution.	We	believe	we	compete	with	about	45	companies	in	the	sale	of	refined	products	to	wholesale	marketing	customers,	including	private-brand	marketers	and large	commercial	and	industrial	consumers;	about	70	companies	in	the	sale	of	refined	products	in	the	spot	market;	ten	refiners	or	marketers	in	the	supply	of	refined products	to	refiner	branded	jobbers	and	dealers;	and	approximately	280	retailers	in	the	retail	sale	of	refined	products.	(A	jobber	is	a	business	who	does	not	carry	out refining	operations,	but	who	supplies	refiner-branded	products	to	gasoline	stations	or	convenience	stores.	Dealers	refer	to	a	retail	service	station	or	convenience	store operator,	affiliated	with	a	brand	identity.)	We	compete	in	the	convenience	store	industry	through	SSA's	retail	outlets.	The	retail	outlets	offer	consumers	gasoline,	diesel fuel	(at	selected	locations)	and	a	broad	mix	of	other	merchandise	and	services.	In	recent	years,	several	nontraditional	fuel	retailers,	such	as	supermarkets,	club	stores	and mass	merchants,	have	affected	the	convenience	store	industry	with	their	entrance	into	the	retail	transportation	fuel	business.

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	while	the	refining	and wholesale	marketing	gross	margin	may	be	adversely	affected	by	crude	oil	price	increases.	Price	differentials	between	sweet	and	sour	crude	oil	also	affect	operating results.	Market	conditions	in	the	oil	and	gas	industry	are	cyclical	and	subject	to	global	economic	and	political	events	and	new	and	changing	governmental	regulations.

# Environmental	Matters

The	Public	Policy	Committee	of	our	Board	of	Directors	is	responsible	for	overseeing	our	position	on	public	issues,	including	environmental	matters.	Our	Corporate Health,	Environment	and	Safety	organization	has	the	responsibility	to	ensure	that	our	operating	organizations	maintain	environmental	compliance	systems	that	are	in accordance	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	Crisis	Management	Team,	composed	primarily	of	senior	management,	which	oversees	the	response	to	any	major	emergency, environmental	or	other	incident	involving	us	or	any	of	our	properties.

Legislation	and	regulations	pertaining	to	climate	change	and	greenhouse	gas	emissions	have	the	potential	to	impact	us.	The	Kyoto	Protocol,	effective	in	2005,	has been	ratified	by	countries	in	which	we	have	or	in	the	future	may	have	operations.	Canadian	federal	and	provincial	laws,	the	U.S.	Energy	Independence	and	Security	Act of	2007,	the	European	Union	requirements	and	California	laws	contain	provisions	related	to	greenhouse	gas	emissions.	Other	climate	change	legislation	and	regulations in	the	United	States,	Canada	and	abroad	are	in	various	stages	of	development	or	implementation.	These	regulations	are	further	along	in	development	in	Alberta,	Canada, and	in	the	European	Union,	where	we	have	significant	operations.	Our	industry	and	businesses

throughout	the	United	States	are	also	awaiting	the	U.S.	Environmental	Protection	Agency's	("EPA")	actions	upon	the	remand	of	the	U.S.	Supreme	Court	decision	in Massachusetts	v.	USEPA,	which	could	have	impacts	on	a	number	of	air	permitting	and	environmental	regulatory	programs.	In	July	2008,	the	EPA	issued	an	Advanced Notice	of	Proposed	Rulemaking	("ANPR")	to	address	the	Supreme	Court	decision	and	to	seek	public	input	on	potential	actions	it	may	take	to	regulate	greenhouse	gas emissions.	Action	by	EPA	on	the	ANPR	is	expected	in	2009.	There	also	is	other	pending	litigation	which	could	affect	whether	EPA	regulates	greenhouse	gas	emissions. In	addition,	a	new	Administration	in	the	U.S.	may	choose	to	address	greenhouse	gas	emissions	through	regulation,	permitting	or	other	action	in	2009.	Our	liquid hydrocarbon,	natural	gas	and	bitumen	production	and	processing	operations	typically	result	in	emissions	of	greenhouse	gases.	Likewise,	emissions	arise	from	our RM&T	operations,	including	the	refining	of	crude	oil	and	the	transportation	of	crude	oil	and	refined	products.	Although	there	may	be	adverse	financial	impact	(including compliance	costs,	potential	permitting	delays	and	potential	reduced	demand	for	crude	oil	or	certain	refined	products)	associated	with	any	legislation,	regulation,	EPA	or other	action,	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	the	additional	measures	and	how	they	will	be	implemented.	Private	party	litigation	has	also	been	brought	against	emitters	of	greenhouse gas	emissions,	but	we	have	not	been	named	in	those	cases.	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.

Our	businesses	are	also	subject	to	numerous	other	laws	and	regulations	relating	to	the	protection	of	the	environment.	These	environmental	laws	and	regulations include	the	Clean	Air	Act	("CAA")	with	respect	to	air	emissions,	the	Clean	Water	Act	("CWA")	with	respect	to	water	discharges,	the	Resource	Conservation	and Recovery	Act	("RCRA")	with	respect	to	solid	and	hazardous	waste	treatment,	storage	and	disposal,	the	Comprehensive	Environmental	Response,	Compensation,	and Liability	Act	("CERCLA")	with	respect	to	releases	and	remediation	of	hazardous	substances	and	the	Oil	Pollution	Act	of	1990	("OPA-90")	with	respect	to	oil	pollution and	response.	In	addition,	many	states	where	we	operate	have	their	own	similar	laws	dealing	with	similar	matters.	New	laws	are	being	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	accurately	defined.	In	some	cases,	they	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	or	conditions	others	have	caused,	or	for	our	acts	that	complied	with	all	applicable	requirements	when	we	performed them.	The	ultimate	impact	of	complying	with	existing	laws	and	regulations	is	not	clearly	known	or	determinable	because	certain	implementing	regulations	for	some environmental	laws	have	not	yet	been	finalized	or,	in	some	instances,	are	undergoing	revision.	These	environmental	laws	and	regulations,	particularly	the	1990 Amendments	to	the	CAA	and	its	implementing	regulations,	new	water	quality	requirements	and	stricter	fuel	regulations,	could	result	in	increased	capital,	operating	and compliance	costs.

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.

Of	particular	significance	to	our	refining	operations	are	EPA	regulations	that	require	reduced	sulfur	levels	in	diesel	fuel	for	off-road	use.	We	have	spent approximately	$120	million	between	2006	and	2008,	and	plan	to	spend	approximately	$50	million	in	2009	on	refinery	investments	to	produce	ultra-low	sulfur	diesel	fuel for	off-road	use,	in	compliance	with	EPA	regulations.	Further,	we	have	estimated	that	we	may	spend	approximately	$1	billion	over	a	five-year	period	beginning	in	2008 to	comply	with	Mobile	Source	Air	Toxics	II	("MSAT	II")	regulations	relating	to	benzene	content	in	refined	products.	We	have	not	finalized	our	strategy	or	cost estimates	to	comply	with	these	requirements.	Our	actual	MSAT	II	expenditures	have	totaled	$76	million	through	December	31,	2008	and	we	expect	to	spend	$200 million	in	2009.	The	cost	estimates	are	forward-looking	statements	and	are	subject	to	change	as	further	work	is	completed	in	2009.

The	EPA	is	in	the	process	of	implementing	regulations	to	address	current	National	Ambient	Air	Quality	Standards	("NAAQS")	for	fine	particulate	emissions	and ozone.	In	connection	with	these	standards,	the	EPA	will	designate	certain	areas	as	"nonattainment,"	meaning	that	the	air	quality	in	such	areas	does	not	meet	the	NAAQS. To	address	these	nonattainment	areas,	the	EPA	proposed	a	rule	in	2004	called	the	Interstate	Air	Quality	Rule	("IAQR")	that	would	require	significant	emissions reductions	in	numerous	states.	The	final	rule,	promulgated	in	2005,	was	renamed	the	Clean	Air	Interstate	Rule	("CAIR").	While	the	EPA	expects	that	states	will	meet their

CAIR	obligations	by	requiring	emissions	reductions	from	electric	generating	units,	states	were	to	have	the	final	say	on	what	sources	they	regulate	to	meet	attainment criteria.	Significant	uncertainty	in	the	final	requirements	of	this	rule	resulted	from	litigation	(State	of	North	Carolina,	et	al.	v.	EPA).	In	July	2008,	the	U.S.	Court	of Appeals	for	the	District	of	Columbia	Circuit	vacated	the	CAIR	in	its	entirety	and	remanded	it	to	EPA	to	promulgate	a	rule	consistent	with	the	Court's	opinion.	In December	2008,	the	Court	modified	its	July	ruling	to	leave	the	CAIR	in	effect	until	EPA	develops	a	new	rule	and	control	program.	It	is	expected	that	the	CAIR	will	be significantly	altered,	and	it	could	result	in	changes	in	emissions	control	strategies.	Our	refinery	operations	are	located	in	affected	states,	and	some	of	these	states	may choose	to	propose	more	stringent	fuels	requirements	to	meet	the	CAIR.	In	addition,	the	EPA	promulgated	a	revised	ozone	standard	in	March	2008,	and	the	EPA	has commenced	the	multi-year	process	to	develop	the	implementing	rules	required	by	the	Clean	Air	Act.	We	cannot	reasonably	estimate	the	final	financial	impact	of	the state	actions	to	implement	the	CAIR	until	the	EPA	has	issued	a	revised	rule	and	states	have	taken	further	action	to	implement	that	rule.	We	also	cannot	reasonably estimate	the	final	financial	impact	of	the	revised	ozone	standard	until	the	implementing	rules	are	established	and	judicial	challenges	over	the	revised	ozone	standard	are resolved.

# Water

We	maintain	numerous	discharge	permits	as	required	under	the	National	Pollutant	Discharge	Elimination	System	program	of	the	CWA	and	have	implemented systems	to	oversee	our	compliance	efforts.	In	addition,	we	are	regulated	under	OPA-90,	which	amended	the	CWA.	Among	other	requirements,	OPA-90	requires	the owner	or	operator	of	a	tank	vessel	or	a	facility	to	maintain	an	emergency	plan	to	respond	to	releases	of	oil	or	hazardous	substances.	Also,	in	case	of	any	such	release, OPA-90	requires	the	responsible	company	to	pay	resulting	removal	costs	and	damages.	OPA-90	also	provides	for	civil	penalties	and	imposes	criminal	sanctions	for violations	of	its	provisions.

Additionally,	OPA-90	requires	that	new	tank	vessels	entering	or	operating	in	U.S.	waters	be	double-hulled	and	that	existing	tank	vessels	that	are	not	double-hulled be	retrofitted	or	removed	from	U.S.	service,	according	to	a	phase-out	schedule.	All	of	the	barges	used	for	river	transport	of	our	raw	materials	and	refined	products	meet the	double-hulled	requirements	of	OPA-90.	We	operate	facilities	at	which	spills	of	oil	and	hazardous	substances	could	occur.	Some	coastal	states	in	which	we	operate have	passed	state	laws	similar	to	OPA-90,	but	with	expanded	liability	provisions,	including	provisions	for	cargo	owner	responsibility	as	well	as	ship	owner	and	operator responsibility.	We	have	implemented	emergency	oil	response	plans	for	all	of	our	components	and	facilities	covered	by	OPA-90,	and	we	have	established	Spill Prevention,	Control	and	Countermeasures	("SPCC")	plans	for	facilities	subject	to	CWA	SPCC	requirements.

# Solid	Waste

We	continue	to	seek	methods	to	minimize	the	generation	of	hazardous	wastes	in	our	operations.	The	Resource	Conservation	and	Recovery	Act	("RCRA") establishes	standards	for	the	management	of	solid	and	hazardous	wastes.	Besides	affecting	waste	disposal	practices,	RCRA	also	addresses	the	environmental	effects	of certain	past	waste	disposal	operations,	the	recycling	of	wastes	and	the	regulation	of	underground	storage	tanks	("USTs")	containing	regulated	substances.	We	have ongoing	RCRA	treatment	and	disposal	operations	at	one	of	our	RM&T	facilities	and	primarily	utilize	offsite	third-party	treatment	and	disposal	facilities.	In	2011, Canada	will	implement	a	ban	on	the	land	application	of	certain	wastes,	and	we	are	developing	options	to	treat	or	dispose	of	these	wastes	consistent	with	these	new restrictions.	Ongoing	waste	handling	and	disposal-related	costs,	however,	are	not	expected	to	be	material.

# Remediation

We	own	or	operate	certain	retail	outlets	where,	during	the	normal	course	of	operations,	releases	of	refined	products	from	USTs	have	occurred.	Federal	and	state laws	require	that	contamination	caused	by	such	releases	at	these	sites	be	assessed	and	remediated	to	meet	applicable	standards.	The	enforcement	of	the	UST	regulations under	RCRA	has	been	delegated	to	the	states,	which	administer	their	own	UST	programs.	Our	obligation	to	remediate	such	contamination	varies,	depending	on	the extent	of	the	releases	and	the	stringency	of	the	laws	and	regulations	of	the	states	in	which	we	operate.	A	portion	of	these	remediation	costs	may	be	recoverable	from	the appropriate	state	UST	reimbursement	funds	once	the	applicable	deductibles	have	been	satisfied.	We	also	have	other	facilities	which	are	subject	to	remediation	under federal	or	state	law.	See	Item	3.	Legal	Proceedings	–	Environmental	Proceedings	–	Other	Proceedings	for	a	discussion	of	these	sites.

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	on	going	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	other	alternate	tailings	management	technologies.	In	February 2009,	the	Alberta	Energy	Resources	Conservation	Board	issued	a	directive	which	more	clearly	defines	criteria	for	managing	oil	sands	tailings.	The	AOSP	Joint	Venture Parties	are	reviewing	this	directive	to	determine	the	impact	on	the	oil	sands	operations	and	the	timeline	for	the	required	compliance.	Increased	compliance	costs	may result	if	tailing	pond	reclamation	technologies	prove	unsuccessful	or	the	directive	requires	additional	measures.

In	2007,	the	U.S.	Congress	passed	the	Energy	Independence	and	Security	Act	("EISA"),	which,	among	other	things,	sets	a	target	of	35	miles	per	gallon	for	the combined	fleet	of	cars	and	light	trucks	in	the	United	States	by	model	year	2020,	and	contains	a	multiple-part	Renewable	Fuel	Standard	("RFS").	The	RFS	was	9.0	billion gallons	of	renewable	fuel	in	2008,	and	is	11.1	billion	gallons	in	2009,	increasing	to	36.0	billion	gallons	by	2022.	In	the	near	term,	the	RFS	will	be	satisfied	primarily with	fuel	ethanol	blended	into	gasoline.	The	RFS	presents	production	and	logistic	challenges	for	both	the	fuel	ethanol	and	petroleum	refining	industries.	The	RFS	has required,	and	may	in	the	future	continue	to	require,	additional	capital	expenditures	or	expenses	by	us	to	accommodate	increased	fuel	ethanol	use.	Within	the	overall	36.0 billion	gallon	RFS,	EISA	establishes	an	advanced	biofuel	RFS	that	begins	with	0.6	billion	gallons	in	2009	and	increases	to	21.0	billion	gallons	by	2022.	Subsets	within the	advanced	biofuel	RFS	include	0.5	billion	gallons	of	biomass-based	diesel	in	2009,	increasing	to	1.0	billion	gallons	in	2012,	and	0.1	billion	gallons	of	cellulosic biofuel	in	2010,	increasing	to	16.0	gallons	by	2022.	The	advanced	biofuels	programs	will	present	specific	challenges	in	that	we	may	have	to	enter	into	arrangements	with other	parties	to	meet	our	obligations	to	use	advanced	biofuels,	including	biomass-based	diesel	and	cellulosic	biofuel,	with	potentially	uncertain	supplies	of	these	new fuels.	There	will	be	compliance	costs	and	uncertainties	regarding	how	we	will	comply	with	the	various	requirements	contained	in	this	law	and	related	regulations.	We may	experience	a	decrease	in	demand	for	refined	petroleum	products	due	to	an	increase	in	combined	fleet	mileage	or	due	to	refined	petroleum	products	being	replaced by	renewable	fuels.

# The	USX	Separation

On	December	31,	2001,	pursuant	to	an	Agreement	and	Plan	of	Reorganization	dated	as	of	July	31,	2001,	Marathon	completed	the	USX	Separation,	in	which:

•its	wholly-owned	subsidiary	United	States	Steel	LLC	converted	into	a	Delaware	corporation	named	United	States	Steel	Corporation	and	became	a	separate, publicly	traded	company;	and

•	 USX	Corporation	changed	its	name	to	Marathon	Oil	Corporation.

As	a	result	of	the	USX	Separation,	Marathon	and	United	States	Steel	are	separate	companies	and	neither	has	any	ownership	interest	in	the	other.

In	connection	with	the	USX	Separation	and	pursuant	to	the	Plan	of	Reorganization,	Marathon	and	United	States	Steel	have	entered	into	a	series	of	agreements governing	their	relationship	after	the	USX	Separation	and	providing	for	the	allocation	of	tax	and	certain	other	liabilities	and	obligations	arising	from	periods	before	the USX	Separation.	The	following	is	a	description	of	the	material	terms	of	one	of	those	agreements.

# Financial	Matters	Agreement

Under	the	financial	matters	agreement,	United	States	Steel	has	assumed	and	agreed	to	discharge	all	of	our	principal	repayment,	interest	payment	and	other obligations	under	the	following,	including	any	amounts	due	on	any	default	or	acceleration	of	any	of	those	obligations,	other	than	any	default	caused	by	us:

•obligations	under	industrial	revenue	bonds	related	to	environmental	projects	for	current	and	former	U.S.	Steel	Group	facilities,	with	maturities	ranging	from 2011	through	2033;

•sale-leaseback	financing	obligations	under	a	lease	for	equipment	at	United	States	Steel's	Fairfield	Works	facility,	with	a	lease	term	to	2012,	subject	to extensions;

•obligations	relating	to	various	lease	arrangements	accounted	for	as	operating	leases	and	various	guarantee	arrangements,	all	of	which	were	assumed	by United	States	Steel;	and

# •certain	other	guarantees.

The	financial	matters	agreement	also	provides	that,	on	or	before	the	tenth	anniversary	of	the	USX	Separation,	United	States	Steel	will	provide	for	our	discharge from	any	remaining	liability	under	any	of	the	assumed	industrial	revenue	bonds.	United	States	Steel	may	accomplish	that	discharge	by	refinancing	or,	to	the	extent	not refinanced,	paying	us	an	amount	equal	to	the	remaining	principal	amount	of	all	accrued	and	unpaid	debt	service	outstanding	on,	and	any	premium	required	to immediately	retire,	the	then	outstanding	industrial	revenue	bonds.

Under	the	financial	matters	agreement,	United	States	Steel	has	all	of	the	existing	contractual	rights	under	the	leases	assumed	from	us,	including	all	rights	related	to purchase	options,	prepayments	or	the	grant	or	release	of	security	interests.	However,	United	States	Steel	has	no	right	to	increase	amounts	due	under	or	lengthen	the	term of	any	of	the	assumed	lease	obligations	without	our	prior	consent	other	than	extensions	set	forth	in	the	terms	of	the	assumed	leases.

The	financial	matters	agreement	requires	us	to	use	commercially	reasonable	efforts	to	assure	compliance	with	all	covenants	and	other	obligations	to	avoid	the occurrence	of	a	default	or	the	acceleration	of	the	payments	on	the	assumed	obligations.	The	agreement	also	obligates	us	to	use	commercially	reasonable	efforts	to	obtain and	maintain	letters	of	credit	and	other	liquidity	arrangements	required	under	the	assumed	obligations.

United	States	Steel's	obligations	to	us	under	the	financial	matters	agreement	are	general	unsecured	obligations	that	rank	equal	to	United	States	Steel's	accounts payable	and	other	general	unsecured	obligations.	The	financial	matters	agreement	does	not	contain	any	financial	covenants	and	United	States	Steel	is	free	to	incur additional	debt,	grant	mortgages	on	or	security	interests	in	its	property	and	sell	or	transfer	assets	without	our	consent.

# 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.	While	no single	customer	accounts	for	more	than	10	percent	of	annual	revenues,	we	have	significant	exposures	to	United	States	Steel	arising	from	the	transaction	discussed	in Note	3	to	the	consolidated	financial	statements.

# 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	30,360	active	employees	as	of	December	31,	2008.	Of	that	number,	19,794	were	employees	of	SSA,	most	of	who	were	employed	at	our	retail	marketing outlets.

Certain	hourly	employees	at	our	Catlettsburg	and	Canton	refineries	are	represented	by	the	United	Steel,	Paper	and	Forestry,	Rubber,	Manufacturing,	Energy,	Allied Industrial	and	Service	Workers	Union	under	labor	agreements	that	expire	on	January	31,	2012.	Negotiations	are	currently	underway	with	the	same	union	in	Texas

City	with	a	contract	expiration	of	March	31,	2009.	The	International	Brotherhood	of	Teamsters	represents	certain	hourly	employees	under	labor	agreements	that	are scheduled	to	expire	on	May	31,	2012	at	our	St.	Paul	Park	refinery	and	January	31,	2011,	at	our	Detroit	refinery.

# Executive	Officers	of	the	Registrant

The	executive	officers	of	Marathon	and	their	ages	as	of	February	1,	2009,	are	as	follows:

Howard	J.	Thill 49 Vice	President,	Investor	Relations	and	Public	Affairs

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

•	 Mr.	Cazalot	was	appointed	president	and	chief	executive	officer	effective	January	2002.

•	 Ms.	Clark	was	appointed	executive	vice	president	and	chief	financial	officer	effective	January	2005.	Ms.	Clark	joined	Marathon	in	January	2004	as	senior vice	president	and	chief	financial	officer.

•	 Mr.	Heminger	was	appointed	executive	vice	president,	downstream	effective	January	2005.	Mr.	Heminger	has	served	as	president	of	MPC	since	September 2001.

•	 Mr.	Hinchman	was	appointed	senior	vice	president,	worldwide	production	effective	January	2002	and	was	appointed	to	his	current	position	effective	April	1, 2008.

•	 Mr.	Howard	was	appointed	senior	vice	president,	corporate	affairs	effective	January	2002.

•	 Mr.	Reinbolt	was	appointed	vice	president,	finance	and	treasurer	effective	January	2002.

•	 Mr.	Roberts	joined	Marathon	in	June	2006	as	senior	vice	president,	business	development	and	was	appointed	executive	vice	president,	upstream	in	April 2008.	Prior	to	joining	Marathon,	he	was	employed	by	BG	Group	from	2003	as	executive	vice	president/managing	director	responsible	for	Asia	and	the Middle	East.

•	 Mr.	Schwind	was	appointed	vice	president,	general	counsel	and	secretary	effective	January	2002.

•	 Mr.	Stewart	was	appointed	vice	president,	accounting	and	controller	effective	May	2006.	Mr.	Stewart	previously	served	as	controller	from	July	2005	to	April 2006.	Prior	to	his	appointment	as	controller,	Mr.	Stewart	was	director	of	internal	audit	from	January	2002	to	June	2005.

•	 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,	including	the	Corporate	Governance	Principles	and	Charters	for	the	Audit	and	Finance	Committee,	Compensation	Committee, Corporate	Governance	and	Nominating	Committee	and	Public	Policy	Committee,	can	be	found	at	www.marathon.com.	In	addition,	our	Code	of	Business	Conduct	and Code	of	Ethics	for	Senior	Financial	Officers	are	available	at	http://www.marathon.com/Investor_Center/Corporate_Governance/.

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	the	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,	or	in	refining	and	wholesale	marketing	gross	margins,	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	and	refining	and	wholesale	marketing	gross	margins	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	and	the	margins	we	realize	on	our	refined	products.	Historically,	the markets	for	liquid	hydrocarbons,	natural	gas	and	refined	products	have	been	volatile	and	may	continue	to	be	volatile	in	the	future.	Many	of	the	factors	influencing	prices of	liquid	hydrocarbons	and	natural	gas	and	refining	and	wholesale	marketing	gross	margins	are	beyond	our	control.	These	factors	include:

•	 worldwide	and	domestic	supplies	of	and	demand	for	liquid	hydrocarbons,	natural	gas	and	refined	products;

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

•the	cost	of	crude	oil	to	be	manufactured	into	refined	products;

•utilization	rates	of	refineries;

•natural	gas	and	electricity	supply	costs	incurred	by	refineries

•the	ability	of	the	members	of	the	Organization	of	Petroleum	Exporting	Countries	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,	as	well	as	on	refining	and	wholesale	marketing	gross	margins, 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	or	refining	and	wholesale	marketing	gross	margins	could	require	us to	reduce	our	capital	expenditures	or	impair	the	carrying	value	of	our	assets.

Estimates	of	liquid	hydrocarbon,	natural	gas	and	bitumen	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	bitumen	reserves.

The	proved	liquid	hydrocarbon	and	natural	gas	reserves	information	included	in	this	report	has	been	derived	from	engineering	estimates.	Those	estimates	were prepared	by	our	in-house	teams	of	reservoir	engineers	and	geoscience	professionals	and	reviewed,	on	a	selected	basis,	by	our	Corporate	Reserves	Group	or	third-party consultants	we	have	retained.	The	estimates	were	calculated	using	liquid	hydrocarbon	and	natural	gas	prices	in	effect	as	of	December	31,	2008,	as	well	as	other conditions	in	existence	as	of	that	date.	Any	significant	future	price

changes	will	have	a	material	effect	on	the	quantity	and	present	value	of	our	proved	liquid	hydrocarbon	and	natural	gas	reserves.	Future	reserve	revisions	could	also	result from	changes	in,	among	other	things,	governmental	regulation	and	severance	and	other	production	taxes.

Proved	liquid	hydrocarbon	and	natural	gas	reserve	estimation	is	a	subjective	process	that	involves	estimating	volumes	to	be	recovered	from	underground accumulations	of	liquid	hydrocarbons	and	natural	gas	that	cannot	be	directly	measured.	Estimates	of	economically	recoverable	liquid	hydrocarbon	and	natural	gas reserves	and	of	future	net	cash	flows	depend	upon	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;

•the	assumed	effects	of	regulation	by	governmental	agencies;	and

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

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

•the	amount	and	timing	of	liquid	hydrocarbon	and	natural	gas	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	and	natural	gas	reserves	reflected	in	this	report	should	not	be	considered	as	the	market value	of	the	reserves	attributable	to	our	liquid	hydrocarbon	and	natural	gas	properties.	As	required	by	SEC	Rule	4-10	of	Regulation	S-X,	the	estimated	discounted	future net	revenues	from	our	proved	liquid	hydrocarbon	and	natural	gas	reserves	are	based	on	prices	and	costs	as	of	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.

The	proved	bitumen	reserves	information	included	in	this	report	has	also	been	derived	from	engineering	estimates.	Reserves	related	to	mining	operations	are defined	as	that	part	of	a	mineral	deposit	which	could	be	economically	and	legally	extracted	or	produced	at	the	time	of	the	reserve	determination.	Proved	reserves	are measured	by	various	testing	and	sampling	methods.	Bitumen	reserves	as	of	December	31,	2008	were	estimated	by	third-party	consultants,	using	volumetric	estimation techniques	similar	to	those	used	in	estimating	liquid	hydrocarbon	and	natural	gas	reserves	and	are	subject	to	many	of	the	same	uncertainties	discussed	above,	except	that estimates	of	bitumen	reserves	are	based	on	average	annual	prices	consistent	with	industry	practice	in	Canada.	The	estimated	quantity	of	net	proved	bitumen	reserves	is based	on	a	number	of	assumptions,	including	(among	others)	commodity	prices,	volumes	in-place,	presently	known	physical	data,	recoverability	of	bitumen,	industry economic	conditions,	levels	of	cash	flow	from	operations	and	other	operating	considerations.	To	the	extent	these	assumptions	prove	inaccurate,	actual	recoveries	could be	different	than	current	estimates.	Future	proved	bitumen	reserve	revisions	could	also	result	from	changes	in,	among	other	things,	governmental	regulation	and taxation.

# 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.

# The	availability	of	crude	oil	and	increases	in	crude	oil	prices	may	reduce	our	refining,	marketing	and	transportation	profitability	and	refining	and	wholesale marketing	gross	margins.

The	profitability	of	our	refining,	marketing	and	transportation	operations	depends	largely	on	the	margin	between	the	cost	of	crude	oil	and	other	feedstocks	that	we refine	and	the	selling	prices	we	obtain	for	refined	products.	We	are	a	net	purchaser	of	crude	oil.	A	significant	portion	of	our	crude	oil	is	purchased	from	various	foreign national	oil	companies,	producing	companies	and	trading	companies,	including	suppliers	from	the	Middle	East.	These	purchases	are	subject	to	political,	geographic	and economic	risks	and	possible	terrorist	activities	attendant	to	doing	business	with	suppliers	located	in	that	area	of	the	world.	Our	overall	refining,	marketing	and transportation	profitability	could	be	adversely	affected	by	the	availability	of	supply	and	rising	crude	oil	and	other	feedstock	prices	which	we	do	not	recover	in	the marketplace.	Refining	and	wholesale	marketing	gross	margins	historically	have	been	volatile	and	vary	with	the	level	of	economic	activity	in	the	various	marketing	areas, the	regulatory	climate,	logistical	capabilities	and	the	available	supply	of	refined	products.

# We	will	continue	to	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	profitability	could	be	materially	reduced.

Our	businesses	are	subject	to	numerous	laws	and	regulations	relating	to	the	protection	of	the	environment,	including	those	relating	to	the	discharge	of	materials	into the	environment,	waste	management,	pollution	prevention	measures,	greenhouse	gas	emissions,	and	characteristics	and	composition	of	gasoline	and	diesel	fuels,	as	well as	laws	and	regulations	relating	to	public	and	employee	safety	and	health	and	facility	security.	We	have	incurred	and	will	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	and	services,	our	operating	results	will	be	adversely	affected.	The	specific	impact	of	these	laws	and	regulations	on	us	and	our	competitors	may vary	depending	on	a	number	of	factors,	including	the	age	and	location	of	operating	facilities,	marketing	areas	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.	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	could	result	in	civil	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	the	United	States,	Canada	and	European	Union.	These include	proposed	federal	legislation	and	state	actions	to	develop	statewide	or	regional	programs,	each	of	which	could	impose	reductions	in	greenhouse	gas	emissions. These	actions	could	result	in	increased	costs	to	(1)	operate	and	maintain	our	facilities,	(2)	install	new	emission	controls	at	our	refineries	and	other	facilities	and (3)	administer	and	manage	any	potential	greenhouse	gas	emissions	or	carbon	tax	program.	Although	uncertain,	these	developments	could	increase	our	costs,	reduce	the demand	for	the	products	we	sell	and	create	delays	in	our	obtaining	air	pollution	permits	for	new	or	modified	facilities.

Our	operations	and	those	of	our	predecessors	could	expose	us	to	civil	claims	by	third	parties	for	alleged	liability	resulting	from	contamination	of	the	environment	or personal	injuries	caused	by	releases	of	hazardous

substances.	For	example,	we	have	been,	and	presently	are,	a	defendant	in	various	litigation	and	other	proceedings	involving	products	liability	and	other	claims	related	to alleged	contamination	of	groundwater	with	the	oxygenate	methyl	tertiary	butyl	ether,	or	MTBE.	We	may	become	involved	in	further	litigation	or	other	proceedings,	or we	may	be	held	responsible	in	existing	or	future	litigation	or	proceedings,	the	costs	of	which	could	be	material.

Environmental	laws	are	subject	to	frequent	change	and	many	of	them	have	become	more	stringent.	In	some	cases,	they	can	impose	liability	for	the	entire	cost	of cleanup	on	any	responsible	party,	without	regard	to	negligence	or	fault,	and	impose	liability	on	us	for	the	conduct	of	others	or	conditions	others	have	caused,	or	for	our acts	that	complied	with	all	applicable	requirements	when	we	performed	them.

In	2007,	the	U.S.	Congress	passed	the	Energy	Independence	and	Security	Act	("EISA"),	which,	among	other	things,	sets	a	target	of	35	miles	per	gallon	for	the combined	fleet	of	cars	and	light	trucks	in	the	United	States	by	model	year	2020,	and	contains	a	multiple-part	Renewable	Fuel	Standard	("RFS").	The	RFS	was	9.0	billion gallons	of	renewable	fuel	in	2008,	and	is	11.1	billion	gallons	in	2009,	increasing	to	36.0	billion	gallons	by	2022.	In	the	near	term,	the	RFS	will	be	satisfied	primarily with	fuel	ethanol	blended	into	gasoline.	The	RFS	presents	production	and	logistics	challenges	for	both	the	fuel	ethanol	and	petroleum	refining	industries.	The	RFS	has required,	and	may	in	the	future	continue	to	require,	additional	capital	expenditures	or	expenses	by	us	to	accommodate	increased	fuel	ethanol	use.	The	advanced	biofuels programs	will	present	specific	challenges	in	that	we	may	have	to	enter	into	arrangements	with	other	parties	to	meet	our	obligations	to	use	advanced	biofuels,	including biomass-based	diesel	and	cellulosic	biofuel,	with	potentially	uncertain	supplies	of	these	new	fuels.	There	will	be	compliance	costs	and	uncertainties	regarding	how	we will	comply	with	the	various	requirements	contained	in	this	law	and	related	regulations.	We	may	experience	a	decrease	in	demand	for	refined	petroleum	products	due	to an	increase	in	combined	fleet	mileage	per	gallon	or	due	to	refined	petroleum	products	being	replaced	by	renewable	fuels.	In	addition,	tax	incentives	and	other	subsidies have	made	renewable	fuels	more	competitive	with	refined	products	than	they	otherwise	would	have	been	which	may	have	reduced	and	may	further	reduce	refined product	margins	and	refined	products'	ability	to	compete	with	renewable	fuels.

# The	recent	distress	in	the	financial	markets	may	impact	our	ability	to	obtain	future	financing	and	could	adversely	affect	entities	with	which	we	do	business.

In	the	future	we	may	require	financing	to	grow	our	business.	Financial	institutions	participate	in	our	revolving	credit	facility	and	provide	us	with	business	insurance coverage,	cash	management	services,	commercial	letters	of	credit	and	short-term	investments.	The	recent	distress	affecting	the	financial	markets	and	the	possibility	that financial	institutions	may	consolidate	or	go	bankrupt	has	reduced	levels	of	activity	in	the	credit	markets.	This	could	diminish	the	amount	of	financing	available	to companies.	In	addition,	such	turmoil	in	the	financial	markets	could	significantly	increase	our	costs	associated	with	borrowing.	Our	liquidity	and	our	ability	to	access	the credit	or	capital	markets	may	also	be	adversely	affected	by	changes	in	the	financial	markets	and	the	global	economy.	Continuing	turmoil	in	the	financial	markets	could make	it	more	difficult	for	us	to	access	capital,	sell	assets,	refinance	our	existing	indebtedness,	enter	into	agreements	for	new	indebtedness	or	obtain	funding	through	the issuance	of	our	securities.	In	addition,	there	could	be	a	number	of	follow-on	effects	from	the	credit	crisis	on	us,	including	insolvency	of	customers,	key	suppliers	and other	counterparties	to	our	commodity	and	foreign	exchange	derivative	instruments.

# Worldwide	political	and	economic	developments	could	damage	our	operations	and	materially	reduce	our	profitability	and	cash	flows.

Local	political	and	economic	factors	in	international	markets	could	have	a	material	adverse	effect	on	us.	A	total	of	63	percent	of	our	liquid	hydrocarbon	and	natural gas	sales	volumes	in	2008	was	derived	from	production	outside	the	United	States	and	70	percent	of	our	proved	liquid	hydrocarbon	and	natural	gas	reserves	as	of December	31,	2008,	were	located	outside	the	United	States.	All	of	our	bitumen	production	and	proved	reserves	are	located	in	Canada.	In	addition,	a	significant	portion of	the	feedstock	requirements	for	our	refineries	is	satisfied	through	supplies	originating	in	Saudi	Arabia,	Kuwait,	Canada,	Mexico	and	various	other	foreign	countries. We	are,	therefore,	subject	to	the	political,	geographic	and	economic	risks	and	possible	terrorist	activities	attendant	to	doing	business	with	suppliers	located	in,	and supplies	originating	from,	those	areas.	There	are	many	risks	associated	with	operations	in	international	markets,	including	changes	in	foreign	governmental	policies relating	to	liquid	hydrocarbon,	natural	gas,	bitumen	or	refined	product	pricing	and	taxation,	other	political,	economic	or	diplomatic	developments	and	international monetary	fluctuations.	These	risks	include:

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

•the	possibility	that	a	foreign	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.

Continued	hostilities	in	the	Middle	East	and	the	occurrence	or	threat	of	future	terrorist	attacks	could	adversely	affect	the	economies	of	the	United	States	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,	natural	gas	and	refined	products.	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	United States	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.

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

Our	exploration	and	production	operations	are	subject	to	unplanned	occurrences,	including	blowouts,	explosions,	fires,	loss	of	well	control,	spills,	hurricanes	and other	adverse	weather,	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.	In	addition,	our	refining,	marketing	and	transportation	operations	are subject	to	business	interruptions	due	to	scheduled	refinery	turnarounds	and	unplanned	events	such	as	explosions,	fires,	pipeline	ruptures	or	other	interruptions,	crude	oil or	refined	product	spills,	severe	weather	and	labor	disputes.	Our	operations	are	also	subject	to	the	additional	hazards	of	pollution,	releases	of	toxic	gas	and	other environmental	hazards	and	risks,	as	well	as	hazards	of	marine	operations,	such	as	capsizing,	collision,	acts	of	piracy	and	damage	or	loss	from	severe	weather	conditions. 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.	Certain	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	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	or	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,	products	liability,	consumer	credit	or	privacy	laws,	product	pricing	or	antitrust	laws	or	any	other	laws	or	regulations that	apply	to	our	operations.	While	an	adverse	outcome	in	most	litigation	matters	would	not	be	expected	to	be	material	to	us,	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.	There	has been	a	trend	in	recent	years	of	litigation	by	attorneys	general	and	other	government	officials	seeking	to	recover	civil	damages	from	companies.	We	are	defending litigation	of	that	type	and	anticipate	that	we	will	be	required	to	defend	new	litigation	of	that	type	in	the	future.	In	addition	to	substantial	liability,	litigation	may	also	seek injunctive	relief	which	could	have	an	adverse	effect	on	our	future	operations.

# If	Ashland	fails	to	pay	its	taxes,	we	could	be	responsible	for	satisfying	various	tax	obligations	of	Ashland.

As	a	result	of	the	transactions	in	which	we	acquired	the	minority	interest	in	MPC	from	Ashland	in	2005,	Marathon	is	severally	liable	for	federal	income	taxes	(and in	some	cases	for	certain	state	taxes)	of	Ashland	for	tax	years	still	open	as	of	the	date	we	completed	the	transactions.	We	have	entered	into	a	tax	matters	agreement	with Ashland,	which	provides	that:

•	 We	will	be	responsible	for	the	tax	liabilities	of	the	Marathon	group	of	companies,	including	the	tax	liabilities	of	MPC	and	the	other	companies	and businesses	we	acquired	in	the	transactions	(for	periods	after	the	completion	of	the	transactions);	and

•	 Ashland	will	generally	be	responsible	for	the	tax	liabilities	of	the	Ashland	group	of	companies	before	the	completion	of	the	transactions,	and	the	income taxes	attributable	to	Ashland's	interest	in	MPC	before	the	completion	of	the	transactions.	However,	under	certain	circumstances	we	will	have	several	liability for	those	tax	liabilities	owed	by	Ashland	to	various	taxing	authorities,	including	the	Internal	Revenue	Service.

If	Ashland	fails	to	pay	any	tax	obligation	for	which	we	are	severally	liable,	we	may	be	required	to	satisfy	this	tax	obligation.	That	would	leave	us	in	the	position	of having	to	seek	indemnification	from	Ashland.	In	that	event,	our	indemnification	claims	against	Ashland	would	constitute	general	unsecured	claims,	which	would	be effectively	subordinate	to	the	claims	of	secured	creditors	of	Ashland,	and	we	would	be	subject	to	collection	risk	associated	with	collecting	unsecured	debt	from	Ashland.

# We	are	required	to	pay	Ashland	for	deductions	relating	to	various	contingent	liabilities	of	Ashland,	which	could	be	material.

We	are	required	to	claim	tax	deductions	for	certain	contingent	liabilities	that	will	be	paid	by	Ashland	after	completion	of	the	transactions.	Under	the	tax	matters agreement,	we	are	required	to	pay	the	benefit	of	those	deductions	to	Ashland,	with	the	computation	and	payment	terms	for	such	tax	benefit	payments	divided	into	two "baskets,"	as	described	below:

Basket	One	–	This	applies	to	the	first	$30	million	of	contingent	liability	deductions	(increased	by	inflation	each	year	up	to	a	maximum	of	$60	million)	that	we	may claim	in	each	year	for	the	first	20	years	following	the	acquisition.	The	benefit	of	Basket	One	deductions	is	determined	by	multiplying	the	amount	of	the	deduction	by	32 percent	(or,	if	different,	by	a	percentage	equal	to	three	percentage	points	less	than	the	highest	federal	income	tax	rate	during	the	applicable	tax	year).	We	are	obligated	to pay	this	amount	to	Ashland.	The	computation	and	payment	of	Basket	One	amounts	does	not	depend	on	our	ability	to	generate	actual	tax	savings	from	the	use	of	the contingent	liability	deductions	in	Basket	One.	Upon	specified	events	related	to	Ashland	(or	after	20	years),	the	contingent	liability	deductions	that	would	otherwise	have been	compensated	under	Basket	One	will	be	taken	into	account	in	Basket	Two.	In	addition,	Basket	One	applies	only	for	federal	income	tax	purposes;	state,	local	or foreign	tax	benefits	attributable	to	specified	liability	deductions	will	be	compensated	only	under	Basket	Two.

Because	we	are	required	to	make	payments	to	Ashland	whether	or	not	we	generate	any	actual	tax	savings	from	the	Basket	One	contingent	liability	deductions,	the amount	of	our	tax	benefit	payments	to	Ashland	with	respect	to	Basket	One	contingent	liability	deductions	may	exceed	the	aggregate	tax	benefits	that	we	derive	from these	deductions.	We	are	obligated	to	make	these	payments	to	Ashland	even	if	we	do	not	have	sufficient	taxable	income	to	realize	any	benefit	for	the	deductions.

Basket	Two	–	All	contingent	liability	deductions	relating	to	Ashland's	pre-transactions	operations	that	are	not	subject	to	Basket	One	are	considered	and compensated	under	Basket	Two.	The	benefit	of	Basket	Two	deductions	is	determined	on	a	"with	and	without"	basis;	that	is,	the	contingent	liability	deductions	are treated	as	the	last	deductions	used	by	the	Marathon	group.	Thus,	if	the	Marathon	group	has	deductions,	tax	credits	or	other	tax	benefits	of	its	own,	it	will	be	deemed	to use	them	to	the	maximum	extent	possible	before	it	will	be	deemed	to	use	the	contingent	liability	deductions.	To	the	extent	that	we	have	the	capacity	to	use	the	contingent liability	deductions	based	on	this	methodology,	the	actual	amount	of	tax	saved	by	the	Marathon	group	through	the	use	of	the	contingent	liability	deductions	will	be calculated	and	paid	to	Ashland.	Because	Basket	Two	amounts	are	calculated	based	on	the	actual	tax	saved	by	the	Marathon	group	from	the	use	of	Basket	Two deductions,	those	amounts	are	subject	to	recalculation	in	the	event	there	is	a	change	in	the	Marathon	group's	tax	liability	for	a	particular	year.	This	could	occur	because of	audit	adjustments	or	carrybacks	of	losses	or	credits	from	other	years,	for	example.	To	the	extent	that	such	a	recalculation	results	in	a	smaller	Basket	Two	benefit	with respect	to	a	contingent	liability	deduction	for	which	Ashland	has	already	received	compensation,	Ashland	is	required	to	repay

such	compensation	to	Marathon.	In	the	event	we	become	entitled	to	any	repayment,	we	would	be	subject	to	collection	risks	associated	with	collecting	an	unsecured	claim from	Ashland.

# If	the	transactions	resulting	in	our	acquisition	of	the	minority	interest	in	MPC	that	was	previously	owned	by	Ashland	were	found	to	constitute	a	fraudulent transfer	or	conveyance,	we	could	be	required	to	provide	additional	consideration	to	Ashland	or	to	return	a	portion	of	interest	in	MPC,	and	either	of	those results	could	have	a	material	adverse	effect	on	us.

In	a	bankruptcy	case	or	lawsuit	initiated	by	one	or	more	creditors	or	a	representative	of	creditors	of	Ashland,	a	court	may	review	our	2005	transactions	with Ashland	under	state	fraudulent	transfer	or	conveyance	laws.	Under	those	laws,	the	transactions	would	be	deemed	fraudulent	if	the	court	determined	that	the	transactions were	undertaken	for	the	purpose	of	hindering,	delaying	or	defrauding	creditors	or	that	the	transactions	were	constructively	fraudulent.	If	the	transactions	were	found	to be	a	fraudulent	transfer	or	conveyance,	we	might	be	required	to	provide	additional	consideration	to	Ashland	or	to	return	all	or	a	portion	of	the	interest	in	MPC	and	the other	assets	we	acquired	from	Ashland.

Under	the	laws	of	most	states,	a	transaction	could	be	held	to	be	constructively	fraudulent	if	a	court	determined	that:

•the	transferor	received	less	than	"reasonably	equivalent	value"	or,	in	some	jurisdictions,	less	than	"fair	consideration"	or	"valuable	consideration";	and

•the	transferor:

•	 was	insolvent	at	the	time	of	the	transfer	or	was	rendered	insolvent	by	the	transfer;

•	 was	engaged,	or	was	about	to	engage,	in	a	business	or	transaction	for	which	its	remaining	property	constituted	unreasonably	small	capital;	or

•intended	to	incur,	or	believed	it	would	incur,	debts	beyond	its	ability	to	pay	as	those	debts	matured.

In	connection	with	our	transactions	with	Ashland	completed	in	2005,	we	delivered	part	of	the	overall	consideration	(specifically,	shares	of	Marathon	common	stock having	a	value	of	$915	million)	to	Ashland's	shareholders.	In	order	to	help	establish	that	Ashland	received	reasonably	equivalent	value	or	fair	consideration	from	us	in the	transactions,	we	obtained	a	written	opinion	from	a	nationally	recognized	appraisal	firm	to	the	effect	that	Ashland	received	amounts	that	were	reasonably	equivalent to	the	combined	value	of	Ashland's	interest	in	MPC	and	the	other	assets	we	acquired.	We	also	obtained	a	favorable	opinion	from	that	appraisal	firm	relating	to	various financial	tests	that	supported	our	conclusion	and	Ashland's	representation	to	us	that	Ashland	was	not	insolvent	either	before	or	after	giving	effect	to	the	closing	of	the transactions.	Those	opinions	were	based	on	specific	information	provided	to	the	appraisal	firm	and	were	subject	to	various	assumptions,	including	assumptions	relating to	Ashland's	existing	and	contingent	liabilities	and	insurance	coverage.	Although	we	are	confident	in	our	conclusions	regarding	(1)	Ashland's	receipt	of	reasonably equivalent	value	or	fair	consideration	and	(2)	Ashland's	solvency,	it	should	be	noted	that	the	valuation	of	any	business	and	a	determination	of	the	solvency	of	any	entity involve	numerous	assumptions	and	uncertainties,	and	it	is	possible	that	a	court	could	disagree	with	our	conclusions.

If	United	States	Steel	fails	to	perform	any	of	its	material	obligations	to	which	we	have	financial	exposure,	we	could	be	required	to	pay	those	obligations,	and	any such	payment	could	materially	reduce	our	cash	flows	and	profitability	and	impair	our	financial	condition.

In	connection	with	the	separation	of	United	States	Steel	from	Marathon,	United	States	Steel	agreed	to	hold	Marathon	harmless	from	and	against	various	liabilities. While	we	cannot	estimate	some	of	these	liabilities,	the	portion	of	these	liabilities	that	we	can	estimate	amounts	to	$513	million	as	of	December	31,	2008,	including accrued	interest	of	$8	million.	If	United	States	Steel	fails	to	satisfy	any	of	those	obligations,	we	would	be	required	to	satisfy	them	and	seek	indemnification	from	United States	Steel.	In	that	event,	our	indemnification	claims	against	United	States	Steel	would	constitute	general	unsecured	claims,	effectively	subordinate	to	the	claims	of secured	creditors	of	United	States	Steel.

The	steel	business	is	highly	competitive	and	a	large	number	of	industry	participants	have	sought	protection	under	bankruptcy	laws	in	the	past.	The	enforceability	of our	claims	against	United	States	Steel	could	become	subject	to	the	effect	of	any	bankruptcy,	fraudulent	conveyance	or	transfer	or	other	law	affecting	creditors'	rights generally,	or	of	general	principles	of	equity,	which	might	become	applicable	to	those	claims	or	other	claims	arising	from	the	facts	and	circumstances	in	which	the separation	was	effected.

# 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	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	those	where	we are	not	the	operator.	We	could	have	limited	influence	over	and	control	of	the	behaviors	and	performance	of	these	operations.	This	could	affect	our	operational performance,	financial	position	and	reputation.

# We	may	issue	preferred	stock	whose	terms	could	dilute	the	voting	power	or	reduce	the	value	of	Marathon	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	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	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,	refineries,	pipeline systems	and	other	important	physical	properties	have	been	described	by	segment	under	Item	1.	Business.	Except	for	oil	and	gas	producing	properties	and	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	and	natural	gas	sales	volumes	and	net	bitumen	production	volumes	are	set	forth	in	Item	8.	Financial	Statements	and	Supplementary	Data	– Supplemental	Statistics.	Estimated	net	proved	liquid	hydrocarbon	and	natural	gas	reserves	are	set	forth	in	Item	8.	Financial	Statements	and	Supplementary	Data	– Supplementary	Information	on	Oil	and	Gas	Producing	Activities	–	Estimated	Quantities	of	Proved	Oil	and	Gas	Reserves	and	estimated	net	proved	bitumen	reserves	are set	forth	in	Item	1.	Business	–	Oil	Sands	Mining.	The	basis	for	estimating	these	reserves	is	discussed	in	Item	7.	Management's	Discussion	and	Analysis	of	Financial Condition	and	Results	of	Operations	–	Critical	Accounting	Estimates	–	Estimated	Net	Recoverable	Reserve	Quantities	–	Proved	Liquid	Hydrocarbon	and	Natural	Gas Reserves	and	–	Proved	Bitumen	Reserves.

# Item	3. Legal	Proceedings

We	are	the	subject	of,	or	a	party	to,	a	number	of	pending	or	threatened	legal	actions,	contingencies	and	commitments	involving	a	variety	of	matters,	including	laws and	regulations	relating	to	the	environment.	Certain	of	these	matters	are	included	below.	The	ultimate	resolution	of	these	contingencies	could,	individually	or	in	the aggregate,	be	material.	However,	we	believe	that	we	will	remain	a	viable	and	competitive	enterprise	even	though	it	is	possible	that	these	contingencies	could	be	resolved unfavorably.

# MTBE	Litigation

We	are	a	defendant,	along	with	other	refining	companies,	in	20	cases	arising	in	three	states	alleging	damages	for	methyl	tertiary-butyl	ether	("MTBE") contamination.	We	have	also	received	seven	Toxic	Substances	Control	Act	notice	letters	involving	potential	claims	in	two	states.	Such	notice	letters	are	often	followed by	litigation.	Like	the	cases	that	were	settled	in	2008,	the	remaining	MTBE	cases	are	consolidated	in	a	multidistrict	litigation	in	the	Southern	District	of	New	York	for pretrial	proceedings.	Nineteen	of	the	remaining	cases	allege	damages	to	water

supply	wells,	similar	to	the	damages	claimed	in	the	settled	cases.	In	the	other	remaining	case,	the	State	of	New	Jersey	is	seeking	natural	resources	damages	allegedly resulting	from	contamination	of	groundwater	by	MTBE.	This	is	the	only	MTBE	contamination	case	in	which	we	are	a	defendant	and	natural	resources	damages	are sought.	We	are	vigorously	defending	these	cases.	We,	along	with	a	number	of	other	defendants,	have	engaged	in	settlement	discussions	related	to	the	majority	of	the cases	in	which	we	are	a	defendant.	We	do	not	expect	our	share	of	liability,	if	any,	for	the	remaining	cases	to	significantly	impact	our	consolidated	results	of	operations, financial	position	or	cash	flows.

# Natural	Gas	Royalty	Litigation

We	are	currently	a	party	in	two	qui	tam	cases,	which	allege	that	federal	and	Indian	lessees	violated	the	False	Claims	Act	with	respect	to	the	reporting	and	payment of	royalties	on	natural	gas	and	natural	gas	liquids.	A	qui	tam	action	is	an	action	in	which	the	relator	files	suit	on	behalf	of	himself	as	well	as	the	federal	government.	One case	is	U.S.	ex	rel	Harrold	E.	Wright	v.	Agip	Petroleum	Co.	et	al,	which	is	primarily	a	gas	valuation	case.	A	tentative	settlement	agreement	has	been	reached.	Such settlement	is	not	expected	to	significantly	impact	our	consolidated	results	of	operations,	financial	position	or	cash	flows.	The	other	case	is	U.S.	ex	rel	Jack	Grynberg	v. Alaska	Pipeline,	et	al.	involving	allegations	of	gas	measurement.	This	case	was	dismissed	by	the	trial	court	and	is	currently	on	appeal	to	the	10th	Circuit	Court	of Appeals.	The	outcome	of	this	case	is	not	expected	to	significantly	impact	our	consolidated	results	of	operations,	financial	position	or	cash	flows.

# Product	Contamination	Litigation

A	lawsuit	filed	in	the	United	States	District	Court	for	the	Southern	District	of	West	Virginia	alleges	that	our	Catlettsburg,	Kentucky	refinery	distributed contaminated	gasoline	to	wholesalers	and	retailers	for	a	period	prior	to	August	2003,	causing	permanent	damage	to	storage	tanks,	dispensers	and	related	equipment, resulting	in	lost	profits,	business	disruption	and	personal	and	real	property	damages.	Following	the	incident,	we	conducted	remediation	operations	at	affected	facilities, and	we	deny	that	any	permanent	damages	resulted	from	the	incident.	Class	action	certification	was	granted	in	August	2007.	We	have	entered	into	a	tentative	settlement agreement	in	this	case.	Notice	of	the	proposed	settlement	has	been	sent	to	the	class	members.	Approval	by	the	court	after	a	fairness	hearing	is	required	before	the settlement	can	be	finalized.	The	fairness	hearing	is	scheduled	in	the	first	quarter	of	2009.	The	proposed	settlement	will	not	significantly	impact	our	consolidated	results of	operations,	financial	position	or	cash	flows.

# Environmental	Proceedings

# U.S.	EPA	Litigation

In	2006,	we	and	other	oil	and	gas	companies	joined	the	State	of	Wyoming	in	filing	a	petition	for	review	against	the	U.S.	EPA	in	the	U.S.	District	Court	for	the District	of	Wyoming.	These	actions	seek	a	court	order	mandating	the	U.S.	EPA	to	disapprove	Montana's	2006	amended	water	quality	standards,	on	grounds	that	the standards	lack	sound	scientific	justification,	they	are	arbitrary	and	capricious,	and	were	adopted	contrary	to	law.	The	water	quality	amendments	at	issue	could	require more	stringent	discharge	limits	and	have	the	potential	to	require	certain	Wyoming	coal	bed	methane	operations	to	perform	more	costly	water	treatment	or	inject produced	water.	Approval	of	these	standards	could	delay	or	prevent	obtaining	permits	needed	to	discharge	produced	water	to	streams	flowing	from	Wyoming	into Montana.	In	February	2008,	U.S.	EPA	approved	Montana's	2006	regulations,	and	we	amended	our	petition	for	review.	The	court	stayed	this	case	while	the	U.S.	EPA mediated	the	matter	between	Montana,	Wyoming	and	the	Northern	Cheyenne	tribe.	Mediation	has	been	unsuccessful	and	the	parties	expect	the	Court	to	set	a	briefing schedule	for	summary	judgment	motions.

# Montana	Litigation

In	June	2006,	we	filed	a	complaint	for	declaratory	judgment	in	Montana	State	District	Court	against	the	Montana	Board	of	Environmental	Review	("MBER")	and the	Montana	Department	of	Environmental	Quality,	seeking	to	set	aside	and	declare	invalid	certain	regulations	of	the	MBER	that	single	out	the	coal	bed	natural	gas industry	and	a	few	streams	in	eastern	Montana	for	excessively	severe	and	unjustified	restrictions	for	surface	water	discharges	of	produced	water	from	coal	bed	methane operations.	None	of	the	streams	affected	by	the	regulations	suffers	impairment	from	coal	bed	natural	gas	discharges.	The	court,	in	deferring	to	the	MBER's	discretion, upheld	the	MBER's	regulations.	This	decision	was	affirmed	by	the	Montana	Supreme	Court;	this	decision	in	the	meanwhile	does	not	impact	our	operations	due	to pending	litigation	with	U.S.	EPA	in	Wyoming	Federal	District	Court.

# Colorado	Litigation

In	2008,	the	State	of	Colorado,	through	its	Department	of	Public	Health	and	Environment,	filed	a	state	court	suit	against	us	and	others	alleging	violations	of	storm water	requirements	in	and	around	an	upstream	production	facility.	The	State	seeks	penalties	above	$100,000.	We	continue	to	work	with	the	state	in	an	effort	to	resolve this	matter.

# New	Mexico	Litigation

In	December	2008,	the	State	of	New	Mexico	filed	a	state	court	suit	against	us	alleging	violations	of	the	New	Mexico	Air	Quality	Control	Act.	The	lawsuit	arose	out of	a	February	2008	notice	of	violation	issued	to	our	Indian	Basin	Natural	Gas	Plant.	We	believe	there	has	been	no	adverse	impact	to	public	health	or	the	environment, having	implemented	voluntary	emission	reduction	measures	over	the	years.	The	state	seeks	penalties	above	$100,000.	We	continue	to	work	with	the	state	in	an	effort	to resolve	the	matter.

# Powder	River	Basin	Litigation

The	U.S.	Bureau	of	Land	Management	("BLM")	completed	multi-year	reviews	of	potential	environmental	impacts	from	coal	bed	methane	development	on	federal lands	in	the	Powder	River	Basin,	including	those	in	Wyoming.	The	BLM	signed	a	Record	of	Decision	("ROD")	on	April	30,	2003,	supporting	increased	coal	bed methane	development.	Plaintiff	environmental	and	other	groups	filed	suit	in	May	2003	in	federal	court	against	the	BLM	to	stop	coal	bed	methane	development	on	federal lands	in	the	Powder	River	Basin	until	the	BLM	conducted	additional	environmental	impact	studies.	Marathon	intervened	as	a	party	in	the	ongoing	litigation	before	the Wyoming	Federal	District	Court.	As	these	lawsuits	to	delay	energy	development	in	the	Powder	River	Basin	progressed	through	the	courts,	the	Wyoming	BLM	continued to	process	permits	to	drill	under	the	ROD.	During	the	last	quarter	of	2008,	the	Court	ruled	in	BLM's	favor,	finding	its	environmental	studies	and	stewardship	were adequate	and	protective	under	federal	law.	The	plaintiffs	have	appealed	this	ruling	to	the	10th	Circuit	Court	of	Appeals.

# Other	Environmental	Proceedings

The	following	is	a	summary	of	proceedings	involving	us	that	were	pending	or	contemplated	as	of	December	31,	2008,	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	("PRPs")	for	each	site	include	present	and	former	owners	and operators	of,	transporters	to	and	generators	of	the	substances	at	the	site.	Liability	is	strict	and	can	be	joint	and	several.	Because	of	various	factors	including	the	difficulty of	identifying	the	responsible	parties	for	any	particular	site,	the	complexity	of	determining	the	relative	liability	among	them,	the	uncertainty	as	to	the	most	desirable remediation	techniques	and	the	amount	of	damages	and	clean-up	costs	and	the	time	period	during	which	such	costs	may	be	incurred,	we	are	unable	to	reasonably estimate	our	ultimate	cost	of	compliance	with	CERCLA.

The	projections	of	spending	for	and/or	timing	of	completion	of	specific	projects	provided	in	the	following	paragraphs	are	forward-looking	statements.	These forward-looking	statements	are	based	on	certain	assumptions	including,	but	not	limited	to,	the	factors	provided	in	the	preceding	paragraph.	To	the	extent	that	these assumptions	prove	to	be	inaccurate,	future	spending	for	and/or	timing	of	completion	of	environmental	projects	may	differ	materially	from	those	stated	in	the	forward- looking	statements.

As	of	December	31,	2008,	we	had	been	identified	as	a	PRP	at	a	total	of	nine	CERCLA	waste	sites	and	we	may	be	a	PRP	at	four	additional	sites	where	we	have received	information	requests	or	other	indications	but	we	do	not	have	sufficient	information	to	establish	liability.	We	are	at	various	stages	of	case	development	at	the nine	PRP	sites	with	some	site	information	being	preliminary	and	incomplete	and	subject	to	change,	but	we	currently	estimate	our	liability	will	be	under	$200,000	at	four sites,	under	$1	million	at	one	site,	under	$2	million	at	two	sites,	and	under	$4	million	at	the	remaining	two	sites.

There	are	also	119	sites,	excluding	retail	marketing	outlets,	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	six	of	these	sites	will	be	under	$100,000	per	site,	that	58	sites	have	potential costs	between	$100,000	and	$1	million	per	site	and	that	29	sites	may	involve	remediation	costs	between	$1	million	and	$5	million	per	site.	Ten	sites	have	incurred remediation	costs	of	more	than	$5	million	per	site.	There	are	16	of	these	sites	for	which	Ashland	retains	responsibility	to	us	for	remediation,	subject	to	caps	and	other requirements	contained	in	the	agreements	with	Ashland	related	to	the	acquisition	of	Ashland's	minority	interest	in	Marathon	Petroleum	Company	LLC	in	2005.	We estimate	that	we	will	be	responsible	for	nearly	$18	million	in	remediation	costs	at	these	sites	which	will	not	be	reimbursed	by	Ashland,	and	we	have	included	this amount	in	our	accrued	environmental	remediation	liabilities.

There	is	one	site	that	involves	a	remediation	program	in	cooperation	with	the	Michigan	Department	of	Environmental	Quality	("MDEQ")	at	a	closed	and dismantled	refinery	site	located	near	Muskegon,	Michigan.	During	the	next	28	years,	we	anticipate	spending	approximately	$4.8	million	in	remediation	costs	at	this	site. In	2009,	interim	remediation	measures	will	continue	to	occur	and	appropriate	site	characterization	and	risk-based	assessments	necessary	for	closure	will	be	refined	and may	change	the	estimated	future	expenditures	for	this	site.	The	closure	strategy	being	developed	for	this	site	and	ongoing	work	at	the	site	are	subject	to	approval	by	the MDEQ.	Expenditures	for	remedial	measures	in	2008	and	2007	were	$434,000	and	$524,000,	respectively,	with	expenditures	for	remedial	measures	in	2009	expected	to be	approximately	$1.6	million.

We	are	subject	to	a	pending	enforcement	matter	with	the	Illinois	Environmental	Protection	Agency	and	the	Illinois	Attorney	General's	Office	since	2002	concerning self-reporting	of	possible	emission	exceedences	and	permitting	issues	related	to	storage	tanks	at	the	Robinson,	Illinois,	refinery.	There	were	no	developments	in	this matter	in	2008.

During	2001,	we	entered	into	a	New	Source	Review	consent	decree	and	settlement	of	alleged	Clean	Air	Act	("CAA")	and	other	violations	with	the	U.S.	EPA covering	all	of	our	refineries.	The	settlement	committed	us	to	specific	control	technologies	and	implementation	schedules	for	environmental	expenditures	and improvements	to	our	refineries	over	approximately	an	eight-year	period,	which	are	now	substantially	complete.	In	addition,	we	have	been	working	on	certain	agreed- upon	supplemental	environmental	projects	as	part	of	this	settlement	of	an	enforcement	action	for	alleged	CAA	violations	and	these	have	been	completed.	As	part	of	this consent	decree,	we	were	required	to	conduct	evaluations	of	refinery	benzene	waste	air	pollution	programs	(benzene	waste	"NESHAPS").	Subject	to	entering	a	formal consent	decree	or	further	amendment	of	the	New	Source	Review	consent	decree	to	memorialize	our	understanding,	we	have	agreed	with	the	U.S.	Department	of	Justice and	U.S.	EPA	to	pay	a	civil	penalty	of	$408,000	and	conduct	supplemental	environmental	projects	of	approximately	$1.1	million,	as	part	of	a	settlement	of	an enforcement	action	for	alleged	CAA	violations	relating	to	benzene	waste	NESHAPS.	We	hope	to	enter	into	a	formal	consent	decree	or	amendment	to	resolve	these matters	in	2009.

In	May	2008,	the	Texas	Commission	on	Environmental	Quality	("TCEQ")	performed	a	benzene	waste	NESHAPS	inspection	at	the	Texas	City	Refinery.	The TCEQ	subsequently	issued	a	notice	of	enforcement	and	a	proposed	agreed	order	seeking	$143,000	in	penalties.	We	hope	to	resolve	this	matter	with	the	TCEQ	in	2009.

The	U.S.	Occupational	Safety	and	Health	Administration	("OSHA")	previously	announced	a	National	Emphasis	Program	to	inspect	most	domestic	oil	refineries. The	inspections	began	in	2007	and	focused	on	compliance	with	the	OSHA	Process	Safety	Management	requirements.	OSHA	or	state-equivalent	agencies	have conducted	inspections	at	the	Canton,	Robinson,	Catlettsburg,	Detroit	and	Texas	City	refineries	with	agreed–to	penalties	of	$321,500	and	$135,000	imposed	in	Canton (2007)	and	Texas	City	(2008),	respectively.	No	penalties	were	imposed	as	a	result	of	the	other	inspections.	Inspections	at	St.	Paul	Park	(2009)	and	Garyville	(2010)	may occur	and	further	enforcement	action	by	OSHA	or	equivalent	state	agency	may	result

In	November	2008,	the	U.S.	EPA	issued	a	notice	of	violation	for	oil	spills	occurring	at	the	Catlettsburg	Refinery	in	2004	and	2008.	Subject	to	entering	a	formal consent	decree	to	memorialize	our	understanding,	we	have	agreed	with	the	U.S.	EPA	to	pay	a	civil	penalty	of	$118,000.	We	hope	to	enter	into	a	formal	consent	decree	to resolve	these	matters	in	2009.

# SEC	Investigation	Relating	to	Equatorial	Guinea

By	letter	dated	July	15,	2004,	the	SEC	notified	us	that	it	was	conducting	an	inquiry	into	payments	made	to	the	government	of	Equatorial	Guinea,	or	to	officials	and persons	affiliated	with	officials	of	the	government	of	Equatorial	Guinea.	By	letter	dated	February	13,	2009,	the	SEC	further	notified	us	that	they	completed	their investigation	and	did	not	intend	to	recommend	any	enforcement	action	in	this	matter.

# Item	4. Submission	of	Matters	to	a	Vote	of	Security	Holders

# 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	common	stock	is	traded	is	the	New	York	Stock	Exchange.	Marathon	common	stock	is	also	traded	on	the	Chicago	Stock Exchange.	The	frequency	and	amount	of	dividends	paid	during	the	last	two	years	is	set	forth	in	Item	8.	Financial	Statements	and	Supplementary	Data	–	Selected Quarterly	Financial	Data.

As	of	January	31,	2009,	there	were	57,275	registered	holders	of	Marathon	common	stock.

Information	concerning	the	quarterly	high	and	low	sales	prices	for	Marathon	common	stock	follows:

|  | 2008 | 2008 | 2007(a) | 2007(a) |
| :--- | :--- | :--- | :--- | :--- |
|  | High | Low | High | Low |
| Quarter\t1 | $61.88 | $45.23 | $102.56 | $83.43 |
| Quarter\t2 | 55.05 | 44.92 | 132.51 | 59.74 |
| Quarter\t3 | 52.78 | 37.48 | 65.04 | 49.24 |
| Quarter\t4 | 38.81 | 19.58 | 62.59 | 53.34 |
| (a) |  |  |  |  |

(a) Prices	are	as	published	each	day;	therefore,	those	before	June	18,	2007	do	not	reflect	the	two-for-one	stock	split.

# Recent	Sales	of	Unregistered	Securities

In	October	2007,	we	issued	29,127,260	shares	of	Marathon	common	stock	to	Western	shareholders	in	connection	with	our	acquisition	of	Western.	This	issuance	of Marathon	common	stock	was	exempt	from	the	registration	requirements	of	the	Securities	Act	of	1933,	as	amended,	by	virtue	of	Section	3(a)(10).

# Dividends

Our	Board	of	Directors	intends	to	declare	and	pay	dividends	on	Marathon	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	common	stock,	the	Board	will	rely	on	our	consolidated	financial	statements	of	Marathon.	Dividends	on	Marathon	common	stock	are	limited	to	our	legally available	funds.

# Issuer	Purchases	of	Equity	Securities

The	following	table	provides	information	about	purchases	by	Marathon	and	its	affiliated	purchaser	during	the	quarter	ended	December	31,	2008,	of	equity securities	that	are	registered	by	Marathon	pursuant	to	Section	12	of	the	Securities	Exchange	Act	of	1934:

|  | Column	(a) | Column	(b) | Column	(c) | Column	(d) |
| :--- | :--- | :--- | :--- | :--- |
|  |  |  | Total\tNumber\tof | Approximate |
|  | Total |  | Shares\tPurchased | Dollar\tValue\tof |
|  | Number\tof |  | as\tPart\tof | Shares\tthat\tMay |
|  | Shares | Average | Publicly | Yet\tBe\tPurchased |
|  | Purchased(a) | Price\tPaid | Announced\tPlans | Under\tthe\tPlans |
| Period | (b) | per\tShare | or\tPrograms(d) | or\tPrograms(d) |
| 10/01/08\t–\t10/31/08 | 27,687 | $38.24 | \t\t\t\t– | $2,080,366,711 |
| 11/01/08\t–\t11/30/08 | 24,957 | $29.22 | \t\t\t\t– | $2,080,366,711 |
| 12/01/08\t–\t12/31/08 | 11,040(c) | $24.26 | \t\t\t\t– | $2,080,366,711 |
| Total | 63,684 | $32.28 | \t\t\t\t– |  |
| (a) |  |  |  |  |

(a) 63,672	shares	of	restricted	stock	were	delivered	by	employees	to	Marathon,	upon	vesting,	to	satisfy	tax	withholding	requirements.

(b) Under	the	terms	of	the	transactions	whereby	we	acquired	the	minority	interest	in	MPC	and	other	businesses	from	Ashland,	Marathon	paid	Ashland	shareholders	cash	in	lieu	of	issuing	fractional	shares	of Marathon's	common	stock	to	which	such	holders	would	otherwise	be	entitled.	We	acquired	12	shares	due	to	acquisition	share	exchanges	and	Ashland	share	transfers	pending	at	the	closing	of	the	transaction.

(c) The	Marathon	Oil	Corporation	Dividend	Reinvestment	and	Direct	Stock	Purchase	Plan	(the	"Dividend	Reinvestment	Plan")	was	temporarily	suspended	effective	December	1,	2008,	and	remains	suspended.	No purchases	of	Marathon	common	stock	to	satisfy	the	requirements	for	dividend	reinvestment	were	made	by	the	administrator	of	the	Dividend	Reinvestment	Plan	after	November	30,	2008.	The	determination	to suspend	the	Dividend	Reinvestment	Plan	was	due	to	the	evaluation	of	the	separation	of	our	businesses	as	described	in	Item	7.	Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of– Evaluation	of	Separation	of	Marathon's	Businesses.

(d) 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,	2008,	66	million	split	adjusted	common	shares had	been	acquired	at	a	cost	of	$2,922	million,	which	includes	transaction	fees	and	commissions	that	are	not	reported	in	the	table	above.	No	share	repurchases	were	made	in	the	fourth	quarter	of	2008.

# Item	6. Selected	Financial	Data

| (Dollars	in	millions,	except	as	noted) | 2008(a) | 2007(b)(c) | 2006 | 2005(d) | 2004 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Statement\tof\tIncome\tData: |  |  |  |  |  |
| Revenues(e) | $ \t77,193 | $64,552 | $64,896 | $62,986 | $49,465 |
| Income\tfrom\tcontinuing\toperations | 3,528 | 3,948 | 4,957 | 3,006 | 1,294 |
| Net\tincome | 3,528 | 3,956 | 5,234 | 3,032 | 1,261 |
| Basic\tper\tshare\tdata: |  |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $4.97 | $5.72 | $6.92 | $4.22 | $1.92 |
| Net\tincome | $4.97 | $5.73 | $7.31 | $4.26 | $1.87 |
| Diluted\tper\tshare\tdata: |  |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $4.95 | $5.68 | $6.87 | $4.19 | $1.91 |
| Net\tincome | $4.95 | $5.69 | $7.25 | $4.22 | $1.86 |
| Statement\tof\tCash\tFlows\tData: |  |  |  |  |  |
| Capital\texpenditures\tfrom\tcontinuing\toperations | $7,146 | $4,466 | $3,433 | $2,796 | $2,141 |
| Dividends\tpaid | 681 | 637 | 547 | 436 | 348 |
| Dividends\tper\tshare | $0.96 | $0.92 | $0.76 | $0.60 | $0.51 |
| Balance\tSheet\tData\tas\tof\tDecember\t31: |  |  |  |  |  |
| Total\tassets | $ \t42,686 | $42,746 | $30,831 | $28,498 | $23,423 |
| Total\tlong-term\tdebt,\tincluding\tcapitalized\tleases | 7,087 | 6,084 | 3,061 | 3,698 | 4,057 |
| Includes\ta\t$1,412\tmillion\timpairment\tof\tgoodwill\trelated\tto\tthe\tOSM\treporting\tunit,\t(see\tNote\t16\tto\tthe\tconsolidated\tfinancial\tstatements)\tand\ta\t$25\tmillion\tafter-tax\timpairment\t($40\tmillion\tpretax)\trelated\tto\tour\n(a) |  |  |  |  |  |

(a) Includes	a	$1,412	million	impairment	of	goodwill	related	to	the	OSM	reporting	unit,	(see	Note	16	to	the	consolidated	financial	statements)	and	a	$25	million	after-tax	impairment	($40	million	pretax)	related	to	our investments	in	ethanol	producing	companies	(see	Note	14	to	the	consolidated	financial	statements). (b) On	October	18,	2007,	we	completed	the	acquisition	of	all	the	outstanding	shares	of	Western.	See	Note	6	to	the	consolidated	financial	statements.

(c) 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'	capital	expenditures	subsequent	to April	2007	are	not	included	in	our	capital	expenditures.	See	Note	4	to	the	consolidated	financial	statements. (d) On	June	30,	2005,	we	acquired	the	38	percent	ownership	interest	in	MPC	previously	held	by	Ashland,	making	it	wholly-owned	by	Marathon.

(e) Effective	April	1,	2006,	we	changed	our	accounting	for	matching	buy/sell	transactions.	This	change	had	no	effect	on	income	from	continuing	operations	or	net	income,	but	the	revenues	and	cost	of	revenues recognized	after	April	1,	2006,	are	less	than	the	amounts	that	would	have	been	recognized	under	previous	accounting	practices.	See	Note	2	to	the	consolidated	financial	statements.

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

We	are	a	global	integrated	energy	company	with	significant	operations	in	the	U.S.,	Canada,	Africa	and	Europe.	Our	operations	are	organized	into	four	reportable segments:

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

•	 Oil	Sands	Mining	("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	by-products.

•	 Refining,	Marketing	&	Transportation	("RM&T")	which	refines,	markets	and	transports	crude	oil	and	petroleum	products,	primarily	in	the	Midwest,	upper Great	Plains,	Gulf	Coast	and	southeastern	regions	of	the	United	States.

•Integrated	Gas	("IG")	which	markets	and	transports	products	manufactured	from	natural	gas,	such	as	liquefied	natural	gas	("LNG")	and	methanol,	on	a worldwide	basis,	and	is	developing	other	projects	to	link	stranded	natural	gas	resources	with	key	demand	areas.

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

We	hold	a	60	percent	interest	in	Equatorial	Guinea	LNG	Holdings	Limited	("EGHoldings").	As	discussed	in	Note	4	to	the	consolidated	financial	statements, effective	May	1,	2007,	we	ceased	consolidating	EGHoldings.	Our	investment	is	accounted	for	using	the	equity	method	of	accounting.	Unless	specifically	noted,	amounts presented	for	the	Integrated	Gas	segment	for	periods	prior	to	May	1,	2007,	include	amounts	related	to	the	minority	interests.

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,	Item	6.	Selected	Financial	Data	and	Item	8.	Financial	Statements	and	Supplementary	Data.

# Evaluation	of	Separation	of	Marathon's	Businesses

On	July	31,	2008,	we	announced	that	our	board	of	directors	would	be	evaluating	the	separation	of	Marathon	into	two	independent,	publicly-traded	companies,	each focused	on	its	own	set	of	business	opportunities.	On	February	3,	2009,	we	further	announced	that	our	board	concluded	it	is	in	the	best	interest	of	our	shareholders	to remain	a	fully	integrated	energy	company.

# Overview

Prevailing	prices	for	the	various	qualities	of	crude	oil	and	natural	gas	that	we	produce	significantly	impact	our	revenues	and	cash	flows.	Prices	were	extremely volatile	in	2008	with	the	following	table	listing	high	and	low	spot	prices	during	the	year	for	key	benchmarks.

On	average,	crude	oil	prices	in	2008	were	higher	than	in	2007.	Crude	oil	prices	climbed	rapidly	through	the	first	half	of	2008	based	upon	expected	strong	global demand,	a	declining	dollar,	ongoing	concerns	about	supplies	of

crude	oil,	and	political	unrest	in	the	Middle	East	and	elsewhere.	Later	in	2008,	crude	oil	prices	dropped	more	rapidly	than	they	had	climbed	as	the	U.S.	dollar	rebounded and	other	countries	entered	recessions	which	decreased	demand.

During	2008,	the	average	spot	price	per	barrel	for	WTI	was	$99.75,	up	from	an	average	of	$72.41	in	2007,	but	ended	the	year	at	$44.60.	The	average	spot	price	per barrel	for	Brent	was	$97.26	in	2008,	up	from	an	average	of	$72.39	in	2007,	but	ended	the	year	at	$36.55.	The	differential	between	WTI	and	Brent	average	prices widened	to	$2.49	in	2008	from	$0.02	in	2007.	Our	domestic	crude	oil	production	is	on	average	heavier	and	higher	in	sulfur	content	than	light	sweet	WTI.	Heavier	and higher	sulfur	crude	oil	(commonly	referred	to	as	heavy	sour	crude	oil)	sells	at	a	discount	to	light	sweet	crude	oil.	Our	international	crude	oil	production	is	relatively sweet	and	is	generally	sold	in	relation	to	the	Brent	crude	oil	benchmark.

Natural	gas	prices	on	average	were	higher	in	2008	than	in	2007.	A	significant	portion	of	our	U.S.	lower	48	states	natural	gas	production	is	sold	at	bid-week	prices or	first-of-month	indices	relative	to	our	specific	producing	areas.	The	average	Henry	Hub	first-of-month	price	index	was	$2.18	per	thousand	cubic	feet	("mcf")	higher	in 2008	than	the	2007	average.	Natural	gas	sales	in	Alaska	are	subject	to	term	contracts.	Our	other	major	natural	gas-producing	regions	are	Europe	and	Equatorial	Guinea, where	large	portions	of	our	natural	gas	sales	are	subject	to	term	contracts,	making	realized	prices	in	these	areas	less	volatile.	As	we	sell	larger	quantities	of	natural	gas from	these	regions,	to	the	extent	that	these	fixed	prices	are	lower	than	prevailing	prices,	our	reported	average	natural	gas	prices	realizations	may	decrease.

E&P	segment	income	during	2008	was	up	57	percent	from	2007,	with	revenue	increases	tied	to	these	increases	in	average	commodity	prices	accounting	for	almost half	of	the	income	improvement.	Liquid	hydrocarbon	and	natural	gas	sales	volumes	were	also	higher	in	2008	than	2007.

Oil	Sands	Mining	segment	revenues	correlate	with	prevailing	market	prices	for	the	various	qualities	of	synthetic	crude	oil	and	vacuum	gas	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	mine	or	upgrader.	During	2008,	our	average	realized	price	for synthetic	crude	oil	and	vacuum	gas	oil	was	$91.90	per	barrel,	up	from	2007,	but	ended	the	year	at	$24.97	per	barrel	impacted	by	a	heavier	yield	in	December	and	a seasonal	decrease	in	the	value	of	our	heavy	output.

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	AECO	natural	gas	sales	index	and	crude	prices	respectively.

The	table	below	shows	benchmark	prices	that	impact	both	our	revenues	and	variable	costs,	listing	high	and	low	spot	prices	during	the	year.

Our	OSM	segment	reported	income	of	$258	million	for	2008,	reflecting	synthetic	crude	oil	and	vacuum	gas	oil	sales	averaging	32	mboepd.	Derivative	instruments intended	to	hedge	price	risk	on	future	sales	have	impacted	revenues	in	the	periods	presented,	with	net	gains	of	$48	million	in	2008	and	net	losses	of	$53	million	in	2007. In	the	first	quarter	of	2009,	we	entered	into	derivative	instruments	which	effectively	offset	certain	of	our	open	derivative	positions.

RM&T	segment	income	depends	largely	on	our	refining	and	wholesale	marketing	gross	margin,	refinery	throughputs,	retail	marketing	gross	margins	for	gasoline, distillates	and	merchandise,	and	the	profitability	of	our	pipeline	transportation	operations.

Our	refining	and	wholesale	marketing	gross	margin	is	the	difference	between	the	prices	of	refined	products	sold	and	the	costs	of	crude	oil	and	other	charge	and blendstocks	refined,	including	the	costs	to	transport	these	inputs	to	our	refineries,	the	costs	of	purchased	products	and	manufacturing	expenses,	including	depreciation. The	crack	spread	is	a	measure	of	the	difference	between	market	prices	for	refined	products	and	crude	oil,	commonly	used	by	the	industry	as	an	indicator	of	the	impact	of price	on	the	refining	margin.	Crack	spreads	can	fluctuate	significantly,	particularly	when	prices	of	refined	products	do	not	move	in	the	same	relationship	as	the	cost	of crude	oil.	As	a	performance	benchmark	and	a	comparison	with	other	industry	participants,	we	calculate	Midwest	(Chicago)	and	U.S.	Gulf	Coast	crack	spreads	that	we feel	most	closely	track	our	operations	and	slate	of	products.	Posted	Light	Louisiana	Sweet	("LLS")	prices	and	a	6-3-2-1	ratio	of	products	(6	barrels	of	crude	oil producing	3	barrels	of	gasoline,	2	barrels	of	distillate	and	1	barrel	of	residual	fuel)	are	used	for	the	crack	spread	calculation.	The	following	table	lists	calculated	average crack	spreads	by	quarter	for	the	Midwest	(Chicago)	and	Gulf	Coast	markets	in	2008.

# Crack	spreads

| (Dollars	per	barrel) | 1st	Qtr | 2nd	Qtr | 3rd	Qtr | 4th	Qtr | 2008 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Chicago\tLLS\t6-3-2-1 | $0.07 | $2.71 | $7.81 | $2.31 | $3.27 |
| US\tGulf\tCoast\tLLS\t6-3-2-1 | $1.39 | $1.99 | $6.32 | ($ 0.01) | $2.45 |

In	addition	to	the	market	changes	indicated	by	the	crack	spreads,	our	refining	and	wholesale	marketing	gross	margin	is	impacted	by	factors	such	as	the	types	of crude	oil	and	other	charge	and	blendstocks	processed,	the	selling	prices	realized	for	refined	products,	the	impact	of	commodity	derivative	instruments	used	to	mitigate price	risk	and	the	cost	of	purchased	products	for	resale.	We	process	significant	amounts	of	sour	crude	oil	which	can	enhance	our	profitability	compared	to	certain	of	our competitors,	as	sour	crude	oil	typically	can	be	purchased	at	a	discount	to	sweet	crude	oil.	Finally,	our	refining	and	wholesale	marketing	gross	margin	is	impacted	by changes	in	manufacturing	costs,	which	are	primarily	driven	by	the	level	of	maintenance	activities	at	the	refineries	and	the	price	of	purchased	natural	gas	used	for	plant fuel.

Our	2008	refining	and	wholesale	marketing	gross	margin	was	the	key	driver	of	the	43	percent	decrease	in	RM&T	segment	income	when	compared	to	2007.	Our average	refining	and	wholesale	marketing	gross	margin	per	gallon	decreased	37	percent,	to	11.66	cents	in	2008	from	18.48	cents	in	2007,	primarily	due	to	the	significant and	rapid	increases	in	crude	oil	prices	early	in	2008	and	lagging	wholesale	price	realizations.

Our	retail	marketing	gross	margin	for	gasoline	and	distillates,	which	is	the	difference	between	the	ultimate	price	paid	by	consumers	and	the	cost	of	refined	products, including	secondary	transportation	and	consumer	excise	taxes,	also	impacts	RM&T	segment	profitability.	While	on	average	demand	has	been	increasing	for	several years,	there	are	numerous	factors	including	local	competition,	seasonal	demand	fluctuations,	the	available	wholesale	supply,	the	level	of	economic	activity	in	our marketing	areas	and	weather	conditions	that	impact	gasoline	and	distillate	demand	throughout	the	year.	In	2008,	demand	began	to	drop	due	to	the	combination	of significant	increases	in	retail	petroleum	prices	and	a	broad	slowdown	in	general	activity.	The	gross	margin	on	merchandise	sold	at	retail	outlets	has	historically	been more	constant.

The	profitability	of	our	pipeline	transportation	operations	is	primarily	dependent	on	the	volumes	shipped	through	our	crude	oil	and	refined	products	pipelines.	The volume	of	crude	oil	that	we	transport	is	directly	affected	by	the	supply	of,	and	refiner	demand	for,	crude	oil	in	the	markets	served	directly	by	our	crude	oil	pipelines.	Key factors	in	this	supply	and	demand	balance	are	the	production	levels	of	crude	oil	by	producers,	the	availability	and	cost	of	alternative	modes	of	transportation,	and refinery	and	transportation	system	maintenance	levels.	The	volume	of	refined	products	that	we	transport	is	directly	affected	by	the	production	levels	of,	and	user	demand for,	refined	products	in	the	markets	served	by	our	refined	product	pipelines.	In	most	of	our	markets,	demand	for	gasoline	peaks	during	the	summer	and	declines	during the	fall	and	winter	months,	whereas	distillate	demand	is	more	ratable	throughout	the	year.	As	with	crude	oil,	other	transportation	alternatives	and	system	maintenance levels	influence	refined	product	movements.

Our	integrated	gas	strategy	is	to	link	stranded	natural	gas	resources	with	areas	where	a	supply	gap	is	emerging	due	to	declining	production	and	growing	demand. Our	integrated	gas	operations	include	marketing	and	transportation	of	products	manufactured	from	natural	gas,	such	as	LNG	and	methanol,	primarily	in	the	U.S.,	Europe and	West	Africa.

Our	most	significant	LNG	investment	is	our	60	percent	ownership	in	a	production	facility	in	Equatorial	Guinea,	which	sells	LNG	under	a	long-term	contract	at prices	tied	to	Henry	Hub	natural	gas	prices.	In	2008,	its

first	full	year	of	operations,	the	plant	sold	3.4	million	metric	tonnes.	Our	share	of	sales	was	2.1	million	tonnes.	Industry	estimates	of	2008	LNG	trade	are	approximately 175	million	metric	tonnes,	which	is	about	25	percent	of	international	natural	gas	trade.	More	LNG	production	facilities	and	tankers	are	being	constructed.	The	recent worldwide	economic	downturn	is	expected	to	lower	natural	gas	consumption	in	various	countries;	therefore,	affecting	near-term	demand	for	LNG.	Long-term	LNG supply	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	own	a	45	percent	interest	in	a	methanol	plant	located	in	Equatorial	Guinea	through	our	investment	in	AMPCO.	Sales	of	methanol	from	the	plant	totaled 792,794	metric	tonnes	in	2008.	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.	The	2008	Chemical	Markets	Associates,	Inc.'s	World	Methanol	Analysis	predicts	demand	for methanol	in	2009	will	be	43	million	metric	tonnes.	Our	plant	capacity	is	1.1	million,	or	3	percent	of	total	demand.	Also	included	in	the	financial	results	of	the	Integrated Gas	segment	are	costs	associated	with	ongoing	development	of	integrated	gas	projects,	including	natural	gas	technology	research.

Integrated	Gas	segment	income	in	2008	was	up	129	percent	from	2007,	primarily	because	the	LNG	production	facility	in	Equatorial	Guinea,	which	commenced operations	in	May	2007,	operated	for	the	full	year.

# 2008	Operating	Highlights

•	 We	added	net	proved	liquid	hydrocarbon	and	natural	gas	reserves	of	110	million	barrels	of	oil	equivalent	("boe"),	excluding	dispositions	of	3	million	boe, while	producing	137	million	boe	during	2008.	Over	the	past	three	years,	we	have	added	net	proved	reserves	of	344	million	boe,	excluding	dispositions	of 48	million	boe,	while	producing	396	million	boe.

•	 We	completed	the	operated	Alvheim/Vilje	development	offshore	Norway,	with	first	production	from	Alvheim	in	June	2008	and	from	Vilje	in	July	2008.

•	 We	completed	the	outside-operated	Neptune	development	in	deepwater	Gulf	of	Mexico,	which	began	producing	in	July	2008.

•	 We	drilled	a	second	appraisal	well	on	the	Droshky	prospect	in	deepwater	Gulf	of	Mexico	and	received	Board	approval	to	develop	the	prospect.

•	 We	announced	a	successful	discovery	well	on	the	Gunflint	prospect	in	deepwater	Gulf	of	Mexico.

•	 We	were	awarded	15	blocks	at	Outer	Continental	Shelf	Lease	Sale	No.	206,	and	a	second	Indonesian	offshore	exploration	block.

•	 We	announced	the	Portia	and	Dione	discoveries	on	deepwater	Angola	Block	31,	bringing	our	total	discoveries	in	Angola	to	28.

•	 We	received	government	approval	to	proceed	with	the	first	development	project	on	Angola	Block	31.

•The	Volund	development	offshore	Norway	continues	to	progress	on	schedule	toward	first	production	in	late	2009	and	will	be	tied	back	to	the	Alvheim infrastructure.

•	 We	have	completed	approximately	75	percent	of	our	Garyville,	Louisiana,	refinery	expansion,	which	is	scheduled	to	start-up	in	the	fourth	quarter	of	2009.

•	 We	commenced	construction	of	the	Detroit	refinery	heavy	oil	upgrading	and	expansion	project,	with	start-up	expected	in	mid-2012.

•Expansion	1	at	the	Athabasca	Oil	Sands	Project	("AOSP")	continues	to	proceed	on	schedule.

# Divestitures

•	 We	sold	our	50-percent	ownership	in	the	Pilot	Travel	Centers	LLC	("PTC")	joint	venture	in	a	$700	million	transaction.

•	 We	sold	our	non-core	outside-operated	assets	and	associated	undeveloped	acreage	in	the	Heimdal	area	offshore	Norway	for	proceeds	of	$301	million.

•	 We	reached	an	agreement	to	sell	our	producing	assets	in	Ireland.

# Consolidated	Results	of	Operations:	2008	compared	to	2007

Revenues	are	summarized	in	the	following	table.

| (In	millions) | 2008 | 2007 |
| :--- | :--- | :--- |
| E&amp;P | $12,486 | $9,155 |
| OSM | 1,122 | 221 |
| RM&amp;T | \t 64,481 | \t 56,075 |
| IG | 93 | 218 |
| Segment\trevenues | \t 78,182 | \t 65,669 |
| Elimination\tof\tintersegment\trevenues | (1,207) | (885) |
| Gain\t(loss)\ton\tU.K.\tgas\tcontracts | 218 | (232) |
| Total\trevenues | $77,193 | $64,552 |
| Items\tincluded\tin\tboth\trevenue\tand\tcosts\tand\texpenses:\nConsumer\texcise\ttaxes\ton\tpetroleum\tproducts\tand\tmerchandise | $5,065 | $5,163 |

E&P	segment	revenues	increased	$3,331	million	in	2008	from	2007.	Higher	average	liquid	hydrocarbon	and	natural	gas	realizations	account	for	over	70	percent	of the	revenue	increase.	Liquid	hydrocarbon	and	natural	gas	sales	volumes	were	also	higher	in	2008	than	2007.	Sales	volumes	also	benefited	from	a	full	year	of	natural	gas sales	to	the	Equatorial	Guinea	LNG	production	facility,	which	we	co-own.	Beginning	mid-year,	both	the	Alvheim/Vilje	development	offshore	Norway	and	the	Neptune development	in	the	Gulf	of	Mexico	contributed	particularly	to	the	liquid	hydrocarbon	sales	increase.	Because	the	majority	of	the	natural	gas	sales	increase	was	fixed- price	sales	to	the	LNG	production	facility	in	Equatorial	Guinea,	our	average	international	natural	gas	realizations	decreased.	Our	share	of	the	income	ultimately generated	by	the	subsequent	export	of	LNG	produced	by	EGHoldings,	as	well	as	methanol	produced	by	AMPCO	is	reflected	in	our	Integrated	Gas	segment	as	discussed below.

| E&amp;P	Operating	Statistics | 2008 | 2007 |
| :--- | :--- | :--- |
| Net\tLiquid\tHydrocarbon\tSales\t(Thousands\tof\tbarrels\tper\tday)(a) |  |  |
| United\tStates | 63 | 64 |
| Europe(b) | 55 | 33 |
| Africa(b) | 93 | 100 |
| Total\tInternational(b) | 148 | 133 |
| WORLDWIDE | 211 | 197 |
| Net\tNatural\tGas\tSales\t(Millions\tof\tcubic\tfeet\tper\tday)(c)(d) |  |  |
| United\tStates | 448 | 477 |
| Europe | 198 | 216 |
| Africa | 370 | 232 |
| Total\tInternational | 568 | 448 |
| WORLDWIDE | \t 1,016 | 925 |
| Total\tWorldwide\tSales\t(Thousands\tof\tbarrels\tof\toil\tequivalent\tper\tday) | 381 | 351 |
| Average\tRealizations(e) |  |  |
| Liquid\tHydrocarbons\t(Dollars\tper\tbarrel) |  |  |
| United\tStates | $86.68 | $60.15 |
| Europe | \t 90.60 | \t 70.31 |
| Africa | \t 90.29 | \t 66.09 |
| Total\tInternational | \t 90.40 | \t 67.15 |
| WORLDWIDE | $89.29 | $64.86 |
| Natural\tGas\t(Dollars\tper\tthousand\tcubic\tfeet) |  |  |
| United\tStates | $7.01 | $5.73 |
| Europe | 8.03 | 6.53 |
| Africa | 0.25 | 0.25 |
| Total\tInternational | 2.97 | 3.28 |
| WORLDWIDE | $4.75 | $4.54 |
| Includes\tcrude\toil,\tcondensate\tand\tnatural\tgas\tliquids.\n(a) |  |  |

(b) Represents	equity	tanker	lifting	and	direct	deliveries	of	liquid	hydrocarbons.	The	amounts	correspond	with	the	basis	for	fiscal	settlements	with	governments.	Crude	oil	purchases,	if	any,	from	host	governments	are excluded.

(c) Represents	net	sales	after	royalties,	except	for	Ireland	where	amounts	are	before	royalties. (d) Includes	natural	gas	acquired	for	injection	and	subsequent	resale	of	32	mmcfd	and	47	mmcfd	in	2008	and	2007.

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

E&P	segment	revenues	included	derivative	gains	of	$22	million	in	2008	and	losses	of	$15	million	in	2007.	Excluded	from	E&P	segment	revenues	were	gains	of $218	million	in	2008	and	losses	of	$232	million	in	2007	related	to	natural	gas	sales	contracts	in	the	United	Kingdom	that	are	accounted	for	as	derivative	instruments.

OSM	segment	revenues	totaled	$1,122	million	in	2008	and	$221	million	in	2007,	reflecting	a	full	year	of	operations	in	2008.	Revenues	were	impacted	by	net	gains in	2008	and	net	losses	in	2007	on	derivative	instruments,	which	expire	December	2009,	that	were	held	by	Western	at	the	acquisition	date	and	intended	to	mitigate	price risk	related	to	future	sales	of	synthetic	crude	oil.	The	2008	net	gain	of	$48	million	included	realized	losses	of	$72	million	and	unrealized	gains	of	$120	million,	while	less than	$1	million	of	the	$53	million	net	loss	in	2007	was	realized.	Additionally,	revenues	were	negatively	impacted	by	reliability	issues	and	the	implementation	of	a revised	tailings	management	plan	that	impacted	ore	grade.	Sales	of	synthetic	crude	oil	averaged	32	mbpd	at	an	average	realized	price	of	$91.90	per	barrel	compared	to	a $71.07	average	realized	price	for	the	period	from	the	October	18,	2007,	acquisition	date	through	December	of	2007.

RM&T	segment	revenues	increased	$8,406	million	in	2008	from	2007.	Higher	refined	product	selling	prices	were	realized	in	2008,	but	lower	sales	volumes	partially offset	the	price	impact.

Income	from	equity	method	investments	increased	$220	million	in	2008	from	2007.	The	Equatorial	Guinea	LNG	production	facility	operated	for	the	full	year	of 2008,	accounting	for	most	of	the	increased	income,	with	54	cargoes	delivered	in	2008	compared	to	24	in	2007.	In	addition,	there	was	an	$81	million	increase	in	PTC income	due	to	higher	retail	margins.	Offsetting	these	increases	was	the	$40	million	pretax	impairment	of	our	equity	investment	in	two	ethanol	production	facilities, losses	generated	by	one	of	those	facilities	and	lower	income	from	AMPCO.	AMPCO	sales	volumes	and	realized	prices	were	lower	in	2008	due	to	temporary	reductions in	available	feedstock	gas	and	plant	reliability	problems.

Net	gain	on	disposal	of	assets	increased	$387	million	as	a	result	of	the	review	of	our	portfolio	of	assets	that	commenced	in	2008.	We	sold	our	outside-operated interests	(24	percent	of	Heimdal	field,	47	percent	of	Vale	field	and	20	percent	of	Skirne	field)	and	associated	undeveloped	acreage	in	offshore	Norway	and	our	share	of the	PTC	joint	venture	in	2008.	Property	sales	in	2007,	primarily	related	to	sales	of	individual	producing	properties	and	retail	outlets	were	not	significant.

Cost	of	revenues	increased	$10,713	million	in	2008	from	2007.	The	increases	were	primarily	in	the	RM&T	segment	and	resulted	from	increases	in	acquisition costs	of	crude	oil.	Acquisition	costs	for	refinery	charge	and	blendstocks	and	for	purchased	refined	products	also	increased,	but	the	impact	of	this	increase	was	partially offset	by	the	impact	of	lower	refinery	throughput.

Depreciation,	depletion	and	amortization	("DD&A")	increased	$565	million	in	2008	from	2007.	The	increase	in	2008	primarily	relates	to	new	assets.	Our	oil sands	assets	operated	for	the	full	year	of	2008	and	two	significant	offshore	developments,	Alvheim/Vilje	offshore	Norway	and	Neptune	in	the	Gulf	of	Mexico,	began operating	at	mid-year.

Goodwill	impairment	expense	of	$1,412	million	relates	to	our	OSM	reporting	unit.	During	the	fourth	quarter	of	2008,	we	tested	our	OSM	reporting	unit's goodwill	for	impairment	and	upon	allocating	fair	value	among	the	reporting	unit's	assets,	there	was	no	remaining	implied	fair	value	of	goodwill	as	of	December	31, 2008.	See	Note	16	to	the	consolidated	financial	statements	for	further	information	about	the	impairment.

Net	interest	and	other	financial	income	or	costs	reflected	$50	million	in	costs	for	2008	and	$41	million	of	income	for	2007,	an	unfavorable	change	of	$91 million	from	2007.	Interest	income	decreased	due	to	lower	interest	rates	and	average	cash	balances	during	2008.	While	interest	expense	also	increased	due	to	a	higher level	of	short-term	commercial	paper	borrowings	throughout	2008	a	similar	increase	in	capitalized	interest	related	to	our	capital	projects	offset	the	impact.

Gain	on	foreign	currency	derivative	instruments	in	2007	represented	gains	on	foreign	currency	derivative	instruments	entered	to	limit	our	exposure	to	changes	in the	Canadian	dollar	exchange	rate	related	to	the	cash	portion	of	the	purchase	price	for	Western.	These	derivative	instruments	were	settled	on	October	17,	2007.

Provision	for	income	taxes	increased	$544	million	in	2008	from	2007,	a	19	percent	increase,	although	income	from	continuing	operations	before	income	taxes increased	only	$124	million,	or	2	percent.	The	effective	tax	rate	in	2008	was	impacted	by	the	goodwill	impairment	which	cannot	be	deducted	for	purposes	of	calculating income	tax.	The	consolidated	effective	tax	rate	was	also	influenced	by	the	geographical	mix	of	income	and	related	tax	expense.	Partially	offsetting	the	effective	tax	rate increase	caused	by	the	goodwill	impairment	and	income	mix	were	benefits	related	to	the	reversal	of	the	valuation	allowance	on	the	Norwegian	net	operating	loss carryforwards	and	a	$252	million	benefit	from	the	remeasurement	of	foreign	currency	denominated	deferred	taxes	to	U.S.	dollars.	The	following	is	an	analysis	of	the effective	income	tax	rates	for	continuing	operations	for	2008	and	2007.	See	Note	12	to	the	consolidated	financial	statements.

|  | 2008 | 2007 |
| :--- | :--- | :--- |
| Statutory\tU.S.\tincome\ttax\trate | 35.0% | 35.0% |
| Effects\tof\tforeign\toperations,\tincluding\tforeign\ttax\tcredits | 16.7 | 9.8 |
| Effects\tof\tnondeductible\tgoodwill\timpairment | 7.1 | – |
| Adjustments\tto\tvaluation\tallowances | (9.6) | – |
| State\tand\tlocal\tincome\ttaxes,\tnet\tof\tfederal\tincome\ttax\teffects | 1.3 | 2.0 |
| Effects\tof\tenacted\tchanges\tin\ttax\tlaws | – | (2.8) |
| Other\ttax\teffects | (1.1) | (1.6) |
| Effective\tincome\ttax\trate\tfor\tcontinuing\toperations | 49.4% | 42.4% |

Segment	income	or	loss	for	2008	and	2007	is	summarized	and	reconciled	to	net	income	in	the	following	table.

| (In	millions) | 2008 | 2007 |
| :--- | :--- | :--- |
| E&amp;P |  |  |
| United\tStates | $869 | $623 |
| International | 1,846 | \t 1,106 |
| E&amp;P\tsegment\tincome | 2,715 | \t 1,729 |
| OSM | 258 | (63) |
| RM&amp;T | 1,179 | \t 2,077 |
| IG | 302 | 132 |
| Segment\tincome | 4,454 | \t 3,875 |
| Items\tnot\tallocated\tto\tsegments,\tnet\tof\tincome\ttaxes: |  |  |
| Corporate\tand\tother\tunallocated\titems | (93) | (122) |
| Gain\t(loss)\ton\tU.K.\tnatural\tgas\tcontracts(a) | 111 | (118) |
| Foreign\tcurrency\tgain\ton\tincome\ttaxes | 252 | 18 |
| Impairments(b) | (1,437) | — |
| Gain\ton\tdispositions | 241 | 8 |
| Gain\ton\tforeign\tcurrency\tderivative\tinstruments | — | 112 |
| Deferred\tincome\ttaxes\t–\ttax\tlegislation\tchanges | — | 193 |
| Loss\ton\tearly\textinguishment\tof\tdebt | — | (10) |
| Net\tincome | $3,528 | $3,956 |
| (a) |  |  |

(b) Impairments	include	a	$1,412	million	impairment	of	goodwill	related	to	the	OSM	reporting	unit	(see	Note	16	to	the	consolidated	financial	statements)	and	a	$25	million	after-tax	impairment	($40	million	pretax) related	to	our	investments	in	ethanol	producing	facilities	(see	Note	14	to	the	consolidated	financial	statements).

United	States	E&P	income	increased	$246	million,	or	39	percent,	in	2008	from	2007.	The	majority	of	the	increase	from	year	to	year	was	due	to	overall	higher average	liquid	hydrocarbon	and	natural	gas	realizations	with	relatively	flat	sales	volumes.	Partially	offsetting	the	benefits	of	higher	prices	were	increases	in	production taxes,	operating	expenses,	DD&A	and	income	taxes.	Exploration	expenses	were	$238	million	for	2008,	lower	than	$274	million	in	2007.

International	E&P	income	increased	$740	million,	or	67	percent,	in	2008	from	2007,	primarily	due	to	higher	average	liquid	hydrocarbon	realizations	and	higher sales	volumes	for	both	liquid	hydrocarbons	and	natural	gas.	Natural	gas	realizations	were	slightly	lower	because	a	significant	portion	of	the	natural	gas	sales	volume increase	related	to	that	sold	in	Equatorial	Guinea	to	the	LNG	production	facility	at	a	fixed	price.	Operating	expenses	and	DD&A,	associated	with	production	from	new developments,	and	income	taxes	also	increased	during	2008.

OSM	segment	reported	income	of	$258	million	in	2008	as	compared	to	a	loss	of	$63	million	in	2007.	An	after-tax	gain	on	crude	oil	derivative	instruments	of	$32 million	was	included	in	2008	income,	while	an	after-tax	loss	of	$40	million	was	recorded	in	2007	(see	Item	7A.	Quantitative	and	Qualitative	Disclosures	about	Market Risk).	Results	for	2008	include	a	full	year	of	operations	in	comparison	to	two	and	one-half	months	of	operation	in	2007.	Bitumen	was	produced	at	an	average	rate	of	25 mbpd	in	2008.	Production	and	processing	levels	were	adversely	impacted	by	planned	and	unplanned	maintenance,	reliability	issues	and	the	implementation	of	a	revised tailings	management	plan	that	impacted	ore	grade,	which	also	increased	operating	costs.

RM&T	segment	income	decreased	$898	million	in	2008	from	2007,	primarily	a	result	of	a	decrease	in	our	refining	and	wholesale	marketing	gross	margin	per	gallon from	18.48	cents	in	2007	to	11.66	cents	in	2008.	The	refining	and	wholesale	marketing	gross	margin	decline	was	consistent	with	the	market	indicators	(crack	spreads)	in the	Midwest	and	Gulf	Coast	regions.	In	addition,	manufacturing	expenses	were	higher	in	2008	due	primarily	to	higher	energy	costs	and	maintenance	activities.

Included	in	the	refining	and	wholesale	marketing	gross	margins	were	pretax	derivative	losses	of	$87	million	in	2008	and	$899	million	in	2007.	The	variance primarily	reflects	falling	crude	futures	prices	in	the	second	half	of	2008,	as	well	as	the	fact	that	we	no	longer	use	derivatives	to	mitigate	domestic	crude	oil	acquisition price	risk.	For

a	more	complete	explanation	of	our	strategies	to	manage	market	risk	related	to	commodity	prices,	see	Quantitative	and	Qualitative	Disclosures	about	Market	Risk.

We	averaged	944	mbpd	of	crude	oil	throughput	in	2008	and	1,010	mbpd	in	2007.	Total	refinery	throughputs	averaged	1,151	mbpd	in	2008	compared	to	1,224	mbpd in	2007.	Crude	and	total	throughputs	were	lower	in	2008	than	in	2007	in	part	due	to	the	effect	Hurricane	Gustav	and	Ike	had	on	U.S.	Gulf	Coast	operations	in	2008.

The	following	table	includes	certain	key	operating	statistics	for	the	RM&T	segment	for	2008	and	2007.

IG	segment	income	increased	$170	million,	or	129	percent	in	2008	from	2007.	The	increase	in	income	was	primarily	related	to	a	full	year	of	operation	of	the	LNG production	facility	in	Equatorial	Guinea,	which	commenced	operations	in	May	2007.	We	hold	a	60	percent	interest	in	the	facility.	Segment	expenses	increased	slightly	in 2008	as	we	continue	to	develop	new	technologies.	In	2008,	we	spent	$92	million	on	gas	commercialization	technologies,	including	completing	construction	of	a	gas-to- fuels	demonstration	plant.	Such	expense	in	2007	was	$42	million.

| (In	millions) | 2007 | 2006 |
| :--- | :--- | :--- |
| E&amp;P | $9,155 | $9,010 |
| OSM | 221 | – |
| RM&amp;T | \t 56,075 | \t 55,941 |
| IG | 218 | 179 |
| Segment\trevenues | \t 65,669 | \t 65,130 |
| Elimination\tof\tintersegment\trevenues | (885) | (688) |
| Gain\t(loss)\ton\tlong-term\tU.K.\tgas\tcontracts | (232) | 454 |
| Total\trevenues | $64,552 | $64,896 |
| Items\tincluded\tin\tboth\trevenue\tand\tcosts\tand\texpenses: |  |  |
| Consumer\texcise\ttaxes\ton\tpetroleum\tproducts\tand\tmerchandise | $5,163 | $4,979 |
| Matching\tcrude\toil\tand\trefined\tproduct\tbuy/sell\ttransactions\tsettled\tin\tcash: |  |  |
| E&amp;P | – | 16 |
| RM&amp;T | 127 | 5,441 |
| Total\tbuy/sell\ttransactions\tincluded\tin\trevenues | $127 | $5,457 |

E&P	segment	revenues	increased	$145	million	in	2007	from	2006.	The	2007	increase	was	primarily	related	to	increased	international	crude	oil	marketing	activities. Higher	liquid	hydrocarbon	realized	prices	were	not	sufficient	to	offset	the	impact	of	sales	volume	declines	as	illustrated	in	the	table	below.	Both	liquid	hydrocarbon	and natural	gas	sales	volumes	from	domestic	operations	decreased	in	2007	primarily	due	to	normal	production	declines	in	the	Gulf	of	Mexico	and	Permian	Basin,	while international	liquid	hydrocarbon	sales	volumes	were	lower	primarily	because	our	Libya	sales	returned	to	normal	levels	compared	to	2006,	which	included	volumes	owed to	our	account	upon	the	resumption	of	our	operations	there.	While	international	natural	gas	sales	volumes	increased,	the	majority	of	the	increase	was	due	sales	to EGHoldings	LNG	production	facility	in	Equatorial	Guinea	that	began	operations	in	the	second	quarter	of	2007.	This	increase	in	fixed-price	sales	volumes	also contributed	to	the	decline	in	our	average	international	natural	gas	realizations.	Our	share	of	the	income	ultimately	generated	by	the	subsequent	export	of	LNG	produced by	EGHoldings,	as	well	as	methanol	produced	by	AMPCO	is	reflected	in	our	Integrated	Gas	segment	as	discussed	below.

| E&amp;P	Operating	Statistics | 2007 | 2006 |
| :--- | :--- | :--- |
| Net\tLiquid\tHydrocarbon\tSales\t(Thousands\tof\tbarrels\tper\tday)(a) |  |  |
| United\tStates | 64 | 76 |
| Europe(b) | 33 | 35 |
| Africa(b) | 100 | 112 |
| Total\tInternational(b) | 133 | 147 |
| Worldwide\tContinuing\tOperations | 197 | 223 |
| Discontinued\tOperations(c) | – | 12 |
| WORLDWIDE | 197 | 235 |
| Net\tNatural\tGas\tSales\t(Millions\tof\tcubic\tfeet\tper\tday)(d)(e) |  |  |
| United\tStates | 477 | 532 |
| Europe | 216 | 243 |
| Africa | 232 | 72 |
| Total\tInternational | 448 | 315 |
| WORLDWIDE | 925 | 847 |
| Total\tWorldwide\tSales\t(Thousands\tof\tbarrels\tof\toil\tequivalent\tper\tday) |  |  |
| Continuing\tOperations | 351 | 365 |
| Discontinued\tOperations | – | 12 |
| WORLDWIDE | 351 | 377 |
| Average\tRealizations(f) |  |  |
| Liquid\tHydrocarbons\t(Dollars\tper\tbarrel) |  |  |
| United\tStates | $60.15 | $54.41 |
| Europe | \t 70.31 | \t 64.02 |
| Africa | \t 66.09 | \t 59.83 |
| Total\tInternational | \t 67.15 | \t 60.81 |
| Worldwide\tContinuing\tOperations | \t 64.86 | \t 58.63 |
| Discontinued\tOperations | – | \t 38.38 |
| WORLDWIDE | $64.86 | $57.58 |
| Natural\tGas\t(Dollars\tper\tthousand\tcubic\tfeet) |  |  |
| United\tStates | $5.73 | $5.76 |
| Europe | 6.53 | 6.74 |
| Africa | 0.25 | 0.27 |
| Total\tInternational | 3.28 | 5.27 |
| WORLDWIDE | $4.54 | $5.58 |
| Includes\tcrude\toil,\tcondensate\tand\tnatural\tgas\tliquids.\n(a) |  |  |

(b) Represents	equity	tanker	lifting	and	direct	deliveries	of	liquid	hydrocarbons.	The	amounts	correspond	with	the	basis	for	fiscal	settlements	with	governments.	Crude	oil	purchases,	if	any,	from	host	governments	are excluded. (c) Represents	our	Russian	oil	exploration	and	production	businesses	that	were	sold	in	June	2006.

(d) Represents	net	sales	after	royalties,	except	for	Ireland	where	amounts	are	before	royalties. (e) Includes	natural	gas	acquired	for	injection	and	subsequent	resale	of	47	mmcfd	and	46	mmcfd	in	2007	and	2006.

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

E&P	segment	revenues	included	derivative	losses	of	$15	million	in	2007	and	gains	of	$25	million	in	2006.	Excluded	from	E&P	segment	revenues	were	losses	of $232	million	in	2007	and	gains	of	$454	million	in	2006	related	to	natural	gas	sales	contracts	in	the	United	Kingdom	that	are	accounted	for	as	derivative	instruments.	See Item	7A.	Quantitative	and	Qualitative	Disclosures	about	Market	Risk.

OSM	segment	revenues	totaled	$221	million	in	2007,	reflecting	sales	for	the	period	subsequent	to	the	October	18,	2007,	Western	acquisition	date.	Revenues	during this	period	were	reduced	by	$53	million	of	unrealized	losses	on	derivative	instruments	held	by	Western	at	the	acquisition	date	intended	to	mitigate	price	risk	related	to future	sales	of	synthetic	crude	oil.	Revenues	were	also	negatively	impacted	by	a	mid-November	fire	and	the	subsequent	curtailment	of	operations	at	the	Scotford upgrader.	Maintenance	work	originally	scheduled	for	the	first	quarter	of	2008	was	performed	in	conjunction	with	the	necessary	repairs.	The	Scotford	upgrader	returned to	operation	in	late	December.

RM&T	segment	revenues	increased	$134	million	in	2007	from	2006,	while	the	portion	related	to	matching	buy/sell	transactions	decreased	$5,314	million.	Matching buy/sell	transactions	arise	from	arrangements	in	which	we	agree	to	buy	a	specified	quantity	and	quality	of	crude	oil	or	refined	product	to	be	delivered	to	a	specified location

while	simultaneously	agreeing	to	sell	a	specified	quantity	and	quality	of	the	same	commodity	at	a	specified	location	to	the	same	counterparty.	Prior	to	April	1,	2006,	all matching	buy/sell	transactions	were	recorded	as	separate	sale	and	purchase	transactions,	or	on	a	"gross"	basis.	For	contracts	entered	into	on	or	after	April	1,	2006,	the income	effects	of	matching	buy/sell	transactions	are	reported	in	cost	of	revenues,	or	on	a	"net"	basis.	Transactions	under	contracts	entered	into	before	April	1,	2006 continued	to	be	reported	on	a	"gross"	basis	until	their	termination.	This	accounting	change	had	no	effect	on	net	or	segment	income	but	the	amounts	of	revenues	and	cost of	revenues	recognized	after	April	1,	2006	are	less	than	the	amounts	that	would	have	been	recognized	under	previous	accounting	practices.

The	decrease	in	revenues	from	matching	buy/sell	transactions	was	a	result	of	the	change	in	accounting	for	these	transactions	effective	April	1,	2006,	discussed above.	Excluding	matching	buy/sell	transactions,	2007	revenues	increased	primarily	as	a	result	of	higher	refined	product	prices.

Income	from	equity	method	investments	increased	$154	million	in	2007	from	2006.	Income	from	the	LNG	production	facility	in	Equatorial	Guinea	accounts	for most	of	the	increase	for	2007,	as	it	began	operations	in	May	2007	and	delivered	24	cargoes	during	the	year.

Cost	of	revenues	increased	$6,689	million	in	2007	from	2006.	The	increase	was	primarily	in	the	RM&T	segment	and	resulted	from	increases	in	acquisition	costs	of crude	oil,	refinery	charge	and	blendstocks	and	purchased	refined	products.	The	increase	was	also	impacted	by	higher	manufacturing	expenses,	primarily	planned maintenance	projects,	or	turnarounds,	in	2007.

Purchases	related	to	matching	buy/sell	transactions	decreased	$5,247	million	in	2007	from	2006	as	a	result	of	the	change	in	accounting	for	matching	buy/sell transactions	discussed	above.

Depreciation,	depletion	and	amortization	increased	$95	million	in	2007	from	2006.	The	increase	in	2007	primarily	relates	to	the	addition	of	the	Oil	Sands Mining	assets	recorded	as	a	result	of	the	Western	acquisition,	increased	accretion	of	asset	retirement	obligations	associated	with	international	E&P	properties	and increased	depreciation	related	to	various	refinery	improvements	in	2006	and	2007,	such	as	our	low-sulfur	diesel	projects.

Selling,	general	and	administrative	expenses	increased	$99	million	in	2007	from	2006.	The	2007	expense	increases	were	primarily	because	personnel	and staffing	costs	increased	throughout	the	year	as	a	result	of	variable	compensation	arrangements	and	increased	business	activity.	Contingency	accruals	also	contributed	to the	2007	increase.

Exploration	expenses	increased	$89	million	in	2007	from	2006.	Exploration	expenses	related	to	dry	wells	and	other	write-offs	totaled	$233	million	and	$166 million	in	2007	and	2006.

Net	interest	and	other	financial	income	or	costs	reflected	$41	million	of	income	for	2007,	a	favorable	change	of	$4	million	from	2006.	Included	in	net	interest and	other	financial	income	or	costs	were	foreign	currency	transaction	gains	of	$2	million	and	$16	million	for	2007	and	2006.

Gain	on	foreign	currency	derivative	instruments	in	2007	represents	gains	on	foreign	currency	derivative	instruments	entered	to	limit	our	exposure	to	changes	in the	Canadian	dollar	exchange	rate	related	to	the	cash	portion	of	the	purchase	price	for	Western.	These	derivative	instruments	were	settled	on	October	17,	2007.

Provision	for	income	taxes	decreased	$1,121	million	in	2007	from	2006	primarily	due	to	the	$2,130	million	decrease	in	income	from	continuing	operations	before income	taxes.	The	decrease	in	our	effective	income	tax	rate	in	2007	was	primarily	a	result	of	the	$193	million	benefit	of	applying	the	Canadian	income	tax	rate reductions	enacted	subsequent	to	our	acquisition	of	Western	to	the	applicable	net	deferred	tax	liabilities.	These	tax	rates	will	decrease	from	32	percent	to	25	percent	by 2012.	The	following	is	an	analysis	of	the	effective	income	tax	rates	for	continuing	operations	for	2007	and	2006.	See	Note	12	to	the	consolidated	financial	statements.

|  | 2007 | 2006 |
| :--- | :--- | :--- |
| Statutory\tU.S.\tincome\ttax\trate | 35.0% | 35.0% |
| Effects\tof\tforeign\toperations,\tincluding\tforeign\ttax\tcredits | 9.8 | 10.1 |
| State\tand\tlocal\tincome\ttaxes,\tnet\tof\tfederal\tincome\ttax\teffects | 2.0 | 1.9 |
| Effects\tof\tenacted\tchanges\tin\ttax\tlaws | (2.8) | (0.2) |
| Other\ttax\teffects | (1.6) | (2.0) |
| Effective\tincome\ttax\trate\tfor\tcontinuing\toperations | 42.4% | 44.8% |

Discontinued	operations	related	to	the	exploration	and	production	businesses	which	were	sold	in	June	2006.	After-tax	gains	on	the	disposal	of	$8	million	and	$243 million	were	also	included	in	discontinued	operations	for	2007	and	2006.	See	Note	8	to	the	consolidated	financial	statements.

As	discussed	in	Note	8	to	the	consolidated	financial	statements,	we	sold	our	Russian	oil	exploration	and	production	businesses	during	2006.	The	activities	of	these operations	have	been	reported	as	discontinued	operations	and	therefore	are	excluded	from	segment	results	for	all	periods	presented.

| (In	millions) | 2007 | 2006 |
| :--- | :--- | :--- |
| E&amp;P |  |  |
| United\tStates | $623 | $873 |
| International | \t 1,106 | \t 1,130 |
| E&amp;P\tsegment\tincome | \t 1,729 | \t 2,003 |
| OSM | (63) | – |
| RM&amp;T | \t 2,077 | \t 2,795 |
| IG | 132 | 16 |
| Segment\tincome | \t 3,875 | \t 4,814 |
| Items\tnot\tallocated\tto\tsegments,\tnet\tof\tincome\ttaxes: |  |  |
| Corporate\tand\tother\tunallocated\titems | (122) | (190) |
| Gain\t(loss)\ton\tU.K.\tnatural\tgas\tcontracts(a) | (118) | 232 |
| Foreign\tcurrency\tgain\t(loss)\ton\tincome\ttaxes | 18 | (22) |
| Gain\ton\tdispositions | 8 | 274 |
| Gain\ton\tforeign\tcurrency\tderivative\tinstruments | 112 | – |
| Deferred\tincome\ttaxes\t–\ttax\tlegislation\tchanges | 193 | 21 |
| \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\t\t\t\t\t\t–\tother\tadjustments(b) | – | 93 |
| Loss\ton\tearly\textinguishment\tof\tdebt | (10) | (22) |
| Discontinued\toperations | – | 34 |
| Net\tincome | $3,956 | $5,234 |
| (a) |  |  |

United	States	E&P	income	decreased	$250	million,	or	29	percent,	in	2007	from	2006.	The	decrease	was	primarily	due	to	the	revenue	decline	discussed	above.	In addition,	exploration	expenses	were	$105	million	higher	in	2007	than	in	2006,	primarily	as	a	result	of	expensing	non-commercial	wells	on	the	Flathead	prospect	in	the Gulf	of	Mexico	in	2007.

International	E&P	income	decreased	$24	million	in	2007	from	2006.	The	revenue	decrease	associated	with	lower	liquid	hydrocarbon	sales	volumes	discussed above	had	the	most	significant	impact	on	pretax	income.

OSM	segment	loss	totaled	$63	million	in	2007,	reflecting	results	for	the	period	subsequent	to	the	October	18,	2007,	Western	acquisition	date.	This	loss	includes	a $40	million	after-tax	unrealized	loss	on	derivative	instruments	held	by	Western	at	the	acquisition	date	intended	to	mitigate	price	risk	related	to	future	sales	of	synthetic crude	oil.	Segment	income	was	also	impacted	by	a	mid-November	fire	and	subsequent	curtailment	of	operations	at	the	Scotford	upgrader.	Maintenance	work	originally scheduled	for	the	first	quarter	of	2008	was	performed	in	conjunction	with	the	necessary	repairs.	The	Scotford	upgrader	returned	to	operation	in	late	December.

RM&T	segment	income	decreased	$718	million	in	2007	from	2006,	primarily	a	result	of	a	decrease	in	our	refining	and	wholesale	marketing	gross	margin	per	gallon from	22.88	cents	in	2006	to	18.48	cents	in	2007.	Though	the	market-based	crack	spreads	for	2007	were	stronger	than	in	2006,	our	refining	and	wholesale	marketing gross	margin	declined	primarily	due	to	the	significant	and	rapid	increase	in	our	crude	oil	costs	during	2007,	including	the	impact	of	derivatives,	and	lagging	wholesale price	realizations.	Our	refining	and	marketing	wholesale	gross	margin	was	further	reduced	by	higher	manufacturing	costs	related	to	planned	maintenance	at	several refineries.	In	addition	to	the	lower	refining	and	wholesale	gross	margin,	segment	income	was	impacted	by	higher	operating	and	administrative	expenses.

Included	in	the	refining	and	wholesale	marketing	gross	margins	were	pretax	derivative	losses	of	$899	million	in	2007	and	gains	of	$400	million	in	2006.	For	a	more complete	explanation	of	our	strategies	to	manage	market	risk	related	to	commodity	prices,	see	Item	7A.	Quantitative	and	Qualitative	Disclosures	about	Market	Risk.

We	averaged	1,010	mbpd	of	crude	oil	throughput	in	2007	and	980	mbpd	in	2006.	Our	reported	crude	oil	refining	capacity	increased	to	1,016	mbpd	in	2007	from 974	mbpd	in	2006	due	to	overall	efficiency	gains	in	the	operation	of	the	refining	units,	reflecting	the	cumulative	effect	of	regular	maintenance,	capital	improvements	and other	process	optimization	efforts.

(a) Sales	revenue	less	cost	of	refinery	inputs	(including	transportation),	purchased	products	and	manufacturing	expenses,	including	depreciation.

IG	segment	income	increased	$116	million	in	2007	from	2006.	During	2007,	construction	of	the	LNG	production	facility	in	Equatorial	Guinea	was	completed ahead	of	schedule	and	on	budget.	The	increase	in	2007	segment	income	over	the	previous	year	was	largely	due	to	the	facility	beginning	operations	in	May	2007	and delivering	24	cargoes	during	the	year.	Additionally,	income	from	our	equity	method	investment	in	AMPCO	was	higher	in	2007	on	increased	methanol	production	due	to plant	downtime	in	2006	and	higher	realized	prices	in	2007.	In	2006,	a	$17	million	pretax	loss	was	recognized	as	a	result	of	the	renegotiation	of	a	technology	agreement and	income	from	our	equity	method	investment	in	AMPCO	was	lower	due	to	plant	downtime	during	a	planned	turnaround	and	subsequent	compressor	repair.

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

# Cash	Flows

Net	cash	provided	from	operating	activities	totaled	$6,782	million	in	2008,	compared	to	$6,521	million	in	2007	and	$5,488	million	in	2006.	The	$261	million increase	in	2008	primarily	reflects	the	impact	of	higher	average	realized	prices.	The	$1,033	million	increase	in	2007	primarily	reflects	working	capital	changes	partially offset	by	lower	net	income.

Net	cash	used	in	investing	activities	totaled	$5,435	million	in	2008,	compared	with	$8,102	million	in	2007	and	$2,955	million	in	2006.	Significant	investing activities	include	capital	expenditures,	acquisitions	of	businesses	and	asset	disposals.

Capital	expenditures	by	segment	for	continuing	operations	for	each	of	the	last	three	years	are	summarized	in	the	following	table.

| (In	millions) | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| E&amp;P |  |  |  |
| United\tStates | $2,036 | $1,354 | $1,302 |
| International | \t 1,077 | \t 1,157 | 867 |
| Total\tE&amp;P | \t 3,113 | \t 2,511 | \t 2,169 |
| OSM | \t 1,038 | 165 | – |
| RM&amp;T | \t 2,954 | \t 1,640 | 916 |
| IG | 4 | 93 | 307 |
| Corporate | 37 | 57 | 41 |
| Total | $7,146 | $4,466 | $3,433 |

Capital	expenditures	for	multiple	years	are	impacted	by	the	following	projects.	In	our	E&P	segment,	development	and	completion	of	the	Alvheim/Vilje	project affected	our	capital	expenditures	in	2006,	2007	and	to	a	lesser	extent	in	2008.	Similarly,	our	Angola	exploration	and	development	projects	impacted	all	three	years.	In our	RM&T	segment,	the	expansion	of	our	Garyville,	Louisiana	refinery	commenced	with	front-end	engineering	and	design	("FEED")	in	2006	followed	by	construction in	2007	and	2008.	Also	in	RM&T,	the	expansion	and	upgrading

of	our	Detroit,	Michigan	refinery	commenced	with	FEED	in	2007	and	construction	in	2008.	Integrated	gas	spending	in	2006	and	through	May	2007	reflects	the completion	of	the	LNG	production	facility	in	Equatorial	Guinea.

New	capital	spending	in	2008	was	primarily	related	to	the	ongoing	AOSP	Expansion	1	in	the	OSM	segment,	and	in	U.S.	exploration	and	development	projects primarily	in	the	Gulf	of	Mexico.

Acquisitions	in	2007	consist	primarily	of	the	$3,907	million	cash	portion	of	the	Western	acquisition	purchase	price,	net	of	the	$44	million	of	cash	acquired.	See Note	6	to	the	consolidated	financial	statements	for	more	information	about	the	Western	acquisition.	In	2006,	acquisitions	primarily	included	cash	payments	of	$718 million	associated	with	our	re-entry	into	Libya.

Disposal	of	assets	totaled	$999	million,	$137	million	and	$134	million	in	2008,	2007	and	2006.	In	2008,	disposal	of	assets	included	proceeds	from	the	sale	of	our outside-operated	interests	and	related	undeveloped	acreage	in	Norway	and	our	share	of	PTC.	Disposal	of	assets	included	proceeds	from	the	sale	of	our	interests	in	two LNG	tankers	in	Alaska	in	2007	and	proceeds	from	the	sale	of	90	percent	of	our	interest	in	Syrian	natural	gas	fields	in	2006.	Disposals	for	all	years	included	proceeds from	the	sale	of	various	domestic	producing	properties	and	SSA	stores.

Disposal	of	discontinued	operations	of	$832	million	in	2006	related	to	the	sale	of	our	Russian	exploration	and	production	businesses	in	June	2006.	See	Note	8	to	the consolidated	financial	statements.

Net	cash	used	in	financing	activities	totaled	$1,193	million	in	2008,	compared	with	net	cash	provided	by	financing	activities	of	$184	million	in	2007	and	cash used	in	financing	activities	of	$2,581	million	in	2006.	Sources	of	cash	in	2008	included	the	issuance	of	$1.0	billion	in	senior	notes.	Sources	of	cash	in	2007	included	the issuance	of	$1.5	billion	in	senior	notes	and	borrowings	of	$578	million	from	the	Norwegian	export	credit	agency.	Significant	uses	of	cash	in	financing	activities	in	all years	were	common	stock	repurchases	under	our	share	repurchase	plan,	dividend	payments	and	debt	repayments.

Significant	noncash	transactions	during	2007	included	the	issuance	of	$1.0	billion	of	5.125	percent	Fixed	Rate	Revenue	Bonds	(Marathon	Oil	Corporation Project)	Series	2007A,	with	a	maturity	date	of	June	1,	2037.	The	proceeds	from	the	bonds,	along	with	interest	income,	are	held	in	trust	to	be	disbursed	to	us	upon	our request	for	reimbursement	of	expenditures	related	to	our	Garyville,	Louisiana	refinery	expansion.	Through	December	31,	2008,	such	reimbursements	have	totaled $1,032	million.	The	$1.0	billion	obligation	is	reflected	as	long-term	debt	and	the	remaining	$16	million	of	trusteed	funds,	including	interest	income	earned	to	date,	is reflected	as	other	noncurrent	assets	in	the	consolidated	balance	sheet	as	of	December	31,	2008.

# Liquidity	and	Capital	Resources

Our	main	sources	of	liquidity	are	cash	and	cash	equivalents,	internally	generated	cash	flow	from	operations,	the	issuance	of	notes,	and	our	$3.0	billion	committed revolving	credit	facility.	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,	share	repurchase	program,	dividend	payments,	defined	benefit	plan	contributions,	repayment	of	debt	maturities	and	other	amounts	that	may	ultimately	be	paid in	connection	with	contingencies.

# Capital	Resources

# Credit	Arrangements	and	Borrowings

At	December	31,	2008,	we	had	$7,087	million	in	long	term	debt	outstanding.	Our	senior	unsecured	debt	is	currently	rated	investment	grade	by	Standard	and	Poor's Corporation,	Moody's	Investor	Services,	Inc.	and	Fitch	Ratings	with	ratings	of	BBB+	(outlook	stable),	Baa1	(outlook	stable),	and	BBB+	(outlook	negative).	Should	one or	all	of	these	agencies	decide	to	downgrade	our	ratings,	it	could	become	more	difficult	and	more	costly	for	us	to	issue	new	debt	or	commercial	paper.	We	do	not	have any	ratings	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,	2008,	we	had	no	borrowings	against	our	revolving	credit	facility	and	no	commercial	paper	outstanding	under	our	U.S.	commercial	paper	program that	is	backed	by	the	revolving	credit	facility.

Effective	April	3,	2008,	we	amended	our	revolving	credit	facility,	extending	the	termination	date	on	$2,625	million	from	May	2012	to	May	2013.	The	remaining $375	million	continues	to	have	a	termination	date	of	May	2012.	No	single	lender	holds	more	than	10	percent	of	the	$3.0	billion	revolving	credit	facility.

On	March	12,	2008,	we	issued	$1.0	billion	aggregate	principal	amount	of	senior	notes	bearing	interest	at	5.9	percent	with	a	maturity	date	of	March	15,	2018. Interest	on	the	senior	notes	is	payable	semi-annually	beginning	September	15,	2008.

Subsequent	to	year	end	2008,	on	February	17,	2009,	we	issued	$700	million	aggregate	principal	amount	of	senior	notes	bearing	interest	at	6.5	percent	with	a maturity	date	of	February	15,	2014	and	$800	million	aggregate	principal	amount	of	senior	notes	bearing	interest	at	7.5	percent	with	a	maturity	date	of	February	15,	2019. Interest	on	both	issues	is	payable	semi-annually	beginning	August	15,	2009.

# Asset	Sales

In	2008,	we	commenced	a	review	of	our	portfolio	of	assets	with	the	intent	of	monetizing	those	assets	which	are	either	mature	or	otherwise	non-strategic.	Through December	31,	2008,	net	proceeds	of	$999	million	have	been	received	from	the	sale	of	assets	identified	in	this	review.

# Shelf	Registration

On	July	26,	2007,	we	filed	a	universal	shelf	registration	statement	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	22	percent	at	December	31,	2008	and	2007.	This	includes $485	million	of	debt	that	is	serviced	by	United	States	Steel.

| (Dollars	in	millions) | 2008 | 2007 |
| :--- | :--- | :--- |
| Long-term\tdebt\tdue\twithin\tone\tyear | $98 | $1,131 |
| Long-term\tdebt | 7,087 | 6,084 |
| Total\tdebt | $7,185 | $7,215 |
| Cash | $1,285 | $1,199 |
| Trusteed\tfunds\tfrom\trevenue\tbonds(a) | $16 | $744 |
| Equity | $21,409 | $19,223 |
| Calculation: |  |  |
| Total\tdebt | $7,185 | $7,215 |
| Minus\tcash | 1,285 | 1,199 |
| Minus\ttrusteed\tfunds\tfrom\trevenue\tbonds | 16 | 744 |
| Total\tdebt\tminus\tcash | 5,884 | 5,272 |
| Total\tdebt | 7,185 | 7,215 |
| Plus\tequity | \t 21,409 | \t 19,223 |
| Minus\tcash | 1,285 | 1,199 |
| Minus\ttrusteed\tfunds\tfrom\trevenue\tbonds | 16 | 744 |
| Total\tdebt\tplus\tequity\tminus\tcash | $27,293 | $24,495 |
| Cash-adjusted\tdebt-to-capital\tratio | 22% | 22% |

(a) Following	the	issuance	of	the	$1.0	billion	of	revenue	bonds	by	the	Parish	of	St.	John	the	Baptist,	the	proceeds	were	trusteed	and	will	be	disbursed	to	us	upon	our	request	for	reimbursement	of	expenditures	related to	the	Garyville	refinery	expansion.	The	trusteed	funds	are	reflected	as	other	noncurrent	assets	in	the	accompanying	consolidated	balance	sheet	as	of	December	31,	2008	and	2007.

# Capital	Requirements

# Capital	Spending

We	have	approved	a	capital,	investment	and	exploration	budget	of	$5,738	million	for	2009,	which	represents	a	24	percent	decrease	from	our	2008	spending. Additional	details	related	to	the	2009	budget	are	discussed	in	Outlook	—	Capital,	Investment	and	Exploration	Budget.

# Other	Significant	Expected	Cash	Outflows

We	plan	to	make	contributions	of	up	to	$439	million	to	our	pension	plans	during	2009.	As	of	December	31,	2008,	$98	million	of	our	long-term	debt	is	due	in	the next	twelve	months.

Dividends	of	$0.96	per	common	share	or	$681	million	were	paid	during	2008.	On	February	2,	2009,	our	Board	of	Directors	declared	a	dividend	of	$0.24	cents	per share	on	Marathon	common	stock,	payable	March	10,	2009,	to	stockholders	of	record	at	the	close	of	business	on	February	18,	2009.

# Share	Repurchase	Program

Since	January	2006,	our	Board	of	Directors	has	authorized	a	common	share	repurchase	program	totaling	$5	billion.	As	of	December	31,	2008,	we	had	repurchased 66	million	common	shares	at	a	cost	of	$2,922	million.	We	have	not	made	any	purchases	under	the	program	since	August	2008.	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	and	cash	from	available	borrowings.

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	a	review	of	our	portfolio	of	assets.	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	liquid	hydrocarbons,	natural	gas	and	refined	products,	actions	of competitors,	disruptions	or	interruptions	of	our	production,	oil	sands	mining	and	bitumen	upgrading	or	refining	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. Factors	that	could	affect	the	review	of	our	portfolio	of	assets	include	the	identification	of	buyers	and	the	negotiation	of	acceptable	prices	and	other	terms,	as	well	as other	customary	closing	conditions.	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	are	changes	in	prices	of	and	demand	for	crude	oil,	natural	gas	and	refined	products,	actions	of	competitors,	disruptions	or	interruptions	of	our	production	or refining	operations	due	to	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,	2008.

|  |  |  | 2010- | 2012- | Later |
| :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Total | 2009 | 2011 | 2013 | Years |
| Long-term\tdebt\t(excludes\tinterest)(a)(b) | $6,880 | $68 | $279 | $1,718 | $4,815 |
| Sale-leaseback\tfinancing(a)(k) | 297 | 14 | 55 | 44 | 184 |
| Capital\tlease\tobligations(a)(k) | 360 | 26 | 37 | 55 | 242 |
| Operating\tlease\tobligations(a) | 967 | 176 | 233 | 180 | 378 |
| Operating\tlease\tobligations\tunder\tsublease(a) | 21 | 5 | 10 | 6 | – |
| Purchase\tobligations: |  |  |  |  |  |
| Crude\toil,\tfeedstock,\trefined\tproduct\tand\tethanol\tcontracts(c) | 9,955 | 8,322 | 662 | 479 | 492 |
| Transportation\tand\trelated\tcontracts | 1,657 | 430 | 401 | 223 | 603 |
| Contracts\tto\tacquire\tproperty,\tplant\tand\tequipment | 4,070 | 1,949 | \t 1,242 | 389 | 490 |
| LNG\tterminal\toperating\tcosts(d) | 153 | 13 | 25 | 25 | 90 |
| Service\tand\tmaterials\tcontracts(e) | 1,567 | 379 | 442 | 205 | 541 |
| Unconditional\tpurchase\tobligations(f) | 50 | 8 | 14 | 14 | 14 |
| Commitments\tfor\toil\tand\tgas\texploration\t(non-capital)(g) | 21 | 19 | 2 | – | – |
| Total\tpurchase\tobligations | \t 17,473 | \t 11,120 | \t 2,788 | \t 1,335 | 2,230 |
| Other\tlong-term\tliabilities\treported\tin\tthe\tconsolidated\tbalance\tsheet(h) | 3,562 | 500 | 704 | 871 | 1,487 |
| Total\tcontractual\tcash\tobligations(i)(j) | $29,560 | $11,909 | $4,106 | $4,209 | $9,336 |
| (a) |  |  |  |  |  |

(a) Upon	the	USX	Separation,	United	States	Steel	assumed	certain	debt	and	lease	obligations,	including	$415	of	long-term	debt	obligations	related	to	industrial	revenue	bonds.	The	Financial	Matters	Agreement provides	that,	on	or	before	the	tenth	anniversary	of	the	USX	Separation,	United	States	Steel	will	provide	for	Marathon's	discharge	from	any	remaining	liability	under	any	of	the	assumed	industrial	revenue	bonds. Such	amounts	are	included	in	the	above	table	because	we	remain	primarily	liable.

(b) We	anticipate	cash	payments	for	interest	of	$426	million	for	2009,	$842	million	for	2010-2011,	$646	million	for	2012-2013	and	$3,603	million	for	the	remaining	years	for	a	total	of	$5,517	million.	Of	these,	we anticipate	cash	payments	for	interest	of	$23	million	for	2009,	$45	million	for	2010-2011,	$32	million	for	2012-2013	and	$207	million	for	the	later	years	to	be	made	by	United	States	Steel. (c) The	majority	of	these	contractual	obligations	as	of	December	31,	2008,	relate	to	contracts	to	be	satisfied	within	the	first	180	days	of	2009.	These	contracts	include	variable	price	arrangements.

(d) We	have	acquired	the	right	to	deliver	58	bcf	of	natural	gas	per	year	to	the	Elba	Island	LNG	re-gasification	terminal.	The	agreement's	primary	term	ends	in	2021.	Pursuant	to	this	agreement,	we	are	also	committed to	pay	for	a	portion	of	the	operating	costs	of	the	terminal.

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

(f) We	are	a	party	to	a	long-term	transportation	services	agreement	with	Alliance	Pipeline.	This	agreement	was	used	by	Alliance	Pipeline	to	secure	its	financing.	This	arrangement	represents	an	indirect	guarantee	of indebtedness.	Therefore,	this	amount	has	also	been	disclosed	as	a	guarantee.

(g) Commitments	for	oil	and	gas	exploration	(non-capital)	include	estimated	costs	related	to	contractually	obligated	exploratory	work	programs	that	are	expensed	immediately,	such	as	geological	and	geophysical costs.

(h) Primarily	includes	obligations	for	pension	and	other	postretirement	benefits	including	medical	and	life	insurance.	We	have	estimated	projected	funding	requirements	through	2018.	Also	includes	certain	tax obligations	recorded	in	accordance	with	FIN	48.

(i) Includes	$497	million	of	contractual	cash	obligations	that	have	been	assumed	by	United	States	Steel.	See	Management's	Discussion	and	Analysis	of	Financial	Condition,	Cash	Flows	and	Liquidity	–	Obligations Associated	with	the	Separation	of	United	States	Steel.

(j) This	table	does	not	include	the	estimated	discounted	liability	for	dismantlement,	abandonment	and	restoration	costs	of	oil	and	gas	properties	of	$	965	million.	See	Note	21	to	the	consolidated	financial	statements.

(k) During	the	interim	period	between	lease	inception	and	effective	date,	long-term	debt	costs	equal	estimated	or	reported	construction	costs	as	of	the	end	of	the	reporting	period,	not	the	minimum	lease payment/rentals.

# 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	have	provided	various	guarantees	related	to	equity	method	investees,	United	States	Steel	and	others.	These	arrangements	are	described	in	Note	27	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.

Sales	of	refined	petroleum	products	to	our	50	percent	equity	method	investee,	PTC,	which	was	sold	in	October	2008,	accounted	for	2.5	percent	or	less	of	our	total sales	revenue	for	2008,	2007	and	2006.	We	believe	that	these	transactions	with	related	parties	have	been	conducted	under	terms	comparable	to	those	with	unrelated parties.

# Obligations	Associated	with	the	Separation	of	United	States	Steel

We	remain	obligated	(primarily	or	contingently)	for	certain	debt	and	other	financial	arrangements	for	which	United	States	Steel	has	assumed	responsibility	for repayment	under	the	terms	of	the	USX	Separation.	United	States	Steel's	obligations	to	us	are	general	unsecured	obligations	that	rank	equal	to	United	States	Steel's accounts	payable	and	other	general	unsecured	obligations.	If	United	States	Steel	fails	to	satisfy	these	obligations,	we	would	become	responsible	for	repayment.	Under	the Financial	Matters	Agreement,	United	States	Steel	has	all	of	the	existing	contractual	rights	under	the	leases	assumed	from	us,	including	all	rights	related	to	purchase options,	prepayments	or	the	grant	or	release	of	security	interests.	However,	United	States	Steel	has	no	right	to	increase	amounts	due	under	or	lengthen	the	term	of	any	of the	assumed	leases,	other	than	extensions	set	forth	in	the	terms	of	the	assumed	leases.

As	of	December	31,	2008,	we	have	identified	the	following	obligations	that	have	been	assumed	by	United	States	Steel:

•$415	million	of	industrial	revenue	bonds	related	to	environmental	improvement	projects	for	current	and	former	United	States	Steel	facilities,	with	maturities ranging	from	2011	through	2033.	Accrued	interest	payable	on	these	bonds	was	$8	million	at	December	31,	2008.	We	anticipate	United	States	Steel	will	make future	interest	payments	of	$23	million	for	2009,	$45	million	for	2010-2011,	$32	million	for	2012-2013	and	$207	million	for	the	later	years.

•$37	million	of	sale-leaseback	financing	under	a	lease	for	equipment	at	United	States	Steel's	Fairfield	Works,	with	a	term	extending	to	2012,	subject	to extensions.	There	was	no	accrued	interest	payable	on	this	financing	at	December	31,	2008.

•$32	million	of	obligations	under	a	lease	for	equipment	at	United	States	Steel's	Clairton	coke-making	facility,	with	a	term	extending	to	2012.	There	was	no accrued	interest	payable	on	this	financing	at	December	31,	2008.

•$21	million	of	operating	lease	obligations,	all	of	which	was	assumed	by	purchasers	of	major	equipment	used	in	plants	and	operations	divested	by	United States	Steel.

•	 A	guarantee	with	respect	to	all	obligations	of	United	States	Steel	to	the	limited	partners	of	the	Clairton	1314B	Partnership,	L.P.,	which	was	terminated	on October	31,	2008.	Upon	termination	of	the	partnership,	we	were	not	released	from	our	obligations	under	guarantee.	United	States	Steel	has	reported	that	it currently	has	no	unpaid	outstanding	obligations	to	the	limited	partners.	See	Note	27	to	the	consolidated	financial	statements.

Of	the	total	$513	million,	obligations	of	$492	million	and	corresponding	receivables	from	United	States	Steel	were	recorded	on	our	consolidated	balance	sheet	as	of December	31,	2008,	(current	portion	–	$23	million;	long-term	portion	–	$469	million).	The	remaining	$21	million	was	related	to	off-balance	sheet	arrangements	and contingent	liabilities	of	United	States	Steel.

United	States	Steel	has	restrictive	covenants	related	to	its	indebtedness	that	could	have	an	adverse	effect	on	its	financial	position	and	liquidity.	In	its	Form	10-K	for the	year	ended	December	31,	2008,	United	States	Steel	reported	that	it	was	in	compliance	with	all	debt	covenants,	but	that	the	current	global	recession	may	affect	its

ability	to	comply	with	those	covenant	and	conditions	in	the	future.	Such	circumstances	could	trigger	a	need	for	United	States	Steel	to	modify	or	replace	credit agreements	on	less	favorable	terms	that	could	adversely	affect	its	flexibility,	cash	flow	and	profitability.

# Outlook

# Capital,	Investment	and	Exploration	Budget

Our	Board	of	Directors	approved	a	capital,	investment	and	exploration	budget	of	$5,738	million	for	2009,	which	includes	budgeted	capital	expenditures	of	$5,547 million.	This	represents	a	24	percent	decrease	from	2008	spending.	The	focus	of	our	2009	budget	is	to	maintain	solid	production	performance,	enhance	our	downstream business	and	provide	necessary	investments	in	mid-	and	long-term	growth	projects.

The	budget	includes	worldwide	exploration	and	production	spending	of	$2,468	million.	A	significant	amount	of	this	budget,	45	percent,	is	targeted	on	projects	that will	sustain	and	grow	production	in	the	short-term,	including	domestic	assets	such	as	those	in	the	Bakken	Shale	and	Piceance	Basin	and	international	development projects	like	Volund	in	Norway.	Mid-term	production	growth	projects	such	as	Droshky	and	Ozona	in	the	Gulf	of	Mexico	and	emerging	resource	plays	in	the	Marcellus and	Woodford	Shales	account	for	34	percent	of	the	2009	budget.	Long-term	projects	will	require	about	20	percent	of	budgeted	funds	in	2009.	The	PSVM	development on	Angola	Block	31,	the	Gudrun	development	in	Norway,	as	well	as	exploration	in	the	Gulf	of	Mexico,	Angola,	Norway	and	Indonesia	are	our	significant	long-term projects.

The	budget	includes	$887	million	for	the	Oil	Sands	Mining	segment	in	2009,	primarily	for	the	continuation	of	Expansion	1.	This	is	slightly	lower	than	2008 spending	due	in	part	to	the	stronger	U.S.	dollar	and	to	the	expected	deferral	of	some	nonessential	projects.

The	budget	includes	$1,944	million	for	RM&T	projects,	with	about	52	percent	budgeted	for	the	Garyville	refinery	expansion	and	17	percent	for	the	Detroit	refinery heavy	oil	upgrading	and	expansion	project.	The	remainder	of	the	budget	is	allocated	to	maintaining	facilities	and	meeting	regulatory	requirements,	notably	the	Mobile Source	Air	Toxics	("MSAT")	regulations	that	will	be	effective	at	the	beginning	of	2011.

The	remaining	$439	million	relates	to	capitalized	interest	and	corporate	activities.

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,	natural	gas	and	refined	products,	actions	of	competitors,	disruptions	or	interruptions	of	our	production	or	refining	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.

Major	exploration	activities	are	currently	underway	or	under	evaluation	worldwide.

Angola	–	We	hold	a	10	percent	outside-operated	interest	in	offshore	Block	31	and	a	30	percent	outside-operated	interest	in	offshore	Block	32.	We	plan	to	participate in	four	to	six	exploration	or	appraisal	wells	in	these	deepwater	blocks	in	2009.	Four	potential	development	hubs	have	been	identified	on	these	two	blocks	and	we continue	to	evaluate	our	discoveries	for	future	development.

Norway	–	We	hold	interests	in	over	510,000	acres	offshore	Norway	and	plan	to	continue	our	exploration	efforts	there.	In	2009,	exploration	drilling	is	expected	to commence	on	additional	prospects	with	the	potential	to	be	tied	back	to	the	Alvheim	complex.

Gulf	of	Mexico	–	We	plan	to	participate	in	one	to	three	exploration	wells	during	2009.	The	exploration	success	on	the	Shenandoah	prospect	was	announced	in February	2009	by	the	operator.	We	own	a	10	percent	outside-operated	interest	in	this	prospect.	Additional	prospects	have	been	identified	in	the	Gulf	of	Mexico deepwater	leases	acquired	in	2007	and	2008.	These	projects	make	up	the	core	of	our	2009	through	2010	Gulf	of	Mexico	exploration	drilling	plans.

Indonesia	–	We	continue	to	evaluate	seismic	data	on	the	Pasangkayu	Block	offshore	Indonesia	and	plan	to	start	exploratory	drilling	there	in	early	2010.	We	are	the operator	of	this	block	and	hold	a	70	percent	interest.	Evaluation	of	the	Bone	Bay	Block	offshore	Indonesia,	which	we	were	awarded	in	2008,	continues	with	plans	to collect	seismic	data	in	2010.	Exploratory	drilling	on	this	block	could	begin	in	2011.	We	have	a	49	percent	interest	in	the	Bone	Bay	Block	and	are	the	operator.

U.S.	onshore	–	We	announced	a	discovery	in	the	Woodford	Shale	in	January	2009.	We	hold	30,000	net	acres	in	the	Woodford	Shale	resource	play	in	the	Anadarko Basin	of	Oklahoma	and	plan	to	participate	in	more	horizontal	wells	in	2009.	We	also	hold	prospective	acreage	in	two	emerging	shale	resource	plays	in	the	U.S.	In	the Appalachian	Basin	we	hold	65,000	net	acres	in	the	Marcellus	Shale	resource	play	in	Pennsylvania	and	West	Virginia.	We	also	hold	25,000	net	acres,	primarily	in	Texas, in	the	Haynesville	Shale	resource	play	in	North	Louisiana	and	East	Texas	.	Our	plans	call	for	initial	drilling	on	some	of	these	leases	in	2009.

Equatorial	Guinea	–	We	are	evaluating	development	scenarios	for	the	Deep	Luba	and	Gardenia	discoveries	on	the	Alba	Block,	one	of	which	includes	production through	the	Alba	field	infrastructure.	We	own	a	63	percent	interest	in	the	Alba	Block	and	serve	as	operator.

# Production

During	2008,	several	of	our	development	projects	were	completed	and	began	producing.	We	have	approved	new	development	projects,	are	evaluating	others	and will	continue	working	on	ongoing	projects	in	2009.

Angola	–	In	2008	we	received	approval	to	proceed	with	this	first	deepwater	PSVM	development	project.	The	development	is	comprised	of	the	Plutao,	Saturno, Venus	and	Marte	discoveries.	Key	contracts	were	awarded	and	construction	work	commenced	in	the	second	half	of	2008.	A	total	of	48	production	and	injection	wells	are planned	for	the	PSVM	development.	First	production	is	targeted	for	2012	with	a	design	capacity	of	about	150,000	gross	bpd

Norway	–	Tie	back	of	the	Volund	field	offshore	Norway	to	the	Alvheim/Vilje	production	facility	continues	with	first	production	expected	in	late	2009.	We	own	a 65	percent	interest	in	Volund	and	serve	as	operator.	In	addition,	we	hold	a	28	percent	outside-operated	interest	in	the	Gudrun	field,	located	120	miles	off	the	coast	of Norway,	where	a	successful	appraisal	well	was	drilled	in	2006.	In	January	2009,	the	operator	announced	a	development	concept	that	includes	a	fixed	processing platform	with	seven	production	wells	that	would	be	tied	to	existing	facilities	on	the	Sleipner	field.	A	final	investment	decision	is	expected	in	2009.

Gulf	of	Mexico	–	The	Droshky	and	Ozona	developments	in	deepwater	Gulf	of	Mexico	were	approved	in	2008.	Rig	capacity	has	been	secured	for	Droshky development	drilling	which	is	expected	to	begin	in	February	2009	with	first	production	targeted	for	2010.	The	project	will	consist	of	four	development	wells	which	will be	tied	back	to	the	nearby	third-party	owned	and	operated	Bullwinkle	platform.	We	own	a	100	percent	working	interest	in	Droshky.	Ozona	development	on	Garden Banks	Block	515	will	begin	in	2009,	with	first	production	expected	in	2011.	We	hold	a	68	percent	working	interest	in	Ozona.

U.S.	onshore	–	We	continue	drilling	on	resource	plays	in	the	Piceance	Basin	of	Colorado	and	the	Williston	Basin	of	North	Dakota	and	eastern	Montana	(the	Bakken shale	resource	play).	In	the	Piceance	Basin,	drilling	and	production	commenced	in	late	2007.	Plans	are	to	drill	150	wells	during	the	next	five	years.	More	than	100 operated	wells	have	already	been	drilled	with	plans	to	drill	approximately	225	additional	wells	during	the	next	five	years.

The	above	discussion	includes	forward-looking	statements	with	respect	to	anticipated	future	exploratory	and	development	drilling,	the	possibility	of	developing Blocks	31	and	32	offshore	Angola	and	the	Droshky	discovery	in	the	Gulf	of	Mexico,	the	timing	of	production	from	the	Neptune	development,	the	Droshky	discovery, the	Alvheim/Vilje	development,	the	Volund	field	and	the	Corrib	project.	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. Except	for	the	Neptune,	Alvheim/Vilje	and	Volund	developments,	the	foregoing	forward-looking	statements	may	be	further	affected	by	the	inability	to	or	delay	in obtaining	necessary	government	and	third-party	approvals	and	permits.	The	possible	developments	of	the	Droshky	discovery	and	Blocks	31	and	32	offshore	Angola 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	AOSP	Expansion	1	continues	in	2009	and	is	expected	to	begin	operations	in	the	2010	to	2011	timeframe.	The	expansion	includes	construction	of	mining	and extraction	facilities	at	the	Jackpine	mine,	expansion	of	treatment	facilities	at	the	existing	Muskeg	River	mine	and	expansion	of	the	Scotford	upgrader,	along	with construction	of	common	infrastructure	sized	to	support	future	mining	expansions.

The	above	discussion	includes	forward-looking	statements	with	respect	to	anticipated	completion	of	the	AOSP	expansion.	Factors	which	could	affect	the	expansion include	transportation	logistics,	availability	of	materials	and	labor,	unforeseen	hazards	such	as	weather	conditions,	delays	in	obtaining	or	conditions	imposed	by necessary	government	and	third-party	approvals	and	other	risks	customarily	associated	with	construction	projects.

The	Garyville	refinery	expansion	is	expected	to	be	completed	and	ready	for	start	up	in	the	fourth	quarter	of	2009.	Total	projected	costs	are	now	estimated	to	be $3.35	billion	(excluding	capitalized	interest).	This	expansion	will	increase	the	refinery's	crude	oil	throughput	capacity	by	180	mbpd	and	will	enable	the	refinery	to provide	an	additional	7.5	million	gallons	of	clean	transportation	fuels	to	the	market	each	day.

Permits	were	obtained	and	construction	commenced	for	the	heavy	oil	upgrading	and	expansion	project	at	our	Detroit,	Michigan,	refinery	in	2008.	Due	to	delays	in the	projected	production	from	Canadian	oil	sands	and	current	market	conditions,	we	have	reevaluated	the	project	construction	schedule	and	now	plan	to	complete	this project	in	mid-2012.	We	now	forecast	the	project	will	cost	$2.2	billion	(excluding	capitalized	interest),	or	about	15	percent	more	than	the	original	budget,	due	primarily to	additional	costs	associated	with	the	project	deferral	as	well	as	a	scope	change	that	will	allow	the	refinery	to	process	heavier	and	more	acidic	crude	oils.

Through	these	investment	projects,	we	expect	to	more	than	double	our	coking	capacity	by	2012,	which	should	lead	to	lower	feedstock	costs	and	increased margins.	In	addition,	as	the	new	units	comprising	the	Garyville	refinery	expansion	reach	full	capacity	utilization,	we	anticipate	the	percentage	of	distillate	produced	to increase.

We	estimate	that	we	will	spend	approximately	$200	million	in	2009	to	comply	with	MSAT	II	regulations.

The	above	discussion	includes	forward-looking	statements	concerning	the	planned	expansion	of	the	Garyville	refinery,	the	Detroit	refinery	heavy	oil	upgrading	and expansion	project	and	MSAT	II	regulations	compliance	costs.	Some	factors	that	could	affect	the	Garyville,	Detroit	and	MSAT	II	projects	include	transportation	logistics, availability	of	materials	and	labor,	unforeseen	hazards	such	as	weather	conditions,	other	risks	customarily	associated	with	construction	projects.	These	factors	(among others)	could	cause	actual	results	to	differ	materially	from	those	set	forth	in	the	forward-looking	statements.

Our	net	worldwide	LNG	sales	volumes	are	expected	to	average	5,700	to	6,400	metric	tonnes	per	day	in	2009.

We	continue	to	invest	in	the	development	of	new	technologies	to	supply	new	energy	sources.	In	2008,	we	completed	construction	of	a	facility	to	demonstrate operation	of	the	fully	integrated	gas-to-fuels	process	at	a	practical	scale.	We	are	evaluating	the	commercialization	of	this	technology	and	have	engaged	an	engineering contractor	to	provide	engineering	and	design	services	for	using	our	proprietary	GTF™	technology	on	a	commercial	scale.

The	above	discussion	contains	forward	looking	statements	with	respect	to	future	LNG	sales	and	the	potential	commercialization	of	our	GTF™	technology. Projected	LNG	sales	volumes	are	based	upon	a	number	of	assumptions,	including	unforeseen	hazards	such	as	weather	conditions,	acts	of	war	or	terrorist	acts	and government	or	military	response	thereto	and	other	operating	and	economic	considerations.	The	foregoing	factors	(among	others)	could	cause	actual	results	to	differ materially	from	those	set	forth	in	the	forward-looking	statements.

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

We	have	incurred	and	will	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,	production	processes	and	whether	it	is	also	engaged	in the	petrochemical	business	or	the	marine	transportation	of	crude	oil	and	refined	products.

Our	environmental	expenditures	for	each	of	the	last	three	years	were:(a)

| (In	millions) | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Capital | $421 | $199 | $176 |
| Compliance |  |  |  |
| Operating\tand\tmaintenance | \t 379 | \t 287 | \t 309 |
| Remediation(b) | 26 | 25 | 20 |
| Total | $826 | $511 | $505 |
| (a) |  |  |  |

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

(b) 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	six	percent	of	capital	expenditures	for	continuing	operations	in	2008,	four	percent	in	2007	and	five	percent	in

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	are	expected	to	be	$373	million	or	seven	percent	of	capital	expenditures	in	2009.	Predictions	beyond	2009	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	$426	million	in	2010;	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,	see	Item	1.	Business	–	Environmental	Matters	and	Item	3.	Legal	Proceedings.

# 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.	Actual	results	could	differ	from	the	estimates	and	assumptions used.

Certain	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.

# Estimated	Net	Recoverable	Reserve	Quantities

# Proved	Liquid	Hydrocarbon	and	Natural	Gas	Reserves

We	use	the	successful	efforts	method	of	accounting	for	our	oil	and	gas	producing	activities.	The	successful	efforts	method	inherently	relies	on	the	estimation	of proved	liquid	hydrocarbon	and	natural	gas	reserves,	both	developed	and	undeveloped.	The	existence	and	the	estimated	amount	of	proved	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.	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	net	recoverable	quantities of	liquid	hydrocarbons	and	natural	gas.

Proved	reserves	are	the	estimated	quantities	of	liquid	hydrocarbons	and	natural	gas	that	geologic	and	engineering	data	demonstrate	with	reasonable	certainty	to	be recoverable	in	future	years	from	known	reservoirs	under	existing	economic	and	operating	conditions.	Estimates	of	proved	reserves	may	change,	either	positively	or negatively,	as	additional	information	becomes	available	and	as	contractual,	operational,	economic	and	political	conditions	change.	During	2008,	net	revisions	of previous	estimates	increased	total	proved	reserves	by	23	million	boe	(less	than	2	percent	of	the	beginning	of	the	year	reserve	estimate).

Our	estimation	of	net	recoverable	quantities	of	liquid	hydrocarbons	and	natural	gas	is	a	highly	technical	process	performed	by	in-house	teams	of	reservoir	engineers and	geoscience	professionals.	All	estimates	prepared	by	these	teams	are	made	in	compliance	with	SEC	Rule	4-10(a)(2),(3)	and	(4)	of	Regulation	S-X	and	SFAS	No.	25, "Suspension	of	Certain	Accounting	Requirements	for	Oil	and	Gas	Producing	Companies	(an	Amendment	of	Financial	Accounting	Standards	Board	("FASB")	Statement No.	19),"	and	disclosed	in	accordance	with	the	requirements	of	SFAS	No.	69,	"Disclosures	about	Oil	and	Gas	Producing	Activities	(an	Amendment	of	FASB	Statements 19,	25,	33	and	39)."	The	SEC	has	amended	its	disclosure	requirements	effective	for	annual	reports	on	Form	10-K	for	fiscal	years	ending	on	or	after	December	31,	2009	– see	Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	–	Accounting	Standards	Not	Yet	Adopted	for	additional	information. Estimates	of	liquid	hydrocarbon	and	natural	gas	reserves	are	based	on	prices	at	December	31,	2008.	Reserve	estimates	are	reviewed	and	approved	by	our	Corporate Reserves	Group.	Any	change	to	proved	reserves	estimates	in	excess	of	2.5	million	boe	on	a	total-field	basis,	within	a	single	month,	must	be	approved	by	the	Director	of Corporate	Reserves,	who	reports	to	our	Chief	Financial	Officer.	The	Corporate	Reserves	Group	may	also	perform	separate,	detailed	technical	reviews	of	reserve estimates	for	significant	fields	that	were	acquired	recently	or	for	properties	with	problematic	indicators	such	as	excessively	long	lives,	sudden	changes	in	performance	or changes	in	economic	or	operating	conditions.

Third-party	consultants	are	engaged	to	prepare	independent	reserve	estimates	for	fields	that	comprise	the	top	80	percent	of	our	total	reserves	over	a	rolling	four-year period.	We	met	this	goal	for	the	four-year	period	ended	December	31,	2008.	For	2006	and	thereafter,	we	established	a	tolerance	level	of	10	percent	for	third-party	reserve estimates	such	that	the	third-party	consultants	discontinue	their	estimation	activities	once	their	results	are	within	10	percent	of	our	internal	estimates.	Should	the	third- party	consultants'	initial	analysis	fail	to	reach	our	tolerance	level,	the	consultants	re-examine	the	information	provided,	request	additional	data	and	refine	their	analysis if	appropriate.	If,	after	this	re-examination,	the	third-party	consultants	cannot	arrive	at	estimates	within	our	tolerance,	we	adjust	our	reserve	estimates	as	necessary	to achieve	estimates	within	our	tolerance	level.	This	independent	third-party	reserve	estimation	process	did	not	result	in	significant	changes	to	our	reserve	estimates	in 2008,	2007,	or	2006.

The	reserves	of	the	Alba	field	in	Equatorial	Guinea	comprise	approximately	38	percent	of	our	total	proved	liquid	hydrocarbon	and	natural	gas	reserves	as	of December	31,	2008.	The	reserves	of	the	next	five	largest	asset	groups	–	the	Waha	concessions	in	Libya,	the	Alvheim/Vilje	development	offshore	Norway,	the	Droshky development	in	Green	Canyon	Block	244	in	the	Gulf	of	Mexico,	the	Oregon	Basin	field	in	the	Rocky	Mountain	area	of	the	United	States	and	the	Foinaven	development in	the	North	Sea	–	comprise	32	percent	of	our	total	proved	liquid	hydrocarbon	and	natural	gas	reserves.

Depreciation	and	depletion	of	producing	liquid	hydrocarbon	and	natural	gas	properties	is	determined	by	the	units-of-production	method	and	could	change	with revisions	to	estimated	proved	developed	reserves.	The	change	in	the	depreciation	and	depletion	rate	over	the	past	three	years	due	to	revisions	of	previous	reserve estimates	has	not	been	significant.	On	average,	a	five	percent	increase	in	the	amount	of	liquid	hydrocarbon	and	natural	gas	reserves	would	lower	the	depreciation	and depletion	rate	by	approximately	$0.47	per	barrel,	which	would	increase	pretax

income	by	approximately	$66	million	annually,	based	on	2008	production.	On	average,	a	five	percent	decrease	in	the	amount	of	liquid	hydrocarbon	and	natural	gas reserves	would	increase	the	depreciation	and	depletion	rate	by	approximately	$0.52	per	barrel	and	would	result	in	a	decrease	in	pretax	income	of	approximately	$73 million	annually,	based	on	2008	production.

# Proved	Bitumen	Reserves

We	acquired	a	20	percent	outside-operated	interest	in	the	AOSP	in	Alberta,	Canada	with	the	acquisition	of	Western	in	October	2007.	Oil	sands	mining	operations	at the	AOSP	are	outside	the	scope	of	SFAS	Nos.	25	and	69	and	SEC	Rule	4-10	of	Regulation	S-X;	therefore,	bitumen	production	and	reserves	are	not	included	in	our Supplementary	Information	on	Oil	and	Gas	Producing	Activities.	As	discussed,	the	SEC	has	recently	issued	a	release	amending	these	disclosures	–	see	Management's Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	–	Accounting	Standards	Not	Yet	Adopted	for	additional	information.

The	estimated	amount	of	proved	bitumen	reserves	affects	the	amount	and	timing	of	costs	depreciated,	depleted	or	amortized	into	net	income.	The	expected	future cash	flows	to	be	generated	by	oil	sands	mining	and	bitumen	upgrading	assets	used	in	testing	oil	sands	mining	and	bitumen	upgrading	assets	for	impairment	also	rely,	in part,	on	estimates	of	proved	bitumen	reserves.

Reserves	related	to	oil	sands	mining	operations	are	defined	as	that	part	of	a	mineral	deposit	which	could	be	economically	and	legally	extracted	or	produced	at	the time	of	the	reserve	determination.	Proved	bitumen	reserves	as	of	December	31,	2008	were	based	on	a	third-party	consultant's	estimate	using	volumetric	estimation techniques	similar	to	those	used	in	estimating	liquid	hydrocarbon	and	natural	gas	reserves,	except	that	estimates	of	bitumen	reserves	are	based	on	annual	average	prices for	2008,	which	is	believed	to	be	consistent	with	industry	practice	in	Canada.

Depreciation	and	depletion	of	most	oil	sands	mining	and	bitumen	upgrading	assets	is	determined	by	the	units-of-production	method	and	could	change	with revisions	to	estimated	proved	bitumen	reserves.	On	average,	a	five	percent	increase	in	estimated	bitumen	reserves	would	lower	the	depreciation	and	depletion	rate	by approximately	$0.98	per	barrel	and	would	result	in	an	increase	in	pretax	income	of	approximately	$9	million	annually,	based	on	2008	production.	On	average,	a	five percent	decrease	in	estimated	bitumen	reserves	would	increase	the	depreciation	and	depletion	rate	by	approximately	$0.52	per	barrel	and	would	result	in	a	decrease	in pretax	income	of	approximately	$5	million	annually,	based	on	2008	production.

# Fair	Value	Estimates

On	January	1,	2008,	we	adopted	SFAS	No.	157	for	those	financial	assets	and	liabilities	recognized	or	disclosed	at	fair	value	in	the	consolidated	financial	statements on	a	recurring	basis.	SFAS	No.	157	defines	fair	value,	establishes	a	framework	for	measuring	fair	value	and	expands	disclosures	about	fair	value	measurements.	It	does not	require	us	to	make	any	new	fair	value	measurements,	but	rather	establishes	a	fair	value	hierarchy	that	prioritizes	the	inputs	to	the	valuation	techniques	used	to measure	fair	value.	Level	1	inputs	are	given	the	highest	priority	in	the	fair	value	hierarchy,	as	they	represent	observable	inputs	that	reflect	unadjusted	quoted	prices	for identical	assets	or	liabilities	in	active	markets	as	of	the	reporting	date,	while	Level	3	inputs	are	given	the	lowest	priority,	as	they	represent	unobservable	inputs	that	are not	corroborated	by	market	data.	Valuation	techniques	that	maximize	the	use	of	observable	inputs	are	favored.	See	Note	17	of	the	consolidated	financial	statements	for disclosures	regarding	our	fair	value	measurements.

In	February	2008,	the	FASB	issued	FASB	Staff	Position	("FSP")	FAS	157-2,	"Effective	Date	of	FASB	Statement	No.	157,"	which	deferred	the	effective	date	of SFAS	No.	157	for	one	year	for	certain	nonfinancial	assets	and	nonfinancial	liabilities.	This	includes	impairments	of	goodwill,	intangible	assets	and	other	long-lived assets,	and	initial	measurement	of	asset	retirement	obligations,	asset	exchanges,	pensions,	business	combinations	and	partial	sales	of	proved	properties.

The	primary	impact	from	the	adoption	of	SFAS	No.	157	at	January	1,	2008,	related	to	the	fair	value	measurement	of	our	derivative	instruments.	Additional information	about	derivatives	and	their	valuation	may	be	found	in	Item	7A.	Quantitative	and	Qualitative	Disclosures	About	Market	Risk.

# Significant	uses	of	fair	value	measurements	include:

•allocation	of	the	purchase	price	paid	to	acquire	businesses	to	the	assets	acquired	and	liabilities	assumed	in	those	acquisitions,

•assessment	of	impairment	of	long-lived	assets,

•assessment	of	impairment	of	goodwill,	and

•recorded	value	of	derivative	instruments.

# Acquisitions

Under	the	purchase	method	of	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	involving property,	plant	and	equipment	and	identifiable	intangible	assets.	We	use	all	available	information	to	make	these	fair	value	determinations	and,	for	certain	acquisitions, engage	third-party	consultants	for	assistance.

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	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.

# Impairment	Assessments	of	Goodwill	and	Long-Lived	Assets

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

•Future	liquid	hydrocarbon	and	natural	gas	prices.	Our	estimates	of	future	prices	are	based	on	our	analysis	of	market	supply	and	demand	and	consideration	of market	price	indicators.	Although	liquid	hydrocarbon	and	natural	gas	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	world-wide	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.	Such	price	estimates	are	consistent	with	those	used	in	our	planning	and	capital	investment	reviews.	There	has been	significant	volatility	in	the	liquid	hydrocarbon	and	natural	gas	prices	and	estimates	of	such	price	curves	are	inherently	imprecise.

•Estimated	recoverable	quantities	of	liquid	hydrocarbons,	natural	gas	and	bitumen.	This	is	based	on	a	combination	of	proved	and	risk-adjusted	probable	and possible	reserves.	These	estimates	are	based	on	work	performed	by	our	engineers	and	that	of	outside	consultants.	Because	of	their	very	nature,	probable	and possible	reserves	are	less	precise	than	those	of	proved	reserves.	We	evaluate	our	probable	and	possible	reserves	using	drilling	results,	reservoir	performance, seismic	interpretation	and	future	plans	to	develop	acreage.	Reserves	are	adjusted	as	new	information	becomes	available.

•Expected	timing	of	production.	Production	forecasts	are	based	on	a	combination	of	proved	and	risk-adjusted	probable	and	possible	reserves	based	on engineering	studies.	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.

•Future	margins	on	refined	products	produced	and	sold.	Our	estimates	of	future	product	margins	are	based	on	our	own	analysis	of	various	supply	and	demand factors,	which	includes,	among	other	things,	industry-wide	capacity,	our	planned	utilization	rate,	end-user	demand,	capital	expenditures,	and	economic conditions.	Such	estimates	are	consistent	with	those	used	in	our	planning	and	capital	investment	reviews.

•	 Discount	rate	commensurate	with	the	risks	involved.	We	apply	a	discount	rate	to	our	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.	This	is	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	those	projections.

The	need	to	test	for	impairment	can	be	based	on	several	indicators,	including	a	significant	reduction	in	prices	of	liquid	hydrocarbons	or	natural	gas,	unfavorable adjustments	to	reserves,	significant	changes	in	the	expected	timing	of	production,	significant	reduction	in	refining	margins,	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,	project	level	for	oil	sands	mining	assets,	refinery	and	associated	distribution	system	level	or	pipeline	system	level	for	refining and	transportation	assets,	or	site	level	for	retail	stores.	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.

An	estimate	as	to	the	sensitivity	to	earnings	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.

# 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.

In	our	E&P	segment,	we	have	two	long-term	contracts	for	the	sale	of	natural	gas	in	the	United	Kingdom	that	are	accounted	for	as	derivative	instruments.	These contracts,	which	expire	in	September	2009,	were	entered	into	in	the	early	1990s	in	support	of	our	investments	in	the	East	Brae	field	and	the	SAGE	pipeline.	The	contract price	is	reset	annually	in	October	and	is	indexed	to	a	basket	of	costs	of	living	and	energy	commodity	indices	for	the	previous	twelve	months.	Consequently,	the	prices under	these	contracts	do	not	track	forward	natural	gas	prices.	The	fair	value	of	these	contracts	is	determined	by	applying	the	difference	between	the	contract	price	and the	U.K.	forward	natural	gas	strip	price	to	the	expected	sales	volumes	under	these	contracts	for	the	shorter	of	the	remaining	contract	terms	or	18	months.	Adjustments	to the	fair	value	of	these	contracts	result	in	non-cash	charges	or	credits	to	income	from	operations.	The	difference	between	the	contract	price	and	the	U.K.	forward	natural gas	strip	price	may	fluctuate	widely	from	time	to	time	and	may	significantly	affect	income	from	operations.	A	10	percent	increase	in	natural	gas	prices	would	decrease the	fair	value	of	these	derivatives	by	$21	million,	while	a	10	percent	decrease	in	natural	gas	prices	would	increase	the	fair	value	of	these	derivatives	by	$21	million	in 2008.

Our	OSM	segment	holds	crude	oil	options	expiring	December	2009,	which	were	designed	to	protect	against	price	decreases	on	portions	of	future	synthetic	crude	oil sales.	The	fair	value	of	these	options	is	measured	using	a	Black-Scholes	option	pricing	model	that	uses	prices	from	the	active	commodity	market	and	a	market	volatility calculated	by	a	third-party	service.	A	10	percent	increase	in	crude	oil	prices	would	decrease	the	fair	value	of	these	options	by	$4	million,	while	a	10	percent	decrease	in crude	oil	prices	would	increase	the	fair	value	of	these	options	by	$13	million	in	2008.

# Expected	Future	Taxable	Income

We	must	estimate	our	expected	future	taxable	income	to	assess	the	realizability	of	our	deferred	income	tax	assets.

Numerous	assumptions	are	inherent	in	the	estimation	of	future	taxable	income,	including	assumptions	about	matters	that	are	dependent	on	future	events,	such	as future	operating	conditions	(particularly	as	related	to	prevailing	oil	and	natural	gas	prices)	and	future	financial	conditions.	The	estimates	and	assumptions	used	in determining	future	taxable	income	are	consistent	with	those	used	in	our	internal	budgets,	forecasts	and	strategic	plans.

In	determining	our	overall	estimated	future	taxable	income	for	purposes	of	assessing	the	need	for	additional	valuation	allowances,	we	consider	proved	and	risk- adjusted	probable	reserves	related	to	our	existing	producing	properties,	as	well	as	estimated	quantities	of	oil	and	natural	gas	related	to	undeveloped	discoveries	if,	in	our judgment,	it	is	likely	that	development	plans	will	be	approved	in	the	foreseeable	future.	In	assessing	the	releasing	of	an	existing	valuation	allowance,	we	consider	the preponderance	of	evidence	concerning	the	realization	of	the	impaired	deferred	tax	asset.

Additionally,	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	these	strategies	and	if	we	expect	to	implement	these	strategies	in	the	event	the forecasted	conditions	actually	occurred.	The	principal	tax	planning	strategy	available	to	us	relates	to	the	permanent	reinvestment	of	the	earnings	of	our	foreign subsidiaries.	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.

# 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	plans	and	our	unfunded	U.S.	retiree	health	care	plan	due	to	the	different	projected	liability	durations	of	8	years	and	13	years.	The selected	rates	are	compared	to	various	similar	bond	indexes	for	reasonableness.	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	modeling	tool.	This	tool	applies	a	yield	curve	to	the	projected	benefit	plan	cash flows	using	a	hypothetical	Aa	yield	curve.	The	yield	curve	represents	a	series	of	annualized	individual	discount	rates	from	1.5	to	30	years.	The	bonds	used	are	rated	Aa or	higher	by	a	recognized	rating	agency	and	only	non-callable	bonds	are	included.	Each	issue	is	required	to	have	at	least	$150	million	par	value	outstanding.	The	top quartile	bonds	are	selected	within	each	maturity	group	to	construct	the	yield	curve.

Of	the	assumptions	used	to	measure	the	December	31,	2008	obligations	and	estimated	2009	net	periodic	benefit	cost,	the	discount	rate	has	the	most	significant effect	on	the	periodic	benefit	cost	reported	for	the	plans.	A	0.25	percent	decrease	in	the	discount	rates	of	6.9	percent	for	our	U.S.	pension	plans	and	6.85	percent	for	our other	U.S.	postretirement	benefit	plans	would	increase	pension	obligations	and	other	postretirement	benefit	plan	obligations	by	$66	million	and	$21	million	and	would increase	defined	benefit	pension	expense	and	other	postretirement	benefit	plan	expense	by	$9	million	and	$3	million.

The	asset	rate	of	return	assumption	considers	the	asset	mix	of	the	plans	(currently	targeted	at	approximately	75	percent	equity	securities	and	25	percent	debt securities	for	the	U.S.	funded	pension	plans	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	assumptions	are compared	to	those	of	peer	companies	and	to	historical	returns	for	reasonableness	and	appropriateness.	A	0.25	percent	decrease	in	the	asset	rate	of	return	assumption would	not	have	a	significant	impact	on	our	defined	benefit	pension	expense.

Compensation	increase	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.

Note	23	to	the	consolidated	financial	statements	includes	detailed	information	about	the	assumptions	used	to	calculate	the	components	of	our	defined	benefit pension	and	other	postretirement	plan	expense	for	2008,	2007	and	2006,	as	well	as	the	obligations	and	accumulated	other	comprehensive	income	reported	on	the	balance sheets	as	of	December	31,	2008,	and	2007.

In	2006,	we	made	certain	plan	design	changes	which	included	an	update	of	the	mortality	table	used	in	the	plans'	definition	of	actuarial	equivalence	and	lump	sum calculations	and	a	20	percent	retiree	cost	of	living	adjustment	for	annuitants.	This	change	increased	our	benefit	obligations	by	$117	million.	There	were	no	plan	design changes	in	2008	or	2007.

# Contingent	Liabilities

We	accrue	contingent	liabilities	for	environmental	remediation,	tax	deficiencies	unrelated	to	income	taxes,	product	liability	claims	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 Management's	Discussion	and	Analysis	of	Environmental	Matters,	Litigation	and	Contingencies.

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

# Accounting	Standards	Not	Yet	Adopted

In	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	in	their	reserve	base	volumes	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.	The	SEC	indicated	that	they	will	continue	to	communicate	with	the	FASB	staff	to	align	their	accounting	standards	with	these rules.	The	FASB	currently	requires	a	single-day,	year-end	price	for	accounting	purposes.

•Permit	companies	to	disclose	their	probable	and	possible	reserves	on	a	voluntary	basis.	In	the	past,	proved	reserves	were	the	only	reserves	allowed	in	the disclosures.

•	 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	will	be	mandatory.

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

If	finalized,	we	will	apply	the	new	disclosure	requirements	in	our	annual	report	on	Form	10-K	for	the	year	ending	December	31,	2009.	The	new	rules	may	not	be applied	to	disclosures	in	quarterly	reports	prior	to	the	first	annual	report	in	which	the	revised	disclosures	are	required.	We	are	currently	in	the	process	of	evaluating	the new	requirements.

Also	in	December	2008,	the	FASB	issued	FSP	FAS	132(R)-1,	"Employers	Disclosures	about	Postretirement	Benefit	Plan	Assets"	which	provides	guidance	on	an employer's	disclosures	about	plan	assets	of	a	defined	benefit	pension	or	other	postretirement	plans.	This	would	require	additional	disclosures	about	investment	policies and	strategies,	the	reporting	of	fair	value	by	asset	category	and	other	information	about	fair	value	measurements.	The	FSP	is	effective	January	1,	2009	and	early application	is	permitted.	Upon	initial	application,	the	provisions	of	FSP	FAS	132(R)-1	are	not	required	for	earlier	periods	that	are	presented	for	comparative	purposes. We	will	expand	our	disclosures	in	accordance	with	FSP	FAS	132(R)-1	in	our	annual	report	on	Form	10-K	for	the	year	ending	December	31,	2009;	however,	the adoption	of	this	standard	is	not	expected	to	have	a	significant	impact	on	our	consolidated	results	of	operations,	financial	position	or	cash	flows.

In	November	2008,	the	FASB	ratified	EITF	08-6,	"Equity	Method	Investment	Accounting	Considerations"	("EITF	08-6")	which	clarifies	how	to	account	for certain	transactions	involving	equity	method	investments.	The	initial	measurement,	decreases	in	value	and	changes	in	the	level	of	ownership	of	the	equity	method investment	are	addressed.	EITF	08-6	is	effective	on	a	prospective	basis	for	our	fiscal	year	beginning	January	1,	2009	and	interim	periods	within	the	years.	Early application	by	an	entity	that	has	previously	adopted	an	alternative	accounting	policy	is	not	permitted.	Since	this	standard	will	be	applied	prospectively,	adoption	is	not expected	to	have	a	significant	impact	on	our	consolidated	results	of	operations,	financial	position	or	cash	flows.

In	June	2008,	the	FASB	issued	FSP	on	Emerging	Issues	Task	Force	("EITF")	03-6-1,	"Determining	Whether	Instruments	Granted	in	Share-Based	Payment Transactions	Are	Participating	Securities"	("FSP	EITF	03-6-1")	which	provides	that	unvested	share-based	payment	awards	that	contain	nonforfeitable	rights	to dividends	or	dividend	equivalents	(whether	paid	or	unpaid)	are	participating	securities	and,	therefore,	need	to	be	included	in	the	earnings	allocation	in	computing earnings	per	share	("EPS")	under	the	two-class	method.	FSP	EITF	03-6-1	is	effective	January	1,	2009,	and	all	prior-period	EPS	data	(including	any	amounts	related	to interim	periods,	summaries	of	earnings	and	selected	financial	data)	will	be	adjusted	retrospectively	to	conform	to	its	provisions.	Early	application	of	FSP	EITF	03-6-1	is not	permitted.	Although	restricted	stock	awards	meet	this	definition	of	participating	securities,	we	do	not	expect	application	of	FSP	EITF	03-6-1	to	have	a	significant impact	on	our	reported	EPS.

In	April	2008,	the	FASB	issued	FSP	on	FAS	142-3	("FSP	FAS	142-3")	which	amends	the	factors	that	should	be	considered	in	developing	renewal	or	extension assumptions	used	to	determine	the	useful	life	of	a	recognized	intangible	asset	under	Statement	of	Financial	Accounting	Standards	("SFAS")	No.	142,	"Goodwill	and Other	Intangible	Assets."	The	intent	of	this	FSP	is	to	improve	the	consistency	between	the	useful	life	of	a	recognized	intangible	asset	and	the	period	of	expected	cash flows	used	to	measure	the	fair	value	of	the	asset.	FSP	FAS	142-3	is	effective	on	January	1,	2009,	early	adoption	is	prohibited.	The	provisions	of	FSP	FAS	142-3	are	to be	applied	prospectively	to	intangible	assets	acquired	after	the	effective	date,	except	for	the	disclosure	requirements	which	must	be	applied	prospectively	to	all	intangible assets	recognized	as	of,	and	subsequent	to,	the	effective	date.	Since	this	standard	will	be	applied	prospectively,	adoption	is	not	expected	to	have	a	significant	impact	on our	consolidated	results	of	operations,	financial	position	or	cash	flows.

In	March	2008,	the	FASB	issued	SFAS	No.	161,	"Disclosures	about	Derivative	Instruments	and	Hedging	Activities	–	an	amendment	of	FASB	Statement No.	133."	This	statement	expands	the	disclosure	requirements	for	derivative	instruments	to	provide	information	regarding	(i)	how	and	why	an	entity	uses	derivative instruments,	(ii)	how	derivative	instruments	and	related	hedged	items	are	accounted	for	under	SFAS	No.	133	and	its	related	interpretations	and	(iii)	how	derivative instruments	and	related	hedged	items	affect	an	entity's	financial	position,	financial	performance	and	cash	flows.	To	meet	these	objectives,	the	statement	requires qualitative	disclosures	about	objectives	and	strategies	for	using	derivatives,	quantitative	disclosures	about	fair	value	amounts	and	gains	and	losses	on	derivative instruments	and	disclosures	about	credit-risk-related	contingent	features	in	derivative	agreements.	This	standard	is	effective	January	1,	2009.	The	statement	encourages but	does	not	require	disclosures	for	earlier	periods	presented	for	comparative	purposes	at	initial	adoption.	We	will	expand	our	disclosures	in	accordance	with	SFAS No.	161	beginning	in	the	first	quarter	of	2009;	however,	the	adoption	of	this	standard	is	not	expected	to	have	a	significant	impact	on	our	consolidated	results	of operations,	financial	position	or	cash	flows.

In	December	2007,	the	FASB	issued	SFAS	No.	141	(Revised	2007),	"Business	Combinations"	("SFAS	No.	141	(R)").	This	statement	significantly	changes	the accounting	for	business	combinations.	Under	SFAS	No.141(R),	an	acquiring	entity	will	be	required	to	recognize	all	the	assets	acquired,	liabilities	assumed	and	any	non- controlling

interest	in	the	acquiree	at	their	acquisition-date	fair	value	with	limited	exceptions.	The	statement	expands	the	definition	of	a	business	and	is	expected	to	be	applicable	to more	transactions	than	the	previous	business	combinations	standard.	The	statement	also	changes	the	accounting	treatment	for	changes	in	control,	step	acquisitions, transaction	costs,	acquired	contingent	liabilities,	in-process	research	and	development,	restructuring	costs,	changes	in	deferred	tax	asset	valuation	allowances	as	a	result of	a	business	combination	and	changes	in	income	tax	uncertainties	after	the	acquisition	date.	Accounting	for	changes	in	valuation	allowances	for	acquired	deferred	tax assets	and	the	resolution	of	uncertain	tax	positions	for	prior	business	combinations	will	impact	tax	expense	instead	of	impacting	recorded	goodwill.	Additional disclosures	are	also	required.	SFAS	No.	141(R)	is	effective	on	January	1,	2009,	for	all	new	business	combinations.	The	adoption	of	this	standard	is	not	expected	to	have a	significant	impact	on	our	consolidated	results	of	operations,	financial	position	or	cash	flows.

Also	in	December	2007,	the	FASB	issued	SFAS	No.	160,	"Noncontrolling	Interests	in	Consolidated	Financial	Statements	–	An	Amendment	of	ARB	No.	51."	This statement	establishes	new	accounting	and	reporting	standards	for	the	noncontrolling	interest	in	a	subsidiary	and	for	the	deconsolidation	of	a	subsidiary.	Specifically,	this statement	clarifies	that	a	noncontrolling	interest	in	a	subsidiary	(sometimes	called	a	minority	interest)	is	an	ownership	interest	in	the	consolidated	entity	that	should	be reported	as	equity	in	the	consolidated	financial	statements,	but	separate	from	the	parent's	equity.	It	requires	that	the	amount	of	consolidated	net	income	attributable	to	the noncontrolling	interest	be	clearly	identified	and	presented	on	the	face	of	the	consolidated	income	statement.	SFAS	No.	160	clarifies	that	changes	in	a	parent's	ownership interest	in	a	subsidiary	that	do	not	result	in	deconsolidation	are	equity	transactions	if	the	parent	retains	its	controlling	financial	interest.	In	addition,	this	statement requires	that	a	parent	recognize	a	gain	or	loss	in	net	income	when	a	subsidiary	is	deconsolidated,	based	on	the	fair	value	of	the	noncontrolling	equity	investment	on	the deconsolidation	date.	Additional	disclosures	are	required	that	clearly	identify	and	distinguish	between	the	interests	of	the	parent	and	the	interests	of	the	noncontrolling owners.	SFAS	No.	160	is	effective	January	1,	2009,	and	early	adoption	is	prohibited.	The	statement	must	be	applied	prospectively,	except	for	the	presentation	and disclosure	requirements	which	must	be	applied	retrospectively	for	all	periods	presented	in	consolidated	financial	statements.	We	do	not	have	significant	noncontrolling interests	in	consolidated	subsidiaries,	and	therefore,	adoption	of	this	standard	is	not	expected	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	crude	oil,	natural	gas	and	refined	product	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.

# 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.	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	also	may	utilize	the	market	knowledge	gained	from	these	activities	to	do	a	limited	amount	of	trading	not	directly	related	to	our physical	transactions.

Our	E&P	segment	primarily	uses	commodity	derivative	instruments	to	mitigate	the	natural	gas	price	risk	during	the	time	that	the	natural	gas	is	held	in	storage before	it	is	sold	or	on	natural	gas	that	is	purchased	to	be	marketed	with	our	own	natural	gas	production.	We	also	may	use	commodity	derivative	instruments	selectively to	protect	against	price	decreases	on	portions	of	our	future	sales	of	liquid	hydrocarbons	or	natural	gas	when	it	is	deemed	advantageous	to	do	so.	The	majority	of	these derivatives	are	measured	at	fair	value	with	a	market	approach	using	broker	quotes	or	third-party	pricing	services,	which	have	been	corroborated	with	data	from	active markets,	making	them	a	Level	2	in	the	fair	value	hierarchy	described	by	SFAS	No.	157.

Unrealized	gains	and	losses	on	certain	natural	gas	contracts	in	the	U.K.	that	are	accounted	for	as	derivative	instruments	are	excluded	from	E&P	segment	income. These	contracts	originated	in	the	early	1990s	and	expire	in	September	2009.	The	contract	prices	are	reset	annually	in	October	based	on	the	previous	twelve-month changes	in	a	basket	of	energy	and	other	indices.	Consequently,	the	prices	under	these	contracts	do	not	track	forward	natural	gas	prices.	The	reported	fair	value	of	the U.K.	natural	gas	contracts	is	measured	with	an	income	approach	by	applying	the	difference	between	the	contract	price	and	the	U.K.	forward	natural	gas	strip	price	to	the expected	sales	volumes	for	the	shorter	of	the	remaining	contract	term	or	18	months.	Such	an	internally	generated	model	is	classified	as	Level	3	in	the	fair	value hierarchy.

Our	OSM	segment	may	use	commodity	derivative	instruments	to	protect	against	price	decreases	on	portions	of	our	future	sales	of	synthetic	crude	oil	when	it	is deemed	advantageous	to	do	so.	The	reported	fair	value	of	these	crude	oil	options,	which	expire	December	2009,	is	measured	using	a	Black-Scholes	option	pricing	model, which	is	an	income	approach	that	utilizes	prices	from	the	active	commodity	market	and	market	volatility	calculated	by	a	third-party	service.	Because	a	third-party service	is	used,	and	their	inputs	represent	unobservable	market	data,	these	are	classified	as	Level	3	in	the	fair	value	hierarchy.

Our	RM&T	segment	primarily	uses	commodity	derivative	instruments	on	a	selective	basis	to	mitigate	crude	oil	price	risk	during	the	time	that	crude	oil	inventories are	held	before	they	are	actually	refined	into	salable	petroleum	products.	We	also	use	derivative	instruments	in	our	RM&T	segment	to	manage	price	risk	related	to refined	petroleum	products,	feedstocks	used	in	the	refining	process	and	ethanol	blended	with	refined	petroleum	products	and	fixed	price	sales	contracts.	We	use commodity	derivative	instruments	to	mitigate	crude	oil	price	risk	between	the	time	that	crude	oil	purchases	are	priced	and	when	they	are	actually	refined	into	salable petroleum	products,	but	we	have	decreased	our	use	of	derivatives	in	this	manner	as	described	further	below.	The	majority	of	these	derivatives	are	exchange-traded contracts	for	crude	oil,	natural	gas,	refined	products	and	ethanol	measured	at	fair	value	with	a	market	approach	using	the	close-of-day	settlement	prices	for	the	market making	them	a	Level	1	in	the	fair	value	hierarchy.	When	broker	accounts	are	covered	by	master	netting	agreements	the	broker	deposits	are	netted	against	the	value	to arrive	at	the	fair	values	of	Level	1	and	Level	2	commodity	derivatives.

Generally,	commodity	derivative	instruments	used	in	our	E&P	segment	qualify	for	hedge	accounting.	As	a	result,	we	do	not	recognize	in	net	income	any	changes	in the	fair	value	of	those	derivative	instruments	until	the

underlying	physical	transaction	occurs.	We	have	not	qualified	commodity	derivative	instruments	used	in	our	OSM	or	RM&T	segments	for	hedge	accounting.	As	a	result, we	recognize	in	net	income	all	changes	in	the	fair	value	of	derivative	instruments	used	in	those	operations.

# Open	Commodity	Derivative	Positions	as	of	December	31,	2008	and	Sensitivity	Analysis

At	December	31,	2008,	our	E&P	segment	held	open	derivative	contracts	to	mitigate	the	price	risk	on	natural	gas	held	in	storage	or	purchased	to	be	marketed	with our	own	natural	gas	production	in	amounts	that	were	in	line	with	normal	levels	of	activity.	At	December	31,	2008,	we	had	no	significant	open	derivative	contracts related	to	our	future	sales	of	liquid	hydrocarbons	and	natural	gas	and	therefore	remained	substantially	exposed	to	market	prices	of	these	commodities.

The	OSM	segment	holds	crude	oil	options	which	were	purchased	by	Western	for	a	three	year	period	(January	2007	to	December	2009).	The	premiums	for	the purchased	put	options	had	been	partially	offset	through	the	sale	of	call	options	for	the	same	three-year	period,	resulting	in	a	net	premium	liability.	Payment	of	the	net premium	liability	is	deferred	until	the	settlement	of	the	option	contracts.	As	of	December	31,	2008,	the	following	put	and	call	options	were	outstanding:

In	the	first	quarter	of	2009,	we	sold	derivative	instruments	at	an	average	exercise	price	of	$50.50	which	effectively	offset	the	open	put	options	for	the	remainder	of 2009.

At	December	31,	2008,	the	number	of	open	derivative	contracts	held	by	our	RM&T	segment	was	lower	than	in	previous	periods.	Starting	in	the	second	quarter	of 2008,	we	decreased	our	use	of	derivatives	to	mitigate	crude	oil	price	risk	between	the	time	that	domestic	spot	crude	oil	purchases	are	priced	and	when	they	are	actually refined	into	salable	petroleum	products.	Instead,	we	are	addressing	this	price	risk	through	other	means,	including	changes	in	contractual	terms	and	crude	oil	acquisition practices.

Additionally,	in	previous	periods,	certain	contracts	in	our	RM&T	segment	for	the	purchase	or	sale	of	commodities	were	not	qualified	or	designated	as	normal purchase	or	normal	sales	under	generally	accepted	accounting	principles	and	therefore	were	accounted	for	as	derivative	instruments.	During	the	second	quarter	of	2008, as	we	decreased	our	use	of	derivatives,	we	began	to	designate	such	contracts	for	the	normal	purchase	and	normal	sale	exclusion.

Sensitivity	analysis	of	the	incremental	effects	on	income	from	operations	("IFO")	of	hypothetical	10	percent	and	25	percent	changes	in	commodity	prices	for	open commodity	derivative	instruments	as	of	December	31,	2008,	is	provided	in	the	following	table.	The	direction	of	the	price	change	used	in	calculating	the	sensitivity amount	for	each	commodity	reflects	that	which	would	result	in	the	largest	incremental	decrease	in	IFO	when	applied	to	the	commodity	derivative	instruments	used	to hedge	that	commodity.

(a) We	remain	at	risk	for	possible	changes	in	the	market	value	of	commodity	derivative	instruments;	however,	such	risk	should	be	mitigated	by	price	changes	in	the	underlying	physical	commodity.	Effects	of	these offsets	are	not	reflected	in	the	sensitivity	analysis.	Amounts	reflect	hypothetical	10	percent	and	25	percent	changes	in	closing	commodity	prices	for	each	open	contract	position	at	December	31,	2008.	Included	in the	natural	gas	impacts	above	were	$21	million	and	$53	million	for	hypothetical	price	changes	of	10	percent	and	25	percent	related	to	the	U.K.	natural	gas	contracts	accounted	for	as	derivative	instruments.	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.	Changes	to	the	portfolio	after December	31,	2008,	would	cause	future	IFO	effects	to	differ	from	those	presented	above.

(b) The	number	of	net	open	contracts	for	the	E&P	segment	varied	throughout	2008,	from	a	low	of	3	contracts	on	October	1,	2008,	to	a	high	of	472	contracts	on	January	29,	2008,	and	averaged	181	for	the	year.	The number	of	net	open	contracts	for	the	RM&T	segment	varied	throughout	2008,	from	a	low	of	13	contracts	on	May	16,	2008,	to	a	high	of	15,599	contracts	on	March	17,	2008,	and	averaged	3,019	for	the	year.	The number	of	net	open	contracts	for	the	OSM	segment	varied	throughout	2008,	from	a	low	of	12,775	contracts	on	December	31,	2008,	to	a	high	of	24,500	contracts	on	January	1,	2008,	and	averaged	18,646	for	the year.	The	commodity	derivative	instruments	used	and	positions	taken	will	vary	and,	because	of	these	variations	in	the	composition	of	the	portfolio	over	time,	the	number	of	open	contracts	by	itself	cannot	be	used to	predict	future	income	effects.

(c) Price	increase. (d) Price	decrease.

# 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,	2008,	we	had	multiple	interest	rate	swap	agreements	with	a	total	notional	amount	of	$450	million,	designated	as	a fair	value	hedge,	which	effectively	resulted	in	an	exchange	of	existing	obligations	to	pay	fixed	interest	rates	for	obligations	to	pay	floating	rates.	The	weighted	average floating	rate	on	these	swap	agreements	is	LIBOR	plus	2.060	percent.

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, 2008,	is	provided	in	the	following	table.

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

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

(c) For	receivables	from	United	States	Steel	and	long-term	debt,	this	assumes	a	10	percent	decrease	in	the	weighted	average	yield-to-maturity	of	our	receivables	and	long-term	debt	at	December	31,	2008.	For	interest rate	swap	agreements,	this	assumes	a	10	percent	decrease	in	the	effective	swap	rate	at	December	31,	2008.

At	December	31,	2008,	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	manage	our	exposure	to	foreign	currency	exchange	rates	by	utilizing	forward	and	option	contracts,	although	we	had	no	option	contracts	open	at	December	31, 2008.	The	primary	objective	of	this	program	is	to	reduce	our	exposure	to	movements	in	foreign	currency	exchange	rates	by	locking	in	such	rates.	The	following	table summarizes	our	derivative	foreign	currency	derivative	instruments	as	of	December	31,	2008.

|  |  |  | Average |  |
| :--- | :--- | :--- | :--- | :--- |
|  |  | Notional | Forward | Fair |
| (In\tmillions) | Period | Amount | Rate(a) | Value(b) |
| Foreign\tCurrency\tForwards |  |  |  |  |
| Dollar\t(Canada) | January\t2009\t–\tFebruary\t2010 | $564 | 1.063(d) | $(68) |
| Euro | January\t2009\t–\tApril\t2010 | $27 | 1.358(d) | $1 |
| Kroner\t(Norway) | January\t2009\t–\tNovember\t2009 | $500 | 6.263(c) | $(8) |
| Rates\tshown\tare\tweighted\taverage\tforward\trates\tfor\tthe\tperiod.\n(a) |  |  |  |  |

(a) Rates	shown	are	weighted	average	forward	rates	for	the	period.

(b) Fair	value	was	based	on	market	rates.

(c) U.S.	dollar	to	foreign	currency. (d) Foreign	currency	to	U.S.	dollar.

The	aggregate	cash	flow	effect	on	foreign	currency	contracts	of	a	hypothetical	10	percent	change	to	exchange	rates	at	December	31,	2008,	would	be	$52	million.

# Counterparty	Risk

We	are	also	exposed	to	credit	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	crude	oil, natural	gas,	refined	products	and	other	feedstocks.	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 | 74 |
| Management's\tReport\ton\tInternal\tControl\tOver\tFinancial\tReporting | 74 |
| Report\tof\tIndependent\tRegistered\tPublic\tAccounting\tFirm | 75 |
| Audited\tConsolidated\tFinancial\tStatements |  |
| Consolidated\tStatements\tof\tIncome | 76 |
| Consolidated\tBalance\tSheets | 77 |
| Consolidated\tStatements\tof\tCash\tFlows | 78 |
| Consolidated\tStatements\tof\tStockholders'\tEquity | 79 |
| Notes\tto\tConsolidated\tFinancial\tStatements | 80 |
| Select\tQuarterly\tFinancial\tData\t(Unaudited) | 121 |
| Supplementary\tInformation\ton\tOil\tand\tGas\tProducing\tActivities\t(Unaudited) | 122 |
| Supplemental\tStatistics\t(Unaudited) | 129 |

# 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")	are	the	responsibility	of management	and	have	been	prepared	in	conformity	with	accounting	principles	generally	accepted	in	the	United	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	seeks	to	assure	the	objectivity	and	integrity	of	its	financial	records	by	careful	selection	of	its	managers,	by	organizational	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.

President	and

Chief	Executive	Officer

Executive	Vice	President

and	Chief	Financial	Officer

Vice	President,	Accounting

and	Controller

# Management's	Report	on	Internal	Control	over	Financial	Reporting

Marathon'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's	management concluded	that	its	internal	control	over	financial	reporting	was	effective	as	of	December	31,	2008.

The	effectiveness	of	Marathon's	internal	control	over	financial	reporting	as	of	December	31,	2008	has	been	audited	by	PricewaterhouseCoopers	LLP,	an independent	registered	public	accounting	firm,	as	stated	in	their	report	which	is	included	herein.

# Report	of	Independent	Registered	Public	Accounting	Firm

In	our	opinion,	the	consolidated	financial	statements	listed	in	the	accompanying	index	present	fairly,	in	all	material	respects,	the	financial	position	of	Marathon	Oil Corporation	and	its	subsidiaries	(the	"Company")	at	December	31,	2008,	and	2007,	and	the	results	of	their	operations	and	their	cash	flows	for	each	of	the	three	years	in the	period	ended	December	31,	2008,	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,	2008,	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.

As	discussed	in	Note	2	to	the	consolidated	financial	statements,	the	Company	changed	its	method	of	accounting	for	purchases	and	sales	of	inventory	with	the	same counterparty	and	defined	benefit	pension	and	other	postretirement	plans	in	2006.

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	27,	2009

# Consolidated	Statements	of	Income

| (In	millions,	except	per	share	data) | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Revenues\tand\tother\tincome: |  |  |  |
| Sales\tand\tother\toperating\trevenues\t(including\tconsumer\texcise\ttaxes) | $75,314 | $62,800 | $57,973 |
| Revenue\tfrom\tmatching\tbuy/sell\ttransactions | – | 127 | 5,457 |
| Sales\tto\trelated\tparties | 1,879 | 1,625 | 1,466 |
| Income\tfrom\tequity\tmethod\tinvestments | 765 | 545 | 391 |
| Net\tgain\ton\tdisposal\tof\tassets | 423 | 36 | 77 |
| Other\tincome | 188 | 74 | 85 |
| Total\trevenues\tand\tother\tincome | \t 78,569 | \t 65,207 | \t 65,449 |
| Costs\tand\texpenses: |  |  |  |
| Cost\tof\trevenues\t(excludes\titems\tbelow) | \t 59,817 | \t 49,104 | \t 42,415 |
| Purchases\trelated\tto\tmatching\tbuy/sell\ttransactions | – | 149 | 5,396 |
| Purchases\tfrom\trelated\tparties | 715 | 363 | 210 |
| Consumer\texcise\ttaxes | 5,065 | 5,163 | 4,979 |
| Depreciation,\tdepletion\tand\tamortization | 2,178 | 1,613 | 1,518 |
| Goodwill\timpairment | 1,412 | – | – |
| Selling,\tgeneral\tand\tadministrative\texpenses | 1,387 | 1,327 | 1,228 |
| Other\ttaxes | 482 | 394 | 371 |
| Exploration\texpenses | 490 | 454 | 365 |
| Total\tcosts\tand\texpenses | \t 71,546 | \t 58,567 | \t 56,482 |
| Income\tfrom\toperations | 7,023 | 6,640 | 8,967 |
| Net\tinterest\tand\tother\tfinancing\tincome\t(costs) | (50) | 41 | 37 |
| Gain\ton\tforeign\tcurrency\tderivative\tinstruments | – | 182 | – |
| Loss\ton\tearly\textinguishment\tof\tdebt | – | (17) | (35) |
| Minority\tinterests\tin\tloss\tof\tEquatorial\tGuinea\tLNG\tHoldings\tLimited | – | 3 | 10 |
| Income\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | 6,973 | 6,849 | 8,979 |
| Provision\tfor\tincome\ttaxes | 3,445 | 2,901 | 4,022 |
| Income\tfrom\tcontinuing\toperations | 3,528 | 3,948 | 4,957 |
| Discontinued\toperations | – | 8 | 277 |
| Net\tincome | $3,528 | $3,956 | $5,234 |
| Per\tShare\tData |  |  |  |
| Basic: |  |  |  |
| Income\tfrom\tcontinuing\toperations | $4.97 | $5.72 | $6.92 |
| Discontinued\toperations | $– | $0.01 | $0.39 |
| Net\tincome | $4.97 | $5.73 | $7.31 |
| Diluted: |  |  |  |
| Income\tfrom\tcontinuing\toperations | $4.95 | $5.68 | $6.87 |
| Discontinued\toperations | $– | $0.01 | $0.38 |
| Net\tincome | $4.95 | $5.69 | $7.25 |

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

# Consolidated	Balance	Sheets

| (In	millions,	except	per	share	data) | 2008 | 2007 |
| :--- | :--- | :--- |
| Assets |  |  |
| Current\tassets: |  |  |
| Cash\tand\tcash\tequivalents | $1,285 | $1,199 |
| Receivables,\tless\tallowance\tfor\tdoubtful\taccounts\tof\t$6\tand\t$3 | 3,094 | 5,672 |
| Receivables\tfrom\tUnited\tStates\tSteel | 23 | 22 |
| Receivables\tfrom\trelated\tparties | 33 | 79 |
| Inventories | 3,507 | 3,277 |
| Other\tcurrent\tassets | 461 | 338 |
| Total\tcurrent\tassets | 8,403 | \t 10,587 |
| Equity\tmethod\tinvestments | 2,080 | 2,630 |
| Receivables\tfrom\tUnited\tStates\tSteel | 469 | 485 |
| Property,\tplant\tand\tequipment,\tless\taccumulated\tdepreciation,\tdepletion\tand\tamortization\tof\t$15,581\tand\t$14,857 | \t 29,414 | \t 24,675 |
| Goodwill | 1,447 | 2,899 |
| Other\tnoncurrent\tassets | 873 | 1,470 |
| Total\tassets | $42,686 | $42,746 |
| Liabilities |  |  |
| Current\tliabilities: |  |  |
| Accounts\tpayable | $4,712 | $7,567 |
| Payables\tto\trelated\tparties | 21 | 44 |
| Payroll\tand\tbenefits\tpayable | 400 | 417 |
| Accrued\ttaxes | 1,133 | 712 |
| Deferred\tincome\ttaxes | 561 | 547 |
| Other\tcurrent\tliabilities | 828 | 842 |
| Long-term\tdebt\tdue\twithin\tone\tyear | 98 | 1,131 |
| Total\tcurrent\tliabilities | 7,753 | \t 11,260 |
| Long-term\tdebt | 7,087 | 6,084 |
| Deferred\tincome\ttaxes | 3,330 | 3,389 |
| Defined\tbenefit\tpostretirement\tplan\tobligations | 1,609 | 1,092 |
| Asset\tretirement\tobligations | 963 | 1,131 |
| Payable\tto\tUnited\tStates\tSteel | 4 | 5 |
| Deferred\tcredits\tand\tother\tliabilities | 531 | 562 |
| Total\tliabilities\nCommitments\tand\tcontingencies | \t 21,277 | \t 23,523 |
| Stockholders'\tEquity |  |  |
| Preferred\tstock\t–\t5\tmillion\tshares\tissued,\t3\tmillion\tand\t5\tmillion\tshares\toutstanding\t(no\tpar\tvalue,\t6\tmillion\tshares\tauthorized) | – | – |
| Common\tstock: |  |  |
|  | 767 | 765 |
| Securities\texchangeable\tinto\tcommon\tstock\t–\t5\tmillion\tshares\tissued,\t3\tmillion\tand\t5\tmillion\tshares\toutstanding\t(no\tpar\tvalue,\tunlimited |  |  |
| shares\tauthorized) | – | – |
| Held\tin\ttreasury,\tat\tcost\t–\t61\tmillion\tand\t55\tmillion\tshares | (2,720) | (2,384) |
| Additional\tpaid-in\tcapital | 6,696 | 6,679 |
| Retained\tearnings | \t 17,259 | \t 14,412 |
| Accumulated\tother\tcomprehensive\tloss | (593) | (249) |
| Total\tstockholders'\tequity | \t 21,409 | \t 19,223 |
| Total\tliabilities\tand\tstockholders'\tequity | $42,686 | $42,746 |

# Consolidated	Statements	of	Cash	Flows

| (In	millions) | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Increase\t(decrease)\tin\tcash\tand\tcash\tequivalents |  |  |  |
| Operating\tactivities: |  |  |  |
| Net\tincome | $3,528 | $3,956 | $5,234 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tprovided\tby\toperating\tactivities: |  |  |  |
| Loss\ton\tearly\textinguishment\tof\tdebt | – | 17 | 35 |
| Income\tfrom\tdiscontinued\toperations | – | (8) | (277) |
| Deferred\tincome\ttaxes | 93 | (347) | 268 |
| Minority\tinterests\tin\tloss\tof\tEquatorial\tGuinea\tLNG\tHoldings\tLimited | – | (3) | (10) |
| Goodwill\timpairment | 1,412 | – | – |
| Depreciation,\tdepletion\tand\tamortization | 2,178 | 1,613 | 1,518 |
| Pension\tand\tother\tpostretirement\tbenefits,\tnet | 130 | 32 | (426) |
| Exploratory\tdry\twell\tcosts\tand\tunproved\tproperty\timpairments | 170 | 233 | 166 |
| Net\tgain\ton\tdisposal\tof\tassets | (423) | (36) | (77) |
| Equity\tmethod\tinvestments,\tnet | 62 | (43) | (200) |
| Changes\tin\tthe\tfair\tvalue\tof\tU.K.\tnatural\tgas\tcontracts | (219) | 232 | (454) |
| Changes\tin: |  |  |  |
| Current\treceivables | 2,619 | (1,338) | (525) |
| Inventories | (274) | (90) | (133) |
| Current\taccounts\tpayable\tand\taccrued\tliabilities | (2,465) | 2,312 | 244 |
| All\tother,\tnet | (29) | (9) | 55 |
| Net\tcash\tprovided\tby\tcontinuing\toperations | 6,782 | 6,521 | 5,418 |
| Net\tcash\tprovided\tby\tdiscontinued\toperations | – | – | 70 |
| Net\tcash\tprovided\tby\toperating\tactivities | 6,782 | 6,521 | 5,488 |
| Investing\tactivities: |  |  |  |
| Capital\texpenditures | (7,146) | (4,466) | (3,433) |
| Acquisitions | – | (3,926) | (741) |
| Disposal\tof\tassets | 999 | 137 | 134 |
| Disposal\tof\tdiscontinued\toperations |  |  |  |
|  | – | – | 832 |
| Trusteed\tfunds\t–\twithdrawals | 752 | 280 | – |
| Investments\t–\tloans\tand\tadvances | (117) | (114) | (17) |
| Investments\t–\trepayments\tof\tloans\tand\treturn\tof\tcapital | 93 | 59 | 298 |
| Deconsolidation\tof\tEquatorial\tGuinea\tLNG\tHoldings\tLimited | – | (37) | – |
| Investing\tactivities\tof\tdiscontinued\toperations | – | – | (45) |
| All\tother,\tnet | (16) | (35) | 17 |
| Net\tcash\tused\tin\tinvesting\tactivities | (5,435) | (8,102) | (2,955) |
| Financing\tactivities: |  |  |  |
| Borrowings | 1,247 | 2,261 | – |
| Debt\tissuance\tcosts | (7) | (20) | – |
| Debt\trepayments | (1,366) | (694) | (501) |
| Issuance\tof\tcommon\tstock | 9 | 27 | 50 |
| Purchases\tof\tcommon\tstock | (402) | (822) | (1,698) |
| Excess\ttax\tbenefits\tfrom\tstock-based\tcompensation\tarrangements | 7 | 30 | 35 |
| Dividends\tpaid | (681) | (637) | (547) |
| Contributions\tfrom\tminority\tshareholders\tof\tEquatorial\tGuinea\tLNG\tHoldings\tLimited | – | 39 | 80 |
| Net\tcash\tprovided\tby\t(used\tin)\tfinancing\tactivities | (1,193) | 184 | (2,581) |
| Effect\tof\texchange\trate\tchanges\ton\tcash | (68) | 11 | 16 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 86 | (1,386) | (32) |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tperiod | 1,199 | 2,585 | 2,617 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tperiod | $1,285 | $1,199 | $2,585 |

# Consolidated	Statements	of	Stockholders'	Equity

|  | Stockholders'	Equity | Stockholders'	Equity | Stockholders'	Equity | Shares | Shares | Shares |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions,\texcept\tper\tshare\tdata) | 2008 | 2007 | 2006 | 2008 | 2007 | 2006 |
| Preferred\tstock\tissued |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $– | $– | $– | 5 | – | – |
| Issuances | – | – | – | – | 5 | – |
| Exchanges | – | – | – | (2) | – | – |
| Balance\tat\tend\tof\tyear | $– | $– | $– | 3 | 5 | – |
| Common\tstock |  |  |  |  |  |  |
| Issued |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $765 | $736 | $734 | 765 | 736 | 734 |
| Issuances | 2 | 29 | 2 | 2 | 29 | 2 |
| Balance\tat\tend\tof\tyear | $767 | $765 | $736 | 767 | 765 | 736 |
| Securities\texchangeable\tfor\tcommon\tstock |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $– | $– | $– | 5 | – | – |
| Issuances | – | – | – | – | 5 | – |
| Exchanges | – | – | – | (2) | – | – |
| Balance\tat\tend\tof\tyear | $– | $– | $– | 3 | 5 | – |
| Held\tin\ttreasury |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $ (2,384) | $ (1,638) | $(8) | (55) | (40) |  |
| Repurchases | (412) | (845) | (1,712) | (8) | (17) | (42) |
| Reissuances\tfor\temployee\tstock\tplans | 76 | 99 | 82 | 2 | 2 | 2 |
| Balance\tat\tend\tof\tyear | $ (2,720) | $ (2,384) | $ (1,638) | (61) | (55) | (40) |
|  |  |  |  | Comprehensive\tIncome | Comprehensive\tIncome |  |
|  |  |  |  | 2008 | 2007 | 2006 |
| Additional\tpaid-in\tcapital |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $6,679 | $4,784 | $4,744 |  |  |  |
| Stock\tissuances | (61) | 1,844 | (8) |  |  |  |
| Stock-based\tcompensation | 78 | 51 | 48 |  |  |  |
| Balance\tat\tend\tof\tyear | $6,696 | $6,679 | $4,784 |  |  |  |
| Unearned\tcompensation |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $– | $– | $(20) |  |  |  |
| Change\tin\taccounting\tprinciple | – | – | 20 |  |  |  |
| Balance\tat\tend\tof\tyear | $– | $– | $– |  |  |  |
| Retained\tearnings |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $14,412 | $11,093 | $6,406 |  |  |  |
| Net\tincome | 3,528 | 3,956 | 5,234 | $3,528 | $3,956 | $5,234 |
| Dividends\tpaid\t($0.96\t,\t$0.92\tand\t$0.76\tper\tshare) | (681) | (637) | (547) |  |  |  |
| Balance\tat\tend\tof\tyear | $17,259 | $14,412 | $11,093 |  |  |  |
| Accumulated\tother\tcomprehensive\tloss |  |  |  |  |  |  |
| Minimum\tpension\tliability\tadjustments |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $– | $– | $(141) |  |  |  |
| Changes\tduring\tyear,\tnet\tof\ttax\tof\t$–,\t$–,\tand\t$74 |  |  | 114 |  |  | 114 |
| Reclassification\tto\tdefined\tbenefit\tpostretirement\tplans | – | – | 27 |  |  |  |
| Balance\tat\tend\tof\tyear | $– | $– | $– |  |  |  |
| Defined\tbenefit\tpostretirement\tplans |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $(263) | $(375) | $– |  |  |  |
| Actuarial\tgain\t(loss),\tnet\tof\ttax\tof\t$146,\t$87 | (248) | 110 | – | (248) | 110 | – |
| Prior\tservice\tcosts,\tnet\tof\ttax\tof\t$2,\t$1 | 2 | 2 | – | 2 | 2 | – |
| Reclassification\tfrom\tminimum\tpension\tliability\tadjustments | – | – | (27) |  |  |  |
| Change\tin\taccounting\tprinciple,\tnet\tof\ttax\tof\t$289 | – | – | (348) |  |  |  |
| Balance\tat\tend\tof\tyear | $(509) | $(263) | $(375) |  |  |  |
| Other |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $14 | $7 | $(10) |  |  |  |
| Changes\tduring\tyear,\tnet\tof\ttax\tof\t$43,\t$4,\tand\t$9 | (98) | 7 | 17 | (98) | 7 | 12 |
| Balance\tat\tend\tof\tyear | $(84) | $14 | $7 |  |  |  |
| Total\tat\tend\tof\tyear | $(593) | $(249) | $(368) |  |  |  |
| Comprehensive\tincome |  |  |  | $3,184 | $4,075 | $5,360 |
| Total\tstockholders'\tequity | $21,409 | $19,223 | $14,607 |  |  |  |

# 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	upgrading	in	Canada; domestic	refining,	marketing	and	transportation	of	crude	oil	and	petroleum	products;	and	worldwide	marketing	and	transportation	of	products	manufactured	from	natural gas,	such	as	liquefied	natural	gas	("LNG")	and	methanol.

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	and	are	carried	at	our share	of	net	assets	plus	loans	and	advances.	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.	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.

Equity	method	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.

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

Certain	reclassifications	of	prior	years'	data	have	been	made	to	conform	to	2008	classifications.

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	continental	United	States,	production	volumes	of	liquid	hydrocarbons	and	natural	gas	are	sold	immediately	and	transported	via	pipeline.	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	the	Scotford	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	the	existing	proved	reserves	were not	adequate	to	cover	an	imbalance.	Imbalances	have	not	been	significant	in	the	periods	presented.

Rebates	from	vendors	are	recognized	as	a	reduction	of	cost	of	revenues	when	the	initiating	transaction	occurs.	Incentives	that	are	derived	from	contractual provisions	are	accrued	based	on	past	experience	and	recognized	in	cost	of	revenues.

Matching	buy/sell	transactions	–	In	a	typical	matching	buy/sell	transaction,	we	enter	into	a	contract	to	sell	a	particular	quantity	and	quality	of	crude	oil	or	refined product	at	a	specified	location	and	date	to	a	particular

counterparty,	and	simultaneously	agrees	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.	Prior	to	April	1,	2006,	we	recorded	all	matching	buy/sell	transactions	in	both	revenues	and	cost	of	revenues	as	separate	sale	and	purchase transactions.	Effective	April	1,	2006,	upon	adoption	of	the	provisions	of	Emerging	Issues	Task	Force	("EITF")	Issue	No.	04-13,	we	account	for	matching	buy/sell arrangements	entered	into	or	modified	as	exchanges	of	inventory,	except	for	those	arrangements	accounted	for	as	derivative	instruments.

# See	Note	2	for	further	information	regarding	adoption	of	EITF	Issue	No.	04-13.

Consumer	excise	taxes	–	We	are	required	by	various	governmental	authorities,	including	countries,	states	and	municipalities,	to	collect	and	remit	taxes	on	certain consumer	products.	Such	taxes	are	presented	on	a	gross	basis	in	revenues	and	costs	and	expenses	in	the	consolidated	statements	of	income.

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	and	allowance	for	doubtful	accounts	–	Our	receivables	primarily	consist	of	customer	accounts	receivable,	including	proprietary	credit	card receivables.	The	allowance	for	doubtful	accounts	is	the	best	estimate	of	the	amount	of	probable	credit	losses	in	our	proprietary	credit	card	receivables.	We	determine	the allowance	based	on	historical	write-off	experience	and	the	volume	of	proprietary	credit	card	sales.	We	review	the	allowance	quarterly	and	past-due	balances	over	180 days	are	reviewed	individually	for	collectability.	All	other	customer	receivables	are	recorded	at	the	invoiced	amounts	and	generally	do	not	bear	interest.	Account balances	for	these	customer	receivables	are	charged	directly	to	bad	debt	expense	when	it	becomes	probable	the	receivable	will	not	be	collected.

Inventories	–	Inventories	are	carried	at	the	lower	of	cost	or	market	value.	Cost	of	inventories	is	determined	primarily	under	the	last-in,	first-out	("LIFO")	method.

Derivative	instruments	–	We	may	use	derivatives	to	manage	our	exposure	to	commodity	price	risk,	interest	rate	risk	and	foreign	currency	risk.	Changes	in	the	fair value	of	derivatives	are	recognized	immediately	in	net	income	unless	the	derivative	qualifies	as	a	hedge	of	future	cash	flows	or	certain	foreign	currency	exposures.	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	hedged	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	hedged	transactions.

For	derivatives	qualifying	as	hedges	of	future	cash	flows	or	certain	foreign	currency	exposures,	the	effective	portion	of	any	changes	in	fair	value	is	recognized	in other	comprehensive	income	and	is	reclassified	to	net	income	when	the	underlying	forecasted	transaction	is	recognized	in	net	income.	Any	ineffective	portion	of	such hedges	is	recognized	in	net	income	as	it	occurs.	For	discontinued	cash	flow	hedges,	prospective	changes	in	the	fair	value	of	the	derivative	are	recognized	in	net	income. The	accumulated	gain	or	loss	recognized	in	other	comprehensive	income	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	other	comprehensive	income	is	immediately	reclassified	into	net	income.

For	derivatives	designated	as	hedges	of	the	fair	value	of	recognized	assets,	liabilities	or	firm	commitments,	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.

In	the	E&P	segment,	two	natural	gas	delivery	commitment	contracts	in	the	United	Kingdom	are	classified	as	derivative	instruments.	These	contracts	contain	pricing provisions	that	are	not	clearly	and	closely	related	to	the	underlying	commodity	and	therefore	must	be	accounted	for	as	derivative	instruments.

As	market	conditions	change,	we	may	use	selective	derivative	instruments	that	assume	market	risk.	For	derivative	instruments	that	are	classified	as	trading,	changes in	fair	value	are	recognized	immediately	in	net

income	and	are	classified	as	other	income.	Any	premium	received	is	amortized	into	net	income	based	on	the	underlying	settlement	terms	of	the	derivative	position.	All related	effects	of	a	trading	strategy,	including	physical	settlement	of	the	derivative	position,	are	recognized	in	net	income	and	classified	as	other	income.

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

Property	acquisition	costs	–	Costs	to	acquire	mineral	interests	in	oil	and	natural	gas	properties,	to	drill	and	equip	exploratory	wells	that	find	proved	reserves	and	to drill	and	equip	development	wells	are	capitalized.	Costs	to	drill	exploratory	wells	that	do	not	find	proved	reserves,	geological	and	geophysical	costs	and	costs	of	carrying and	retaining	unproved	properties	are	expensed.	Costs	incurred	for	exploratory	wells	that	find	reserves	that	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	not	less	than	quarterly.

Capitalized	costs	related	to	oil	sands	mining	are	those	specifically	related	to	the	acquisition,	exploration,	development	and	construction	of	mining	projects. Development	costs	to	expand	the	capacity	of	existing	mines	are	also	capitalized.

Depreciation,	Depletion	and	Amortization	–	Capitalized	costs	of	producing	oil	and	natural	gas	properties	are	depreciated	and	depleted	on	a	units-of-production	basis based	on	estimated	proved	oil	and	gas	reserves.

Oil	sands	mining	properties	and	the	related	bitumen	upgrading	facility	are	depreciated	and	depleted	on	a	units-of-production	basis.	Mobile	equipment	used	in mining	operations	is	depreciated	on	a	straight-line	basis	over	the	estimated	useful	lives	of	the	assets,	which	range	from	10	to	20	years.

Support	equipment	and	other	property,	plant	and	equipment	related	to	oil	and	gas	producing	and	oil	sands	mining	activities	are	depreciated	on	a	straight-line	basis over	their	estimated	useful	lives	which	range	from	5	to	39	years.

Property,	plant	and	equipment	unrelated	to	oil	and	gas	producing	or	oil	sands	mining	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	42	years.

Impairments	–	We	evaluate	our	oil	and	gas	producing	properties	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	total	proved	and	risk-adjusted	probable	and	possible	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	based	on	total	proved	and	risk-adjusted	probable and	possible	reserves	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.

Assets	related	to	oil	sands	mining	are	reviewed	for	impairment	whenever	events	or	changes	in	circumstances	indicate	that	the	carrying	value	may	not	be recoverable	from	estimated	undiscounted	future	net	cash	flows	based	on	total	bitumen	reserves.	Assets	deemed	to	be	impaired	are	written	down	to	their	fair	value,	as determined	by	discounted	future	net	cash	flows.

Refining,	marketing	and	transportation	assets	are	reviewed	for	impairment	whenever	events	or	changes	in	the	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.

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.

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	are	incurred	for	planned	major	refinery	maintenance	("turnarounds").	These	types	of	costs	include	contractor	repair	services, materials	and	supplies,	equipment	rentals	and	our	labor	costs.	Such	costs	are	expensed	in	the	period	incurred.

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.	If	recoveries	of	remediation	costs	from	third	parties	are	probable,	a	receivable	is	recorded	and	is	discounted	when	the	estimated	amount	is	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.	Asset	retirement	obligations	for	such facilities	include	costs	to	dismantle	and	relocate	or	dispose	of	production	platforms,	gathering	systems,	wells	and	related	structures	and	restoration	costs	of	land	and seabed,	including	those	leased.	Estimates	of	these	costs	are	developed	for	each	property	based	on	the	type	of	production	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.

To	a	lesser	extent,	asset	retirement	obligations	related	to	dismantlement,	site	restoration	of	oil	sands	mining	facilities	and,	conditional	asset	retirement	obligations for	removal	and	disposal	of	fire-retardant	material	from	certain	refining	facilities	have	also	been	recognized.	The	amounts	recorded	for	such	obligations	are	based	on	the most	probable	current	cost	projections.	Asset	retirement	obligations	have	not	been	recognized	for	the	removal	of	materials	and	equipment	from	or	the	closure	of	certain refinery,	pipeline,	marketing	and	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	and	oil	sands	mining	facilities	and	on	a	straight-line	basis	for	refining	facilities,	while	accretion	escalates	over	the	lives	of	the	assets.

Deferred	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	fair	value	calculated	and	ultimately,	the	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	Marathon	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.	New	Accounting	Standards

FSP	FIN	39-1	–	In	April	2007,	the	Financial	Accounting	Standards	Board	("FASB")	issued	FASB	Staff	Position	("FSP")	FASB	Interpretation	No.	39	("FSP	FIN 39-1"),	"Offsetting	of	Amounts	Related	to	Certain	Contracts",	which	allows	a	party	to	a	master	netting	agreement	to	offset	the	fair	value	amounts	related	to	the	right	to reclaim	collateral	against	the	fair	value	amounts	recognized	for	derivative	instruments.	Such	treatment	was	consistent	with	our	accounting	policy;	therefore,	adoption	of FSP	FIN	No.	39-1	effective	January	1,	2008,	did	not	have	any	effect	on	our	consolidated	financial	position.

SFAS	No.	159	–	In	February	2007,	the	FASB	issued	Statement	of	Financial	Accounting	Standards	("SFAS")	No.	159,	"The	Fair	Value	Option	for	Financial	Assets and	Financial	Liabilities."	This	statement	permits	entities	to	choose	to	measure	at	fair	value	many	financial	instruments	and	certain	other	items	that	are	not	currently required	to	be	measured	at	fair	value.	It	requires	that	unrealized	gains	and	losses	on	items	for	which	the	fair	value	option	has	been	elected	be	recorded	in	net	income.	The statement	also	establishes	presentation	and	disclosure	requirements	designed	to	facilitate	comparisons	between	entities	that	choose	different	measurement	attributes	for similar	types	of	assets	and	liabilities.	We	did	not	elect	the	fair	value	option	when	this	standard	became	effective	on	January	1,	2008,	nor	have	we	chosen	the	fair	value option	for	any	assets	or	liabilities	subsequent	to	that	date.

SFAS	No.	157	–	In	September	2006,	the	FASB	issued	SFAS	No.	157,	"Fair	Value	Measurements."	This	statement	defines	fair	value,	establishes	a	framework	for measuring	fair	value	in	generally	accepted	accounting	principles	and	expands	disclosures	about	fair	value	measurements.	SFAS	No.	157	does	not	require	any	new	fair value	measurements	but	may	require	some	entities	to	change	their	measurement	practices.	Effective	January	1,	2008,	we	adopted	SFAS	No.	157,	except	for measurements	of	those	nonfinancial	assets	and	liabilities	subject	to	the	one-year	deferral,	which	for	us	includes	impairments	of	goodwill,	intangible	assets	and	other long-lived	assets,	and	initial	measurement	of	asset	retirement	obligations,	asset	exchanges,	business	combinations	and	partial	sales	of	proved	properties.	Adoption	did	not have	a	significant	effect	on	our	consolidated	results	of	operations	or	financial	position.

In	February	2008,	the	FASB	issued	FSP	FAS	157-1,	"Application	of	FASB	Statement	No.	157	to	FASB	Statement	No.	13	and	Other	Accounting	Pronouncements That	Address	Fair	Value	Measurements	for	Purposes	of

Lease	Classification	or	Measurement	under	Statement	13,"	which	removes	certain	leasing	transactions	from	the	scope	of	SFAS	No.	157,	and	FSP	FAS	157-2,	"Effective Date	of	FASB	Statement	No.	157,"	which	defers	the	effective	date	of	SFAS	No.	157	for	one	year	for	certain	nonfinancial	assets	and	nonfinancial	liabilities,	except	those that	are	recognized	or	disclosed	at	fair	value	in	the	financial	statements	on	a	recurring	basis.

In	October	2008,	the	FASB	issued	FSP	FAS	157-3,	"Determining	the	Fair	Value	of	a	Financial	Asset	When	the	Market	for	That	Asset	Is	Not	Active,"	which clarifies	the	application	of	SFAS	No.	157	in	a	market	that	is	not	active	and	provides	an	example	to	illustrate	key	considerations	in	determining	the	fair	value	of	a financial	asset	when	the	market	for	that	financial	asset	is	not	active.	FSP	FAS	157-3	was	effective	upon	issuance,	including	prior	periods	for	which	financial	statements have	not	been	issued,	and	any	revisions	resulting	from	a	change	in	the	valuation	technique	or	its	application	shall	be	accounted	for	as	a	change	in	accounting	estimate. Application	of	FSP	FAS	157-3	did	not	cause	us	to	change	our	valuation	techniques	for	assets	and	liabilities	measured	under	SFAS	No.	157.

The	additional	disclosures	regarding	assets	and	liabilities	recorded	at	fair	value	and	measured	under	SFAS	No.	157	are	presented	in	Note	17.

SFAS	No.	158	–	In	September	2006,	the	FASB	issued	SFAS	No.	158,	"Employers'	Accounting	for	Defined	Benefit	Pension	and	Other	Postretirement	Plans	–	An Amendment	of	FASB	Statements	No.	87,	88,	106,	and	132	(R)."	This	standard	requires	an	employer	to:	(1)	recognize	in	its	statement	of	financial	position	an	asset	for	a plan's	overfunded	status	or	a	liability	for	a	plan's	underfunded	status;	(2)	measure	a	plan's	assets	and	its	obligations	that	determine	its	funded	status	as	of	the	end	of	the employer's	fiscal	year	(with	limited	exceptions);	and	(3)	recognize	changes	in	the	funded	status	of	a	plan	in	the	year	in	which	the	changes	occur	through	comprehensive income.	The	funded	status	of	a	plan	is	measured	as	the	difference	between	plan	assets	at	fair	value	and	the	benefit	obligation.	For	a	pension	plan,	the	benefit	obligation	is the	projected	benefit	obligation	and	for	any	other	postretirement	plan	it	is	the	accumulated	postretirement	benefit	obligation.	We	adopted	SFAS	No.	158	prospectively	as of	December	31,	2006	and	recognized	the	funded	status	of	our	plans	in	the	consolidated	balance	sheets,	with	a	cumulative	effect	of	a	change	in	accounting	principle	of $348	million	in	stockholders'	equity.	The	adoption	of	SFAS	No.	158	had	no	impact	on	our	measurement	date	as	we	have	historically	measured	the	plan	assets	and benefit	obligations	of	our	pension	and	other	postretirement	plans	as	of	December	31.	See	Note	23	for	additional	disclosures	regarding	defined	benefit	pension	and	other postretirement	plans	required	by	SFAS	No.	158.

EITF	Issue	No.	04-13	–	In	September	2005,	the	FASB	ratified	the	consensus	reached	by	the	EITF	on	Issue	No.	04-13,	"Accounting	for	Purchases	and	Sales	of Inventory	with	the	Same	Counterparty."	The	consensus	establishes	the	circumstances	under	which	two	or	more	inventory	purchase	and	sale	transactions	with	the	same counterparty	should	be	recognized	at	fair	value	or	viewed	as	a	single	exchange	transaction	subject	to	APB	Opinion	No.	29,	"Accounting	for	Nonmonetary Transactions."	In	general,	two	or	more	transactions	with	the	same	counterparty	must	be	combined	for	purposes	of	applying	APB	Opinion	No.	29	if	they	are	entered	into in	contemplation	of	each	other.	The	purchase	and	sale	transactions	may	be	pursuant	to	a	single	contractual	arrangement	or	separate	contractual	arrangements	and	the inventory	purchased	or	sold	may	be	in	the	form	of	raw	materials,	work-in-process	or	finished	goods.

Effective	April	1,	2006,	we	adopted	the	provisions	of	EITF	Issue	No.	04-13	prospectively.	EITF	Issue	No.	04-13	changes	the	accounting	for	matching	buy/sell arrangements	that	are	entered	into	or	modified	on	or	after	April	1,	2006	(except	for	those	accounted	for	as	derivative	instruments).	In	a	typical	matching	buy/sell transaction,	we	enter	into	a	contract	to	sell	a	particular	quantity	and	quality	of	crude	oil	or	refined	product	at	a	specified	location	and	date	to	a	particular	counterparty	and simultaneously	agrees	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.	Prior	to	adoption	of	EITF	Issue	No.	04-13,	we	recorded	such	matching	buy/sell	transactions	in	both	revenues	and	cost	of	revenues	as	separate	sale	and purchase	transactions.	Upon	adoption,	we	accounted	for	such	transactions	as	exchanges	of	inventory.

Transactions	arising	from	matching	buy/sell	arrangements	entered	into	before	April	1,	2006	were	reported	as	separate	sale	and	purchase	transactions,	until	all	such contracts	ceased.

The	adoption	of	EITF	Issue	No.	04-13	no	effect	on	net	income.	The	amounts	of	revenues	and	cost	of	revenues	recognized	after	April	1,	2006	are	less	than	the amounts	that	would	have	been	recognized	under	previous	accounting	practices.

# 3.	Information	about	United	States	Steel

The	USX	Separation	–	Prior	to	December	31,	2001,	Marathon	had	two	outstanding	classes	of	common	stock:	USX	–	Marathon	Group	common	stock,	which	was intended	to	reflect	the	performance	of	our	energy	business,	and	USX	–	U.S.	Steel	Group	common	stock	("Steel	Stock"),	which	was	intended	to	reflect	the	performance of	our	steel	business.	On	December	31,	2001,	in	a	tax-free	distribution	to	holders	of	Steel	Stock,	we	exchanged	the	common	stock	of	United	States	Steel	for	all outstanding	shares	of	Steel	Stock	on	a	one-for-one	basis	(the	"USX	Separation").	In	connection	with	the	USX	Separation,	Marathon	and	United	States	Steel	entered	into a	number	of	agreements,	including:

Financial	Matters	Agreement	–	Marathon	and	United	States	Steel	entered	into	a	Financial	Matters	Agreement	that	provides	for	United	States	Steel's	assumption	of certain	industrial	revenue	bonds	and	certain	other	financial	obligations	of	Marathon.	The	Financial	Matters	Agreement	also	provides	that,	on	or	before	the	tenth anniversary	of	the	USX	Separation,	United	States	Steel	will	provide	for	our	discharge	from	any	remaining	liability	under	any	of	the	assumed	industrial	revenue	bonds.

Under	the	Financial	Matters	Agreement,	United	States	Steel	has	all	of	the	existing	contractual	rights	under	the	leases	assumed,	including	all	rights	related	to purchase	options,	prepayments	or	the	grant	or	release	of	security	interests.	However,	United	States	Steel	has	no	right	to	increase	amounts	due	under	or	lengthen	the	term of	any	of	the	assumed	leases,	other	than	extensions	set	forth	in	the	terms	of	any	of	the	assumed	leases.

United	States	Steel	was	the	sole	general	partner	of	Clairton	1314B	Partnership,	L.P.,	which	owned	certain	cokemaking	facilities	at	United	States	Steel	Clairton Works.	We	guaranteed	to	the	limited	partners	all	obligations	of	United	States	Steel	under	the	partnership	documents	("the	Clairton	1314B	Guarantee").	The	Financial Matters	Agreement	requires	United	States	Steel	to	use	commercially	reasonable	efforts	to	have	Marathon	released	from	its	obligations	under	this	guarantee.	The Clairton	1314B	Partnership	was	terminated	on	October	31,	2008.	We	were	not	released	from	our	obligations	under	the	Clairton	1314B	Guarantee	upon	termination	of the	partnership.	As	a	result,	we	continue	to	guarantee	the	United	States	Steel	indemnification	of	the	former	limited	partners	for	certain	income	tax	exposures.

The	Financial	Matters	Agreement	requires	us	to	use	commercially	reasonable	efforts	to	assure	compliance	with	all	covenants	and	other	obligations	to	avoid	the occurrence	of	a	default	or	the	acceleration	of	payments	on	the	assumed	obligations.

United	States	Steel's	obligations	to	Marathon	under	the	Financial	Matters	Agreement	are	general	unsecured	obligations	that	rank	equal	to	United	States	Steel's accounts	payable	and	other	general	unsecured	obligations.	The	Financial	Matters	Agreement	does	not	contain	any	financial	covenants	and	United	States	Steel	is	free	to incur	additional	debt,	grant	mortgages	on	or	security	interests	in	its	property	and	sell	or	transfer	assets	without	our	consent.

Tax	Sharing	Agreement	–	Marathon	and	United	States	Steel	entered	into	a	Tax	Sharing	Agreement	that	reflects	each	party's	rights	and	obligations	relating	to payments	and	refunds	of	income,	sales,	transfer	and	other	taxes	that	are	attributable	to	periods	beginning	prior	to	and	including	the	USX	Separation	date	and	taxes resulting	from	transactions	effected	in	connection	with	the	USX	Separation.

In	2006,	in	accordance	with	the	terms	of	the	Tax	Sharing	Agreement,	Marathon	paid	$35	million	to	United	States	Steel	in	connection	with	the	settlement	with	the Internal	Revenue	Service	of	the	consolidated	federal	income	tax	returns	of	USX	Corporation	for	the	years	1995	through	2001.	The	final	payment	of	$13	million	to United	States	Steel	related	to	income	tax	returns	under	the	Tax	Sharing	Agreement	was	made	in	January	2007.

# 4.	Deconsolidation	of	Equatorial	Guinea	LNG	Holdings	Limited

Equatorial	Guinea	LNG	Holdings	Limited	("EGHoldings"),	in	which	we	hold	a	60	percent	interest,	was	formed	for	the	purpose	of	constructing	and	operating	an LNG	production	facility.	During	facility	construction,	EGHoldings	was	a	variable	interest	entity	("VIE")	that	was	consolidated	because	we	were	its	primary	beneficiary. Once	the	LNG	production	facility	commenced	its	primary	operations	and	began	to	generate	revenue	in	May	2007,

EGHoldings	was	no	longer	a	VIE.	Effective	May	1,	2007,	we	no	longer	consolidate	EGHoldings,	despite	the	fact	that	we	hold	majority	ownership,	because	the	minority shareholders	have	rights	limiting	our	ability	to	exercise	control	over	the	entity.	We	account	for	our	investment	in	EGHoldings,	using	the	equity	method	of	accounting,	at our	share	of	net	assets	plus	loans	and	advances.	Our	investment	is	included	in	the	equity	method	investments	line	of	our	consolidated	balance	sheet	(see	Note	14	to	the consolidated	financial	statements).

# 5.	Related	Party	Transactions

During	2008,	2007	and	2006	only	our	equity	method	investees	were	considered	related	parties	including:

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

•	 Centennial	Pipeline	LLC	("Centennial"),	in	which	we	have	a	50	percent	interest.	Centennial	operates	a	refined	products	pipeline	and	storage	facility.

•EGHoldings,	in	which	we	have	a	60	percent	noncontrolling	interest.	EGHoldings	processes	liquefied	natural	gas.

•The	Andersons	Clymers	Ethanol	LLC,	in	which	we	have	a	35	percent	interest,	and	The	Andersons	Marathon	Ethanol	LLC,	in	which	we	have	a	50	percent interest	("Ethanol	investments").	These	companies	each	own	an	ethanol	production	facility.

•LOOP	LLC,	in	which	we	have	a	51	percent	noncontrolling	interest.	LOOP	LLC	operates	an	offshore	oil	port.

•Pilot	Travel	Centers	LLC	("PTC"),	in	which	we	sold	our	50	percent	interest	in	October	2008.	PTC	owns	and	operates	travel	centers	in	the	United	States.

•Poseidon	Oil	Pipeline	Company,	L.L.C.	("Poseidon"),	in	which	we	have	a	28	percent	interest.	Poseidon	transports	crude	oil.

We	believe	that	transactions	with	related	parties	were	conducted	under	terms	comparable	to	those	with	unrelated	parties.

Related	party	sales	to	PTC	consist	primarily	of	petroleum	products.	Revenues	from	related	parties	were	as	follows:

Western	Oil	Sands	Inc.	–	On	October	18,	2007,	we	completed	the	acquisition	of	all	the	outstanding	shares	of	Western	Oil	Sands	Inc.	("Western")	for	cash	and securities	of	$5,833	million.	Subsequent	to	the	transaction,	Western's	name	was	changed	to	Marathon	Oil	Canada	Corporation.	The	acquisition	was	accounted	for	under the	purchase	method	of	accounting	and,	as	such,	our	results	of	operations	include	Western's	results	from	October	18,	2007.	Western's	oil	sands	mining	and	bitumen upgrading	operations	are	reported	as	a	separate	Oil	Sands	Mining	segment,	while	its	ownership	interests	in	leases	where	in-situ	recovery	techniques	are	expected	to	be utilized	are	included	in	the	E&P	segment.

The	final	purchase	price	for	the	Western	acquisition	was	as	follows:

(a) Western	shareholders	received	cash	of	3,808	million	Canadian	dollars. (b) Western	shareholders	received	29	million	shares	of	Marathon	common	stock	and	5	million	securities	exchangeable	for	Marathon	common	stock	valued	at	$55.70	per	share,	which	was	the	average	common	stock price	over	the	trading	days	between	July	26	and	August	1,	2007	(the	days	surrounding	the	announcement	of	the	transaction).

The	primary	reasons	for	the	acquisition	and	the	principal	factors	contributing	to	a	purchase	price	resulting	in	goodwill	are:	access	to	the	long-life	Athabasca	Oil Sands	Project	("AOSP")	of	northern	Alberta,	Canada;	the	opportunity	to	realize	a	fully-integrated	oil	strategy,	capitalizing	on	the	ownership	of	this	asset	by	aligning production	from	the	AOSP	developments,	including	planned	expansions	of	the	current	mining	operations,	with	our	refining	system;	potential	for	expanded	growth opportunities	in	the	Athabasca	region;	and	access	to	a	trained	workforce	with	expertise	in	bitumen	production	and	upgrading	and	in	synthetic	crude	oil	marketing.	The goodwill	arising	from	the	purchase	price	allocation	was	$1,508	million,	of	which	$1,437	million	was	assigned	to	the	Oil	Sands	Mining	segment	and	$71	million	was assigned	to	the	E&P	segment.	Reductions	of	$25	million	were	made	to	Oil	Sands	Mining	segment	goodwill	upon	resolution	of	tax	and	royalty	issues	in	2008.	None	of the	goodwill	is	deductible	for	tax	purposes.

The	following	table	summarizes	the	fair	values	of	the	assets	and	liabilities	acquired	as	of	October	18,	2007.

The	following	unaudited	pro	forma	data	was	prepared	as	if	the	acquisition	of	Western	had	been	consummated	at	the	beginning	of	each	period	presented.	The	pro forma	data	is	based	on	historical	information	and	does	not	reflect	the	actual	results	that	would	have	occurred	nor	is	it	indicative	of	future	results	of	operations.

| (In	millions,	except	per	share	amounts) | 2007 | 2006 |
| :--- | :--- | :--- |
| Revenues\tand\tother\tincome | $66,089 | $66,283 |
| Income\tfrom\tcontinuing\toperations | 3,495 | 4,765 |
| Net\tincome | 3,503 | 5,042 |
| Per\tshare\tdata: |  |  |
| Income\tfrom\tcontinuing\toperations\tbasic | $5.07 | $6.35 |
| Income\tfrom\tcontinuing\toperations\tdiluted | $5.03 | $6.30 |
| Net\tincome\tbasic | $5.08 | $6.72 |
| Net\tincome\tdiluted | $5.04 | $6.67 |

# 7.	Dispositions

Outside-operated	Norwegian	properties	–	On	October	31,	2008,	we	closed	the	sale	of	our	Norwegian	outside-operated	properties	and	undeveloped	offshore acreage	in	the	Heimdal	area	of	the	Norwegian	North	Sea	for	net	proceeds	of	$301	million,	with	a	pretax	gain	of	$254	million	as	of	December	31,	2008.

Pilot	Travel	Centers	–	On	October	8,	2008,	we	completed	the	sale	of	our	50	percent	ownership	interest	in	PTC.	Sale	proceeds	were	$625	million,	with	a	pretax	gain on	the	sale	of	$126	million.	Immediately	preceding	the	sale,	we	received	a	$75	million	partial	redemption	of	our	ownership	interest	from	PTC	that	was	accounted	for	as	a return	of	investment.

Operated	Irish	properties	–	On	December	17,	2008,	we	agreed	to	sell	our	operated	properties	located	in	Ireland	for	proceeds	of	$180	million,	before	post-closing adjustments	and	cash	on	hand	at	closing.	Closing	is	subject	to	completion	of	the	necessary	administrative	processes.

As	of	December	31,	2008,	operating	assets	and	liabilities	were	classified	as	held	for	sale,	as	disclosed	by	major	class	in	the	following	table:

| (In	millions) | 2008 |
| :--- | :--- |
| Current\tassets\nNoncurrent\tassets | $164\n\t 103 |
| Total\tassets | \t 267 |
| Current\tliabilities | 62 |
| Noncurrent\tliabilities | \t 199 |
| Total\tliabilities | \t 261 |
| Net\tassets\theld\tfor\tsale | $6 |

# 8.	Discontinued	Operations

On	June	2,	2006,	we	sold	our	Russian	oil	exploration	and	production	businesses	in	the	Khanty-Mansiysk	region	of	western	Siberia.	Under	the	terms	of	the agreement,	we	received	$787	million	for	these	businesses,	plus	preliminary	working	capital	and	other	closing	adjustments	of	$56	million,	for	a	total	transaction	value	of $843	million.	Proceeds	net	of	transaction	costs	and	cash	held	by	the	Russian	businesses	at	the	transaction	date	totaled	$832	million.	A	gain	on	the	sale	of	$243	million ($342	million	before	income	taxes)	was	reported	in	discontinued	operations	for	2006.	Income	taxes	on	this	gain	were	reduced	by	the	utilization	of	a	capital	loss carryforward.	Exploration	and	Production	segment	goodwill	of	$21	million	was	allocated	to	the	Russian	assets	and	reduced	the	reported	gain.	Adjustments	to	the	sales price	were	completed	in	2007	and	an	additional	gain	on	the	sale	of	$8	million	($13	million	before	income	taxes)	was	recognized.

The	activities	of	the	Russian	businesses	have	been	reported	as	discontinued	operations	in	the	consolidated	statements	of	income	and	the	consolidated	statements	of cash	flows	for	2006.	Revenues	applicable	to	discontinued	operations	were	$173	million	and	pretax	income	from	discontinued	operations	was	$45	million	for	2006.

# 9.	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,	stock	appreciation	rights	and	restricted	stock,	provided	the	effect	is	not	antidilutive.

|  | 2008 | 2008 | 2007 | 2007 | 2006 | 2006 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions\texcept\tper\tshare\tdata) | Basic | Diluted | Basic | Diluted | Basic | Diluted |
| Income\tfrom\tcontinuing\toperations | $3,528 | $ 3,528 | $3,948 | $ 3,948 | $4,957 | $ 4,957 |
| Discontinued\toperations | – | – | 8 | 8 | 277 | 277 |
| Net\tincome | $3,528 | $ 3,528 | $3,956 | $ 3,956 | $5,234 | $ 5,234 |
| Weighted\taverage\tcommon\tshares\toutstanding | 709 | 709 | 690 | 690 | 716 | 716 |
| Effect\tof\tdilutive\tsecurities | – | 4 | – | 5 | – | 6 |
| Weighted\taverage\tcommon\tshares,\tincluding\tdilutive\teffect | 709 | 713 | 690 | 695 | 716 | 722 |
| Per\tshare:\nIncome\tfrom\tcontinuing\toperations | $4.97 | $4.95 | $5.72 | $5.68 | $6.92 | $6.87 |
| Discontinued\toperations | $– | $– | $0.01 | $0.01 | $0.39 | $0.38 |
| Net\tincome | $4.97 | $4.95 | $5.73 | $5.69 | $7.31 | $7.25 |

The	per	share	calculations	above	exclude	5.4	million	and	3.2	million	stock	options	and	stock	appreciation	rights	in	2008	and	2007	that	were	antidilutive.	There	were no	antidilutive	stock	options	or	stock	appreciation	rights	in	2006.	Restricted	stock	was	not	antidilutive	in	2008,	2007	or	2006.

# 10.	Segment	Information

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

•Exploration	and	Production	("E&P")	–	explores	for,	produces	and	markets	liquid	hydrocarbons	and	natural	gas	on	a	worldwide	basis;

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

•	 Refining,	Marketing	and	Transportation	("RM&T")	–	refines,	markets	and	transports	crude	oil	and	petroleum	products,	primarily	in	the	Midwest,	upper Great	Plains,	Gulf	Coast	and	southeastern	regions	of	the	U.S.;	and

•Integrated	Gas	("IG")	–	markets	and	transports	products	manufactured	from	natural	gas,	such	as	LNG	and	methanol,	on	a	worldwide	basis,	and	is	developing other	projects	to	link	stranded	natural	gas	resources	with	key	demand	areas.

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	minority	interests	and	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.	All	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	are	accounted	for	as	derivative	instruments,	impairments	or infrequently	occurring	items	(as	determined	by	the	CODM)	also	are	not	allocated	to	operating	segments.

Revenues	from	external	customers	are	attributed	to	geographic	areas	based	on	selling	location.	No	single	customer	accounts	for	more	than	10	percent	of	annual revenues.

| (In	millions) | E&amp;P | OSM | RM&amp;T | IG | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 2008 |  |  |  |  |  |
| Revenues: |  |  |  |  |  |
| Customer | $11,636 | $922 | $62,445 | $93 | $ 75,096 |
| Intersegment^(a) | 798 | 200 | 209 | – | 1,207 |
| Related\tparties | 52 | – | 1,827 | – | 1,879 |
| Segment\trevenues | 12,486 | 1,122 | 64,481 | 93 | 78,182 |
| Elimination\tof\tintersegment\trevenues | (798) | (200) | (209) | – | (1,207) |
| Gain\ton\tU.K.\tnatural\tgas\tcontracts | 218 | – | – | – | 218 |
| Total\trevenues | $11,906 | $922 | $64,272 | $93 | $ 77,193 |
| Segment\tincome | $2,715 | $258 | $1,179 | $302 | $4,454 |
| Income\tfrom\tequity\tmethod\tinvestments^(b) | 225 | – | 178 | 402 | 805 |
| Depreciation,\tdepletion\tand\tamortization^(b) | 1,386 | 143 | 606 | 3 | 2,138 |
| Income\ttax\tprovision^(b) | 2,912 | 93 | 684 | 131 | 3,820 |
| Capital\texpenditures^(c)(d) | 3,113 | 1,038 | 2,954 | 4 | 7,109 |
| 2007 |  |  |  |  |  |
| Revenues: |  |  |  |  |  |
| Customer | $8,623 | $181 | $54,137 | $218 | $ 63,159 |
| Intersegment^(a) | 497 | 40 | 348 | – | 885 |
| Related\tparties | 35 | – | 1,590 | – | 1,625 |
| Segment\trevenues | 9,155 | 221 | 56,075 | 218 | 65,669 |
| Elimination\tof\tintersegment\trevenues | (497) | (40) | (348) | – | (885) |
| Loss\ton\tU.K.\tnatural\tgas\tcontracts | (232) | – | – | – | (232) |
| Total\trevenues | $8,426 | $181 | $55,727 | $218 | $ 64,552 |
| Segment\tincome\t(loss) | $1,729 | $(63) | $2,077 | $132 | $3,875 |
| Income\tfrom\tequity\tmethod\tinvestments | 238 | – | 139 | 168 | 545 |
| (b) |  |  |  |  |  |
| Depreciation,\tdepletion\tand\tamortization | 963 | 22 | 587 | 6 | 1,578 |
| Minority\tinterest\tin\tloss\tof\tsubsidiary | – | – | – | 3 | 3 |
| (b) |  |  |  |  |  |
| Income\ttax\tprovision\t(benefit) | 2,172 | (21) | 1,183 | 24 | 3,358 |
| (c)(d) |  |  |  |  |  |
| Capital\texpenditures | 2,511 | 165 | 1,640 | 93 | 4,409 |
| 2006 |  |  |  |  |  |
| Revenues: |  |  |  |  |  |
| Customer | $8,326 | $– | $54,471 | $179 | $ 62,976 |
| (a) |  |  |  |  |  |
| Intersegment | 672 | – | 16 | – | 688 |
| Related\tparties | 12 | – | 1,454 | – | 1,466 |
| Segment\trevenues | 9,010 | – | 55,941 | 179 | 65,130 |
| Elimination\tof\tintersegment\trevenues | (672) | – | (16) | – | (688) |
| Gain\ton\tU.K.\tnatural\tgas\tcontracts | 454 | – | – | – | 454 |
| Total\trevenues | $8,792 | $– | $55,925 | $179 | $ 64,896 |
| Segment\tincome | $2,003 | $– | $2,795 | $16 | $4,814 |
| Income\tfrom\tequity\tmethod\tinvestments | 206 | – | 145 | 40 | 391 |
| (b) |  |  |  |  |  |
| Depreciation,\tdepletion\tand\tamortization | 919 | – | 558 | 9 | 1,486 |
| Minority\tinterest\tin\tloss\tof\tsubsidiary | – | – | – | 10 | 10 |
| (b) |  |  |  |  |  |
| Income\ttax\tprovision | 2,371 | – | 1,642 | 8 | 4,021 |
| (c)(d) |  |  |  |  |  |
| Capital\texpenditures | 2,169 | – | 916 | 307 | 3,392 |
| (a) |  |  |  |  |  |

(a) Management	believes	intersegment	transactions	were	conducted	under	terms	comparable	to	those	with	unrelated	parties.

(b) Differences	between	segment	totals	and	our	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	reconciliation	below. (c) Differences	between	segment	totals	and	our	totals	represent	amounts	related	to	corporate	administrative	activities.

(d) Through	April	2007,	Integrated	Gas	segment	capital	expenditures	include	EGHoldings	at	100	percent.	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'	capital	expenditures	subsequent	to	April	2007	are	not	included	in	our	capital	expenditures.

(e) As	discussed	in	Note	8,	the	Russian	businesses	that	were	sold	on	June	2,	2006	have	been	accounted	for	as	discontinued	operations.	Segment	information	for	all	presented	periods	excludes	the	amounts	for	these Russian	operations.

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

| (In	millions) | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Segment\tincome | $4,454 | $3,875 | $4,814 |
| Items\tnot\tallocated\tto\tsegments,\tnet\tof\tincome\ttaxes: |  |  |  |
| Corporate\tand\tother\tunallocated\titems | (93) | (122) | (190) |
| Gain\t(loss)\ton\tU.K.\tnatural\tgas\tcontracts | 111 | (118) | 232 |
| Foreign\tcurrency\tgain\t(loss)\ton\tincome\ttaxes | 252 | 18 | (22) |
| Impairments(a) | (1,437) | – | – |
| Gain\ton\tdispositions | 241 | 8 | 274 |
| Gain\ton\tforeign\tcurrency\tderivative\tinstruments | – | 112 | – |
| Deferred\tincome\ttaxes\t–\ttax\tlegislation\tchanges | – | 193 | 21 |
| –\tother\tadjustments(b) | – | – | 93 |
| Loss\ton\tearly\textinguishment\tof\tdebt | – | (10) | (22) |
| Discontinued\toperations | – | – | 34 |
| Net\tincome | $3,528 | $3,956 | $5,234 |
| Impairments\tinclude\tthe\t$1,412\tmillion\timpairment\tof\tgoodwill\trelated\tto\tthe\tOSM\treporting\tunit,\tsee\tNote\t16\tto\tthe\tconsolidated\tfinancial\tstatements\tand\tthe\t$25\tmillion\tafter-tax\timpairment\t($40\tmillion\tpretax)\n(a) |  |  |  |

(a) Impairments	include	the	$1,412	million	impairment	of	goodwill	related	to	the	OSM	reporting	unit,	see	Note	16	to	the	consolidated	financial	statements	and	the	$25	million	after-tax	impairment	($40	million	pretax) related	to	our	investments	in	ethanol	producing	companies,	see	Note	14	to	the	consolidated	financial	statements. (b) Other	deferred	tax	adjustments	in	2006	represent	a	benefit	recorded	for	cumulative	income	tax	basis	differences	associated	with	prior	periods.

The	following	reconciles	total	revenues	to	sales	and	other	operating	revenues	(including	consumer	excise	taxes)	as	reported	in	the	consolidated	statements	of income.

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

| (In	millions) | 2008 | 2007 |
| :--- | :--- | :--- |
| United\tStates | $16,298 | $13,133 |
| Canada | 7,775 | 6,980 |
| Equatorial\tGuinea | 2,732 | 2,842 |
| Other\tinternational | 4,719 | 4,393 |
| Total | $31,524 | $27,348 |

Revenues	by	product	line	were:

# 12.	Income	Taxes

Income	tax	provisions	(benefits)	were:

|  | 2008 | 2008 | 2008 | 2007 | 2007 | 2007 | 2006 | 2006 | 2006 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Current | Deferred | Total | Current | Deferred | Total | Current | Deferred | Total |
| Federal | $923 | $193 | $1,116 | $1,290 | $(2) | $1,288 | $1,579 | $72 | $1,651 |
| State\tand\tlocal | 146 | 12 | 158 | 184 | 22 | 206 | 230 | 30 | 260 |
| Foreign | 2,283 | (112) | \t 2,171 | 1,774 | (367) | \t 1,407 | 1,945 | 166 | \t 2,111 |
| \t\t\t\tTotal | $3,352 | $93 | $3,445 | $3,248 | $(347) | $2,901 | $3,754 | $268 | $4,022 |

A	reconciliation	of	the	federal	statutory	income	tax	rate	(35	percent)	applied	to	income	from	continuing	operations	before	income	taxes	to	the	provision	for	income taxes	follows:

| (In	millions) | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Statutory\trate\tapplied\tto\tincome\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | $2,440 | $2,397 | $3,143 |
| Effects\tof\tforeign\toperations,\tincluding\tforeign\ttax\tcredits(a) | \t 1,168 | 671 | 909 |
| Effects\tof\tnondeductible\tgoodwill\timpairment | 494 | – | – |
| Adjustments\tto\tvaluation\tallowances(b) | (671) | – | – |
| State\tand\tlocal\tincome\ttaxes,\tnet\tof\tfederal\tincome\ttax\teffects | 92 | 134 | 170 |
| Credits\tother\tthan\tforeign\ttax\tcredits | (7) | (3) | (2) |
| Domestic\tmanufacturing\tdeduction | (44) | (64) | (47) |
| Effects\tof\tpartially-owned\tcompanies | (4) | (5) | (6) |
| Effects\tof\tenacted\tchanges\tin\ttax\tlaws(c) | – | (193) | (21) |
| Adjustment\tof\tprior\tyears\tfederal\tincome\ttaxes(d) | (30) | (27) | (119) |
| Other | 7 | (9) | (5) |
| \t\t\t\tProvision\tfor\tincome\ttaxes | $3,445 | $2,901 | $4,022 |
| (a) |  |  |  |

(b) The	adjustments	to	the	valuation	allowance	related	primarily	to	the	release	of	the	Norwegian	valuation	allowance.	In	2008,	we	released	the	valuation	allowance	on	the	Norwegian	deferred	tax	asset	upon completion	of	the	operated	Alvheim/Vilje	development	offshore	Norway,	with	first	production	from	Alvheim	in	June	2008	and	from	Vilje	in	July	2008.

(c) The	amounts	in	all	periods	represent	the	income	tax	benefits	of	applying	income	tax	rate	changes	to	the	applicable	net	deferred	tax	asset	or	liability	balances.	In	2007,	subsequent	to	the	Western	acquisition, decreases	to	the	Canadian	income	tax	rates	were	enacted.	In	2006,	the	U.K.	supplemental	corporation	tax	rate	("SCT")	was	increased,	which	resulted	in	a	benefit	due	to	the	net	deferred	tax	asset	position	related	to the	SCT.

(d) The	2006	adjustment	of	prior	years'	federal	income	taxes	was	primarily	related	to	a	$93	million	credit	as	a	result	of	an	analysis	of	the	tax	consequences	attributable	to	prior	years'	differences	between	the	financial statement	carrying	amounts	of	assets	and	liabilities	and	their	tax	bases	for	U.S.	federal	income	tax	purposes.

Deferred	tax	assets	and	liabilities	resulted	from	the	following:

| (In	millions) | 2008 | 2007 |
| :--- | :--- | :--- |
| Deferred\ttax\tassets: |  |  |
| Employee\tbenefits | $918 | $703 |
| Operating\tloss\tcarryforwards(a) | \t 1,150 | \t 1,596 |
| Derivative\tinstruments | 86 | 284 |
| Foreign\ttax\tcredits(b) | \t 1,088 | 838 |
| Other | 160 | 169 |
| Valuation\tallowances |  |  |
| Federal(c) | – | (29) |
| State | (50) | (55) |
| Foreign(d) | (212) | (917) |
| Total\tdeferred\ttax\tassets | \t 3,140 | \t 2,589 |
| Deferred\ttax\tliabilities: |  |  |
| Property,\tplant\tand\tequipment | \t 4,679 | \t 4,610 |
| Inventories | 649 | 652 |
| Investments\tin\tsubsidiaries\tand\taffiliates | \t 1,361 | 987 |
| Other | 63 | 89 |
| Total\tdeferred\ttax\tliabilities | \t 6,752 | \t 6,338 |
| Net\tdeferred\ttax\tliabilities | $3,612 | $3,749 |
| At\tDecember\t31,\t2008,\tforeign\toperating\tloss\tcarryforwards\tprimarily\tinclude\t$562\tmillion\tfor\tNorway\tregular\tincome\ttax,\t$1,044\tmillion\tfor\tNorway\tspecial\tpetroleum\ttax\tand\t$585\tmillion\tfor\tAngola\tincome\n(a) |  |  |

(a) At	December	31,	2008,	foreign	operating	loss	carryforwards	primarily	include	$562	million	for	Norway	regular	income	tax,	$1,044	million	for	Norway	special	petroleum	tax	and	$585	million	for	Angola	income tax.	The	Norway	and	Angola	operating	loss	carryforwards	have	no	expiration	dates.	The	remainder	of	foreign	carryforwards	were	in	several	other	foreign	jurisdictions,	the	majority	of	which	expire	in	2009	through 2020.	State	operating	loss	carryforwards	of	$719	million	expire	in	2009	through	2028.	The	state	operating	loss	carryforwards	primarily	relate	to	the	period	prior	to	the	USX	Separation	and	were	offset	by	valuation allowances.

(b) Our	expectation	regarding	our	ability	to	realize	the	benefit	of	foreign	tax	credits	is	based	on	certain	assumptions	concerning	future	operating	conditions	(particularly	as	related	to	prevailing	commodity	prices), income	generated	from	foreign	sources	and	our	tax	profile	in	the	years	that	such	credits	may	be	claimed.

(c) Federal	valuation	allowances	decreased	$29	million	in	2008	and	increased	$10	million	in	2007	primarily	due	to	the	realizibility	of	foreign	tax	credits.	In	2006,	federal	valuation	allowances	decreased	$101	million primarily	due	to	$79	million	of	carryforward	losses	utilized	in	conjunction	with	the	sale	of	our	Russian	oil	exploration	and	production	businesses.

(d) Foreign	valuation	allowances	decreased	$705	million	in	2008,	primarily	due	to	the	release	of	the	Norwegian	valuation	allowance.	Foreign	valuation	allowances	increased	$306	million	and	$176	million	in	2007 and	2006	primarily	as	a	result	of	net	operating	loss	carryforwards	generated	in	those	years	in	Norway,	Angola	and	several	other	jurisdictions.

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

|  | December	31, | December	31, |
| :--- | :--- | :--- |
| (In\tmillions) | 2008 | 2007 |
| Assets: |  |  |
| Other\tcurrent\tassets | $36 | $2 |
| Other\tnoncurrent\tassets | 243 | 185 |
| Liabilities: |  |  |
| Current\tdeferred\tincome\ttaxes | 561 | 547 |
| Noncurrent\tdeferred\tincome\ttaxes | \t 3,330 | \t 3,389 |
| Net\tdeferred\ttax\tliabilities | $3,612 | $3,749 |

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 2005	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	or	provided	for these	liabilities.	As	of	December	31,	2008,	our	income	tax	returns	remain	subject	to	examination	in	the	following	major	tax	jurisdictions	for	the	tax	years	indicated.

(a) Includes	federal	and	state	jurisdictions.

We	adopted	FIN	No	48	as	of	January	1,	2007.	Total	unrecognized	tax	benefits	were	$39	million	and	$40	million	as	of	December	31,	2008	and	2007.	If	the unrecognized	tax	benefits	as	of	December	31,	2008	were	recognized,	$29	million	would	affect	our	effective	income	tax	rate.	There	were	$10	million	of	uncertain	tax positions	as	of	that	date	for	which	it	is	reasonably	possible	that	the	amount	of	unrecognized	tax	benefits	would	significantly	decrease	during	2009.

The	following	table	summarizes	the	activity	in	unrecognized	tax	benefits:

| (In	millions) | 2008 | 2007 |
| :--- | :--- | :--- |
| January\t1\tbalance | $40 | $48 |
| Additions\tbased\ton\ttax\tpositions\trelated\tto\tthe\tcurrent\tyear | – | 11 |
| Additions\tfor\ttax\tpositions\tof\tprior\tyears | 24 | 30 |
| Reductions\tfor\ttax\tpositions\tof\tprior\tyears | (26) | (30) |
| Settlements | 1 | (19) |
| December\t31\tbalance | $39 | $40 |

In	connection	with	the	adoption	of	FIN	No.	48,	we	changed	the	presentation	of	interest	and	penalties	related	to	income	taxes	in	the	consolidated	statement	of income.	Effective	January	1,	2007,	such	interest	and	penalties	are	prospectively	recorded	as	part	of	the	provision	for	income	taxes.	Prior	to	January	1,	2007,	such	interest was	recorded	as	part	of	net	interest	and	other	financing	costs	and	such	penalties	as	selling,	general	and	administrative	expenses.	Interest	and	penalties	were	a	net	$14 million	credit	to	income	in	the	year	ended	December	31,	2008	and	were	a	net	$8	million	credit	to	income	for	the	year	ended	December	31,	2007.	As	of	December	31, 2008	and	2007,	$8	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	$4,962	million	in	2008,	$2,900	million	in	2007,	and	$3,570	million	in 2006.

Undistributed	income	of	certain	consolidated	foreign	subsidiaries	at	December	31,	2008	amounted	to	$1,626	million	for	which	no	deferred	U.S.	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	$569	million	would	have	been	incurred.

# 13.	Inventories

|  | December	31, | December	31, |
| :--- | :--- | :--- |
| (In\tmillions) | 2008 | 2007 |
| Liquid\thydrocarbons,\tnatural\tgas\tand\tbitumen | $1,376 | $1,203 |
| Refined\tproducts\tand\tmerchandise | \t 1,797 | \t 1,792 |
| Supplies\tand\tsundry\titems | 334 | 282 |
| Total,\tat\tcost | $3,507 | $3,277 |

The	LIFO	method	accounted	for	90	percent	and	89	percent	of	total	inventory	value	at	December	31,	2008	and	2007.	Current	acquisition	costs	were	estimated	to exceed	the	LIFO	inventory	value	at	December	31,	2008	and	2007	by	$777	million	and	$4,034	million.

# 14.	Equity	Method	Investments

|  | Ownership	as	of | December	31, | December	31, |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | December\t31,\t2008 | 2008 | 2007 |
| EGHoldings(a) | 60% | $1,053 | $1,014 |
| Alba\tPlant\tLLC | 52% | 315 | 395 |
| Atlantic\tMethanol\tProduction\tCompany\tLLC(b) | 45% | 235 | 245 |
| LOOP\tLLC | 51% | 143 | 183 |
| Ethanol\tinvestments(c) | 35%\t/\t50% | 70 | 97 |
| PTC(d) | 0% | – | 493 |
| Other |  | 264 | 203 |
| Total |  | $2,080 | $2,630 |
| (a) |  |  |  |

(a) As	discussed	in	Note	4,	we	ceased	consolidating	EGHoldings	effective	May	1,	2007;	thereafter,	our	investments	has	been	accounted	for	using	the	equity	method	of	accounting.	EGHoldings'	results	are	included	in the	income	data	below	after	May	1,	2007. (b) Atlantic	Methanol	Production	Company	LLC	is	engaged	in	methanol	production	activity.

(c) As	discussed	in	Note	5,	Ethanol	investments	represent	our	ownership	in	The	Andersons	Clymers	Ethanol	LLC	and	The	Anderson	Marathon	Ethanol	LLC.

(d) On	October	8,	2008,	we	completed	the	sale	of	our	50	percent	ownership	interest	in	Pilot	Travel	Centers	LLC,	as	discussed	in	Note	7	to	the	consolidated	financial	statements.

Our	Ethanol	investments	were	impaired	by	$40	million	($25	million,	net	of	tax),	in	the	fourth	quarter	of	2008,	due	to	an	other-than-temporary	loss	in	value	as	a result	of	declining	demand	and	prices	for	ethanol,	a	poor	outlook	for	short-term	future	profitability	and,	in	the	case	of	one	production	facility,	recurring	operating	losses.

Summarized	financial	information	for	equity	method	investees	is	as	follows:

| (In	millions) | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Income\tdata\t–\tyear: |  |  |  |
| Revenues\tand\tother\tincome | $15,766 | $14,133 | $ 11,873 |
| Income\tfrom\toperations | 1,608 | 1,098 | 746 |
| Net\tincome | 1,436 | 1,038 | 710 |
| Balance\tsheet\tdata\t–\tDecember\t31: |  |  |  |
| Current\tassets | $837 | $1,279 |  |
| Noncurrent\tassets | 4,692 | 5,998 |  |
| Current\tliabilities | 993 | 1,512 |  |
| Noncurrent\tliabilities | 821 | 1,378 |  |

As	of	December	31,	2008,	the	carrying	value	of	our	equity	method	investments	was	$361	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	except	for	$49	million	of	the	excess	related	to goodwill.

Dividends	and	partnership	distributions	received	from	equity	method	investees	(excluding	distributions	that	represented	a	return	of	capital	previously	contributed) were	$827	million	in	2008,	$502	million	in	2007	and	$191	million	in	2006.	In	2008	we	received	a	$75	million	partial	redemption	of	our	partnership	interest	from	Pilot Travel	Centers	that	was	accounted	for	as	a	return	of	our	investment.

# 15.	Property,	Plant	and	Equipment

| (In	millions,	except	per	share	data) | 2008 | 2007 |
| :--- | :--- | :--- |
| Exploration\tand\tproduction | $22,497 | $21,232 |
| Oil\tsands\tmining\tand\tbitumen\tupgrading | 7,935 | 6,691 |
| Refining | 9,026 | 6,462 |
| Marketing | 2,144 | 2,123 |
| Transportation | 2,592 | 2,331 |
| Gas\tLiquefaction | 26 | 26 |
| Other | 775 | 667 |
| Total | $44,995 | $39,532 |
| Less\taccumulated\tdepreciation,\tdepletion\tand\tamortization | 15,581 | 14,857 |
| Net\tproperty,\tplant\tand\tequipment | $29,414 | $24,675 |

Property,	plant	and	equipment	includes	gross	assets	acquired	under	capital	leases	of	$82	million	and	$74	million	at	December	31,	2008	and	2007,	with	related amounts	in	accumulated	depreciation,	depletion	and	amortization	of	$18	million	and	$13	million	at	December	31,	2008	and	2007.

Property	impairments	were	$21	million,	$19	million	and	$25	million	in	2008,	2007	and	2006.	The	economic	and	commodity	price	declines	in	the	latter	part	of	2008 caused	us	to	assess	the	carrying	value	of	our	assets.	No	significant	impairments	resulted	due	to	the	cash	flows	these	assets	are	expected	to	generate.	Should	market conditions	continue	to	deteriorate	or	commodity	prices	continue	to	decline,	further	assessment	of	the	carrying	value	of	assets	may	be	necessary.

Deferred	exploratory	well	costs	were	as	follows:

|  |  | December	31, |  |
| :--- | :--- | :--- | :--- |
| (In\tmillions,\texcept\tper\tshare\tdata) | 2008 | 2007 | 2006 |
| Amounts\tcapitalized\tless\tthan\tone\tyear\tafter\tcompletion\tof\tdrilling | $863 | $683 | $377 |
| Amounts\tcapitalized\tgreater\tthan\tone\tyear\tafter\tcompletion\tof\tdrilling | 54 | \t 100 | 93 |
| Total\tdeferred\texploratory\twell\tcosts | $917 | $783 | $470 |
| Number\tof\tprojects\twith\tcosts\tcapitalized\tgreater\tthan\tone\tyear\tafter\tcompletion\tof\tdrilling | 2 | 3 | 3 |

Exploratory	well	costs	capitalized	greater	than	one	year	after	completion	of	drilling	as	of	December	31,	2008	included	$30	million	related	to	wells	in	Equatorial Guinea	(primarily	Corona	and	Gardenia)	that	was	primarily	incurred	in	2004	and	$24	million	for	the	Gudrun	appraisal	well	offshore	Norway	that	was	primarily	incurred in	2006.

The	Equatorial	Guinea	discovery	wells	are	part	of	our	long-term	LNG	strategy.	These	discoveries	will	be	developed	when	the	natural	gas	supply	from	the	nearby Alba	Field	starts	to	decline.

Development	plans	are	underway	for	the	North	Sea	Gudrun	field,	which	contains	both	oil	and	natural	gas.	The	development	concept	was	announced	by	the	operator in	January	2009.	We	hold	a	28	percent	working	interest	in	Gudrun.	A	final	investment	decision	is	expected	in	2009.

The	net	changes	in	deferred	exploratory	well	costs	were	as	follows:

| (In	millions) | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Beginning\tBalance | $783 | $470 | $363 |
| Additions | 413 | \t 394 | \t 174 |
| Dry\twell\texpense | (63) | (39) | (27) |
| Transfers\tto\tdevelopment | (216) | (42) | (21) |
| Dispositions | – | – | (19) |
| Ending\tBalance | $917 | $783 | $470 |

# 16.	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	goodwill	impairment	test	during	the	second	quarter	for	our	E&P	reporting	unit,	during	the	third	quarter	for our	OSM	reporting	unit	and	during	the	fourth	quarter	for	our	reporting	units	comprising	the	RM&T	segment,	at	which	time	no	impairment	to	the	carrying	value	of goodwill	was	identified.

The	disruption	in	the	credit	and	equity	markets	and	the	significant	change	in	commodity	prices	that	transpired	during	the	latter	part	of	2008	impacts	several	of	the significant	assumptions	used	in	our	determination	of	fair	value.	As	a	result,	we	tested	goodwill	for	impairment	again	in	the	fourth	quarter	of	2008	for	our	E&P	and	OSM reporting	units.

As	there	was	limited	market-based	data	available,	we	principally	used	an	income	based	discounted	cash	flow	model	to	compute	the	fair	value	of	our	reporting	units. In	applying	this	valuation	method,	there	was	a	significant	amount	of	judgment	required,	involving	estimates	regarding	amount	and	timing	of	future	production, commodity	prices	and	the	discount	rate	appropriate	for	each	reporting	unit.	We	used	our	planning	and	capital	investment	projections,	which	considers	factors	such	as	a combination	of	proved	and	risk	adjusted	probable	and	possible	reserves,	expected	future	commodity	prices	and	operating	costs.	An	appropriate	discount	rate	was	selected for	each	of	the	reporting	units.	We	also	compared	our	significant	assumptions	used	to	determine	the	fair	value	amounts	against	other	market-based	information,	if available.	In	addition,	we	considered	several	fair	value	determination	scenarios	using	key	assumption	sensitivities	to	corroborate	our	fair	value	estimates.

Testing	goodwill	for	impairment	is	a	two	step	process.	The	first	step	of	the	goodwill	impairment	test,	used	to	identify	potential	impairment,	compares	the	fair	value of	a	reporting	unit	with	its	carrying	amount,	including	goodwill.	If	the	fair	value	of	a	reporting	unit	exceeds	its	carrying	amount,	goodwill	of	the	reporting	unit	is	not considered	to	be	impaired,	thus	the	second	step	of	the	impairment	test	is	unnecessary.	If	the	carrying	amount	of	a	reporting	unit	exceeds	its	fair	value,	the	second	step	of the	goodwill	impairment	test	is	performed	to	measure	the	amount	of	impairment,	if	any.	Our	fourth	quarter	2008	fair	value	estimate	for	the	OSM	reporting	unit	was	less than	the	carrying	amount.

The	second	step	of	the	goodwill	impairment	test,	used	to	measure	the	amount	of	impairment	loss,	compares	the	implied	fair	value	of	reporting	unit	goodwill	with	the carrying	amount	of	that	goodwill.	The	implied	fair	value	of	goodwill	shall	be	determined	in	the	same	manner	as	the	amount	of	goodwill	recognized	in	a	business combination.	This	requires	a	hypothetical	purchase	price	to	be	established	as	if	the	fair	value	of	the	reporting	unit	was	the	current	price	paid	to	acquire	the	reporting	unit. To	determine	what	the	implied	fair	value	of	the	recorded	goodwill	would	be,	the	fair	value	for	that	reporting	unit	is	hypothetically	allocated	to	all	assets	and	liabilities within	that	reporting	unit.	If	the	carrying	amount	of	reporting	unit	goodwill	exceeds	the	implied	fair	value	of	that	goodwill,	an	impairment	loss	is	required	to	be recognized	in	an	amount	equal	to	that	excess.

The	second	step	in	the	goodwill	impairment	process	indicated	there	was	no	remaining	implied	fair	value	of	goodwill	as	of	December	31,	2008,	for	the	OSM reporting	unit.	This	was	largely	due	to	the	recent	disruption	in	the	credit	and	equity	markets,	which	impacts	discount	rate	assumptions,	a	change	in	the	timing	of	expected production	and	the	decline	in	commodity	prices.	As	a	result,	a	$1,412	million	impairment	of	goodwill	for	the	OSM	reporting	unit	was	recorded	and	is	reported	on	a separate	line	of	our	consolidated	statement	of	income	for	2008.

While	the	fair	values	of	our	other	reporting	units	exceed	the	carrying	value	at	the	present	time,	should	market	conditions	continue	to	deteriorate	or	commodity prices	continue	to	decline,	the	goodwill	of	our	other	reporting	units	could	require	impairment.

The	changes	in	the	carrying	amount	of	goodwill	for	the	years	ended	December	31,	2007,	and	2008,	were	as	follows:

| (In	millions) | E&amp;P | OSM | RM&amp;T | Total |
| :--- | :--- | :--- | :--- | :--- |
| Balance\tas\tof\tDecember\t31,\t2006 | $519 | $– | $879 | $1,398 |
| Acquired | 71 | 1,437 | – | 1,508 |
| Adjusted(a) | – | – | (7) | (7) |
| Balance\tas\tof\tDecember\t31,\t2007 | \t 590 | 1,437 | 872 | 2,899 |
| Adjusted(a) | (17) | (25) | 7 | (35) |
| Impaired | – | (1,412) | – | (1,412) |
| Disposed(b) | (5) |  | – | (5) |
| Balance\tas\tof\tDecember\t31,\t2008 | $568 | $– | $879 | $1,447 |
| Adjustments\trelated\tto\tprior\tperiod\tincome\ttax\tand\troyalty\tadjustments.\n(a) |  |  |  |  |

(b) Goodwill	was	allocated	to	the	Norwegian	outside-operated	properties	sold	in	2008.

# 17.	Fair	Value	Measurements

As	defined	in	SFAS	No.	157,	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.	SFAS	No.	157	describes	three	approaches	to	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.

SFAS	No.	157	does	not	prescribe	which	valuation	technique	should	be	used	when	measuring	fair	value	and	does	not	prioritize	among	the	techniques.	SFAS No.	157	establishes	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	reporting	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	reporting	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.

We	use	a	market	or	income	approach	for	recurring	fair	value	measurements	and	endeavor	to	use	the	best	information	available.	Accordingly,	valuation	techniques that	maximize	the	use	of	observable	inputs	are	favored.	Financial	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.

The	following	table	presents	net	financial	assets	and	liabilities	accounted	for	at	fair	value	on	a	recurring	basis	as	of	December	31,	2008:

| (In	millions) | Level	1 | Level	2 | Level	3 | Total |
| :--- | :--- | :--- | :--- | :--- |
| Derivative\tinstruments: |  |  |  |  |
| Commodity | $107 | $6 | $(55) | $58 |
| Interest\trate | – | – | 29 | 29 |
| Foreign\tcurrency | – | (75) | – | (75) |
| Total\tderivative\tinstruments | 107 | (69) | (26) | 12 |
| Other\tassets | 2 | – | – | 2 |
| Total\tat\tfair\tvalue | $109 | $(69) | $(26) | $14 |

Deposits	of	$121	million	in	broker	accounts	covered	by	master	netting	agreements	are	included	in	fair	values	of	commodity	derivatives.	Derivatives	in	Level	1	are exchange-traded	contracts	for	crude	oil,	natural	gas,	refined	products	and	ethanol	measured	at	fair	value	with	a	market	approach	using	the	close-of-day	settlement	prices for	the	market.	Derivatives	in	Level	2	are	measured	at	fair	value	with	a	market	approach	using	broker	quotes	or	third-party	pricing	services,	which	have	been corroborated	with	data	from	active	markets.	Level	3	derivatives	are	measured	at	fair	value	using	either	a	market	or	income	approach.	Generally	at	least	one	input	is unobservable,	such	as	the	use	of	an	internally	generated	model	or	an	external	data	source.

Commodity	derivatives	in	Level	3	include	a	$72	million	liability	related	to	two	U.K.	natural	gas	sales	contracts	that	are	accounted	for	as	derivative	instruments	and a	$52	million	asset	for	crude	oil	options	related	to	sales	of	Canadian	synthetic	crude	oil.	The	fair	value	of	the	U.K.	natural	gas	contracts	is	measured	with	an	income approach	by	applying	the	difference	between	the	contract	price	and	the	U.K.	forward	natural	gas	strip	price	to	the	expected	sales	volumes	for	the	shorter	of	the	remaining contract	term	or	18	months.	These	contracts	originated	in	the	early	1990s	and	expire	in	September	2009.	The	contract	prices	are	reset	annually	in	October	based	on	the previous	twelve-month	changes	in	a	basket	of	energy	and	other	indices.	Consequently,	the	prices	under	these	contracts	do	not	track	forward	natural	gas	prices.	The	crude oil	options,	which	expire	December	2009,	are	measured	at	fair	value	using	a	Black-Scholes	option	pricing	model,	an	income	approach	that	utilizes	prices	from	an	active market	and	market	volatility	calculated	by	a	third-party	service.

The	interest	rate	derivatives	are	measured	at	fair	value	using	quotes	from	our	counterparties	which	are	compared	to	internal	calculations	made	using	rates	posted	by a	pricing	service.	Because	we	are	unable	to	independently	verify	those	rates	directly	to	the	market,	such	inputs	are	considered	Level	3.

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.

The	change	in	unrealized	losses	included	in	net	income	related	to	instruments	held	at	December	31,	2008,	was	an	addition	of	$299	million	for	2008.	Amounts reported	in	net	income	are	classified	as	sales	and	other	operating	revenues	or	cost	of	revenues	for	commodity	derivative	instruments,	as	net	interest	and	other	financing income	for	interest	rate	derivative	instruments	and	as	cost	of	revenues	for	foreign	currency	derivatives,	except	those	designated	as	hedges	of	future	capital	expenditures. Amounts	related	to	foreign	currency	derivatives	designated	as	hedges	of	future	capital	expenditures	accumulate	in	other	comprehensive	income	and	are	amortized	to depletion,	depreciation	and	amortization	over	the	life	of	the	capital	asset.

The	following	table	summarizes	financial	instruments,	excluding	the	derivative	financial	instruments	reported	above,	by	individual	balance	sheet	line	item	at December	31,	2008	and	2007.

|  | 2008 | 2008 | 2007 | 2007 |
| :--- | :--- | :--- | :--- | :--- |
|  | Fair | Carrying | Fair | Carrying |
| (In\tmillions) | Value | Amount | Value | Amount |
| Financial\tassets |  |  |  |  |
| Receivables\tfrom\tUnited\tStates\tSteel,\tincluding\tcurrent\tportion | $438 | $492 | $500 | $507 |
| Other\tnoncurrent\tassets(a) | 286 | 113 | \t 1,140 | 899 |
| Total\tfinancial\tassets | 724 | 605 | \t 1,640 | 1,406 |
| Financial\tliabilities |  |  |  |  |
| Long-term\tdebt,\tincluding\tcurrent\tportion(b) | \t 5,683 | 6,880 | \t 7,176 | 6,947 |
| Total\tfinancial\tliabilities | $5,683 | $6,880 | $7,176 | $6,947 |
| (a) |  |  |  |  |

(a) Includes	restricted	cash,	cost	method	investments	and	miscellaneous	long-term	receivables	or	deposits. (b) Excludes	capital	leases.

Our	current	assets	and	liabilities	accounts	contain	financial	instruments,	the	most	significant	of	which	are	trade	accounts	receivables	and	payables.	We	believe	the carrying	values	of	our	current	assets	and	liabilities	approximate	fair	value,	with	the	exception	of	the	current	portion	of	receivables	from	United	States	Steel	and	the current	portion	of	our	long-term	debt	which	is	reported	above.	Our	fair	value	assessment	incorporates	a	variety	of	considerations,	including	(1)	the	short-term	duration of	the	instruments	(e.g.,	less	than	1	percent	of	our	trade	receivables	and	payables	are	outstanding	for	greater	than	90	days),	(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	fair	value	of	the	receivables	from	United	States	Steel	is	measured	using	an	income	approach	that	discounts	the	future	expected	payments	over	the	remaining term	of	the	obligations.	Because	this	asset	is	not	publicly-traded	and	not	easily	transferable,	a	hypothetical	market	based	upon	United	States	Steel's	borrowing	rate	curve is	assumed	and	the	majority	of	inputs	to	the	calculation	are	Level	3.	The	industrial	revenue	bonds	are	to	be	redeemed	on	or	before	the	tenth	anniversary	of	the	USX Separation	per	the	Financial	Matters	Agreement.

The	majority	of	our	restricted	cash	represent	cash	accounts	that	earn	interest;	therefore,	the	balance	approximates	fair	value.	Other	financial	assets	included	in	our other	noncurrent	assets	line	include	cost	method	investments	and	miscellaneous	long-term	receivables	or	deposits.	Fair	value	for	the	cost	method	investments	is measured	using	an	income	approach.	Estimated	future	cash	flows,	obtained	from	our	internal	forecasts	or	forecasts	from	the	partially	owned	companies,	are	discounted 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	these	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.

Long-term	receivables	and	deposits	are	also	measured	using	an	income	approach.	The	expected	timing	of	payments	are	scheduled	and	then	discounted	using	a	rate deemed	appropriate.

# 18.	Derivative	Instruments

Derivative	instruments	are	recorded	at	fair	value.	Derivative	instruments	on	our	consolidated	balance	sheet	are	reported	on	a	net	basis	by	brokerage	firm,	as permitted	by	master	netting	agreements.	For	further	information	regarding	the	fair	value	measurement	of	derivative	instruments	see	Note	17.

The	following	table	sets	forth	quantitative	information	by	category	of	derivative	instrument	at	December	31,	2008	and	2007.	These	amounts	are	reported	on	a	gross basis	by	individual	derivative	instrument.

|  | 2008 | 2008 | 2007 | 2007 |
| :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Assets | (Liabilities) | Assets | (Liabilities) |
| Commodity\tInstruments |  |  |  |  |
| Fair\tvalue\thedges:(a) |  |  |  |  |
| OTC\tcommodity\tswaps | $– | $(12) | $10 | $(5) |
| Non-hedge\tdesignation: |  |  |  |  |
| Exchange-traded\tcommodity\tfutures | 279 | (277) | 423 | (506) |
| Exchange-traded\tcommodity\toptions | 16 | (18) | 312 | (287) |
| OTC\tcommodity\tswaps | 25 | (55) | 17 | (26) |
| OTC\tcommodity\toptions | 65 | (14) | – | (136) |
| U.K.\tnatural\tgas\tcontracts(b) | – | (72) | – | (291) |
| Physical\tcommodity\tcontracts(c) | – | – | 271 | (198) |
| Financial\tInstruments |  |  |  |  |
| Fair\tvalue\thedges: |  |  |  |  |
| OTC\tinterest\trate\tswaps(d) | 29 | – | – | (3) |
| Cash\tflow\thedges:(e) |  |  |  |  |
| OTC\tforeign\tcurrency\tforwards | $2 | $(77) | $12 | $– |
| (a) |  |  |  |  |

(a) There	was	no	ineffectiveness	associated	with	fair	value	hedges	for	2008	or	2007	because	the	hedging	instruments	and	the	existing	firm	commitment	contracts	were	priced	on	the	same	underlying	index.	Derivative instruments	used	in	the	fair	value	hedges	mature	in	2009.

(b) The	contract	price	under	the	U.K.	natural	gas	contracts	is	reset	annually	and	is	indexed	to	a	basket	of	costs	of	living	and	energy	commodity	indices	for	the	previous	12	months.	The	fair	value	of	these	contracts	is determined	by	applying	the	difference	between	the	contract	price	and	the	U.K.	forward	natural	gas	strip	price	to	the	expected	sales	volumes	under	these	contracts.	The	U.K.	natural	gas	contracts	expire	September, 2009.

(c) Certain	physical	commodity	contracts	were	classified	as	derivative	instruments	in	2007	because	certain	volumes	covered	by	these	contracts	were	physically	netted	at	particular	delivery	locations.	The	netting process	caused	all	contracts	at	such	delivery	locations	to	be	considered	derivative	instruments.	Other	physical	contracts	that	we	chose	not	to	designate	as	normal	purchases	or	normal	sales	in	that	period	were	also been	accounted	for	as	derivative	instruments.	Beginning	in	the	second	quarter	of	2008,	we	ceased	netting	volumes	and	elected	the	normal	purchase	and	normal	sale	designation	for	our	physical	commodity contracts;	therefore	reducing	substantially	our	number	of	derivative	instruments.

(d) The	fair	value	of	OTC	interest	rate	swaps	excludes	accrued	interest	amounts	not	yet	settled.	As	of	December	31,	2008,	and	2007,	accrued	interest	was	a	receivable	of	$1	million	and	a	payable	of	$3	million.	The net	fair	value	of	the	OTC	interest	rate	swaps	as	of	December	31,	2008	and	2007	is	included	in	long-term	debt.	See	Note	20.

(e) The	changes	in	fair	value	of	cash	flow	hedges	included	less	than	$1	million	ineffectiveness	during	2008	and	no	ineffectiveness	during	2007.

# 19.	Short	Term	Debt

We	have	a	commercial	paper	program	that	is	supported	by	the	unused	and	available	credit	on	our	revolving	credit	facility	discussed	in	Note	20.	At	December	31, 2008	and	2007,	there	were	no	commercial	paper	borrowings	outstanding.

# 20.	Long	Term	Debt

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

| (In	millions) | 2008 | 2007 |
| :--- | :--- | :--- |
| Marathon\tOil\tCorporation: |  |  |
| Revolving\tcredit\tfacility(a) | $– | $– |
| 6.850%\tnotes\tdue\t2008 | – | 400 |
| 6.125%\tnotes\tdue\t2012(b) | 450 | 450 |
| 6.000%\tnotes\tdue\t2012(b) | 400 | 400 |
| 5.900%\tnotes\tdue\t2018(c) | \t 1,000 | – |
| 6.800%\tnotes\tdue\t2032(b) | 550 | 550 |
| 9.375%\tdebentures\tdue\t2012 | 87 | 87 |
| 9.125%\tdebentures\tdue\t2013 | 174 | 174 |
| 6.000%\tdebentures\tdue\t2017(b) | 750 | 750 |
| 9.375%\tdebentures\tdue\t2022 | 65 | 65 |
| 8.500%\tdebentures\tdue\t2023 | 116 | 116 |
| 8.125%\tdebentures\tdue\t2023 | 172 | 172 |
| 6.600%\tdebentures\tdue\t2037(b) | 750 | 750 |
| 4.550%\tpromissory\tnote,\tsemi-annual\tpayments\tdue\t2009\t–\t2015 | 476 | 544 |
| Series\tA\tmedium\tterm\tnotes\tdue\t2022 | 3 | 3 |
|  | 439 | 439 |
| 5.125%\tobligation\trelating\tto\trevenue\tbonds\tdue\t2037(e) | \t 1,000 | 1,000 |
| Sale-leaseback\tfinancing\tdue\t2009\t–\t2012(f) | 37 | 45 |
| Capital\tlease\tobligation\tdue\t2009\t–\t2012(g) | 32 | 38 |
| Consolidated\tsubsidiaries |  |  |
| Revolving\tcredit\tfacility\tdue\t2012(h) | – | 599 |
| 8.375%\tsecured\tnotes\tdue\t2012(b)(i) | 448 | 448 |
| Sale-leaseback\tfinancing\tdue\t2009\t–\t2024(j) | 103 | 45 |
| Capital\tlease\tobligations\tdue\t2009\t–\t2020(j) | 80 | 108 |
| Total(k)(l) | \t 7,132 | 7,183 |
| Unamortized\tfair\tvalue\tdifferential\tfor\tdebt\tassumed\tin\tacquisitions | 37 | 47 |
| Unamortized\tdiscount | (13) | (12) |
| Fair\tvalue\tadjustments\ton\tnotes\tsubject\tto\thedging(m) | 29 | (3) |
| Amounts\tdue\twithin\tone\tyear | (98) | (1,131) |
| Total\tlong-term\tdebt\tdue\tafter\tone\tyear | $7,087 | $6,084 |
| (a) |  |  |

(a) During	2008,	we	entered	into	an	amendment	of	our	$3.0	billion	revolving	credit	facility,	extending	the	termination	date	on	$2,625	million	from	May	2012	to	May	2013.	The	remaining	$375	million	continues	to have	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,	2008	was	0.08	percent. (b) These	notes	contain	a	make-whole	provision	allowing	us	the	right	to	repay	the	debt	at	a	premium	to	market	price.

(c) On	March	12,	2008,	we	issued	$1.0	billion	aggregate	principal	amount	of	senior	notes	bearing	interest	at	5.9	percent	with	a	maturity	date	of	March	15,	2018.	Interest	on	the	senior	notes	is	payable	semi-annually beginning	September	15,	2008.

(d) United	States	Steel	has	assumed	responsibility	for	repayment	of	$415	million	of	these	obligations.	The	Financial	Matters	Agreement	provides	that,	on	or	before	the	tenth	anniversary	of	the	USX	Separation,	United States	Steel	will	provide	for	our	discharge	from	any	remaining	liability	under	any	of	the	assumed	industrial	revenue	bonds.

(e) During	2007,	the	Parish	of	St.	John	the	Baptist,	where	our	Garyville,	Louisiana,	refinery	is	located,	issued	these	revenue	bonds	associated	with	our	Garyville	refinery	expansion.	We	are	solely	obligated	to	service the	principal	and	interest	payments	associated	with	the	bonds.	The	proceeds	from	the	bonds,	including	interest	income,	were	trusteed	to	be	disbursed	to	us	upon	request	for	reimbursement	of	expenditures	related	to the	expansion.	Through	December	31,	2008,	such	reimbursements	have	totaled	$1,032	million.	The	remaining	$16	million	of	trusteed	funds,	including	interest	income	earned	to	date,	is	reflected	as	other	noncurrent assets	in	the	consolidated	balance	sheet	as	of	December	31,	2008.

(f) This	sale-leaseback	financing	arrangement	relates	to	a	lease	of	a	slab	caster	at	United	States	Steel's	Fairfield	Works	facility	in	Alabama.	We	are	the	primary	obligor	under	this	lease.	Under	the	Financial	Matters Agreement,	United	States	Steel	has	assumed	responsibility	for	all	obligations	under	this	lease.	This	lease	is	an	amortizing	financing	with	a	final	maturity	of	2012,	subject	to	additional	extensions.

(g) This	obligation	relates	to	a	lease	of	equipment	at	United	States	Steel's	Clairton	Works	cokemaking	facility	in	Pennsylvania.	We	are	the	primary	obligor	under	this	lease.	Under	the	Financial	Matters	Agreement, United	States	Steel	has	assumed	responsibility	for	all	obligations	under	this	lease.	This	lease	is	an	amortizing	financing	with	a	final	maturity	of	2012.

(h) Marathon	Oil	Canada	Corporation	had	an	805	million	Canadian	dollar	revolving	term	credit	facility	which	was	secured	by	substantially	all	of	Marathon	Oil	Canada	Corporation's	assets	and	included	certain financial	covenants,	including	leverage	and	interest	coverage	ratios.	In	February	2008,	the	outstanding	balance	was	repaid	and	the	facility	was	terminated.

(i) These	notes	are	senior	secured	notes	of	Marathon	Oil	Canada	Corporation.	The	notes	were	secured	by	substantially	all	of	Marathon	Oil	Canada	Corporation's	assets.	In	January	2008,	we	provided	a	full	and unconditional	guarantee	covering	the	payment	of	all	principal	and	interest	due	under	the	senior	notes.

(j) These	obligations	as	of	December	31,	2008	include	$126	million	related	to	assets	under	construction	at	that	date	for	which	capital	leases	or	sale-leaseback	financings	will	commence	upon	completion	of construction.	The	amounts	currently	reported	are	based	upon	the	percent	of	construction	completed	as	of	December	31,	2008	and	therefore	do	not	reflect	future	minimum	lease	obligations	of	$209	million.

(l) In	the	event	of	a	change	in	control,	as	defined	in	the	related	agreements,	debt	obligations	totaling	$669	million	at	December	31,	2008,	may	be	declared	immediately	due	and	payable. (m) See	Note	17	for	information	on	interest	rate	swaps.

On	February	17,	2009,	we	issued	$700	million	aggregate	principal	amount	of	senior	notes	bearing	interest	at	6.5	percent	with	a	maturity	date	of	February	15,	2014 and	$800	million	aggregate	principal	amount	of	senior	notes	bearing	interest	at	7.5	percent	with	a	maturity	date	of	February	15,	2019.	Interest	on	both	issues	is	payable semi-annually	beginning	August	15,	2009.

# 21.	Asset	Retirement	Obligations

The	following	summarizes	the	changes	in	asset	retirement	obligations:

| (In	millions) | 2008 | 2007 |
| :--- | :--- | :--- |
| Asset\tretirement\tobligations\tas\tof\tJanuary\t1 | $1,134 | $1,044 |
| Liabilities\tincurred,\tincluding\tacquisitions | 30 | 60 |
| Liabilities\tsettled | (94) | (10) |
| Accretion\texpense\t(included\tin\tdepreciation,\tdepletion\tand\tamortization) | 66 | 61 |
| Revisions\tto\tprevious\testimates | 24 | (17) |
| Held\tfor\tsale(a) | (195) | – |
| Deconsolidation\tof\tEGHoldings | – | (4) |
| Asset\tretirement\tobligations\tas\tof\tDecember\t31(b) | $965 | $1,134 |
| (a) |  |  |

(a) See	Note	7	for	information	related	to	our	assets	held	for	sale. (b) Includes	asset	retirement	obligation	of	$2	and	$3	million	classified	as	short-term	at	December	31,	2008,	and	2007.

# 22.	Supplemental	Cash	Flow	Information

| (In	millions) | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Net\tcash\tprovided\tfrom\toperating\tactivities\tfrom\tcontinuing\toperations\tincluded: |  |  |  |
| Interest\tpaid\t(net\tof\tamounts\tcapitalized) | $92 | $66 | $96 |
| Income\ttaxes\tpaid\tto\ttaxing\tauthorities | 2,921 | 3,283 | 4,149 |
| Income\ttax\tsettlements\tpaid\tto\tUnited\tStates\tSteel | – | 13 | 35 |
| Commercial\tpaper\tand\trevolving\tcredit\tarrangements,\tnet: |  |  |  |
| Commercial\tpaper\t–\tissuances | $46,706 | $12,751 | $1,321 |
| \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–\trepayments | (46,706) | (12,751) | (1,321) |
| Credit\tagreements\t–\tborrowings | 404 | – | – |
| \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–\trepayments | (404) | – | – |
| Noncash\tinvesting\tand\tfinancing\tactivities: |  |  |  |
| Asset\tretirement\tcosts\tcapitalized,\texcluding\tacquisitions | $26 | $8 | $286 |
| Debt\tpayments\tassumed\tby\tUnited\tStates\tSteel | 14 | 21 | 24 |
| Capital\tlease\tand\tsale-leaseback\tfinancing\tobligations | 84 | 49 | 1 |
| Bond\tobligation\tassumed\tfor\ttrusteed\tfunds | – | 1,000 | – |
| Acquisitions: |  |  |  |
| Debt\tand\tother\tliabilities\tassumed | – | 1,541 | 26 |
| Common\tstock\tor\tsecurities\texchangeable\tfor\tcommon\tstock\tissued\tto\tseller | – | 1,910 | – |
| Noncash\teffect\tof\tdeconsolidation\tof\tEGHoldings: |  |  |  |
| Decrease\tin\tnon-cash\tassets | $– | $1,759 | $– |
| Equity\tmethod\tinvestment\trecorded | – | 942 | – |
| Decrease\tin\tliabilities | – | 310 | – |
| Elimination\tof\tminority\tinterests | – | 544 | – |

# 23.	Defined	Benefit	and	Other	Postretirement	Plans

We	have	noncontributory	defined	benefit	pension	plans	covering	substantially	all	domestic	employees	as	well	as	international	employees	located	in	Ireland, Norway	and	the	United	Kingdom.	Benefits	under	these	plans	are	based	primarily	on	years	of	service	and	final	average	pensionable	earnings.

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	nonunion	and	union-represented retiree	beneficiaries.	Other	postretirement	benefits	have	not	been	funded	in	advance.

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

|  | Pension	Benefits | Pension	Benefits | Pension	Benefits | Pension	Benefits | Other	Benefits | Other	Benefits |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2008 | 2008 | 2007 | 2007 | 2008 | 2007 |
| (In\tmillions) | U.S. | Int'l | U.S. | Int'l |  |  |
| Change\tin\tbenefit\tobligations: |  |  |  |  |  |  |
| Benefit\tobligations\tat\tJanuary\t1 | $2,143 | $426 | $2,077 | $381 | $736 | $821 |
| Service\tcost | 127 | 19 | 126 | 14 | 18 | 22 |
| Interest\tcost | 135 | 25 | 124 | 18 | 44 | 45 |
| Actuarial\tloss\t(gain) | (58) | (72) | (8) | 9 | (75) | (122) |
| Plan\tamendment | – | 1 | – | – | – | – |
| Foreign\tcurrency\texchange\trate\tchanges | – | (99) | – | 13 | – | – |
| Benefits\tpaid | (183) | (12) | (176) | (9) | (29) | (30) |
| Benefit\tobligations\tat\tDecember\t31 | $2,164 | $288 | $2,143 | $426 | $694 | $736 |
| Change\tin\tplan\tassets: |  |  |  |  |  |  |
| Fair\tvalue\tof\tplan\tassets\tat\tJanuary\t1 | $1,790 | $381 | $1,688 | $301 | $–\t\t $– | $–\t\t $– |
| Actual\treturn\ton\tplan\tassets | (448) | (28) | 148 | 28 | – | – |
| Employer\tcontributions | 44 | 41 | 130 | 55 | – | – |
| Foreign\tcurrency\texchange\trate\tchanges | – | (94) | – | 6 | – | – |
| Benefits\tpaid\tto\tplan\tassets | (183) | (12) | (176) | (9) | – | – |
| Fair\tvalue\tof\tplan\tassets\tat\tDecember\t31 | $1,203 | $288 | $1,790 | $381 | $–\t\t $– | $–\t\t $– |
| Funded\tstatus\tof\tplans\tat\tDecember\t31 | $(961) | $– | $(353) | $ (45) | $(694) | $(736) |
| Amounts\trecognized\tin\tthe\tconsolidated\tbalance\tsheet: |  |  |  |  |  |  |
| Current\tliabilities | (11) | – | (7) | – | (35) | (35) |
| Noncurrent\tliabilities | (950) | – | (346) | (45) | (659) | (701) |
| Accrued\tbenefit\tcost | $(961) | $– | $(353) | $ (45) | $(694) | $(736) |
| Pretax\tamounts\tin\taccumulated\tother\tcomprehensive\tincome:(a) |  |  |  |  |  |  |
| Net\tloss\t(gain) | $785 | $26 | $281 | $62 | $(23) | $54 |
| Prior\tservice\tcost\t(credit) | 106 | 1 | 119 | – | (36) | (44) |
| Excludes\tamounts\trelated\tto\tLOOP\tLLC,\tan\tequity\tmethod\tinvestee\twith\tdefined\tbenefit\tpension\tand\tpostretirement\tplans\tfor\twhich\tnet\tlosses\tof\t$10\tmillion\tand\t$7\tmillion\twere\treflected\tin\taccumulated\tother\n(a) |  |  |  |  |  |  |

(a) Excludes	amounts	related	to	LOOP	LLC,	an	equity	method	investee	with	defined	benefit	pension	and	postretirement	plans	for	which	net	losses	of	$10	million	and	$7	million	were	reflected	in	accumulated	other comprehensive	income,	reflecting	our	51	percent	share.

The	accumulated	benefit	obligation	for	all	defined	benefit	pension	plans	was	$1,975	million	and	$2,028	million	as	of	December	31,	2008	and	2007.

The	following	summarizes	all	of	our	defined	benefit	pension	plans	that	have	accumulated	benefit	obligations	in	excess	of	plan	assets

|  | 2008 | 2008 | 2007 | 2007 |
| :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | U.S. | Int'l | U.S. | Int'l |
| Projected\tbenefit\tobligation | $(2,164) | $\t\t– | $(100) | $(397) |
| Accumulated\tbenefit\tobligation | (1,711) | – | (81) | (366) |
| Fair\tvalue\tof\tplan\tassets | 1,203 | – | – | 352 |

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.

|  | 2008 | 2008 | 2007 | 2007 | 2006 | 2006 | Other	Benefits | Other	Benefits | Other	Benefits |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | U.S. | Int'l | U.S. | Int'l | U.S. | Int'l | 2008 | 2007 | 2006 |
| Components\tof\tnet\tperiodic\tbenefit\tcost: |  |  |  |  |  |  |  |  |  |
| Service\tcost | $127 | $19 | $126 | $14 | $117 | $17 | $18 | $22 | $23 |
| Interest\tcost | 135 | 25 | 124 | 18 | 113 | 17 | 44 | 45 | 42 |
| Expected\treturn\ton\tplan\tassets | (142) | (26) | (135) | (19) | (103) | (15) | – | – | – |
| Amortization\t–\tprior\tservice\tcost\t(credit) | 13 | – | 13 | – | 8 | – | (8) | (10) | (11) |
| –\tactuarial\tloss | 29 | 3 | 36 | 3 | 34 | 7 | 1 | 8 | 9 |
| Net\tperiodic\tbenefit\tcost(a) | $162 | $21 | $164 | $16 | $169 | $26 | $55 | $65 | $63 |
| (a) |  |  |  |  |  |  |  |  |  |

|  | Pension	Benefits | Pension	Benefits | Other |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | \t\t\t\tU.S. | \t\t\t\tInt'l | Benefits |
| 2008 |  |  |  |
| Other\tchanges\tin\tplan\tassets\tand\tbenefit\tobligations\trecognized\tin\tother\tcomprehensive\tincome\t(pretax): |  |  |  |
| Actuarial\tloss\t(gain) | $532 | $(32) | $(76) |
| Amortization\tof\tactuarial\tloss | (29) | (3) | (1) |
| Prior\tservice\tcost | – | 1 | – |
| Amortization\tof\tprior\tservice\tcredit\t(cost) | (13) | – | 8 |
| Total\trecognized\tin\tother\tcomprehensive\tincome | $490 | $(34) | $(69) |
| Total\trecognized\tin\tnet\tperiodic\tbenefit\tcost\tand\tother\tcomprehensive\tincome | $652 | $(13) | $(14) |
| 2007 |  |  |  |
| Other\tchanges\tin\tplan\tassets\tand\tbenefit\tobligations\trecognized\tin\tother\tcomprehensive\tincome\t(pretax): |  |  |  |
| Actuarial\tloss\t(gain) | $(21) | $7 | $(122) |
| Amortization\tof\tactuarial\tloss | (36) | (3) | (8) |
| Amortization\tof\tprior\tservice\tcredit\t(cost) | (13) | – | 10 |
| Total\trecognized\tin\tother\tcomprehensive\tincome | $(70) | $4 | $(120) |
| Total\trecognized\tin\tnet\tperiodic\tbenefit\tcost\tand\tother\tcomprehensive\tincome | $94 | $20 | $(55) |

The	estimated	net	loss	and	prior	service	cost	for	the	defined	benefit	pension	plans	that	will	be	amortized	from	accumulated	other	comprehensive	income	into	net periodic	benefit	cost	in	2009	are	$25	million	and	$13	million.	The	estimated	net	gain	and	prior	service	credit	for	the	other	defined	benefit	postretirement	plans	that	will be	amortized	from	accumulated	other	comprehensive	income	into	net	periodic	benefit	cost	in	2009	are	$1	million	and	$5	million.

Plan	assumptions	–	The	following	summarizes	the	assumptions	used	to	determine	the	benefit	obligations	at	December	31,	and	net	periodic	benefit	cost	for	the defined	benefit	pension	and	other	postretirement	plans	for	the	2008,	2007	and	2006.

|  | 2008 | 2008 | 2007 | 2007 | 2006 | 2006 | Other	Benefits | Other	Benefits | Other	Benefits |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | U.S. | Int'l | U.S. | Int'l | U.S. | Int'l | 2008 | 2007 | 2006 |
| Weighted\taverage\tassumptions\tused\tto\tdetermine\tbenefit\tobligation: |  |  |  |  |  |  |  |  |  |
| Discount\trate | 6.90% | 6.70% | 6.30% | 5.80% | 5.80% | 5.20% | 6.85% | 6.60% | 5.90% |
| Rate\tof\tcompensation\tincrease | 4.50% | 4.75% | 4.50% | 5.15% | 4.50% | 4.75% | 4.50% | 4.50% | 4.50% |
| Weighted\taverage\tactuarial\tassumptions\tused\tto\tdetermine\tnet\tperiodic\tbenefit |  |  |  |  |  |  |  |  |  |
| cost: |  |  |  |  |  |  |  |  |  |
| Discount\trate(a) | 6.30% | 5.80% | 5.81% | 5.20% | 5.70% | 4.70% | 6.60% | 5.90% | 5.75% |
| Expected\tlong-term\treturn\ton\tplan\tassets | 8.50% | 6.48% | 8.50% | 6.45% | 8.50% | 6.07% | – | – | – |
| Rate\tof\tcompensation\tincrease | 4.50% | 5.15% | 4.50% | 4.75% | 4.50% | 4.55% | 4.50% | 4.50% | 4.50% |
| (a) |  |  |  |  |  |  |  |  |  |

(a) On	December	15,	2007,	due	to	an	interim	remeasurement,	the	discount	rate	for	the	U.S.	pension	plans	was	increased	to	5.93	percent	from	5.80	percent.	On	July	31,	2006,	due	to	an	interim	remeasurement,	the discount	rate	for	the	U.S.	pension	plans	was	increased	to	6.00	percent	from	5.50	percent.

# Expected	long-term	return	on	plan	assets

U.S.	Plans	–	Historical	markets	are	studied	and	long-term	historical	relationships	between	equities	and	fixed	income	securities	are	preserved	consistent	with	the widely	accepted	capital	market	principle	that	assets	with	higher	volatility	generate	a	greater	return	over	the	long	term.	Certain	components	of	the	asset	mix	are	modeled with	various	assumptions	regarding	inflation,	debt	returns	and	stock	yields.	The	assumptions	are	compared	to	those	of	peer	companies	and	to	historical	returns	for reasonableness	and	appropriateness.

International	Plans	–	The	overall	expected	long-term	return	on	plan	assets	is	derived	using	the	expected	returns	on	the	individual	asset	classes,	weighted	by holdings	as	of	year	end.	The	long-term	rate	of	return	on	equity	investments	is	assumed	to	be	2.5	percent	greater	than	the	yield	on	local	government	bonds.	Expected returns	on	debt	securities	are	estimated	directly	at	market	yields	and	on	cash	are	estimated	at	the	local	currency	base	rate.

# Assumed	health	care	cost	trend

The	following	summarizes	the	assumed	health	care	cost	trend	rates.

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:

|  | 2008 | 2008 | 2007 | 2007 |
| :--- | :--- | :--- | :--- | :--- |
|  | U.S. | Int'l | U.S. | Int'l |
| Equity\tsecurities | 74% | 61% | 74% | 68% |
| Debt\tsecurities | 21% | 38% | 20% | 32% |
| Real\testate | 4% | 0% | 3% | 0% |
| Other | 1% | 1% | 3% | 0% |
| Total | 100% | 100% | 100% | 100% |

# Plan	investment	policies	and	strategies

U.S.	Plans	–	The	investment	policy	reflects	the	funded	status	of	the	plans	and	our	future	ability	to	make	further	contributions.	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.	As	a	result, equity	investments	will	likely	continue	to	exceed	50	percent	of	the	value	of	the	fund.	Accordingly,	bond	and	other	fixed-	income	investments	will	comprise	the	remainder of	the	fund.	Short-term	investments	shall	reflect	the	liquidity	requirements	for	making	pension	payments.	The	plans'	targeted	asset	allocation	is	comprised	of	75	percent equity	securities	and	25	percent	fixed-income,	real	estate-related	securities.	The	plans'	assets	are	managed	by	a	third-party	investment	manager.	The	investment	manager has	limited	discretion	to	move	away	from	the	target	allocations	based	upon	the	manager's	judgment	as	to	current	confidence	or	concern	for	the	capital	markets. Investments	are	diversified	by	industry	and	type,	limited	by	grade	and	maturity.	The	policy	prohibits	investments	in	any	securities	in	the	steel	industry	and	allows derivatives	subject	to	strict	guidelines,	such	that	derivatives	may	only	be	written	against	equity	securities	in	the	portfolio.	Investment	performance	and	risk	is	measured and	monitored	on	an	ongoing	basis	through	quarterly	investment	meetings	and	periodic	asset	and	liability	studies.

International	Plans	–	The	objective	of	the	investment	policy	is	to	achieve	a	long-term	return	which	is	consistent	with	assumptions	made	by	the	actuary	in determining	the	funding	requirements	of	the	plans.	The	target	asset	allocation	is	70	percent	equity	securities	and	30	percent	debt	securities.	The	day-to-day	management of	the	plans'	assets	is	delegated	to	several	professional	investment	managers.	The	spread	of	assets	by	type	and	the	investment	managers'	policies	on	investing	in individual	securities	within	each	type	provide	adequate	diversification	of	investments.	The	use	of	derivatives	by	the	investment	managers	is	permitted	and	plan	specific, subject	to	strict	guidelines.	Investment	performance	and	risk	is	measured	and	monitored	on	an	ongoing	basis	through	quarterly	investment	portfolio	reviews	and	periodic asset	and	liability	studies.

Plan	Contributions	–	We	expect	to	make	contributions	to	the	funded	pension	plans	of	up	to	$439	million	in	2009.	Cash	contributions	to	be	paid	from	our	general assets	for	the	unfunded	pension	and	postretirement	plans	are	expected	to	be	approximately	$11	million	and	$40	million	in	2009.

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

|  | Benefits | Benefits | Other |
| :--- | :--- | :--- | :--- |
| (In\tmillions) | U.S. | Int'l | Benefits(a) |
| 2009 | $178 | $10 | $40 |
| 2010 | 195 | 12 | 43 |
| 2011 | 214 | 13 | 46 |
| 2012 | 239 | 15 | 49 |
| 2013 | 253 | 15 | 52 |
| 2014\tthrough\t2018 | \t 1,410 | \t 117 | 307 |
| Expected\tMedicare\treimbursements\tfor\t2009\tthrough\t2018\ttotal\t$57\tmillion.\n(a) |  |  |  |

Other	Plan	Contributions	–	We	also	contribute	to	several	defined	contribution	plans	for	eligible	employees.	Contributions	to	these	plans	totaled	$49	million	in 2008,	$55	million	in	2007	and	$47	million	in	2006.

# 24.	Stock-Based	Compensation	Plans

# Description	of	the	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	Marathon	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	Marathon	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	Marathon	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	vest	or	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	Marathon	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	Marathon	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.

Stock-based	performance	awards	–	Prior	to	2005,	we	granted	stock-based	performance	awards	under	the	2003	Plan.	No	stock-based	performance	awards	have	been granted	under	the	2007	Plan.	Beginning	in	2005,	we	discontinued	granting	stock-based	performance	awards	and	instead	now	grant	cash-settled	performance	units	to officers.	All	stock-based	performance	awards	granted	under	the	2003	Plan	have	either	vested	or	been	forfeited.	As	a	result,	there	are	no	outstanding	stock-based performance	awards.

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	U.S.-based	officers	of	Marathon	and	its	consolidated	subsidiaries	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	granted	in	2008	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	other	than	the	Chairman	receive	annual	grants	of	common	stock	units,	and	they	are	required	to	hold	those units	until	they	leave	the	Board	of	Directors.	When	dividends	are	paid	on	Marathon	common	stock,	directors	receive	dividend	equivalents	in	the	form	of	additional common	stock	units.

# Total	Stock-based	Compensation	Expense

Total	employee	stock-based	compensation	expense	was	$43	million,	$66	million	and	$78	million	in	2008,	2007	and	2006.	The	total	related	income	tax	benefits were	$16	million,	$24	million	and	$29	million.	In	2008	and	2007,	cash	received	upon	exercise	of	stock	option	awards	was	$9	million	and	$27	million.	Tax	benefits realized	for	deductions	during	2008	and	2007	that	were	in	excess	of	the	stock-based	compensation	expense	recorded	for	options	exercised	and	other	stock-based	awards vested	during	the	period	totaled	$7	million	and	$30	million.	Cash	settlements	of	stock	option	awards	totaled	$1	million	in	2007.	There	were	no	cash	settlements	in	2008.

# Stock	Option	Awards

During	2008,	2007	and	2006,	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:

|  | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Weighted\taverage\texercise\tprice\tper\tshare | $51.74 | $60.94 | $37.84 |
| Expected\tannual\tdividends\tper\tshare | $0.96 | $0.96 | $0.80 |
| Expected\tlife\tin\tyears | 4.8 | 5.0 | 5.1 |
| Expected\tvolatility | 30% | 27% | 28% |
| Risk-free\tinterest\trate | 3.1% | 4.1% | 5.0% |
| Weighted\taverage\tgrant\tdate\tfair\tvalue\tof\tstock\toption\tawards\tgranted | $13.03 | $17.24 | $10.19 |

     The	following	is	a	summary	of	stock	option	award	activity	in	2008.

| The	following	is	a	summary	of	stock	option	award	activity	in	2008. |  |  |
| :--- | :--- | :--- |
|  |  | Weighted- |
|  |  | Average |
|  | Number\tof | Exercise |
|  | Shares | price |
| Outstanding\tat\tDecember\t31,\t2007 | 12,214,853 | $34.58 |
| Granted | 2,558,409 | 51.74 |
| Exercised | (491,248) | 18.07 |
| Cancelled | (440,266) | 51.75 |
| Outstanding\tat\tDecember\t31,\t2008 | 13,841,748 | 37.59 |

The	intrinsic	value	of	stock	option	awards	exercised	during	2008,	2007	and	2006	was	$12	million,	$64	million	and	$107	million.	Of	those	amounts,	$0,	$10	million and	$32	million	relate	to	stock	options	with	tandem	SARs.

The	following	table	presents	information	related	to	stock	option	awards	at	December	31,	2008.

|  | Outstanding | Outstanding | Outstanding | Exercisable | Exercisable |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  | Weighted- |  |  |  |
|  |  | Average |  |  |  |
|  | Number | Remaining | Weighted- | Number | Weighted- |
| Range\tof | of\tShares | Contractual | Average | of\tShares | Average |
| Exercise\tPrices | Under\tOption | Life | Exercise\tPrice | Under\tOption | Exercise\tPrice |
| $\t12.75-17.00 | \t\t3,353,046 | 5 | $15.56 | 3,353,046 | $15.56 |
| \t\t\t23.21-29.10 | \t\t2,443,668 | 6 | 24.97 | 2,440,477 | 24.96 |
| \t\t\t37.82-47.91 | \t\t2,711,108 | 8 | 38.11 | 1,682,455 | 37.84 |
| \t\t\t51.17-61.33 | \t\t5,333,926 | 9 | 56.95 | 1,021,896 | 60.95 |
| Total | 13,841,748 | 7 | 37.59 | 8,497,874 | 28.13 |

As	of	December	31,	2008,	the	aggregate	intrinsic	value	of	stock	option	awards	outstanding	was	$45	million.	The	aggregate	intrinsic	value	and	weighted	average remaining	contractual	life	of	stock	option	awards	currently	exercisable	were	$45	million	and	6	years.	As	of	December	31,	2008,	the	number	of	fully-vested	stock	option awards	and	stock	option	awards	expected	to	vest	was	13,697,959.	The	weighted	average	exercise	price	and	weighted	average	remaining	contractual	life	of	these	stock option	awards	were	$37.45	and	7	years	and	the	aggregate	intrinsic	value	was	$45	million.	As	of	December	31,	2008,	unrecognized	compensation	cost	related	to	stock option	awards	was	$45	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.

| The	following	is	a	summary	of	restricted	stock	award	activity. |  |  |
| :--- | :--- | :--- |
|  |  | Weighted- |
|  |  | Average |
|  |  | Grant\tDate |
|  | Awards | Fair\tValue |
| Unvested\tat\tDecember\t31,\t2007 | 1,527,831 | $39.87 |
| Granted | 1,510,378 | 46.85 |
| Vested | (851,545) | 32.77 |
| Forfeited | (137,409) | 43.52 |
| Unvested\tat\tDecember\t31,\t2008 | 2,049,255 | 47.72 |

The	vesting	date	fair	value	of	restricted	stock	awards	which	vested	during	2008,	2007	and	2006	was	$38	million,	$29	million	and	$32	million.

As	of	December	31,	2008,	there	was	$75	million	of	unrecognized	compensation	cost	related	to	restricted	stock	awards	which	is	expected	to	be	recognized	over	a weighted	average	period	of	2.1	years.

# Stock-Based	Performance	Awards

All	stock-based	performance	awards	have	either	vested	or	been	forfeited.	The	vesting	date	fair	value	of	stock-based	performance	awards	which	vested	during	2007 and	2006	was	$38	million	and	$21	million.

# 25.	Stockholders'	Equity

Common	stock	–	On	April	25,	2007,	our	stockholders	approved	an	increase	in	the	number	of	authorized	shares	of	Marathon	common	stock	from	550	million	to	1.1 billion	shares,	and	the	Board	of	Directors	subsequently	declared	a	two-for-one	split	of	Marathon	common	stock.	The	stock	split	was	effected	in	the	form	of	a	stock dividend	distributed	on	June	18,	2007,	to	stockholders	of	record	at	the	close	of	business	on	May	23,	2007.	Stockholders	received	one	additional	share	of	Marathon common	stock	for	each	share	of	common	stock	held	as	of	the	close	of	business	on	the	record	date.	In	addition,	shares	of	Marathon	common	stock	issued	or	issuable	for stock-based	awards	under	our	incentive	compensation	plans	were	proportionately	increased	in	accordance	with	the	terms	of	the	plans.	Common	stock	and	per	share (except	par	value)	information	for	all	periods	presented	has	been	restated	in	the	consolidated	financial	statements	and	notes	to	reflect	the	stock	split.

During	2008	and	2007,	we	had	the	following	common	stock	issuances	in	addition	to	shares	issued	for	employee	stock-based	awards:

•In	2008,	2	million	common	shares	were	issued	upon	the	redemption	of	the	Exchangeable	Shares	described	below.

•	 On	October	18,	2007,	in	connection	with	the	acquisition	of	Western	discussed	in	Note	6,	we	distributed	29	million	shares	of	Marathon	common	stock	valued at	$55.70	per	share	to	Western's	shareholders.

The	Board	of	Directors	has	authorized	the	repurchase	of	up	to	$5	billion	of	Marathon	common	stock.	Purchases	under	the	program	may	be	in	either	open	market transactions,	including	block	purchases,	or	in	privately	negotiated	transactions.	We	will	use	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,	2008,	we	have	acquired 66	million	common	shares	at	a	cost	of	$2,922	million	under	the	program,	including	8	million	common	shares	acquired	during	2008	at	a	cost	of	$402	million.	No	shares have	been	acquired	since	August	2008.

Securities	exchangeable	into	Marathon	common	stock	–	As	discussed	in	Note	6,	we	acquired	all	of	the	outstanding	shares	of	Western	on	October	18,	2007.	The Western	shareholders	who	were	Canadian	residents	received,	at	their	election,	cash,	Marathon	common	stock,	securities	exchangeable	into	Marathon	common	stock	(the "Exchangeable	Shares")	or	a	combination	thereof.	The	Western	shareholders	elected	to	receive	5	million	Exchangeable	Shares	as	part	of	the	acquisition	consideration. The	Exchangeable	Shares	are	shares	of	an	indirect	Canadian	subsidiary	of	Marathon	and,	at	the	acquisition	date,	were	exchangeable	on	a	one-for-one	basis	into Marathon	common	stock.	Subsequent	to	the	acquisition,	the	exchange	ratio	is	adjusted	to	reflect	cash	dividends,	if	any,	paid	on	Marathon	common	stock	and	cash dividends,	if	any,	paid	on	the	Exchangeable	Shares.	The	exchange	ratio	at	December	31,	2008,	was	1.02811	common	shares	for	each	Exchangeable	Share.	The Exchangeable	Shares	are	exchangeable	at	the	option	of	the	holder	at	any	time	and	are	automatically	redeemable	on	October	18,	2011.

Holders	of	Exchangeable	Shares	are	entitled	to	instruct	a	trustee	to	vote	(or	obtain	a	proxy	from	the	trustee	to	vote	directly)	on	all	matters	submitted	to	the	holders of	Marathon	common	stock.	The	number	of	votes	to	which	each	holder	is	entitled	is	equal	to	the	whole	number	of	shares	of	Marathon	common	stock	into	which	such holder's	Exchangeable	Shares	would	be	exchangeable	based	on	the	exchange	ratio	in	effect	on	the	record	date	for	the	vote.	The	voting	right	is	attached	to	voting preferred	shares	of	Marathon	that	were	issued	to	a	trustee	in	an	amount	equivalent	to	the	Exchangeable	Shares	at	the	acquisition	date	as	discussed	below.	Additional shares	of	voting	preferred	stock	will	be	issued	as	necessary	to	adjust	the	number	of	votes	to	account	for	changes	in	the	exchange	ratio.

Preferred	shares	–	In	connection	with	the	acquisition	of	Western	discussed	in	Note	6,	the	Board	of	Directors	authorized	a	class	of	voting	preferred	stock	consisting of	6	million	shares.	Upon	completion	of	the	acquisition,	we	issued	5	million	shares	of	this	voting	preferred	stock	to	a	trustee,	who	holds	the	shares	for	the	benefit	of	the holders	of	the	Exchangeable	Shares	discussed	above.	Each	share	of	voting	preferred	stock	is	entitled	to	one	vote	on	all	matters	submitted	to	the	holders	of	Marathon common	stock.	Each	holder	of	Exchangeable	Shares	may	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	will	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	will	vote	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 will	have	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,	will be	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	will	not	be	entitled	to	receive	any	assets	of	Marathon	available	for	distribution	to	its	stockholders.	The	voting	preferred	stock	is	not	convertible	into	any other	class	or	series	of	the	capital	stock	of	Marathon	or	into	cash,	property	or	other	rights,	and	may	not	be	redeemed.

We	lease	a	wide	variety	of	facilities	and	equipment	under	operating	leases,	including	land	and	building	space,	office	equipment,	production	facilities	and transportation	equipment.	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(a) | Obligations |
| 2009 | $40 | $181 |
| 2010 | 45 | 133 |
| 2011 | 47 | 110 |
| 2012 | 60 | 100 |
| 2013 | 39 | 85 |
| Later\tyears | 426 | 379 |
| Sublease\trentals | – | (21) |
| Total\tminimum\tlease\tpayments | $657 | $967 |
| Less\timputed\tinterest\tcosts | (198) |  |
| Present\tvalue\tof\tnet\tminimum\tlease\tpayments | $459 |  |
| (a) |  |  |

(a) Capital	lease	obligations	includes	$335	million	related	to	assets	under	construction	as	of	December	31,	2008.	These	leases	are	currently	reported	in	long-term	debt	based	on	percentage	of	construction	completed	at $126	million.

In	connection	with	past	sales	of	various	plants	and	operations,	we	assigned	and	the	purchasers	assumed	certain	leases	of	major	equipment	used	in	the	divested plants	and	operations	of	United	States	Steel.	In	the	event	of	a	default	by	any	of	the	purchasers,	United	States	Steel	has	assumed	these	obligations;	however,	we	remain primarily	obligated	for	payments	under	these	leases.	Minimum	lease	payments	under	these	operating	lease	obligations	of	$21	million	have	been	included	above	and	an equal	amount	has	been	reported	as	sublease	rentals.

Of	the	$459	million	present	value	of	net	minimum	capital	lease	payments,	$69	million	was	related	to	obligations	assumed	by	United	States	Steel	under	the Financial	Matters	Agreement.

# Operating	lease	rental	expense	was:

| (In	millions) | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Minimum\trental(a) | $245 | $209 | $172 |
| Contingent\trental | 22 | 33 | 28 |
| Sublease\trentals | – | – | (7) |
| Net\trental\texpense | $267 | $242 | $193 |
| (a) |  |  |  |

# 27.	Contingencies	and	Commitments

We	are	the	subject	of,	or	party	to,	a	number	of	pending	or	threatened	legal	actions,	contingencies	and	commitments	involving	a	variety	of	matters,	including	laws and	regulations	relating	to	the	environment.	Certain	of	these	matters	are	discussed	below.	The	ultimate	resolution	of	these	contingencies	could,	individually	or	in	the aggregate,	be	material	to	our	consolidated	financial	statements.	However,	management	believes	that	we	will	remain	a	viable	and	competitive	enterprise	even	though	it	is possible	that	these	contingencies	could	be	resolved	unfavorably.

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,	2008	and	2007,	accrued	liabilities	for	remediation	totaled	$111	million	and	$108	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.	Receivables	for	recoverable	costs	from	certain	states,	under programs	to	assist	companies	in	clean-up	efforts	related	to	underground	storage	tanks	at	retail	marketing	outlets,	were	$60	and	$66	million	at	December	31,	2008	and 2007.

We	are	a	defendant,	along	with	other	refining	companies,	in	20	cases	arising	in	three	states	alleging	damages	for	methyl	tertiary-butyl	ether	("MTBE") contamination.	We	have	also	received	seven	Toxic	Substances	Control	Act	notice	letters	involving	potential	claims	in	two	states.	Such	notice	letters	are	often	followed by	litigation.	Like	the	cases	that	were	settled	in	2008,	the	remaining	MTBE	cases	are	consolidated	in	a	multidistrict	litigation	in	the	Southern	District	of	New	York	for pretrial	proceedings.	Nineteen	of	the	remaining	cases	allege	damages	to	water	supply	wells,	similar	to	the	damages	claimed	in	the	settled	cases.	In	the	other	remaining case,	the	State	of	New	Jersey	is	seeking	natural	resources	damages	allegedly	resulting	from	contamination	of	groundwater	by	MTBE.	This	is	the	only	MTBE contamination	case	in	which	we	are	a	defendant	and	natural	resources	damages	are	sought.	We	are	vigorously	defending	these	cases.	We,	along	with	a	number	of	other defendants,	have	engaged	in	settlement	discussions	related	to	the	majority	of	the	cases	in	which	we	are	a	defendant.	We	do	not	expect	our	share	of	liability,	if	any,	for the	remaining	cases	to	significantly	impact	our	consolidated	results	of	operations,	financial	position	or	cash	flows.

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.

Guarantees	Related	to	Indebtedness	of	Equity	Method	Investees	–	We	hold	interests	in	an	offshore	oil	port,	LOOP	LLC,	and	a	crude	oil	pipeline	system,	LOCAP LLC.	Both	LOOP	LLC	and	LOCAP	LLC	have	secured	various	project	financings	with	throughput	and	deficiency	agreements.	Under	the	agreements,	we	are	required	to advance	funds	if	the	investees	are	unable	to	service	their	debt.	Any	such	advances	are	considered	prepayments	of	future	transportation	charges.	The	terms	of	the agreements	vary	but	tend	to	follow	the	terms	of	the	underlying	debt.	Our	maximum	potential	undiscounted	payments	under	these	agreements	totaled	$172	million	as	of December	31,	2008.

We	hold	an	interest	in	a	refined	products	pipeline	through	our	investment	in	Centennial,	and	have	guaranteed	the	repayment	of	Centennial's	outstanding	balance under	a	Master	Shelf	Agreement	which	expires	in	2024.	The	guarantee	arose	in	order	for	Centennial	to	obtain	adequate	financing.	Our	maximum	potential	undiscounted payments	under	this	agreement	totaled	$65	million	as	of	December	31,	2008.

Other	Guarantees	–	We	have	entered	into	other	guarantees	with	maximum	potential	undiscounted	payments	totaling	$266	million	as	of	December	31,	2008,	which consist	primarily	of	leases	of	corporate	assets	containing	general	lease	indemnities	and	guaranteed	residual	values,	commitments	to	contribute	cash	to	equity	method investees	for	certain	catastrophic	events	in	lieu	of	procuring	insurance	coverage,	a	performance	guarantee	and	a	long-term	transportation	services	agreement.

United	States	Steel	was	the	sole	general	partner	of	Clairton	1314B	Partnership,	L.P.,	which	owned	certain	cokemaking	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	$650	million	as	of	December	31,	2008.

General	Guarantees	Associated	with	Asset	Disposals	–	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,	2008	and	2007,	our	contract	commitments	to	acquire	property,	plant	and	equipment	totaled	$4,070	million	and	$3,893 million.

Other	contingencies	–	In	November	2006,	the	government	of	Equatorial	Guinea	enacted	a	new	hydrocarbon	law	governing	petroleum	operations	in	Equatorial Guinea.	The	transitional	provision	of	the	law	provides	that	all	contractors	and	the	terms	of	any	contract	to	which	they	are	a	party	will	be	subject	to	the	law.	The governmental	agency	responsible	for	the	energy	industry	was	given	the	authority	to	renegotiate	any	contract	for	the	purpose	of	adapting	any	terms	and	conditions	that	are inconsistent	with	the	new	law.	We	are	in	the	process	of	determining	what	impact	this	law	may	have	on	our	existing	operations	in	Equatorial	Guinea.

•	 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	will	be	mandatory.

If	finalized,	we	will	begin	complying	with	the	disclosure	requirements	in	our	annual	report	on	Form	10-K	for	the	year	ending	December	31,	2009.	The	new	rules may	not	be	applied	to	disclosures	in	quarterly	reports	prior	to	the	first	annual	report	in	which	the	revised	disclosures	are	required.	We	are	currently	in	the	process	of evaluating	the	new	requirements.

In	June	2008,	the	FASB	issued	FSP	on	EITF	03-6-1,	"Determining	Whether	Instruments	Granted	in	Share-Based	Payment	Transactions	Are	Participating Securities"	("FSP	EITF	03-6-1")	which	provides	that	unvested	share-based	payment	awards	that	contain	nonforfeitable	rights	to	dividends	or	dividend	equivalents (whether	paid	or	unpaid)	are	participating	securities	and,	therefore,	need	to	be	included	in	the	earnings	allocation	in	computing	earnings	per	share	("EPS")	under	the	two- class	method.	FSP	EITF	03-6-1	is	effective	January	1,	2009	and	all	prior-period	EPS	data	(including	any	amounts	related	to	interim	periods,	summaries	of	earnings	and selected	financial	data)	will	be	adjusted	retrospectively	to	conform	to	its	provisions.	Early	application	of	FSP	EITF	03-6-1	is	not

permitted.	Although	restricted	stock	awards	meet	this	definition	of	participating	securities,	we	do	not	expect	application	of	FSP	EITF	03-6-1	to	have	a	significant	impact on	our	reported	EPS.

In	April	2008,	the	FASB	issued	FSP	on	FAS	142-3	("FSP	FAS	142-3")	which	amends	the	factors	that	should	be	considered	in	developing	renewal	or	extension assumptions	used	to	determine	the	useful	life	of	a	recognized	intangible	asset	under	SFAS	No.	142,	"Goodwill	and	Other	Intangible	Assets."	The	intent	of	this	FSP	is	to improve	the	consistency	between	the	useful	life	of	a	recognized	intangible	asset	and	the	period	of	expected	cash	flows	used	to	measure	the	fair	value	of	the	asset.	FSP FAS	142-3	is	effective	on	January	1,	2009,	early	adoption	is	prohibited.	The	provisions	of	FSP	FAS	142-3	are	to	be	applied	prospectively	to	intangible	assets	acquired after	the	effective	date,	except	for	the	disclosure	requirements	which	must	be	applied	prospectively	to	all	intangible	assets	recognized	as	of,	and	subsequent	to,	the effective	date.	Since	this	standard	will	be	applied	prospectively,	adoption	is	not	expected	to	have	a	significant	impact	on	our	consolidated	results	of	operations,	financial position	or	cash	flows.

In	December	2007,	the	FASB	issued	SFAS	No.	141	(Revised	2007),	"Business	Combinations"	("SFAS	No.	141	(R)").	This	statement	significantly	changes	the accounting	for	business	combinations.	Under	SFAS	No.	141(R),	an	acquiring	entity	will	be	required	to	recognize	all	the	assets	acquired,	liabilities	assumed	and	any	non- controlling	interest	in	the	acquiree	at	their	acquisition-date	fair	value	with	limited	exceptions.	The	statement	expands	the	definition	of	a	business	and	is	expected	to	be applicable	to	more	transactions	than	the	previous	business	combinations	standard.	The	statement	also	changes	the	accounting	treatment	for	changes	in	control,	step acquisitions,	transaction	costs,	acquired	contingent	liabilities,	in-process	research	and	development,	restructuring	costs,	changes	in	deferred	tax	asset	valuation allowances	as	a	result	of	a	business	combination	and	changes	in	income	tax	uncertainties	after	the	acquisition	date.	Accounting	for	changes	in	valuation	allowances	for acquired	deferred	tax	assets	and	the	resolution	of	uncertain	tax	positions	for	prior	business	combinations	will	impact	tax	expense	instead	of	impacting	recorded goodwill.	Additional	disclosures	are	also	required.	SFAS	No.	141(R)	is	effective	on	January	1,	2009	for	all	new	business	combinations.	The	adoption	of	this	standard	is not	expected	to	have	a	significant	impact	on	our	consolidated	results	of	operations,	financial	position	or	cash	flows.

# Selected	Quarterly	Financial	Data	(Unaudited)

|  | 2008 | 2008 | 2008 | 2008 | 2007 | 2007 | 2007 | 2007 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 1st | 2nd | 3rd | 4th | 1st | 2nd | 3rd | 4th |
| (In\tmillions,\texcept\tper\tshare\tdata) | Qtr. | Qtr. | Qtr. | Qtr. | Qtr. | Qtr. | Qtr. | Qtr. |
| Revenues | $17,822 | $21,912 | $23,114 | $14,345 | $12,869 | $16,736 | $16,762 | $18,185 |
| Income\tfrom\toperations | 1,290 | 1,594 | 3,754 | 385 | 1,316 | 2,756 | 1,619 | 949 |
| Income\t(loss)\tfrom\tcontinuing\toperations | 731 | 774 | 2,064 | (41)(a) | 717 | 1,542 | 1,021 | 668 |
| Discontinued\toperations | – | – | – | – | – | 8 | – | – |
| Net\tincome\t(loss) | 731 | 774 | 2,064 | (41)(a) | 717 | 1,550 | 1,021 | 668 |
| Common\tstock\tdata |  |  |  |  |  |  |  |  |
| Net\tincome\t(loss)\tper\tshare: |  |  |  |  |  |  |  |  |
| –\tBasic | $1.03 | $1.09 | $2.92 | $(0.06) | $1.04 | $2.27 | $1.50 | $0.95 |
| –\tDiluted | $1.02 | $1.08 | $2.90 | $(0.06)(b) | $1.03 | $2.25 | $1.49 | $0.94 |
| Dividends\tpaid\tper\tshare | $0.24 | $0.24 | $0.24 | $0.24 | $0.20 | $0.24 | $0.24 | $0.24 |
| (a) |  |  |  |  |  |  |  |  |

(a) Reflects	a	$1,412	million	impairment	of	goodwill	related	to	the	OSM	segment.	See	Note	16	to	the	consolidated	financial	statements.

(b) Because	a	loss	was	reported	for	the	quarter,	all	outstanding	awards	were	antidilutive.	See	Note	9	to	the	consolidated	financial	statements	for	the	calculation	of	annual	earnings	per	share.

# 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,	Ireland	and	Norway;	Africa,	which	primarily	includes	activities	in	Angola,	Equatorial	Guinea,	Gabon	and	Libya;	and	Other	International	("Other	Int'l"), which	includes	activities	in	Canada	and	Indonesia,	and	other	international	locations	outside	of	Europe	and	Africa.	Discontinued	operations	("Disc	Ops")	represent Marathon's	Russian	oil	exploration	and	production	businesses	that	were	sold	in	2006.

# Capitalized	Costs	and	Accumulated	Depreciation,	Depletion	and	Amortization

|  |  | United |  |  | Other |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) |  | States | Europe | Africa | Int'l | Total |
| 2008 | Capitalized\tcosts: |  |  |  |  |  |
|  | Proved\tproperties | $10,008 | $8,460 | $2,257 | $1 | $20,726 |
|  | Unproved\tproperties | 1,170 | 53 | 549 | 326 | 2,098 |
|  | Suspended\texploratory\twells | 373 | 56 | 480 | 8 | 917 |
|  | Total | 11,551 | 8,569 | 3,286 | 335 | 23,741 |
|  | Accumulated\tdepreciation,\tdepletion\tand\tamortization: |  |  |  |  |  |
|  | Proved\tproperties | 5,927 | 4,995 | 627 | 1 | 11,550 |
|  | Unproved\tproperties | 69 | 1 | 9 | 8 | 87 |
|  | Total | 5,996 | 4,996 | 636 | 9 | 11,637 |
|  | Net\tcapitalized\tcosts | $5,555 | $3,573 | $2,650 | $326 | $12,104 |
| 2007 | Capitalized\tcosts: |  |  |  |  |  |
|  | Proved\tproperties | $8,325 | $8,191 | $2,108 | $60 | $18,684 |
|  | Unproved\tproperties | 1,133 | 64 | 474 | 261 | 1,932 |
|  | Suspended\texploratory\twells | 312 | 76 | 395 | – | 783 |
|  | Total | 9,770 | 8,331 | 2,977 | 321 | 21,399 |
|  | Accumulated\tdepreciation,\tdepletion\tamortization: |  |  |  |  |  |
|  | Proved\tproperties | 5,478 | 5,070 | 482 | 1 | 11,031 |
|  | Unproved\tproperties | 67 | 6 | 9 | – | 82 |
|  | Total | 5,545 | 5,076 | 491 | 1 | 11,113 |
|  | Net\tcapitalized\tcosts | $4,225 | $3,255 | $2,486 | $320 | $10,286 |

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

|  |  | United |  |  | Other | Continuing | Disc |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) |  | States | Europe | Africa | Int'l | Operations | Ops | Total |
| 2008 | Property\tacquisition: |  |  |  |  |  |  |  |
|  | Proved | $5 | $– | $– | $– | $5 | $– | $5 |
|  | Unproved | 395 | – | 8 | 65 | 468 | – | 468 |
|  | Exploration | 738 | 57 | 156 | 58 | 1,009 | – | 1,009 |
|  | Development | 1,019 | 683 | 196 | – | 1,898 | – | 1,898 |
|  | Capitalized\tasset\tretirement\tcosts | 53 | (6) | (21) | – | 26 | – | 26 |
|  | Total | $2,210 | $734 | $339 | $123 | $3,406 | $– | $3,406 |
| 2007 | Property\tacquisition: |  |  |  |  |  |  |  |
|  | Proved | $4 | $– | $– | $– | $4 | $– | $4 |
|  | Unproved | 142 | 1 | 1 | 315 | 459 | – | 459 |
|  | Exploration | 523 | 68 | 219 | 44 | 854 | – | 854 |
|  | Development | 759 | 806 | 85 | – | 1,650 | – | 1,650 |
|  | Capitalized\tasset\tretirement\tcosts | (62) | 61 | 9 | – | 8 | – | 8 |
|  | Total | $1,366 | $936 | $314 | $359 | $2,975 | $– | $2,975 |
| 2006 | Property\tacquisition: |  |  |  |  |  |  |  |
|  | Proved | $4 | $– | $19 | $– | $23 | $– | $23 |
|  | Unproved | 526 | 3 | 3 | 4 | 536 | – | 536 |
|  | Exploration | 224 | 36 | 169 | 70 | 499 | 2 | 501 |
|  | Development | 603 | 607 | 40 | – | 1,250 | 43 | 1,293 |
|  | Capitalized\tasset\tretirement\tcosts | 78 | 201 | 13 | 2 | 294 | 1 | 295 |
|  | Total | $1,435 | $847 | $244 | $76 | $2,602 | $46 | $2,648 |
| (a) | Includes\tcosts\tincurred\twhether\tcapitalized\tor\texpensed. |  |  |  |  |  |  |  |

# Supplementary	Information	on	Oil	and	Gas	Producing	Activities	(Unaudited)	C	O	N	T	I	N	U	E	D

# Results	of	Operations	for	Oil	and	Gas	Producing	Activities

|  |  | United |  |  | Other |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) |  | States | Europe | Africa | Int'l | Total |
| 2008 | Revenues\tand\tother\tincome: |  |  |  |  |  |
|  | Sales^(a) | $2,619 | $1,283 | $1,930 | $– | $ 5,832 |
|  | Transfers | 547 | 1,062 | 1,170 | – | 2,779 |
|  | Other\tincome^(b) | 1 | 254 | – | – | 255 |
|  | Total\trevenues | 3,167 | 2,599 | 3,100 | – | 8,866 |
| Expenses: | Expenses: |  |  |  |  |  |
|  | Production\tcosts | (692) | (319) | (145) | – | (1,156) |
|  | Transportation\tcosts | (153) | (59) | (36) | – | (248) |
|  | Exploration\texpenses | (238) | (88) | (47) | (117) | (490) |
|  | Depreciation,\tdepletion\tand\tamortization | (671) | (512) | (144) | (1) | (1,328) |
|  | Administrative\texpenses | (49) | (15) | (5) | (37) | (106) |
|  | Total\texpenses | (1,803) | (993) | (377) | (155) | (3,328) |
|  | Other\tproduction-related\tincome\t(loss)^(c) | (1) | 35 | 1 | – | 35 |
|  | Results\tbefore\tincome\ttaxes | 1,363 | 1,641 | 2,724 | (155) | 5,573 |
|  | Income\ttax\t(provision)\tbenefit | (516) | (598) | (1,892) | 58 | (2,948) |
|  | Results\tof\tcontinuing\toperations | $847 | $1,043 | $832 | $(97) | $ 2,625 |
| 2007 | Revenues\tand\tother\tincome: |  |  |  |  |  |
|  | Sales^(a) | $2,110 | $1,198 | $1,380 | $– | $ 4,688 |
|  | Transfers | 299 | 60 | 1,031 | – | 1,390 |
|  | Other\tincome^(b) | 3 | – | 2 | 7 | 12 |
|  | Total\trevenues | 2,412 | 1,258 | 2,413 | 7 | 6,090 |
| Expenses: | Expenses: |  |  |  |  |  |
|  | Production\tcosts | (550) | (234) | (164) | – | (948) |
|  | Transportation\tcosts | (122) | (39) | (28) | – | (189) |
|  | Exploration\texpenses | (274) | (23) | (118) | (37) | (452) |
|  | Depreciation,\tdepletion\tand\tamortization | (486) | (278) | (130) | – | (894) |
|  | Administrative\texpenses | (56) | (11) | (6) | (34) | (107) |
|  | Total\texpenses | (1,488) | (585) | (446) | (71) | (2,590) |
|  | (c) |  |  |  |  |  |
|  | Other\tproduction-related\tincome | – | 103 | 6 | – | 109 |
|  | Results\tbefore\tincome\ttaxes | 924 | 776 | 1,973 | (64) | 3,609 |
|  | Income\ttax\t(provision)\tbenefit | (343) | (377) | (1,368) | 24 | (2,064) |
|  | Results\tof\tcontinuing\toperations | $581 | $399 | $605 | $(40) | $ 1,545 |
|  | Results\tof\tdiscontinued\toperations | $– | $– | $– | $8 | $8 |
| 2006 | Revenues\tand\tother\tincome: |  |  |  |  |  |
|  | (a) |  |  |  |  |  |
|  | Sales | $2,329 | $1,240 | $1,300 | $– | $ 4,869 |
|  | Transfers | 307 | 58 | 1,168 | – | 1,533 |
|  | (b) |  |  |  |  |  |
|  | Other\tincome | 3 | – | – | 46 | 49 |
|  | Total\trevenues | 2,639 | 1,298 | 2,468 | 46 | 6,451 |
| Expenses: | Expenses: |  |  |  |  |  |
|  | Production\tcosts | (512) | (207) | (126) | – | (845) |
|  | Transportation\tcosts | (124) | (44) | (33) | – | (201) |
|  | Exploration\texpenses | (169) | (29) | (91) | (73) | (362) |
|  | Depreciation,\tdepletion\tand\tamortization | (458) | (281) | (127) | – | (866) |
|  | Administrative\texpenses | (41) | (10) | (6) | (36) | (93) |
|  | Total\texpenses | (1,304) | (571) | (383) | (109) | (2,367) |
|  | (c) |  |  |  |  |  |
|  | Other\tproduction-related\tincome | – | 73 | 1 | – | 74 |
|  | Results\tbefore\tincome\ttaxes | 1,335 | 800 | 2,086 | (63) | 4,158 |
|  | Income\ttax\t(provision)\tbenefit | (489) | (358) | (1,457) | 4 | (2,300) |
|  | Results\tof\tcontinuing\toperations | $846 | $442 | $629 | $(59) | $ 1,858 |
|  | Results\tof\tdiscontinued\toperations | $– | $– | $– | $273 | $273 |
| (a) |  |  |  |  |  |  |

(a) Excludes	noncash	effects	of	changes	in	the	fair	value	of	certain	natural	gas	sales	contracts	in	the	United	Kingdom. (b) Includes	net	gain	on	disposal	of	assets.

(c) Includes	revenues,	net	of	associated	costs,	from	activities	that	are	an	integral	part	of	our	production	operations	which	may	include	processing	or	transportation	of	third-party	production,	the	purchase	and subsequent	resale	of	natural	gas	utilized	for	reservoir	management	and	providing	storage	capacity.

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

| (In	millions) | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Results\tof\tcontinuing\toperations | $2,625 | $1,545 | $1,858 |
| Items\tnot\tincluded\tin\tresults\tof\tcontinuing\toil\tand\tgas\toperations,\tnet\tof\ttax: |  |  |  |
| Marketing\tincome\tand\ttechnology\tcosts | 58 | 36 | 40 |
| Income\tfrom\tequity\tmethod\tinvestments | 201 | 154 | 135 |
| Other | (6) | (6) | 1 |
| Items\tnot\tallocated\tto\tE&amp;P\tsegment\tincome: |  |  |  |
| Gain\ton\tasset\tdisposition | (163) | – | (31) |
| E&amp;P\tsegment\tincome | $2,715 | $1,729 | $2,003 |

# Average	Production	Costs	^(a)

|  | United |  |  | Continuing |
| :--- | :--- | :--- | :--- | :--- |
| (Per\tbarrel\tof\toil\tequivalent) | States | Europe | Africa | Operations |
| 2008 | $13.71 | $10.56 | $ 2.56 | $8.42 |
| 2007 | \t 10.46 | 10.41 | 3.26 | 7.56 |
| 2006 | 8.51 | 8.36 | 2.78 | 6.48 |
| (a) |  |  |  |  |

(a) Computed	using	production	costs,	which	excludes	transportation	costs,	as	disclosed	in	the	Results	of	Operations	for	Oil	and	Gas	Producing	Activities	and	as	defined	by	the	Securities	and	Exchange	Commission. Natural	gas	volumes	were	converted	to	barrels	of	oil	equivalent	using	a	conversion	factor	of	six	mcf	of	natural	gas	to	one	barrel	of	oil.

# Average	Realizations

|  | United<br>States | Europe | Africa | Continuing<br>Operations | Disc<br>Ops |
| :--- | :--- | :--- | :--- | :--- | :--- |
| (Excluding\tderivative\tgains\tand\tlosses) |  |  |  |  |  |
| Liquid\thydrocarbons\t(per\tbbl)\n2008 | $86.68 | $90.60 | $90.29 | $89.29 | $– |
| Natural\tgas\t(per\tmcf)(a)(b) | 7.01 | 8.20 | 0.25 | 4.67 | – |
| Liquid\thydrocarbons\t(per\tbbl)\n2007 | $60.15 | $70.31 | $66.09 | $64.86 | $– |
| Natural\tgas\t(per\tmcf)(a)(b) | 5.73 | 6.55 | 0.25 | 4.44 | – |
| Liquid\thydrocarbons\t(per\tbbl)\n2006 | $54.41 | $64.02 | $59.83 | $58.63 | $38.38 |
| Natural\tgas\t(per\tmcf)(a)(b) | 5.76 | 6.78 | 0.27 | 5.52 | – |
| (a) |  |  |  |  |  |

(b) The	Africa	realizations	primarily	represent	fixed	prices	under	long-term	contracts	with	Alba	Plants	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.

# Estimated	Quantities	of	Proved	Oil	and	Gas	Reserves

Estimates	of	proved	reserves	have	been	prepared	by	in-house	teams	of	reservoir	engineers	and	geoscience	professionals.	Reserve	estimates	are	periodically reviewed	by	our	Corporate	Reserves	Group	to	assure	that	rigorous	professional	standards	and	the	reserves	definitions	prescribed	by	the	U.S.	Securities	and	Exchange Commission	("SEC")	are	consistently	applied	throughout	the	Company.

Proved	reserves	are	the	estimated	quantities	of	oil	and	natural	gas	that	geologic	and	engineering	data	demonstrate	with	reasonable	certainty	to	be	recoverable	in future	years	from	known	reservoirs	under	existing	economic	and	operating	conditions.	Estimates	of	proved	reserves	may	change,	either	positively	or	negatively,	as additional	information	becomes	available	and	as	contractual,	economic	and	political	conditions	change.

Our	net	proved	reserve	estimates	have	been	adjusted	as	necessary	to	reflect	all	contractual	agreements,	royalty	obligations	and	interests	owned	by	others	at	the	time of	the	estimate.	Only	reserves	that	are	estimated	to	be	recovered	during	the	term	of	the	current	contract	have	been	included	in	the	proved	reserve	estimate	unless	there	is a	clear	and	consistent	history	of	contract	extension.	Reserves	from	properties	governed	by	production	sharing	contracts	have	been	calculated	using	the	"economic interest"	method	prescribed	by	the	SEC.	Reserves	that	are	not	currently	considered	proved,	such	as	those	that	may	result	from	extensions	of	currently	proved	areas	or that	may	result	from	applying	secondary	or	tertiary	recovery	processes	not	yet	tested	and	determined	to	be	economic	are	excluded.	Purchased	natural	gas	utilized	in reservoir	management	and	subsequently	resold	is	also	excluded.	We	do	not	have	any	quantities	of	oil	and	gas	reserves	subject	to	long-term	supply	agreements	with foreign	governments	or	authorities	in	which	we	act	as	producer.

Proved	developed	reserves	are	the	quantities	of	oil	and	gas	expected	to	be	recovered	through	existing	wells	with	existing	equipment	and	operating	methods.	In some	cases,	proved	undeveloped	reserves	may	require	substantial	new	investments	in	additional	wells	and	related	facilities.

|  | United |  |  | Continuing |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| (Millions\tof\tbarrels) | States | Europe | Africa(a) | Operations | Disc\tOps |
| Liquid\tHydrocarbons |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2006 | 189 | 98 | 373 | 660 | 44 |
| Purchase\tof\treserves\tin\tplace | – | – | 1 | 1 | – |
| Revisions\tof\tprevious\testimates | 2 | 8 | 49 | 59 | 1 |
| Improved\trecovery | 3 | – | – | 3 | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 6 | 15 | 15 | 36 | 4 |
| Production(b) | (28) | (13) | (41) | (82) | (4) |
| Sales\tof\treserves\tin\tplace | – | – | – | – | (45) |
| End\tof\tyear\t–\t2006 | 172 | 108 | 397 | 677 | – |
| Purchase\tof\treserves\tin\tplace | 2 | – | – | 2 | – |
| Revisions\tof\tprevious\testimates | 2 | 7 | (8) | 1 | – |
| Improved\trecovery | 8 | – | – | 8 | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 5 | 13 | 16 | 34 | – |
| Production(b) | (23) | (13) | (36) | (72) | – |
| End\tof\tyear\t–\t2007 | 166 | 115 | 369 | 650 | – |
| Revisions\tof\tprevious\testimates | 3 | (1) | 8 | 10 | – |
| Improved\trecovery | 1 | – | – | 1 | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 31 | 11 | 11 | 53 | – |
| Production(b) | (23) | (20) | (34) | (77) | – |
| Sales\tof\treserves\tin\tplace | – | (1) | – | (1) | – |
| End\tof\tyear\t–\t2008 | 178 | 104 | 354 | 636 | – |

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

|  | United |  |  | Continuing |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
| (Billions\tof\tcubic\tfeet) | States | Europe | Africa(a) | Operations | Disc\tOps |
| Natural\tGas |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2006 | 1,209 | 486 | 1,852 | 3,547 | – |
| Purchase\tof\treserves\tin\tplace | – | 4 | 8 | 12 | – |
| Revisions\tof\tprevious\testimates | (5) | 4 | 139 | 138 | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 59 | 20 | 24 | 103 | – |
| Production(b) | (194) | (70) | (26) | (290) | \t\t\t\t\t\t\t\t– |
| End\tof\tyear\t–\t2006 | 1,069 | 444 | 1,997 | 3,510 | – |
| Purchase\tof\treserves\tin\tplace | 1 | – | – | 1 | – |
| Revisions\tof\tprevious\testimates | (36) | (5) | 60 | 19 | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 148 | 4 | 88 | 240 | – |
| Production(b) | (174) | (61) | (84) | (319) | – |
| Sales\tof\treserves\tin\tplace | (1) | – | – | (1) | – |
| End\tof\tyear\t–\t2007 | 1,007 | 382 | 2,061 | 3,450 | – |
| Revisions\tof\tprevious\testimates | 79 | (51) | 49 | 77 | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 165 | 30 | – | 195 | – |
| Production(b) | (164) | (60) | (135) | (359) | – |
| Sales\tof\treserves\tin\tplace | (2) | (10) | – | (12) | – |
| End\tof\tyear\t–\t2008 | 1,085 | 291 | 1,975 | 3,351 | – |
| Proved\tdeveloped\treserves: |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2006 | 943 | 326 | 638 | 1,907 | – |
| End\tof\tyear\t–\t2006 | 857 | 238 | 648 | 1,743 | – |
| End\tof\tyear\t–\t2007 | 761 | 173 | 1,515 | 2,449 | – |
| End\tof\tyear\t–\t2008 | 839 | 129 | 1,382 | 2,350 | – |
| (a) |  |  |  |  |  |

# Information	on	Proved	Bitumen	Reserves	Not	Included	Above

In	addition	to	the	liquid	hydrocarbon	and	natural	gas	proved	reserves	above,	we	have	interests	in	proved	bitumen	reserves	in	Canada	associated	with	the	AOSP. Under	SEC	regulations,	these	reserves	are	considered	mining-related	and	not	part	of	oil	and	gas	reserves,	and	therefore	are	not	included	in	our	tabular	presentation	of	oil and	gas	reserves.	The	bitumen	reserves	are	also	not	included	in	the	standardized	measure	of	discounted	future	net	cash	flows	relating	to	proved	oil	and	gas	reserves	on the	following	page.

# Standardized	Measure	of	Discounted	Future	Net	Cash	Flows	and	Changes	Therein	Relating	to	Proved	Oil	and	Gas	Reserves

Future	cash	inflows	are	computed	by	applying	year-end	prices	of	oil	and	natural	gas	relating	to	our	proved	reserves	to	the	year-end	quantities	of	those	reserves. Future	price	changes	are	considered	only	to	the	extent	provided	by	contractual	arrangements	in	existence	at	year-end.

The	assumptions	used	to	compute	the	proved	reserve	valuation	do	not	necessarily	reflect	our	expectations	of	actual	revenues	to	be	derived	from	those	reserves	or their	present	worth.	Assigning	monetary	values	to	the	estimated	quantities	of	reserves,	described	on	the	preceding	page,	does	not	reduce	the	subjective	and	ever- changing	nature	of	such	reserve	estimates.

Additional	subjectivity	occurs	when	determining	present	values	because	the	rate	of	producing	the	reserves	must	be	estimated.	In	addition	to	uncertainties	inherent in	predicting	the	future,	variations	from	the	expected	production	rate	also	could	result	directly	or	indirectly	from	factors	outside	of	our	control,	such	as	unintentional delays	in	development,	environmental	concerns,	changes	in	prices	or	regulatory	controls.

The	reserve	valuation	assumes	that	all	reserves	will	be	disposed	of	by	production.	However,	if	reserves	are	sold	in	place	or	subjected	to	participation	by	foreign governments,	additional	economic	considerations	could	also	affect	the	amount	of	cash	eventually	realized.

Future	production,	transportation	and	administrative	costs	and	development	costs	are	computed	by	estimating	the	expenditures	to	be	incurred	in	developing	and producing	the	proved	oil	and	gas	reserves	at	the	end	of	the	year,	based	on	year-end	costs	and	assuming	continuation	of	existing	economic	conditions.

Future	income	tax	expenses	are	computed	by	applying	the	appropriate	year-end	statutory	tax	rates,	with	consideration	of	future	tax	rates	already	legislated,	to	the future	pretax	net	cash	flows	relating	to	our	proved	oil	and	gas	reserves.	Oil	and	gas	related	tax	credits	and	allowances	are	recognized.

Discount	was	derived	by	using	a	discount	rate	of	10	percent	annually.

|  | United |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | States | Europe | Africa | Total |
| 2008 |  |  |  |  |
| Future\tcash\tinflows | $11,295 | $6,802 | $13,044 | $31,141 |
| Future\tproduction,\ttransportation\tand\tadministrative\tcosts | (6,045) | (2,386) | (2,294) | (10,725) |
| Future\tdevelopment\tcosts | (2,673) | (2,101) | (638) | (5,412) |
| Future\tincome\ttax\texpenses | (443) | (192) | (7,871) | (8,506) |
| Future\tnet\tcash\tflows | $2,134 | $2,123 | $2,241 | $6,498 |
| 10\tpercent\tannual\tdiscount\tfor\testimated\ttiming\tof\tcash\tflows | (703) | (191) | (1,000) | (1,894) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tproved\toil\tand\tgas\treserves | $1,431 | $1,932 | $1,241 | $4,604 |
| 2007 |  |  |  |  |
| Future\tcash\tinflows | $19,432 | $14,795 | $32,312 | $66,539 |
| Future\tproduction,\ttransportation\tand\tadministrative\tcosts | (5,769) | (3,358) | (2,199) | (11,326) |
| Future\tdevelopment\tcosts | (1,299) | (2,397) | (705) | (4,401) |
| Future\tincome\ttax\texpenses | (4,047) | (3,961) | (22,378) | (30,386) |
| Future\tnet\tcash\tflows | $8,317 | $5,079 | $7,030 | $20,426 |
| 10\tpercent\tannual\tdiscount\tfor\testimated\ttiming\tof\tcash\tflows | (3,297) | (777) | (2,857) | (6,931) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tproved\toil\tand\tgas\treserves | $5,020 | $4,302 | $4,173 | $13,495 |
| 2006 |  |  |  |  |
| Future\tcash\tinflows | $13,435 | $8,713 | $22,799 | $44,947 |
| Future\tproduction,\ttransportation\tand\tadministrative\tcosts | (5,512) | (2,564) | (1,877) | (9,953) |
| Future\tdevelopment\tcosts | (762) | (1,781) | (495) | (3,038) |
| Future\tincome\ttax\texpenses | (2,217) | (1,709) | (14,847) | (18,773) |
| Future\tnet\tcash\tflows | $4,944 | $2,659 | $5,580 | $13,183 |
| 10\tpercent\tannual\tdiscount\tfor\testimated\ttiming\tof\tcash\tflows | (1,818) | (408) | (2,439) | (4,665) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tproved\toil\tand\tgas\treserves | $3,126 | $2,251 | $3,141 | $8,518 |

# Summary	of	Changes	in	Standardized	Measure	of	Discounted	Future	Net	Cash	Flows	Relating	to	Proved	Oil	and	Gas	Reserves

| (In	millions) | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Sales\tand\ttransfers\tof\toil\tand\tgas\tproduced,\tnet\tof\tproduction,\ttransportation\tand\tadministrative\tcosts | $(7,141) | $(4,887) | $(5,312) |
| Net\tchanges\tin\tprices\tand\tproduction,\ttransportation\tand\tadministrative\tcosts\trelated\tto\tfuture\tproduction | (18,290) | \t 12,845 | (1,342) |
| Extensions,\tdiscoveries\tand\timproved\trecovery,\tless\trelated\tcosts | 663 | 1,816 | 1,290 |
| Development\tcosts\tincurred\tduring\tthe\tperiod | 1,916 | 1,654 | 1,251 |
| Changes\tin\testimated\tfuture\tdevelopment\tcosts | (1,584) | (1,727) | (527) |
| Revisions\tof\tprevious\tquantity\testimates | 53 | 290 | 1,319 |
| Net\tchanges\tin\tpurchases\tand\tsales\tof\tminerals\tin\tplace | (13) | 23 | 30 |
| Accretion\tof\tdiscount | 2,796 | 1,726 | 1,882 |
| Net\tchange\tin\tincome\ttaxes | 12,805 | (6,751) | (660) |
| Timing\tand\tother | (96) | (12) | (14) |
| Net\tchange\tfor\tthe\tyear | (8,891) | 4,977 | (2,083) |
| Beginning\tof\tthe\tyear | 13,495 | 8,518 | \t 10,601 |
| End\tof\tyear | $4,604 | $13,495 | $8,518 |
| Net\tchange\tfor\tthe\tyear\tfrom\tdiscontinued\toperations | $– | $– | $(216) |

# Supplemental	Statistics	(Unaudited)

| (In	millions,	except	as	noted) | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Segment\tIncome\t(Loss) |  |  |  |
| Exploration\tand\tProduction |  |  |  |
| United\tStates | $869 | $623 | $873 |
| International | 1,846 | \t 1,106 | \t 1,130 |
| E&amp;P\tsegment | 2,715 | \t 1,729 | \t 2,003 |
| Oil\tSands\tMining | 258 | (63) | — |
| Refining,\tMarketing\tand\tTransportation | 1,179 | \t 2,077 | \t 2,795 |
| Integrated\tGas | 302 | 132 | 16 |
| Segment\tincome | 4,454 | \t 3,875 | \t 4,814 |
| Items\tnot\tallocated\tto\tsegments,\tnet\tof\tincome\ttaxes: |  |  |  |
| Corporate\tand\tother\tunallocated\titems | (93) | (122) | (190) |
| Gain\t(loss)\ton\tU.K.\tnatural\tgas\tcontracts | 111 | (118) | 232 |
| Foreign\tcurrency\tgain\t(loss)\ton\tincome\ttaxes | 252 | 18 | (22) |
| Impairments | (1,437) | — | — |
| Gain\ton\tdispositions | 241 | 8 | 274 |
| Gain\ton\tforeign\tcurrency\tderivative\tinstruments | — | 112 | — |
| Deferred\tincome\ttaxes\t–\ttax\tlegislation | — | 193 | 21 |
| –\tother\tadjustments(a) | — | — | 93 |
| Loss\ton\tearly\textinguishment\tof\tdebt | — | (10) | (22) |
| Discontinued\toperations | — | — | 34 |
| Net\tincome | $3,528 | $3,956 | $5,234 |
| Capital\tExpenditures |  |  |  |
| Exploration\tand\tProduction | $3,113 | $2,511 | $2,169 |
| Oil\tSands\tMining | 1,038 | 165 | — |
| Refining,\tMarketing\tand\tTransportation | 2,954 | \t 1,640 | 916 |
| Integrated\tGas(b) | 4 | 93 | 307 |
| Discontinued\tOperations | — | — | 45 |
| Corporate | 37 | 57 | 41 |
| Total | $7,146 | $4,466 | $3,478 |
| Exploration\tExpenses |  |  |  |
| United\tStates | $238 | $274 | $169 |
| International | 252 | 180 | 196 |
| Total | $490 | $454 | $365 |
| (a) |  |  |  |

(a) Other	deferred	tax	adjustments	in	2006	represent	a	benefit	recorded	for	cumulative	income	tax	basis	differences	associated	with	prior	periods. (b) Through	April	2007,	includes	EGHoldings	at	100	percent.	Effective	May	1,	2007,	we	no	longer	consolidate	EGHoldings	and	our	investment	in	EGHoldings	is	accounted	for	prospectively	using	the	equity	method of	accounting;	therefore,	EGHoldings'	capital	expenditures	subsequent	to	April	2007	are	not	included	in	our	capital	expenditures.

| (In	millions,	except	as	noted) | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| E&amp;P\tOperating\tStatistics |  |  |  |
| Net\tLiquid\tHydrocarbon\tSales\t(mbpd)(c) |  |  |  |
| United\tStates | 63 | 64 | 76 |
| Europe | 55 | 33 | 35 |
| Africa | 93 | 100 | 112 |
| Total\tInternational | 148 | 133 | 147 |
| Worldwide\tContinuing\tOperations | 211 | 197 | 223 |
| Discontinued\tOperations | – | – | 12 |
| Worldwide | 211 | 197 | 235 |
| Natural\tgas\tliquids\tincluded\tin\tabove | 20 | 22 | 23 |
| Natural\tGas\tSales\t(mmcfd)(c)(d) |  |  |  |
| United\tStates | 448 | 477 | 532 |
| Europe | 198 | 216 | 243 |
| Africa | 370 | 232 | 72 |
| Total\tInternational | 568 | 448 | 315 |
| Worldwide | \t 1,016 | 925 | 847 |
| Total\tWorldwide\tSales\t(mboepd) |  |  |  |
| Continuing\tOperations | 381 | 351 | 365 |
| Discontinued\tOperations | – | – | 12 |
| Worldwide | 381 | 351 | 377 |
| Average\tRealizations(e) |  |  |  |
| Liquid\tHydrocarbons\t(per\tbbl) |  |  |  |
| United\tStates | $86.68 | $60.15 | $54.41 |
| Europe | \t 90.60 | \t 70.31 | \t 64.02 |
| Africa | \t 90.29 | \t 66.09 | \t 59.83 |
| Total\tInternational | \t 90.40 | \t 67.15 | \t 60.81 |
| Worldwide\tContinuing\tOperations | \t 89.29 | \t 64.86 | \t 58.63 |
| Discontinued\tOperations | – | – | \t 38.38 |
| Worldwide | $89.29 | $64.86 | $57.58 |
| Natural\tGas\t(per\tmcf) |  |  |  |
| United\tStates | $7.01 | $5.73 | $5.76 |
| Europe | 8.03 | 6.53 | 6.74 |
| Africa(f) | 0.25 | 0.25 | 0.27 |
| Total\tInternational | 2.97 | 3.28 | 5.27 |
| Worldwide | $4.75 | $4.54 | $5.58 |
| Net\tProved\tReserves\tat\tyear-end\t(developed\tand\tundeveloped) |  |  |  |
| Liquid\tHydrocarbons\t(mmbbl) |  |  |  |
| United\tStates | 178 | 166 | 172 |
| International | 458 | 484 | 505 |
| Total | 636 | 650 | 677 |
| Developed\treserves\tas\ta\tpercentage\tof\ttotal\tnet\treserves | 81% | 72% | 84% |
| Natural\tGas\t(bcf) |  |  |  |
| United\tStates | \t 1,085 | \t 1,007 | \t 1,069 |
| International | \t 2,266 | \t 2,443 | \t 2,441 |
| Total | \t 3,351 | \t 3,450 | \t 3,510 |
| Developed\treserves\tas\ta\tpercentage\tof\ttotal\tnet\treserves | 70% | 71% | 50% |
| (c) |  |  |  |

(c) Amounts	represent	net	sales	after	royalties,	except	for	Ireland	where	amounts	are	before	royalties.

(d) Includes	natural	gas	acquired	for	injection	and	subsequent	resale	of	32	mmcfd,	47	mmcfd	and	46	mmcfd	for	the	years	2008,	2007	and	2006.

(e) Excludes	gains	and	losses	on	derivative	instruments	and	the	unrealized	effects	U.K.	natural	gas	contracts	that	are	accounted	for	as	derivatives. (f) 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.

| (In	millions,	except	as	noted) | 2008 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| OSM\tOperating\tStatistics(g) |  |  |  |
| Net\tBitumen\tProduction\t(mbpd)(h) | 25 | 4 | – |
| Net\tSynthetic\tCrude\tSales\t(mbpd)(h) | 32 | 4 | – |
| Synthetic\tCrude\tAverage\tRealization\t(per\tbbl)(i) | $91.90 | $71.07 | $– |
| Net\tProved\tBitumen\tReserves\tat\tyear-end\t(mmbbl) | 388 | 421 | – |
| RM&amp;T\tOperating\tStatistics |  |  |  |
| Refinery\tRuns\t(mbpd) |  |  |  |
| Crude\toil\trefined | 944 | 1,010 | 980 |
| Other\tcharge\tand\tblend\tstocks | 207 | 214 | 234 |
| Total | 1,151 | 1,224 | 1,214 |
| Refined\tProduct\tYields\t(mbpd) |  |  |  |
| Gasoline | 609 | 646 | 661 |
| Distillates | 342 | 349 | 323 |
| Propane | 22 | 23 | 23 |
| Feedstocks\tand\tspecial\tproducts | 96 | 108 | 107 |
| Heavy\tfuel\toil | 24 | 27 | 26 |
| Asphalt | 75 | 86 | 89 |
| Total | 1,168 | 1,239 | 1,229 |
| Refined\tProducts\tSales\tVolumes\t(mbpd)(j) | 1,352 | 1,410 | 1,425 |
| Matching\tbuy/sell\tvolumes\tincluded\tabove | – | – | 24 |
| Refining\tand\tWholesale\tMarketing\tGross |  |  |  |
| Margin\t(per\tgallon)\t(k) | $0.1166 | $0.1848 | $0.2288 |
| Speedway\tSuperAmerica |  |  |  |
| Retail\toutlets | 1,617 | 1,636 | 1,636 |
| Gasoline\tand\tdistillate\tsales\t(millions\tof\tgallons) | 3,215 | 3,356 | 3,301 |
| Gasoline\tand\tdistillate\tgross\tmargin\t(per\tgallon) | $0.1387 | $0.1119 | $0.1156 |
| Merchandise\tsales | $2,838 | $2,796 | $2,706 |
| Merchandise\tgross\tmargin | $716 | $705 | $667 |
| IG\tOperating\tStatistics |  |  |  |
| Net\tSales\t(mtpd)(l) |  |  |  |
| LNG | 6,285 | 3,310 | 1,026 |
| Methanol | 975 | 1,308 | 905 |
| (g) |  |  |  |

(g) The	oil	sands	mining	operations	were	acquired	October	18,	2007.	Daily	volumes	reported	in	2007	represent	activity	after	the	acquisition	date	over	by	the	total	number	of	days	in	the	period. (h) Amounts	are	before	royalties.

(i) Excludes	gains	and	losses	on	derivative	instruments. (j) Total	average	daily	volumes	of	all	refined	product	sales	to	wholesale,	branded	and	retail	(SSA)	customers.

(k) Sales	revenue	less	cost	of	refinery	inputs,	purchased	products	and	manufacturing	expenses,	including	depreciation. (l) Includes	both	consolidated	sales	volumes	and	our	share	of	the	sales	volumes	of	equity	method	investees.	LNG	sales	from	Alaska	are	conducted	through	a	consolidated	subsidiary.	LNG	and	methanol	sales	from Equatorial	Guinea	are	conducted	through	equity	method	investees.

# 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	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	2008,	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	2009	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	2009	Annual	Meeting	of	Stockholders.

We	have	adopted	a	Code	of	Ethics	for	Senior	Financial	Officers.	It	is	available	on	our	website	at

http://www.marathon.com/Investor_Center/Corporate_Governance/Code_of_Ethics_for_Senior_Financial_Officers/.

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

# Section	16(a)	Beneficial	Ownership	Reporting	Compliance

Section	16(a)	of	the	Securities	Exchange	Act	of	1934,	as	amended,	requires	that	our	directors	and	executive	officers,	and	persons	who	own	more	than	ten	percent	of a	registered	class	of	our	equity	securities,	file	reports	of	beneficial	ownership	on	Form	3	and	changes	in	beneficial	ownership	on	Form	4	or	Form	5	with	the	SEC.	Based solely	on	our	review	of	the	reporting	forms	and	written	representations	provided	to	us	by	the	individuals	required	to	file	reports,	we	believe	that	each	of	our	executive officers	and	directors	has	complied	with	the	applicable	reporting	requirements	for	transactions	in	our	securities	during	the	fiscal	year	ended	December	31,	2008.

# 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	2009	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	2009	Annual	Meeting	of	stockholders.

# Securities	Authorized	for	Issuance	Under	Equity	Compensation	Plans

The	following	table	provides	information	as	of	December	31,	2008	with	respect	to	shares	of	Marathon	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.

|  | Column	(a) | Column	(b) | Column	(c) |
| :--- | :--- | :--- | :--- |
|  | Number\tof |  | Number\tof |
|  | securities | Weighted- | securities |
|  | to\tbe\tissued | average | remaining |
|  | upon | exercise | available\tfor |
|  | exercise\tof | price\tof | future |
|  | outstanding | outstanding | issuance |
|  | options, | options, | under\tequity |
|  | warrants | warrants | compensation |
| Plan\tcategory | and\trights | and\trights(c) | plans(d) |
| Equity\tcompensation\tplans\tapproved\tby\tstockholders | 13,010,970(a) | $37.59 | 26,716,689(e) |
| Equity\tcompensation\tplans\tnot\tapproved\tby\tstockholders | 94,133(b) | N/A | – |
| Total | 13,105,103 | N/A | 26,716,689 |
| Includes\tthe\tfollowing:\n(a) |  |  |  |

(a) Includes	the	following:

•6,664,809	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	common	stock	on	December	31,	2008,	of	$27.36	per	share;

•492,780	stock	options	outstanding	under	the	1990	Stock	Plan;

•178,457	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	30,399	and	148,058;

•213,670	restricted	stock	units	granted	to	non-officers	under	the	2007	Plan	and	outstanding	as	of	December	31,	2008;	and

•27,654	restricted	stock	units	granted	to	non-officers	under	the	2003	Plan	and	outstanding	as	of	December	31,	2008.

In	addition	to	the	awards	reported	above,	1,536,829	shares	and	271,102	shares	of	restricted	stock	were	issued	and	outstanding	as	of	December	31,	2008,	but	subject	to	forfeiture	restrictions	under	the	2007	Plan	and the	2003	Plan.

(b) Reflects	awards	of	common	stock	units	made	to	non-employee	directors	under	the	Deferred	Compensation	Plan	for	Non-Employee	Directors	prior	to	April	30,	2003.	When	a	non-employee	director	leaves	the Board,	he	or	she	will	be	issued	actual	shares	of	Marathon	common	stock	in	place	of	the	common	stock	units. (c) Weighted-average	exercise	prices	do	not	take	the	restricted	stock	units	or	common	stock	units	into	account	as	these	awards	have	no	exercise	price. (d) Excludes	securities	reflected	in	column	(a).

(e) Reflects	the	shares	available	for	issuance	under	the	2007	Plan.	No	more	than	10,150,289	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.

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	of	our	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	Marathon	common	stock	on	that	date.	The	ongoing	value	of	each	common	stock	unit	equals	the	market	price	of	a share	of	Marathon	common	stock.	When	the	non-employee	director	leaves	the	Board,	he	or	she	is	issued	actual	shares	of	Marathon	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 2009	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	2009	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	Company	LLC.

2.7++ Amended	and	Restated	Arrangement	Agreement	among	Marathon	Oil	Corporation,	1339971	Alberta	Ltd.,	Western	Oil	Sands	Inc.	and WesternZagros	Resources	Inc.,	dated	as	of	September	14,	2007	(incorporated	by	reference	to	Exhibit	2.7	to	the	Registration	Statement	on Form	S-3ASR	(File	No.	333-146772)	of	Marathon	Oil	Corporation	filed	on	October	17,	2007).

2.8++ Amending	Agreement	among	Marathon	Oil	Corporation,	1339971	Alberta	Ltd,	Western	Oil	Sands	Inc.	and	WesternZagros	Resources Inc.,	dated	as	of	October	15,	2007	(incorporated	by	reference	to	Exhibit	2.8	to	the	Registration	Statement	on	Form	S-3ASR	(File	No.	333- 146772)	of	Marathon	Oil	Corporation	filed	on	October	17,	2007).

4.6 Indenture	dated	February	26,	2002	between	Marathon	and	The	Bank	of	New	York	Trust	Company,	N.A.,	successor	in	interest	to JPMorgan	Chase	Bank	as	Trustee,	relating	to	senior	debt	securities	of	Marathon	(incorporated	by	reference	to	Exhibit	4.4	to	Marathon's Registration	Statement	on	Form	S-3	filed	with	the	SEC	on	July	26,	2007	(Reg.	No	333-144874)).

Pursuant	to	CFR	229.601(b)(4)(iii),	instruments	with	respect	to	long-term	debt	issues	have	been	omitted	where	the	amount	of	securities authorized	under	such	instruments	does	not	exceed	10%	of	the	total	consolidated	assets	of	Marathon.	Marathon	hereby	agrees	to	furnish	a copy	of	any	such	instrument	to	the	Commission	upon	its	request.

10.32* Executive	Tax,	Estate,	and	Financial	Planning	Program	(Amended	and	Restated	as	of	January	1,	2009).

++ Marathon	agrees	to	furnish	supplementally	a	copy	of	any	omitted	schedule	to	the	United	States	Securities	and	Exchange	Commission	upon	request.

# 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.

Michael	K.	Stewart

Vice	President,	Accounting	and	Controller

Pursuant	to	the	requirements	of	the	Securities	Exchange	Act	of	1934,	this	report	has	been	signed	below	by	the	following	persons	on	February	27,	2009	on	behalf	of the	registrant	and	in	the	capacities	indicated.

/S/				MICHAEL	K.	STEWART Michael	K.	Stewart

Executive	Vice	President	and	Chief	Financial	Officer



Question: what percentage of pipeline barrels handled consisted of crude oil trunk lines in 2007?
Calculation: barrels_crude_oil = 1451
barrels_total = 2500
percent_crude_oil = barrels_crude_oil / barrels_total
answer = percent_crude_oil * 100
Answer: 58.0%