# 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,	2007

Commission	file	number	1-5153

# Marathon	Oil	Corporation

(Exact	name	of	registrant	as	specified	in	its	charter)

Delaware

(State	of	Incorporation)

(Address	of	principal	executive	offices)

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

Title	of	Each	Class

Common	Stock,	par	value	$1.00

Name	of	Each	Exchange	on	Which	Registered

New	York	Stock	Exchange	and

Chicago	Stock	Exchange

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

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

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

Indicate	by	check	mark	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.			¨

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,	2007:	$40.740	billion.	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	708,970,468	shares	of	Marathon	Oil	Corporation	Common	Stock	outstanding	as	of	January	31,	2008.

# Documents	Incorporated	By	Reference:

Portions	of	the	registrant's	proxy	statement	relating	to	its	2008	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).

| Item	1. | Business | 2 |
| :--- | :--- | :--- |
| Item\t1A. | Risk\tFactors | 24 |
| Item\t1B. | Unresolved\tStaff\tComments | 30 |
| Item\t2. | Properties | 30 |
| Item\t3. | Legal\tProceedings | 31 |
| Item\t4. | Submission\tof\tMatters\tto\ta\tVote\tof\tSecurity\tHolders | 35 |
| PART\tII |  |  |
| Item\t5. | Market\tfor\tRegistrant's\tCommon\tEquity,\tRelated\tStockholder\tMatters\tand\tIssuer\tPurchases\tof\tEquity\tSecurities | 35 |
| Item\t6. | Selected\tFinancial\tData | 36 |
| Item\t7. | Management's\tDiscussion\tand\tAnalysis\tof\tFinancial\tCondition\tand\tResults\tof\tOperations | 37 |
| Item\t7A. | Quantitative\tand\tQualitative\tDisclosures\tabout\tMarket\tRisk | 62 |
| Item\t8. | Financial\tStatements\tand\tSupplementary\tData | F-1 |
| Item\t9. | Changes\tin\tand\tDisagreements\twith\tAccountants\ton\tAccounting\tand\tFinancial\tDisclosure | 66 |
| Item\t9A. | Controls\tand\tProcedures | 66 |
| Item\t9B. | Other\tInformation | 66 |
| PART\tIII |  |  |
| Item\t10. | Directors,\tExecutive\tOfficers\tand\tCorporate\tGovernance | 66 |
| Item\t11. | Executive\tCompensation | 67 |
| Item\t12. | Security\tOwnership\tof\tCertain\tBeneficial\tOwners\tand\tManagement\tand\tRelated\tStockholder\tMatters | 67 |
| Item\t13. | Certain\tRelationships\tand\tRelated\tTransactions,\tand\tDirector\tIndependence | 68 |
| Item\t14. | Principal\tAccounting\tFees\tand\tServices | 68 |
| PART\tIV |  |  |
| Item\t15. | Exhibits,\tFinancial\tStatement\tSchedules | 69 |
| SIGNATURES |  | 74 |

# 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	"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	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.

# Acquisition	of	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	billion. Western's	debt	was	$1.063	billion	at	closing.	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	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	9	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	11	countries.	Principal	exploration	activities	are	in	the	United	States,	Angola,	Norway	and Indonesia.	Principal	development	and	production	activities	are	in	the	United	States,	the	United	Kingdom,	Norway,	Ireland,	Equatorial	Guinea	and	Libya.

Our	2007	worldwide	net	liquid	hydrocarbon	sales	averaged	197	thousand	barrels	per	day	("mbpd").	Our	2007	worldwide	net	natural	gas	sales,	including	natural	gas acquired	for	injection	and	subsequent	resale,	averaged	925	million	cubic	feet	per	day	("mmcfd").	In	total,	our	2007	worldwide	net	sales	averaged	351	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.)	In	2008,	our	worldwide	net	liquid	hydrocarbon	and	natural	gas	sales	are	expected	to	average	380	to	420	mboepd, excluding	future	acquisitions	and	dispositions.

The	above	projections	of	2008	worldwide	net	liquid	hydrocarbon	and	natural	gas	sales	are	forward-looking	statements.	Some	factors	that	could	potentially	affect levels	of	sales	include	pricing,	supply	and	demand	for	petroleum	products,	the	amount	of	capital	available	for	exploration	and	development,	regulatory	constraints, timing	of	commencing	production	from	new	wells,	drilling	rig	availability,	inability	to	obtain	or	delay	in	obtaining	necessary	government	and	third-party	approvals	and permits,	unforeseen	hazards	such	as	weather	conditions,	acts	of	war	or	terrorist	acts	and	the	governmental	or	military	response,	and	other	geological,	operating	and economic	considerations.	These	factors	(among	others)	could	cause	actual	results	to	differ	materially	from	those	set	forth	in	the	forward-looking	statements.

# Exploration

In	the	United	States	during	2007,	we	drilled	59	gross	(39	net)	exploratory	wells	of	which	47	gross	(29	net)	wells	encountered	commercial	quantities	of hydrocarbons.	Of	these	47	wells,	none	were	temporarily	suspended	or	in	the	process	of	being	completed	at	year	end.	Internationally,	we	drilled	25	gross	(6	net) exploratory	wells	of	which	16	gross	(4	net)	wells	encountered	commercial	quantities	of	hydrocarbons.	Of	these	16	wells,	10	gross	(3	net)	wells	were	temporarily suspended	or	were	in	the	process	of	being	completed	at	December	31,	2007.

United	States	–	The	Gulf	of	Mexico	continues	to	be	a	core	area	for	us.	At	the	end	of	2007,	we	had	interests	in	71	blocks	in	the	Gulf	of	Mexico,	including	64	in	the deepwater	area.	In	October	2007,	we	were	the	high	bidder	on	27	blocks	offered	in	the	federal	Outer	Continental	Shelf	Lease	Sale	No.	205	conducted	by	the	U.S. Minerals	Management	Service	("MMS")	and	were	awarded	these	leases	in	early	2008.	Representing	a	total	net	investment	of	$222	million	for	us,	13	blocks	were	bid	100 percent	by	us,	and	the	remaining	14	blocks	were	bid	in	conjunction	with	partners.	Our	plans	call	for	initial	drilling	on	some	of	these	leases	in	2009	or	2010.	The	contract for	the	rig	has	an	initial	term	of	two	years	with	an	option	to	extend	for	an	additional	two	years.

In	2007,	we	drilled	the	Droshky	(previously	named	Troika	Deep)	deepwater	discovery	well.	This	well	and	two	appraisal	sidetrack	wells	are	located	on	Green Canyon	Block	244	in	the	Gulf	of	Mexico	and	we	are	in	the	process	of	drilling	additional	appraisal	wells.	We	have	secured	an	additional	year	of	drilling	rig	capacity	in 2009	for	development	drilling	in	anticipation	of	a	2008	project	sanction.	The	timing	of	initial	production	from	the	Droshky	discovery	will	be	dependent	upon	delivery	of key	equipment	and	regulatory	approvals,	but	could	be	as	early	as	2010.	We	hold	a	100	percent	working	interest	in	the	Drohsky	discovery.

In	late	2007,	drilling	of	an	appraisal	well	began	on	the	Stones	prospect	(Walker	Ridge	Block	508)	after	a	2005	discovery.	We	hold	a	30	percent	outside-operated interest	in	the	Stones	prospect.

In	2001,	a	successful	discovery	well	was	drilled	on	the	Ozona	prospect	(Garden	Banks	Block	515)	in	the	Gulf	of	Mexico	and,	in	2002,	two	sidetrack	wells	were drilled.	We	are	continuing	to	evaluate	options	to	develop	the	Ozona	prospect.	Commercial	terms	have	been	secured	for	the	tie-back	and	processing	of	Ozona	production and	we	have	been	actively	searching	for	a	rig	to	drill	the	development	well.	We	hold	a	68	percent	operated	interest	in	the	Ozona	prospect.

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	February 2008,	27	discoveries	on	these	blocks	have	been	announced,	including	eight	in	2007	and	one	in	early	2008.	These	discoveries	represent	four	potential	development	hubs. Four	discoveries	and	one	successful	appraisal	well	form	a	planned	development	area	in	the	northeastern	portion	of	Block	31.	Nine	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	our	first	potential	development	in	the eastern	area	of	that	block.

Norway	–	We	hold	interests	in	over	800,000	gross	acres	offshore	Norway	and	plan	to	continue	our	exploration	effort	there.	We	hold	a	28	percent	outside-operated interest	in	the	Gudrun	field,	located	120	miles	off	the	coast	of	Norway,	where	we	are	focused	on	subsurface	evaluation	and	assessing	development	concepts	after	a successful	appraisal	well	in	2006.	First	production	from	Gudrun	is	expected	in	2012.	In	2007,	we	also	continued	to	advance	exploration	opportunities	in	the	Alvheim area,	the	first	of	which	is	expected	to	be	drilled	in	2009.

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	will	begin	collecting	geophysical	data	in	the	first	quarter	of	2008.	We	expect	to	begin	exploratory	drilling	in	2009.

In	addition,	we	were	awarded	two	study	agreements	and	farmed	into	additional	study	agreements	in	Indonesia	in	2007	which	could	lead	to	the	acquisition	of	new leaseholds	at	a	future	lease	sale.

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	or	additional	LNG	markets	are	entered	that	require	increased	natural	gas	supply.

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	2007	included	the	drilling	of	eight	wells,	six	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.

United	Kingdom	–	During	2007,	we	acquired	a	45	percent	outside-operated	interest	in	three	exploratory	onshore	coal	bed	methane	licenses	in	the	United	Kingdom, representing	128,000	gross	acres.	Three	exploration	wells	have	been	drilled	on	two	of	the	licenses	and	additional	delineation	and	production	testing	is	planned	during 2008.	We	also	plan	to	participate	in	the	U.K.	Onshore	Licensing	Round	during	2008	to	secure	additional	acreage.

In	the	U.K.	portion	of	the	North	Sea,	Marathon	participated	in	a	discovery	in	Block	204/23	adjacent	to	the	Foinaven	field.	This	Foinaven	Southwest	discovery encountered	hydrocarbons	and	will	be	considered	for	a	potential	tieback	to	the	nearby	infrastructure.

Ukraine	–	In	2007,	we	signed	a	cooperation	agreement	with	a	Ukrainian	partner	to	carry	out	a	study	in	the	Dneiper-Donets	Basin	in	north	central	Ukraine.	The	joint study	will	be	conducted	over	three	years	on	an	area	of	joint	interest	covering	10,000	square	miles	and	could	lead	to	the	joint	exploration	for	hydrocarbons.

# Production	(including	development	activities)

United	States	–	Our	U.S.	operations	accounted	for	32	percent	of	our	2007	worldwide	net	liquid	hydrocarbon	sales	volumes	and	52	percent	of	our	worldwide	net natural	gas	sales	volumes.

During	2007,	our	net	sales	in	the	Gulf	of	Mexico	averaged	25	mbpd	of	liquid	hydrocarbons,	representing	39	percent	of	our	total	U.S.	net	liquid	hydrocarbon	sales, and	28	mmcfd	of	natural	gas,	representing	6	percent	of	our	total	U.S.	net	natural	gas	sales.	Net	liquid	hydrocarbon	and	natural	gas	sales	in	the	Gulf	of	Mexico	decreased from	the	prior	year,	mainly	due	to	normal	production	rate	declines.	At	year-end	2007,	we	held	interests	in	seven	producing	fields	and	eight	platforms	in	the	Gulf	of Mexico,	of	which	we	operate	four	platforms.

The	majority	of	our	sales	volumes	in	the	Gulf	of	Mexico	come	from	the	Petronius	development	in	Viosca	Knoll	Blocks	786	and	830.	We	own	a	50	percent	outside- operated	working	interest	in	these	blocks.	The	Petronius	platform	provides	processing	and	transportation	services	to	adjacent	third-party	fields.	For	example,	Petronius processes	the	production	from	our	Perseus	field	which	commenced	production	in	April	2005	and	is	located	five	miles	from	the	platform.

We	hold	a	30	percent	outside-operated	working	interest	in	the	Neptune	deepwater	development	on	Atwater	Valley	Blocks	573,	574,	575,	617	and	618	in	the	Gulf	of Mexico,	120	miles	off	the	coast	of	Louisiana.	The	development	plan	for	Neptune	was	sanctioned	in	2005	and	includes	seven	subsea	wells	tied	back	to	a	stand-alone mini-tension	leg	platform.	Construction	of	the	platform	and	facility	continued	through	2007	with	first	production	expected	at	the	end	of	the	first	quarter	of	2008.

We	believe	that	we	are	one	of	the	largest	natural	gas	producers	in	the	Cook	Inlet	and	adjacent	Kenai	Peninsula	of	Alaska.	In	2007,	our	net	natural	gas	sales	from Alaska	averaged	142	mmcfd,	representing	30	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	20	mbpd	and	114	mmcfd	in	2007.	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	and	Powder	River	Basin	areas.	Development	of	the Powder	River	Basin	continued	in	2007	with	170	operated	wells	drilled,	which	was	up	from	the	119	wells	drilled	in	2006.	Additional	development	of	our	southwest Wyoming	interests	continued	in	2007	where	we	participated	in	the	drilling	of	30	wells.

We	also	have	domestic	natural	gas	operations	in	Oklahoma,	east	Texas	and	north	Louisiana,	with	combined	net	sales	of	148	mmcfd	in	2007,	and	liquid hydrocarbon	operations	in	the	Permian	Basin	of	southeast	New	Mexico	and	west	Texas,	with	net	sales	of	12	mbpd	in	2007.

We	hold	320,000	acres	in	the	Williston	Basin	(the	Bakken	shale	formation)	following	the	acquisition	of	an	additional	70,000	acres	in	late	2007.	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	with	approximately	350	locations	to be	drilled	over	the	next	four	to	five	years.	We	currently	have	six	operated	drilling	rigs	running	in	our	Bakken	shale	program	and	ended	2007	with	a	net	production	rate	of 2,600	barrels	of	oil	equivalent	per	day.

We	hold	a	natural	gas	leasehold	in	the	Piceance	Basin	of	Colorado,	located	in	Garfield	County	in	the	Greater	Grand	Valley	field	complex.	The	acreage	is	located near	adjacent	production.	Our	plans	include	drilling	approximately	700	wells	in	the	next	ten	years.	Drilling	and	production	commenced	in	late	2007.

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.	Our	share	of	liquid	hydrocarbon	sales	from	the	Brae	area	averaged	14	mbpd	in	2007.	Our	share	of	Brae natural	gas	sales	averaged	139	mmcfd,	or	31	percent	of	our	international	natural	gas	sales	volumes,	in	2007	and	decreased	from	the	prior	year	as	a	result	of	natural	field declines	in	the	North	and	East	Brae	natural	gas	condensate	fields.

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	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	an	approximate	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.	Our	share	of	sales from	the	Foinaven	fields	averaged	17	mbpd	of	liquid	hydrocarbons	and	9	mmcfd	of	natural	gas	in	2007.

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	eight	licenses.

We	are	the	operator	of	the	Alvheim	complex	located	on	the	Norwegian	Continental	Shelf.	This	development	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.	The	complex	consists	of	a	floating	production, storage	and	offloading	vessel	("FPSO")	with	subsea	infrastructure.	Produced	oil	will	be	transported	by	shuttle	tanker	and	produced	natural	gas	will	be	transported	to	the SAGE	system	using	a	new	14-inch,	24-mile	cross	border	pipeline.	The	multipurpose	shuttle	tanker	that	has	been	modified	to	serve	as	the	FPSO	sailed	from	the	shipyard in	mid-February	2008	to	undergo	testing,	after	which	it	will	proceed	offshore	for	connection	to	the	subsea	infrastructure.	The	Alvheim	development	will	initially	include ten	producing	wells	and	two	water	disposal	wells	in	the	drilling	program,	which	will	continue	through	the	fourth	quarter	of	2008.	The	nearby	Vilje	discovery,	in	which we	own	a	47	percent	outside-operated	working	interest,	will	also	be	produced	through	the	Alvheim	FPSO.	The	two	Vilje	development	wells	were	drilled	and	completed in	2007.	First	production	from	the	Alvheim/Vilje	development	is	expected	at	the	end	of	the	first	quarter	of	2008,	weather	permitting.

In	early	2007,	the	Norwegian	government	approved	a	plan	for	development	and	operation	to	develop	the	Volund	field	as	a	subsea	tie-back	to	the	Alvheim	FPSO. The	Volund	development	will	consist	of	one	production	well	and	one	water	disposal	well,	both	of	which	will	be	drilled	in	the	first	half	of	2009	with	an	additional	two wells	to	be	drilled	in	the	latter	part	of	2009.	The	produced	oil	will	be	exported	via	the	shuttle	tankers	discussed	above,	and	the	associated	natural	gas	will	be	exported	via the	Alvheim-to-SAGE	pipeline.	The	Volund	development,	in	which	we	own	a	65	percent	working	interest	and	serve	as	operator,	is	expected	to	begin	production	in	2009.

During	2007,	net	liquid	hydrocarbon	and	natural	gas	sales	in	Norway	from	the	Heimdal,	Vale	and	Skirne	fields	averaged	2	mbpd	and	29	mmcfd.	We	own	a	24 percent	outside-operated	working	interest	in	the	Heimdal	field,	a	47	percent	outside-operated	working	interest	in	the	Vale	field	and	a	20	percent	outside-operated working	interest	in	the	Skirne	field.

Ireland	–	We	own	a	100	percent	working	interest	in	the	Kinsale	Head,	Ballycotton	and	Southwest	Kinsale	natural	gas	fields	and	an	87	percent	operated	working interest	in	the	Seven	Heads	natural	gas	field	in	the	Celtic	Sea	offshore	Ireland.	Net	natural	gas	sales	in	Ireland	were	39	mmcfd	in	2007.	In	June	2006,	we	were	awarded the	first	commercial	natural	gas	storage	license	in	Ireland,	which	allows	us	to	provide	full	third-party	storage	services	from	the	Southwest	Kinsale	field.	The	unit	has	a total	working	volume	of	7	bcf	per	annum.	Both	indigenous

Kinsale	natural	gas	and	natural	gas	imported	from	a	transmission	system	are	injected	and	withdrawn	from	the	facility	under	contractual	arrangements	that	expire	in	April 2009.	Additionally,	natural	gas	produced	from	our	other	fields	or	purchased	from	other	parties	can	be	stored	at	Southwest	Kinsale	for	future	sale	to	customers.

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.	Two	wells	have	been	completed,	and	three	additional	wells	are	planned	to	be	completed	in	2008.	The main	20-inch	offshore	pipeline	installation	is	also	planned	for	2008.	Terminal	construction	is	underway.	The	operator	expects	first	production	from	the	field	in	the	fourth quarter	of	2009.

Equatorial	Guinea	–	We	own	a	63	percent	operated	working	interest	in	the	Alba	field	offshore	Equatorial	Guinea	and	a	52	percent	interest	in	an	onshore	liquefied petroleum	gas	("LPG")	processing	plant	held	through	an	equity	method	investee.	During	2007,	net	liquid	hydrocarbon	sales	averaged	45	mbpd,	or	34	percent	of	our international	liquid	hydrocarbon	sales	volumes,	and	net	natural	gas	sales	averaged	228	mmcfd,	or	51	percent	of	our	international	natural	gas	sales	volumes.	Net	liquid hydrocarbon	sales	volumes	in	2007	included	33	mbpd	of	condensate	and	12	mbpd	of	LPG.

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.	During	2007,	a	gross	130	mmcfd	of	dry	natural	gas	was supplied	to	the	methanol	plant	and	a	gross	268	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.

Libya	–	Net	liquid	hydrocarbon	sales	in	Libya	averaged	45	mbpd	in	2007	compared	to	54	mbpd	in	2006,	of	which	a	total	of	8	mbpd	were	owed	to	our	account	upon the	resumption	of	our	operations	in	Libya.	The	2007	net	liquid	hydrocarbon	sales	in	Libya	represented	34	percent	of	our	international	liquid	hydrocarbon	sales	volumes. Net	natural	gas	sales	in	Libya	averaged	4	mmcfd	in	2007.

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	10	mbpd	of	liquid	hydrocarbons	in	2007.	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

We	hold	an	interest	in	an	exploration	and	production	license	in	Sudan.	We	suspended	all	operations	in	Sudan	in	1985	due	to	civil	unrest.	We	have	had	no	employees in	the	country	and	have	derived	no	economic	benefit	from	those	interests	since	that	time.	The	U.S.	government	imposed	sanctions	against	Sudan	in	1997	and	we	have not	made	any	payments	related	to	Sudan	since	then.	We	have	abided	and	will	continue	to	abide	by	all	U.S.	sanctions	related	to	Sudan.	We	have	reached	an	agreement	to transfer	our	interest	in	this	license	to	the	operator.	Governmental	approval	of	this	transfer	is	expected	in	the	first	quarter	of	2008.

We	discovered	the	Ash	Shaer	and	Cherrife	natural	gas	fields	in	Syria	in	the	1980s.	We	have	recognized	no	revenues	in	any	period	from	activities	in	Syria	and	we impaired	our	entire	investment	in	Syria	in	1998.	In	2006,	the	Syrian	government	approved	the	assignment	of	90	percent	of	our	interest	in	the	Ash	Shaer	and	Cherrife natural	gas	fields	to	a	non-U.S.	company.	We	closed	the	transaction	on	November	1,	2006,	and	received	cash	proceeds	of	$46	million.	The	remaining	10	percent	interest was	assigned	to	the	same	company	on	December	21,	2007,	for	$5	million.

The	above	discussion	of	the	E&P	segment	includes	forward-looking	statements	with	respect	to	anticipated	future	exploratory	and	development	drilling,	the possibility	of	developing	the	Gudrun	field	offshore	Norway,	Blocks	31	and	32	offshore	Angola,	the	Foinaven	Southwest	discovery	in	the	U.K.	portion	of	the	North	Sea and	the	Equatorial	Guinea	discoveries,	the	possibility	of	obtaining	access	to	new	leaseholds	in	Indonesia	and	additional	coal	bed	methane	licenses	in	the	United Kingdom,	joint	exploration	for	hydrocarbons	in	the	Ukraine	and	the	timing	of	production	from	the	Droshky	discovery,	the	Gudrun	discovery,	the	Neptune	development, 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	obtain	or	delay	in obtaining	necessary	government	and	third-party	approvals	and	permits.	The	possible	developments	on	the	Gudrun	field,	Blocks	31	and	32	offshore	Angola,	the	Foinaven Southwest	discovery	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	joint	exploration	for	hydrocarbons	in	the	Ukraine	include	results	of	technical studies	and	continued	favorable	investment	climate.	The	above	discussion	of	the	E&P	segment	also	includes	forward-looking	statements	with	respect	to	our	intention	to exit	a	license	in	Sudan	which	could	be	potentially	impacted	by	a	delay	in	receiving	governmental	approval.	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,	2007,	our	net	proved	liquid	hydrocarbon	and	natural	gas	reserves	totaled	1.225	billion	boe,	of	which	42	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 | Undeveloped | Undeveloped | Undeveloped |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 |
| Liquid\tHydrocarbons\t(Millions\tof\tbarrels) |  |  |  |  |  |  |
| United\tStates | 135 | 150 | 165 | 166 | 172 | 189 |
| Europe | 32 | 35 | 39 | 115 | 108 | 98 |
| Africa | 304 | 381 | 368 | 369 | 397 | 373 |
| Worldwide\tContinuing\tOperations | 471 | 566 | 572 | 650 | 677 | 660 |
| Discontinued\tOperations(a) | – | – | 31 | – | – | 44 |
| WORLDWIDE | 471 | 566 | 603 | 650 | 677 | 704 |
| Developed\treserves\tas\ta\tpercent\tof\ttotal\tnet\tproved\treserves | 72% | 84% | 86% |  |  |  |
| Natural\tGas\t(Billions\tof\tcubic\tfeet) |  |  |  |  |  |  |
| United\tStates | 761 | 857 | 943 | 1,007 | 1,069 | 1,209 |
| Europe | 173 | 238 | 326 | 382 | 444 | 486 |
| Africa | 1,515 | 648 | 638 | 2,061 | 1,997 | 1,852 |
| WORLDWIDE | 2,449 | 1,743 | 1,907 | 3,450 | 3,510 | 3,547 |
| Developed\treserves\tas\ta\tpercent\tof\ttotal\tnet\tproved\treserves | 71% | 50% | 54% |  |  |  |
| Total\tBOE\t(Millions\tof\tbarrels) |  |  |  |  |  |  |
| United\tStates | 262 | 293 | 322 | 334 | 350 | 390 |
| Europe | 61 | 75 | 93 | 179 | 182 | 179 |
| Africa | 556 | 489 | 475 | 712 | 730 | 682 |
| Worldwide\tContinuing\tOperations | 879 | 857 | 890 | 1,225 | 1,262 | 1,251 |
| Discontinued\tOperations(a) | – | – | 31 | – | – | 44 |
| WORLDWIDE | 879 | 857 | 921 | 1,225 | 1,262 | 1,295 |
| Developed\treserves\tas\ta\tpercent\tof\ttotal\tnet\tproved\treserves | 72% | 68% | 71% |  |  |  |
| (a) |  |  |  |  |  |  |

Proved	developed	liquid	hydrocarbon	and	natural	gas	reserves	represented	72	percent	of	total	proved	reserves	as	of	December	31,	2007,	as	compared	to	68	percent as	of	December	31,	2006.	Of	the	346	million	boe	of	proved	undeveloped	reserves	at	year-end	2007,	58	percent	of	the	volume	is	associated	with	projects	that	have	been included	in	proved	reserves	for	more	than	three	years	while	17	percent	of	the	proved	undeveloped	reserves	were	added	during	2007.

During	2007,	we	added	a	total	of	88	million	boe	of	net	proved	liquid	hydrocarbon	and	natural	reserves,	principally	in	Libya,	Norway	and	the	Piceance	Basin	of Colorado.	We	disposed	of	0.2	million	boe,	while	producing

125	million	boe.	Of	the	total	net	proved	reserve	additions,	38	million	boe	were	proved	developed	and	50	million	boe	were	proved	undeveloped	reserves.	During	2007, we	transferred	109	million	boe	from	proved	undeveloped	to	proved	developed	reserves.	Costs	incurred	for	the	periods	ended	December	31,	2007,	2006	and	2005 relating	to	the	development	of	proved	undeveloped	liquid	hydrocarbon	and	natural	gas	reserves,	were	$1.250	billion,	$1.010	billion	and	$955	million.	As	of December	31,	2007,	estimated	future	development	costs	relating	to	the	development	of	proved	undeveloped	liquid	hydrocarbon	and	natural	gas	reserves	for	the	years 2008	through	2010	are	projected	to	be	$859	million,	$376	million	and	$293	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	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	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	2006	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	180	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.

(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	Marathon's	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	47	mmcfd,	46	mmcfd	and	38	mmcfd	in	2007,	2006	and	2005.

# Productive	and	Drilling	Wells

The	following	table	sets	forth	productive	wells	and	service	wells	as	of	December	31,	2007,	2006	and	2005,	and	drilling	wells	as	of	December	31,	2007.

# 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(b) | Wells(c) | Wells(c) |
|  | Gross | Net | Gross | Net | Gross | Net | Gross | Net |
| 2007 |  |  |  |  |  |  |  |  |
| United\tStates | 5,864 | 2,111 | 5,184 | 3,734 | 2,737 | 700 | 37 | 11 |
| Europe | 54 | 20 | 76 | 41 | 29 | 11 | 5 | 3 |
| Africa | 964 | 161 | 13 | 9 | 99 | 18 | 6 | 1 |
| WORLDWIDE | 6,882 | 2,292 | 5,273 | 3,784 | 2,865 | 729 | 48 | 15 |
| 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 |  |  |
| WORLDWIDE | 6,637 | 2,242 | 5,642 | 4,113 | 2,860 | 865 |  |  |
| 2005 |  |  |  |  |  |  |  |  |
| United\tStates | 5,724 | 2,029 | 5,254 | 3,696 | 2,723 | 827 |  |  |
| Europe | 51 | 19 | 68 | 37 | 29 | 10 |  |  |
| Africa | 926 | 155 | 13 | 8 | 97 | 18 |  |  |
| Other\tInternational | 156 | 156 | — | — | 50 | 50 |  |  |
| WORLDWIDE | 6,857 | 2,359 | 5,335 | 3,741 | 2,899 | 905 |  |  |
| (a) |  |  |  |  |  |  |  |  |

(a) Includes	active	wells	and	wells	temporarily	shut-in.	Of	the	gross	productive	wells,	wells	with	multiple	completions	operated	by	Marathon	totaled	303,	294	and	278	as	of	December	31,	2007,	2006	and	2005. 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)

|  |  | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- | :--- |
| United\tStates |  |  |  |  |
| Development(b) | –\tOil | 9 | 32 | 46 |
|  | –\tNatural\tGas | 172 | 186 | 288 |
|  | –\tDry | — | 5 | 4 |
|  | \t\t\t\t\t\t\t\tTotal | 181 | 223 | 338 |
| Exploratory | –\tOil | 9 | 3 | 2 |
|  | –\tNatural\tGas | 13 | 8 | 17 |
|  | –\tDry | 12 | 3 | 2 |
|  | \t\t\t\t\t\t\t\tTotal | 34 | 14 | 21 |
|  | \t\t\t\t\t\t\t\tTotal\tUnited\tStates | 215 | 237 | 359 |
| International |  |  |  |  |
| Development(b) | –\tOil | 7 | 51 | 68 |
|  | –\tNatural\tGas | — | 1 | 2 |
|  | –\tDry | — | — | 1 |
|  | \t\t\t\t\t\t\t\tTotal | 7 | 52 | 71 |
| Exploratory | –\tOil | 3 | 19 | 2 |
|  | –\tNatural\tGas | 1 | — | — |
|  | –\tDry | 2 | 6 | 4 |
|  | \t\t\t\t\t\t\t\tTotal | 6 | 25 | 6 |
|  | \t\t\t\t\t\t\t\tTotal\tInternational | 13 | 77 | 77 |
|  | \t\t\t\t\t\t\t\tWORLDWIDE | 228 | 314 | 436 |
| (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	table	sets	forth,	by	geographic	area,	the	developed	and	undeveloped	exploration	and	production	acreage	that	we	held	as	of	December	31,	2007.

# Gross	and	Net	Acreage

|  | Developed | Developed | Undeveloped | Undeveloped | Undeveloped | Undeveloped |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (Thousands\tof\tacres) | Gross | Net | Gross | Net | Gross | Net |
| United\tStates | 1,107 | 837 | 2,055 | 1,450 | 3,162 | 2,287 |
| Europe | 424 | 349 | 1,251 | 515 | 1,675 | 864 |
| Africa | 12,977 | 2,150 | 2,843 | 691 | 15,820 | 2,841 |
| Other\tInternational | — | — | 1,722 | 994 | 1,722 | 994 |
| WORLDWIDE | 14,508 | 3,336 | 7,871 | 3,650 | 22,379 | 6,986 |

# 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	certain	oil	sands	deposits	in	the	Athabasca	region	and	upgrades	the	bitumen	to	synthetic	crude	oil.	The	AOSP's	initial	asset	is	the mining	and	extraction	operations	of	the	Muskeg	River	mine	located	45	miles	north	of	Fort	McMurray,	Alberta,

which	began	bitumen	production	in	2003,	together	with	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.	As	of	December	31,	2007,	we	have	rights	to	participate	in	developed	and	undeveloped	leases	totaling 46,000	net	acres.	We	are	entitled	to	participate	in	future	expansion	opportunities	on	other	nearby	oil	sands	leases	owned	by	the	operator	and,	prior	to	December	6,	2009, on	any	new	lands	acquired	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	high-quality,	synthetic crude	oils.	Bitumen	production	from	the	mine	is	taken	by	pipeline	to	the	Scotford	upgrader,	which	uses	hydro-conversion	technology	to	upgrade	the	bitumen	into	two streams	of	synthetic	crude	oil	(Premium	Albian	Synthetic	and	Albian	Heavy	Synthetic)	and	vacuum	gas	oil.	The	vacuum	gas	oil	is	sold	to	the	operator	under	a	long-term contract	for	use	in	its	refinery	adjacent	to	the	upgrading	facility.	When	the	AOSP	is	operating	at	its	current	capacity,	our	net	bitumen	production	is	30	mbpd,	but operations	were	curtailed	at	the	Scotford	upgrader	subsequent	to	the	Western	acquisition	date	due	to	a	mid-November	fire.	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.	Net	bitumen	production averaged	4	mbpd	for	2007,	based	on	total	volumes	from	the	October	18,	2007	acquisition	date	over	total	days	in	the	year.	Bitumen	production	averaged	19	mbpd	for	the post-acquisition	period.

As	of	December	31,	2007,	our	net	proved	bitumen	reserves	were	estimated	to	be	421	million	barrels.	Proved	reserves	can	be	added	as	expansions	are	permitted, funding	is	approved	and	certain	stipulations	of	the	joint	venture	agreement	are	satisfied.

In	2006,	the	first	fully-integrated	expansion	of	the	existing	AOSP	facilities	was	approved.	The	Phase	1	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	AOSP	Phase	1	expansion	is	under	construction	and	we	anticipate	that	it	will	be	complete	in	late 2010.	Work	is	underway	to	determine	the	feasibility	of	additional	AOSP	expansion	projects	including	pursuing	regulatory	approvals.

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

# Refining,	Marketing	and	Transportation

# Refining

We	own	and	operate	seven	refineries	with	an	aggregate	refining	capacity	of	1.016	million	barrels	per	day	("mmbpd")	of	crude	oil.	During	2007,	our	refineries processed	1.010	mmbpd	of	crude	oil	and	214	mbpd	of	other	charge	and	blend	stocks.	The	table	below	sets	forth	the	location	and	daily	throughput	capacity	of	each	of	our refineries	as	of	December	31,	2007.	These	capacity	amounts	increased	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.

| Crude	Oil	Refining	Capacity |  |
| :--- | :--- |
| (Thousands\tof\tbarrels\tper\tday) |  |
| 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	can	process	a	wide	variety	of	crude	oils	and	produce	typical	refinery	products,	including	reformulated	and	low-sulfur	gasolines	and	ultra-low	sulfur	diesel	fuel. We	also	produce	asphalt	cements,	polymerized	asphalt,	asphalt	emulsions	and	industrial	asphalts.	We	manufacture	petroleum	pitch,	primarily	used	in	the	graphite electrode,	clay	target	and	refractory	industries.	Additionally,	we	manufacture	aromatics,	aliphatic	hydrocarbons,	cumene,	base	lube	oil,	polymer	grade	propylene,	maleic anhydride	and	slack	wax.

Our	refineries	are	integrated	via	pipelines,	terminals	and	barges	to	maximize	operating	efficiency.	The	transportation	links	that	connect	our	refineries	allow	the movement	of	intermediate	products	to	optimize	operations	and	the	production	of	higher	margin	products.	For	example,	naphtha	may	be	moved	from	Texas	City	to Robinson	where	excess	reforming	capacity	is	available.	Also,	by	shipping	intermediate	products	between	facilities	during	partial	refinery	shutdowns,	we	are	able	to utilize	processing	capacity	that	is	not	directly	affected	by	the	shutdown	work.

Planned	maintenance	activities	requiring	temporary	shutdown	of	certain	refinery	operating	units,	or	turnarounds,	are	periodically	performed	at	each	refinery.	We completed	fluid	catalytic	cracking	unit	turnarounds	at	our	Catlettsburg,	Robinson	and	St.	Paul	Park	refineries	in	2007.

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

| (Thousands	of	barrels	per	day) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Gasoline | 646 | 661 | 644 |
| Distillates | 349 | 323 | 318 |
| Propane | 23 | 23 | 21 |
| Feedstocks\tand\tSpecial\tProducts | 108 | 107 | 96 |
| Heavy\tFuel\tOil | 27 | 26 | 28 |
| Asphalt | 86 | 89 | 85 |
| TOTAL | 1,239 | 1,229 | 1,192 |

In	2006,	we	approved	an	expansion	of	our	Garyville,	Louisiana	refinery	by	180	mbpd	to	436	mbpd,	at	a	projected	cost	of	$3.2	billion	(excluding	capitalized interest).	Construction	commenced	in	early	2007	and	continues	on	schedule	with	additional	project	construction	phases	commencing	in	early	2008.	We	expect	to complete	the	expansion	in	late	2009.	In	2007,	we	approved	a	heavy	oil	upgrading	and	expansion	project	at	our	Detroit,	Michigan	refinery,	at	a	projected	cost	of	$1.9 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	is	expected	to	begin	in	the	first	half	of	2008,	subject	to	obtaining	necessary	environmental permits,	and	is	expected	to	be	completed	in	late	2010.	When	completed,	these	two	expansion	projects	will	increase	our	current	total	crude	oil	refining	capacity	by	19 percent.

# Marketing

We	are	a	supplier	of	gasoline	and	distillates	to	resellers	and	consumers	within	our	market	area	in	the	Midwest,	upper	Great	Plains,	Gulf	Coast	and	southeastern regions	of	the	United	States.	In	2007,	our	refined	products	sales	volumes	totaled	21.6	billion	gallons,	or	1.410	mmbpd.	The	average	sales	price	of	our	refined

products	in	aggregate	was	$86.53	per	barrel	for	2007.	The	following	table	sets	forth	our	refined	products	sales	by	product	group	and	our	average	sales	price	for	each	of the	last	three	years.

| (Thousands	of	barrels	per	day) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Gasoline | 791 | 804 | 836 |
| Distillates | 377 | 375 | 385 |
| Propane | 23 | 23 | 22 |
| Feedstocks\tand\tSpecial\tProducts | 103 | 106 | 96 |
| Heavy\tFuel\tOil | 29 | 26 | 29 |
| Asphalt | 87 | 91 | 87 |
| TOTAL\t(a) | 1,410 | 1,425 | 1,455 |
| Average\tsales\tprice\t(Dollars\tper\tbarrel) | $86.53 | $77.76 | $66.42 |
| (a) |  |  |  |

(a) Includes	matching	buy/sell	volumes	of	24	mbpd	and	77	mbpd	in	2006	and	2005.	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	2007	and	the	remainder	of	2006	than	would	have	been	reported	under	our	previous	accounting	practices.	See	Note	2	to	the	consolidated	financial statements.

The	wholesale	distribution	of	petroleum	products	to	private	brand	marketers	and	to	large	commercial	and	industrial	consumers	and	sales	in	the	spot	market accounted	for	69	percent	of	our	refined	products	sales	volumes	in	2007.	We	sold	49	percent	of	our	gasoline	volumes	and	89	percent	of	our	distillates	volumes	on	a wholesale	or	spot	market	basis.	Half	of	our	propane	is	sold	into	the	home	heating	market,	with	the	balance	being	purchased	by	industrial	consumers.	Propylene,	cumene, aromatics,	aliphatics	and	sulfur	are	domestically	marketed	to	customers	in	the	chemical	industry.	Base	lube	oils,	maleic	anhydride,	slack	wax,	extract	and	pitch	are	sold throughout	the	United	States	and	Canada,	with	pitch	products	also	being	exported	worldwide.	We	market	asphalt	through	owned	and	leased	terminals	throughout	the Midwest,	upper	Great	Plains,	Gulf	Coast	and	southeastern	regions	of	the	United	States.	Our	customer	base	includes	approximately	750	asphalt-paving	contractors, government	entities	(states,	counties,	cities	and	townships)	and	asphalt	roofing	shingle	manufacturers.

We	have	blended	ethanol	with	gasoline	for	over	15	years	and	increased	our	blending	program	in	2007,	in	part	due	to	renewable	fuel	mandates.	We	blended	41	mbpd of	ethanol	into	gasoline	in	2007	and	35	mbpd	in	both	2006	and	2005.	The	future	expansion	or	contraction	of	our	ethanol	blending	program	will	be	driven	by	the economics	of	the	ethanol	supply	and	changes	in	government	regulations.	We	sell	reformulated	gasoline	in	parts	of	our	marketing	territory,	primarily	Chicago,	Illinois; Louisville,	Kentucky;	northern	Kentucky;	Milwaukee,	Wisconsin	and	Hartford,	Illinois,	and	we	sell	low-vapor-pressure	gasoline	in	nine	states.	We	also	sell	biodiesel	in Minnesota,	Illinois	and	Kentucky.

As	of	December	31,	2007,	we	supplied	petroleum	products	to	about	4,400	Marathon	branded-retail	outlets	located	primarily	in	Ohio,	Michigan,	Indiana,	Kentucky and	Illinois.	Branded	retail	outlets	are	also	located	in	Georgia,	Florida,	Minnesota,	Wisconsin,	North	Carolina,	Tennessee,	West	Virginia,	Virginia,	South	Carolina, Alabama,	Pennsylvania,	and	Texas.	Sales	to	Marathon-brand	jobbers	and	dealers	accounted	for	16	percent	of	our	refined	product	sales	volumes	in	2007.

Speedway	SuperAmerica	LLC	("SSA"),	our	wholly-owned	subsidiary,	sells	gasoline	and	diesel	fuel	primarily	through	retail	outlets	that	we	operate.	Sales	of refined	products	through	these	SSA	retail	outlets	accounted	for	15	percent	of	our	refined	products	sales	volumes	in	2007.	As	of	December	31,	2007,	SSA	had	1,636 retail	outlets	in	nine	states	that	sold	petroleum	products	and	convenience	store	merchandise	and	services,	primarily	under	the	brand	names	"Speedway"	and "SuperAmerica."	SSA's	revenues	from	the	sale	of	non-petroleum	merchandise	totaled	$2.796	billion	in	2007,	compared	with	$2.706	billion	in	2006.	Profit	levels	from the	sale	of	such	merchandise	and	services	tend	to	be	less	volatile	than	profit	levels	from	the	retail	sale	of	gasoline	and	diesel	fuel.	SSA	also	operates	59	Valvoline	Instant Oil	Change	retail	outlets	located	in	Michigan	and	northwest	Ohio.

Pilot	Travel	Centers	LLC	("PTC"),	our	joint	venture	with	Pilot	Corporation	("Pilot"),	is	the	largest	operator	of	travel	centers	in	the	United	States	with	286	locations in	37	states	and	Canada	at	December	31,	2007.	The	travel	centers	offer	diesel	fuel,	gasoline	and	a	variety	of	other	services,	including	on-premises	brand-name restaurants	at	many	locations.	Pilot	and	Marathon	each	own	a	50	percent	interest	in	PTC.

Our	retail	marketing	strategy	is	focused	on	SSA's	Midwest	operations,	additional	growth	of	the	Marathon	brand	and	continued	growth	for	PTC.

# Supply	and	Transportation

We	obtain	most	of	the	crude	oil	we	refine	from	negotiated	contracts	and	purchases	or	exchanges	on	the	spot	market.	In	2007,	U.S.-sourced	crude	oil	averaged	527 mbpd,	or	52	percent,	of	the	crude	oil	processed	at	our	refineries,	including	a	net	15	mbpd	from	our	production	operations	included	in	the	E&P	segment.	Canada	was	the source	for	14	percent,	or	138	mbpd,	of	crude	oil	processed	in	2007.	Other	foreign	sources	supplied	34	percent,	or	345	mbpd,	of	the	crude	oil	processed	by	our	refineries, including	180	mbpd	from	the	Middle	East.	This	crude	oil	was	acquired	from	various	foreign	national	oil	companies,	producing	companies	and	trading	companies.	The following	table	provides	information	on	the	sources	of	crude	oil	for	each	of	the	last	three	years.

# Sources	of	Crude	Oil	Refined

We	operate	a	system	of	pipelines,	terminals	and	barges	to	provide	crude	oil	to	our	refineries	and	refined	products	to	our	marketing	areas.	At	December	31,	2007,	we owned,	leased,	operated	or	held	equity	method	investments	in	68	miles	of	crude	oil	gathering	lines,	3,717	miles	of	crude	oil	trunk	lines	and	3,860	miles	of	refined products	trunk	lines.

Excluding	equity	method	investees,	our	owned	or	operated	common	carrier	pipelines	transported	the	volumes	shown	in	the	following	table	for	each	of	the	last	three years.

| (Thousands	of	barrels	per	day) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Crude\toil\tgathering\tlines | 17 | 17 | 18 |
| Crude\toil\ttrunk\tlines | 1,500 | 1,484 | 1,619 |
| Refined\tproducts\ttrunk\tlines | 1,175 | 1,101 | 1,219 |
| TOTAL | 2,692 | 2,602 | 2,856 |

At	December	31,	2007	we	had	interests	in	the	following	pipelines:

•100	percent	ownership	of	Ohio	River	Pipe	Line	LLC,	which	owns	a	refined	products	pipeline	extending	from	Kenova,	West	Virginia	to	Columbus,	Ohio, known	as	Cardinal	Products	Pipeline;

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

•51	percent	interest	in	LOOP	LLC	("LOOP"),	the	owner	and	operator	of	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;

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

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

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

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

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

Our	85	owned	and	operated	light	product	and	asphalt	terminals	are	strategically	located	throughout	the	Midwest,	upper	Great	Plains	and	southeastern	United	States. In	October	2007,	we	executed	an	agreement	to	purchase	four	light	product	terminals	in	Ohio	and	an	ownership	interest	in	a	refined	product	pipeline.	This	transaction	is expected	to	close	by	the	end	of	the	second	quarter	of	2008,	pending	completion	of	various	pre-closing	activities,	including	obtaining	necessary	government	approvals.

Our	marine	transportation	operations	include	15	towboats	and	182	barges	that	transport	refined	products	on	the	Ohio,	Mississippi	and	Illinois	rivers,	their	tributaries and	the	Intercoastal	Waterway.	We	lease	and	own	over	2,500	rail	cars	of	various	sizes	and	capacities	for	movement	and	storage	of	petroleum	products	and	over	150 tractors	and	tank	trailers.

# Ethanol	Production

In	2007,	we	acquired	a	35	percent	interest	in	an	entity	which	owns	and	operates	a	110-million-gallon-per-year	ethanol	facility	in	Clymers,	Indiana,	and	continued construction	of	another	110-million-gallon-per-year	ethanol	facility	in	Greenville,	Ohio.	The	Greenville	plant,	in	which	we	own	a	50	percent	interest,	began	production	in February	2008.	Both	of	these	facilities	are	managed	by	our	partner,	The	Andersons,	Inc.	and	will	enable	us	to	maintain	the	reliability	of	a	portion	of	our	future	ethanol supplies.

The	above	discussion	of	the	RM&T	segment	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.	The	above	discussion	also	includes	forward-looking	statements	concerning	the	purchase	of	four	terminals	and	an	interest	in	a	pipeline	which	is subject	to	customary	closing	conditions	and	may	be	affected	by	the	inability	or	delay	in	obtaining	necessary	regulatory	approvals	and	other	operating	and	economic considerations.	These	factors	(among	others)	could	cause	actual	results	to	differ	materially	from	those	set	forth	in	the	forward-looking	statements.

# 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	an	FOB	Bioko Island	basis,	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	1,464,088	metric	tonnes	in	2007.

In	2007	we	completed	those	portions	of	the	front-end	engineering	and	design	("FEED")	required	to	support	the	near-term	efforts	related	to	a	potential	second	LNG production	facility	on	Bioko	Island,	Equatorial	Guinea.	The	scope	of	the	FEED	work	for	the	potential	4.4	mmtpa	LNG	project	included	feed	gas	metering,	liquefaction, refrigeration,	ethylene	storage,	boil-off	gas	compression,	product	transfer	to	storage	and	LNG	product	metering.	We	expect	to	make	progress	towards	an	investment decision	in	2008.

We	also	own	a	30	percent	interest	in	a	Kenai,	Alaska,	natural	gas	liquefaction	plant,	which	is	accounted	for	under	the	equity	method	of	accounting,	and	have	an undivided	interest	in	a	long-term	lease	for	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.	This	contract	continues	through	March	2009,	with	2007	LNG	deliveries	totaling	48	bcf.	In	January	2007,	along with	our	partner,	we	filed	a	request	with	the	DOE	to	extend	the	export	license	for	this	natural	gas	liquefaction	plant	through	March	2011.	This	application	has	received favorable	support	from	the	State	of	Alaska	but	still	requires	final	DOE	approval.

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	1,060,653	metric tonnes	in	2007.	Production	from	the	plant	is	used	to	supply	customers	in	Europe	and	the	United	States.

# Natural	Gas	Technology

We	invest	in	natural	gas	technology	research,	including	proprietary	Gas-To-Fuels™	("GTF")	technology	which	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.	We	have	designed and	are	constructing	a	10-bpd	demonstration	facility	for	this	technology,	with	initial	startup	scheduled	for	the	second	half	of	2008.	Expectations	for	the	demonstration plant	include	the	ability	to	demonstrate	operations	of	the	fully	integrated	process	at	a	practical	scale	and	to	measure	the	conversion	efficiencies	of	the	total	process, catalyst	performance	and	materials	durability.	This	critical	performance	data	will	support	scale-up	cost	estimates	for	a	commercial	installation	and	provide	the	basis	for continued	technical	developments	in	this	area.	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	("GTL")	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	on	industry	sources,	we	rank	eighth	among	U.S.-based	petroleum	companies	on	the	basis	of	2006	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.	In	addition,	not	all	refineries	are	able	to	process	or	refine	synthetic	crude	oil.	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.	We	rank	fifth	among	U.S.	petroleum	companies	on	the	basis	of	U.S.	crude	oil	refining	capacity	as	of	December	31,	2007.	We	compete	in	four distinct	markets	–	wholesale,	spot,	branded	and	retail	distribution	–	for	the	sale	of	refined	products.	We	believe	we	compete	with	about	40	companies	in	the	wholesale distribution	of	petroleum	products	to	private	brand	marketers	and	large	commercial	and	industrial	consumers;	about	75	companies	in	the	sale	of	petroleum	products	in the	spot	market;	ten	refiner/marketers	in	the	supply	of	branded	petroleum	products	to	dealers	and	jobbers;	and	approximately	275	petroleum	product	retailers	in	the	retail sale	of	petroleum	products.	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.	Some	locations	also	have	on-premises	brand-name	restaurants	such	as	Subway™.	We	also compete	in	the	travel	center	industry	through	our	50	percent	ownership	in	PTC.

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.

# The	Separation

On	December	31,	2001,	pursuant	to	an	Agreement	and	Plan	of	Reorganization	dated	as	of	July	31,	2001,	Marathon	completed	the	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	Separation,	Marathon	and	United	States	Steel	are	separate	companies	and	neither	has	any	ownership	interest	in	the	other.

In	connection	with	the	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	Separation	and	providing	for	the	allocation	of	tax	and	certain	other	liabilities	and	obligations	arising	from	periods	before	the	Separation.	The following	is	a	description	of	the	material	terms	of	two	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 2009	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	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	also	requires	United	States	Steel	to	use	commercially	reasonable	efforts	to	have	us	released	from	our	obligations	under	a	guarantee we	provided	with	respect	to	all	of	United	States	Steel's	obligations	under	a	partnership	agreement	between	United	States	Steel,	as	general	partner,	and	General	Electric Credit	Corporation	of	Delaware	and	Southern	Energy	Clairton,	LLC,	as	limited	partners.	United	States	Steel	may	dissolve	the	partnership	under	certain	circumstances, including	if	it	is	required	to	fund	accumulated	cash	shortfalls	of	the	partnership	in	excess	of	$150	million.	In	addition	to	the	normal	commitments	of	a	general	partner, United	States	Steel	has	indemnified	the	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	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.

# Obligations	Associated	with	the	Separation	as	of	December	31,	2007

See	Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	–	Obligations	Associated	with	the	Separation	of	United	States	Steel for	a	discussion	of	our	obligations	associated	with	the	Separation.

# 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 Responsibility	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	Marathon	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 both	in	the	United	States	and	abroad	are	in	various	stages	of	development.	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.	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	refining	crude	oil	and	transportation	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	products)	associated	with	any	legislation,	regulation,	EPA	or	other action,	the	extent	and	magnitude	of	impact	cannot	be	reliably	or	accurately	estimated	due	to	newness	of	the	requirements	and	the	present	uncertainty	regarding	the additional	measures	and	how	they	will	be	implemented.	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	similar	laws	dealing	with	the	same	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	always	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	Legal	Proceedings	and 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	now	plan	to	spend approximately	$350	million	between	2006	and	2012	on	refinery	investments	to	produce	ultra-low	sulfur	diesel	fuel	for	off-road	use,	in	compliance	with	EPA	regulations. This	is	a	forward-looking	statement.	Some	factors	(among	others)	that	could	potentially	affect	these	compliance	costs	include	final	investment	decisions,	completion	of project	detailed	engineering,	construction	and	start-up	activities.	Further,	we	previously	estimated	that	we	would	spend	approximately	$400	million	over	a	four-year period	beginning	in	2008	to	comply	with	Mobile	Source	Air	Toxics	II	regulations	relating	to	benzene.	We	have	not	finalized	our	strategy	or	cost	estimates	to	comply with	these	recently	promulgated	requirements,	but	the	cost	estimates	will	increase	and	may	be	approximately	$1	billion	over	a	three-year	period	beginning	in	2008.	The cost	estimates	have	increased	due	to	better	definition	of	the	projects	needed	to	meet	the	requirements	of	the	finalized	regulations	and	updated	construction	cost estimates.	The	cost	estimates	are	forward-looking	statements	and	are	subject	to	change	as	FEED	work	is	completed	in	2008.

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	will	have	the	final	say	on	what	sources	they	regulate	to	meet	attainment criteria.	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.	Also, on	July	11,	2007,	the	EPA	proposed	a	revised	ozone	standard.	Once	the	revised	ozone	standard	is	promulgated,	the	EPA	will	begin	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	states have	taken	further	action	and	we	cannot	reasonably	estimate	the	final	financial	impact	of	the	revised	ozone	standard	until	the	implementing	rules	are	established.

# 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	such	releases	OPA- 90	requires	responsible	companies	to	pay	resulting	removal	costs	and	damages,	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.	Several	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	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.	Ongoing	RCRA-related	costs,	however,	are	not	expected	to	be	material.	In addition,	Canada	will	be	implementing	a	ban	on	the	land	application	of	certain	wastes	and	we	are	reviewing	options	to	treat	or	dispose	of	these	wastes	consistent	with these	new	restrictions.

# Remediation

We	own	or	operate	certain	retail	outlets	where,	during	the	normal	course	of	operations,	releases	of	petroleum	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	Legal	Proceedings	–	Environmental	Proceedings	–	Other	Proceedings	for	a	discussion	of	these	sites.

The	Energy	Policy	Act	of	2005	established	a	Renewable	Fuel	Standard	("RFS")	providing	that	all	gasoline	sold	in	the	United	States	contain	a	minimum	of	4.0 billion	gallons	of	renewable	fuel	in	2006.	The	RFS	increases	gradually	each	year	until	2012,	when	the	RFS	will	be	7.5	billion	gallons	of	renewable	fuel.	The	EPA	issued a	final	rule	in	May	2007	and	the	program	went	into	effect	on	September	1,	2007.	We	have	put	the	necessary	systems	in	place	to	track	and	report	our	compliance	with these	requirements.

The	recently-passed	Energy	Independence	and	Security	Act	of	2007	contains	multiple	RFSs.	The	overall	requirement	starts	with	9.0	billion	gallons	of	renewable fuel	required	in	2008	and	ramps	up	to	36.0	billion	gallons	in	2022.	Inside	of	the	overall	requirement	is	an	advanced	biofuels	mandate	which	begins	in	2009	and	increases to	21.0	billion	gallons	by	2022.	Subsets	within	the	advanced	biofuels	requirements	require	1.0	billion	gallons	of	biomass-based	diesel	fuel	by	2012	and	16.0	billion gallons	of	cellulosic	ethanol	by	2022.	The	EPA	has	not	yet	issued	a	proposal	and	a	final	rule	to	implement	this	program.	This	program	presents	specific	challenges	in that	a	refiner	like	us	may	have	to	enter	into	arrangements	with	other	parties	to	meet	its	obligations	to	use	advanced	biofuels	and	cellulosic	ethanol	if	it	cannot	produce these	fuels	itself.	We	may	also	experience	a	decrease	in	demand	of	our	current	refinery-produced	petroleum	products	to	the	extent	they	are	replaced	by	advanced biofuels	and	cellulosic

ethanol	and	overall	demand	does	not	increase	to	replace	this	loss.	There	will	be	compliance	costs	and	uncertainties	regarding	how	we	will	comply	with	the	mandates contained	in	this	law	and	rule,	but	the	extent	and	magnitude	of	impact	cannot	be	reliably	or	accurately	estimated	due	to	the	uncertainty	of	these	measures	at	this	time. We	are	and	will	be	developing	potential	strategies	for	compliance	with	such	requirements.

# Employees

We	had	29,524	active	employees	as	of	December	31,	2007.	Of	that	number,	19,578	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,	2009.	The	same	union	represents	certain	hourly	employees	at	our	Texas	City refinery	under	a	labor	agreement	that	expires	on	March	31,	2009.	The	International	Brotherhood	of	Teamsters	represents	certain	hourly	employees	under	labor agreements	that	are	scheduled	to	expire	on	May	31,	2009	at	our	St.	Paul	Park	refinery	and	January	31,	2010	at	our	Detroit	refinery.

# Executive	Officers	of	the	Registrant

The	executive	officers	of	Marathon	and	their	ages	as	of	February	1,	2008,	are	as	follows:

With	the	exception	of	Ms.	Clark	and	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.	Behrman	was	appointed	senior	vice	president,	worldwide	exploration	effective	January	2002.

•	 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,	prior	to	which	she	was	employed	by	Nuevo	Energy	Company	from	2001	to	December	2003	as	senior	vice president	and	chief	financial	officer.

•	 Mr.	Heminger	was	appointed	executive	vice	president	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.

•	 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.	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.	He	served	as	advisor	to	the	vice	chairman	of	ChevronTexaco Corporation	from	2001	to	2003.

•	 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.	Prior	to	his	appointment	as	director	of	investor	relations,	Mr.	Thill	was	manager	of	investor	relations	from	January	2002 to	March	2003.

# 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/.

Marathon's	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

Marathon	is	subject	to	various	risks	and	uncertainties	in	the	course	of	its	business.	The	following	summarizes	some,	but	not	all,	of	the	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,	as	well	as	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;

•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	climatic	changes;

•natural	disasters	such	as	hurricanes	and	tornados;

•the	price	and	availability	of	alternative	and	competing	fuels;

•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,	as	well	as	lower	refining	and	wholesale	marketing	gross	margins,	may	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	and/or	third- party	consultants	we	have	retained.	The	estimates	were	calculated	using	liquid	hydrocarbon	and	natural	gas	prices	in	effect	as	of	December	31,	2007,	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,	2007	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.	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;	and

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

# Increases	in	crude	oil	prices	and	environmental	or	other	regulations	may	reduce	our	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	attendant	to	doing	business	with	suppliers	located	in	that	area	of	the	world.	Our	overall	RM&T	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.

In	addition,	various	regulations	have	imposed,	and	are	expected	to	continue	to	impose,	increasingly	stringent	and	costly	requirements	on	our	refining,	marketing and	transportation	operations,	which	may	reduce	our	refining	and	wholesale	marketing	gross	margins.

# We	will	continue	to	incur	substantial	capital	expenditures	and	operating	costs	as	a	result	of	compliance	with,	and	changes	in	environmental	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.	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	reasonably	likely	that	the	scientific	and	political	attention	to	issues	concerning	the	existence	and	extent	of	climate	change	will	continue,	with	the potential	for	further	regulations	that	could	affect	our	operations.	Although	uncertain,	these	developments	could	increase	costs	or	reduce	the	demand	for	the	products	we sell.

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.

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.

# 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	59	percent	of	our	liquid	hydrocarbon	and	natural gas	sales	volumes	in	2007	was	derived	from	production	outside	the	United	States	and	73	percent	of	our	proved	liquid	hydrocarbon	and	natural	gas	reserves	as	of December	31,	2007	were	located	outside	the	United	States.	All	of	our	bitumen	production	and	proved	reserves	are	located	in	Canada.

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.	Actions	by	both	the	United	States	and	host	governments	have	affected operations	significantly	in	the	past	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,	inclement	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	and	damage	or	loss	from	severe	weather	conditions.	These	hazards could	result	in	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	litigation	arising	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	these	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 materially

reduce	our	profitability.	Historically,	we	have	maintained	insurance	coverage	for	physical	damage	and	resulting	business	interruption	to	our	major	onshore	and	offshore facilities.	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.

# We	may	not	be	successful	in	integrating	and	optimizing	assets	acquired	in	our	acquisition	of	Western.

Risks	associated	with	acquisitions	include	those	relating	to:

•liability	for	known	or	unknown	environmental	conditions	or	other	contingent	liabilities	not	covered	by	indemnification	or	insurance;

•greater	than	anticipated	expenditures	required	for	compliance	with	environmental	or	other	regulatory	standards,	or	for	investments	to	improve	operating results;

•difficulties	in	achieving	anticipated	operational	improvements;

•diversion	of	management	time	and	attention	from	our	existing	businesses	and	other	priorities;	and

•difficulties	in	integrating	the	financial,	technological	and	management	standards,	processes,	procedures	and	controls	of	an	acquired	business	into	those	of	our existing	operations.

Such	acquisition	risks	are	in	addition	to	any	risks	inherent	in	the	operations	of	an	oil	sands	mining	business.

# 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.

# Marathon	is	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%	(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	the	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	our	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	coverages.	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	$533	million	as	of	December	31,	2007,	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.

# We	may	issue	preferred	stock	whose	terms	could	dilute	the	voting	power	or	reduce	the	value	of	our	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	our	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	our 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

As	of	the	date	of	this	filing,	we	have	no	unresolved	comments	from	the	staff	of	the	Securities	and	Exchange	Commission.

# Item	2. Properties

The	location	and	general	character	of	the	principal	liquid	hydrocarbon	and	natural	gas	properties,	oil	sands	mining	properties	and	facilities,	refineries,	pipeline systems	and	other	important	physical	properties	of	Marathon	have	been	described	by	segment	under	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	Financial	Statements	and	Supplementary	Data	– Supplemental	Statistics.	Estimated	net	proved	liquid	hydrocarbon	and	natural	gas	reserves	are	set	forth	in	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	Business	–	Oil	Sands	Mining.	The	basis	for	estimating	these	reserves	is	discussed	in	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

Marathon	is	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	Marathon	will	remain	a	viable	and	competitive	enterprise	even	though	it	is	possible	that	these	contingencies	could	be resolved	unfavorably.

# Natural	Gas	Royalty	Litigation

As	of	December	31,	2005,	Marathon	had	been	served	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	plaintiff	states	that	he	sues	for	himself,	as	well as	the	state	government.	The	Department	of	Justice	has	announced	that	it	would	intervene	or	has	reserved	judgment	on	whether	to	intervene	against	specified	oil	and	gas companies	and	also	announced	that	it	would	not	intervene	against	certain	other	defendants	including	Marathon.	One	of	the	cases,	U.S.	ex	rel	Jack	J.	Grynberg	v.	Alaska Pipeline	Co.,	et	al,	which	was	primarily	a	gas	measurement	case,	was	dismissed	as	to	Marathon	on	October	20,	2006	on	jurisdictional	grounds.	The	second	case,	U.S.	ex rel	Harrold	E.	Wright	v.	Agip	Petroleum	Co.	et	al,	is	primarily	a	gas	valuation	case.	The	Wright	case	is	in	the	discovery	phase.

In	October	2006,	Marathon	was	served	with	an	additional	qui	tam	case,	filed	in	the	Western	District	of	Oklahoma,	which	alleges	that	Marathon	violated	the	False Claims	Act	by	failing	to	pay	the	government	past	due	interest	resulting	from	royalty	adjustments	for	crude	oil,	natural	gas	and	other	hydrocarbon	production.	The	case	is styled	United	States	of	America	ex	rel.	Randy	L.	Little	and	Lanis	G.	Morris	v.	ENI	Petroleum	Co.,	et	al.	This	case	asserts	that	Marathon	and	other	defendants	are	liable for	past	due	interest,	penalties,	punitive	damages	and	attorneys	fees.	Other	than	the	allegation	of	a	$1,360	underpayment	for	the	month	of	May	2003,	the	parties	in interest	(Randy	L.	Little	and	Lanis	G.	Morris)	have	plead	general	damages	with	no	other	specific	amounts	against	Marathon.	Marathon	intends	to	continue	to	vigorously defend	these	cases.

# 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	progress	through	the	courts,	the	Wyoming	BLM	continues	to	process permits	to	drill	under	the	ROD.

In	the	Environmental	Defense	Fund	("EDF")	v.	BLM	case	before	the	Federal	District	Court	of	Wyoming,	the	EDF	alleged	that	in	2002,	the	BLM	did	not sufficiently	evaluate	the	air	impacts	associated	with	coal	bed	natural	gas	production	in	the	Powder	River	Basin,	as	well	as	other	oil	and	gas	operations	in	Wyoming. Marathon	and	other	producers	had	intervened.	In	June	2007,	the	Federal	District	Court	for	the	District	of	Wyoming	dismissed	the	EDF	case	(without	prejudice	as	to refiling).

# MTBE	Litigation

Marathon	is	a	defendant	along	with	many	other	refining	companies	in	over	50	cases	in	12	states	alleging	methyl	tertiary-butyl	ether	("MTBE")	contamination	in groundwater.	All	of	these	cases,	after	their	removal	from	state	to	federal	court,	have	been	consolidated	in	a	multi-district	litigation	("MDL")	in	the	Southern	District	of New	York	for	pretrial	proceedings.	The	plaintiffs	generally	are	water	providers	or	governmental	authorities	and	they	allege	that	refiners,	manufacturers	and	sellers	of gasoline	containing	MTBE	are	collectively	liable,	under	market	share	and/or	other	"alternative	liability"	theories,	for	manufacturing	a	defective	product.	Several	of	these lawsuits	allege	contamination	in	areas	that	are	outside	of	Marathon's	marketing	area.	All	of	the	cases	seek	punitive	damages	or	treble	damages	under	a	variety	of	statutes and	theories.	In	one	of	the	cases,	the	State	of	New	Jersey	is	seeking	natural	resources	damages	allegedly	resulting	from	contamination	of	groundwater	by	MTBE.	This	is the	only	case	in	which	Marathon	is	a	defendant	and	natural	resources	damages	are	sought.	Marathon	stopped	producing	MTBE	at	its	refineries	in	October	2002.

The	MDL	court	has	identified	four	"test"	cases	to	proceed	ahead	of	the	remaining	MDL	cases.	The	first	of	these	test	cases	(County	of	Suffolk	(NY)	and	Suffolk County	Water	Authority	v.	Amerada	Hess	Corporation,	et	al.)	is	scheduled	for	trial	in	September	2008.	Marathon	is	a	defendant	in	this	test	case.	Marathon	is	engaged	in ongoing	settlement	discussions	related	to	the	majority	of	the	cases	in	which	it	is	defendant,	including	the	Suffolk	County,	New	York	test	case,	and	such	settlement,	if any,	is	not	expected	to	significantly	impact	Marathon's	consolidated	results	of	operations,	financial	position	or	cash	flows.

# Product	Contamination	Litigation

A	lawsuit	was	filed	in	the	United	States	District	Court	for	the	Southern	District	of	West	Virginia	and	alleges	that	Marathon's	Catlettsburg,	Kentucky	refinery	sold defective	gasoline	to	wholesalers	and	retailers,	causing	permanent	damage	to	storage	tanks,	dispensers	and	related	equipment,	resulting	in	lost	profits,	business disruption	and	personal	and	real	property	damages.	Class	action	certification	was	granted	in	August	2007.	In	2002,	Marathon	conducted	extensive	cleaning	operations	at affected	facilities	and	denies	that	any	permanent	damages	resulted	from	the	incident.	Marathon	previously	settled	with	many	of	the	potential	class	members	in	this	case and	intends	to	vigorously	defend	this	action.

# Environmental	Proceedings

# U.S.	EPA	Litigation

In	2002,	Marathon	and	the	American	Petroleum	Institute	("API")	brought	a	petition	before	the	U.S.	District	Court	for	the	District	of	Columbia,	challenging	the	U.S. EPA's	2002	promulgation	of	new	Oil	Spill	Prevention,	Countermeasures	and	Control	regulations	on	several	grounds;	while	the	dispute	has	been	settled,	the	one remaining	count	is	over	the	U.S.	EPA's	regulatory	definition	of	waters	covered	by	the	Clean	Water	Act.	Marathon	and	API	contend	that	the	U.S.	EPA's	regulations	run contrary	to	recent	decisions	of	the	U.S.	Supreme	Court	which,	in	finding	federal	agencies	had	gone	greatly	beyond	the	intentions	of	Congress	as	to	what	waters	were covered	by	the	Clean	Water	Act,	narrowed	the	universe	of	what	waters	the	federal	government,	rather	than	state	governments,	had	jurisdiction	to	regulate.	The	case	is ongoing	with	oral	arguments	to	be	heard	in	February	2008.

In	September	2006,	Marathon	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.	These	September	2006	actions	have been	consolidated	with	our	pending	April	2006	action	against	the	U.S.	EPA	in	the	same	court.	The	water	quality	amendments	at	issue,	if	approved,	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.	The court	has	stayed	this	case	while	the	U.S.	EPA	mediates	the	matter	between	Montana,	Wyoming	and	the	Northern	Cheyenne	tribe.	Mediation	and	settlement	talks continue	while	the	litigation	is	on	hold.

# Montana	Litigation

In	June	2006,	Marathon	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	is now	being	appealed	to	the	Montana	Supreme	Court	and	does	not	impact	Marathon	operations	in	the	meanwhile.

# Wyoming	Proceedings

The	Wyoming	Environmental	Quality	Council	("EQC"),	which	oversees	the	State	Department	of	Environmental	Quality	("DEQ"),	has	before	it	an	administrative petition	filed	by	the	Powder	River	Basis	Resource	Council	in	2006	seeking	new	water	quality	sulfate	and	barium	standards	for	coal	bed	methane	produced	water	and	a requirement	that	all	such	water	be	beneficially	reused.	The	petition	seeks	to	expand	the	authority	of	the	DEQ	to	regulate	the	quantity	of	water	discharges.	It	would narrow	the	definition	of	required	"beneficial	use"	discharges	and	would	impose	stricter	effluent	standards	for	discharged	water.	The	EQC	is	also	considering	adoption	of a	rule	which	would	impose	more	stringent	water	quality	limits	as	to	produced	water	discharges	that	come	from	any	new	coal	bed	methane	or	conventional	oil	and	gas operations.	The	DEQ	made	this	proposal	citing	a	statutory	directive	that	all	waters	that	are	suitable	for	agriculture	may	not	be	degraded.	Marathon	contends	that	its waters	as	currently	regulated	are	beneficial	to	crops	and	livestock,	rather	than	being	a	potential	threat.	The	EQC	would	have	to	decide	how	stringent	a	water	quality standard	it	would	adopt	for	new	discharges.

In	response	to	the	Governor	of	Wyoming's	veto	of	a	state	agency	adoption	of	a	rule	that	would	allow	the	DEQ	to	regulate	the	quantity	of	coal	bed	methane	water discharges,	an	activist	group	has	sued	in	state	court	to	overturn	the	veto.	In	June	2007,	Marathon	and	another	producer	filed	a	motion	to	intervene.	The	DEQ	has	begun issuing	renewal	water	discharge	and	other	permits	with	stringent	limits	based	on	its	agricultural	use	policy	rather	than	upon	any	regulation.	The	permits	could	require more	costly	water	treatment	or	injection.	Marathon	is	appealing	every	permit	issued	in	this	way.	In	2007,	the	state	court	dismissed	the	activist	group's	lawsuit,	and	its time	for	appeal	has	expired.

# Other	Environmental	Proceedings

The	following	is	a	summary	of	proceedings	involving	Marathon	that	were	pending	or	contemplated	as	of	December	31,	2007	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,	Marathon	is	unable	to	reasonably estimate	its	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,	2007,	Marathon	had	been	identified	as	a	PRP	at	a	total	of	ten	CERCLA	waste	sites.	Based	on	currently	available	information,	which	is	in	many cases	preliminary	and	incomplete,	Marathon	believes	that	its	liability	for	clean-up	and	remediation	costs	in	connection	with	five	of	these	sites	will	be	under	$1	million per	site	(with	four	of	these	five	sites	being	under	$100,000	each).	As	to	the	remaining	five	sites,	Marathon	believes	that	its	liability	for	clean-up	and	remediation	costs	in connection	with	two	of	these	sites	will	be	under	$4	million	per	site.	Marathon	is	not	far	enough	along	in	the	process	to	determine	the	cost	for	the	remaining	three	sites, but	two	of	the	sites	may	be	$1	million	to	$2	million	or	more	each	and	the	other	may	be	under	$1	million.	In	addition,	there	are	two	sites	for	which	Marathon	has	received information	requests	or	other	indications	that	it	may	be	a	PRP	under	CERCLA,	but	for	which	sufficient	information	is	not	presently	available	to	confirm	the	existence	of liability.

There	are	also	119	sites,	excluding	retail	marketing	outlets,	related	to	Marathon	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,	Marathon	believes	that	its	liability	for	clean-up	and	remediation	costs	in	connection	with	17	of	these	sites	will	be	under	$100,000	per	site, that	54	sites	have	potential	costs	between	$100,000	and	$1	million	per	site	and	that	19	sites	may	involve	remediation	costs	between	$1	million	and	$5	million	per	site. Nine	sites	have	incurred	remediation	costs	of	more	than	$5	million	per	site	and	there	are	six	sites	with	insufficient	information	to	estimate	future	remediation	costs.	There are	14	other	sites	for	which	Ashland	retains	responsibility	to	Marathon	for	remediation,	subject	to	caps	and	other	requirements	contained	in	the	agreements	with	Ashland related	to	Marathon's	acquisition	of	Ashland's	minority	interest	in	MPC	in	2005.	Marathon	estimates	that	it	will	be	responsible	for	nearly	$8	million	in	remediation	costs at	these	sites	which	will	not	be	reimbursed	by	Ashland,	and	Marathon	has	included	this	amount	in	its	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	29	years,	Marathon	anticipates	spending	approximately	$6	million	in	remediation	costs	at this	site.	In	2008,	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	2007	and	2006	were	$524,000	and	$461,000,	with	expenditures	for	remedial	measures	in	2008	expected to	be	approximately	$2	million.

MPC	has	had	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.

During	2001,	Marathon	entered	into	a	New	Source	Review	consent	decree	and	settlement	of	alleged	Clean	Air	Act	and	other	violations	with	the	EPA	covering	all of	its	refineries.	The	settlement	committed	Marathon	to	specific	control	technologies	and	implementation	schedules	for	environmental	expenditures	and	improvements to	its	refineries	over	approximately	an	eight-year	period.	In	addition,	Marathon	has	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	substantially	completed.	As	part	of	this	consent	decree,	Marathon	was	required to	conduct	evaluations	of	its	refinery	benzene	waste	air	pollution	programs.	These	evaluations	resulted	in	disclosure	of	benzene	waste	compliance	issues	at	the	Canton and	Catlettsburg	refineries.	The	U.S.	Department	of	Justice	has	informed	Marathon	that	it	will	seek	several	hundred	thousand	dollars	of	civil	penalties	(potentially	to include	supplemental	environmental	projects)	for	these	matters.	No	formal	enforcement	action	has	been	brought	but	Marathon	will	attempt	to	resolve	these	matters	in 2008.

The	U.S.	Occupational	Safety	and	Health	Administration	("OSHA")	has	announced	a	National	Emphasis	Program	where	it	plans	to	inspect	most	of	the	domestic	oil refinery	locations.	The	inspections	began	in	2007	and	focus	on	compliance	with	the	OSHA	Process	Safety	Management	requirements.	OSHA	conducted	an	inspection	at the	Canton	refinery	over	several	months	in	2007.	This	inspection	resulted	in	an	informal	settlement	agreement	with	OSHA	in	December	2007	under	which	a	penalty	of $321,500	was	paid	and	Marathon	agreed	to	various	abatement	measures.	OSHA	is	scheduled	to	conduct	an	inspection	of	the	Robinson	refinery	in	the	first	quarter	of 2008	and	may	conduct	inspections	of	other	Marathon	refineries	during	that	year.	Further	enforcement	actions	by	OSHA	may	result	from	these	inspections.

# SEC	Investigation	Relating	to	Equatorial	Guinea

By	letter	dated	July	15,	2004,	the	SEC	notified	Marathon	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.	This	inquiry	followed	an	investigation	and	public	hearing	conducted	by	the	U.S. Senate	Permanent	Subcommittee	on	Investigations,	which	reviewed	the	transactions	of	various	foreign	governments,	including	those	of	Equatorial	Guinea,	with	Riggs Bank.	The	investigation	and	hearing	also	reviewed	the	operations	of	U.S.	oil	and	gas	companies,	including	Marathon,	in	Equatorial	Guinea.	There	was	no	finding	in	the Subcommittee's	report	that	Marathon	violated	the	U.S.	Foreign	Corrupt	Practices	Act	or	any	other	applicable	laws	or	regulations.	Marathon	voluntarily	produced documents	requested	by	the	SEC	in	that	inquiry.	On	August	1,	2005,	Marathon	received	a	subpoena	issued	by	the	SEC	pursuant	to	a	formal	order	of	investigation requiring	the	production	of	the	documents	that	had	already	been	produced	or	that	were	in	the	process	of	being	identified	and	produced	in	response	to	the SEC's	prior	requests,	and	requesting	the	production	of	additional	materials.	Marathon	has	been	and	intends	to	continue	cooperating	with	the	SEC	in	this	investigation.

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

# Not	applicable.

# PART	II

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

The	principal	market	on	which	Marathon's	common	stock	is	traded	is	the	New	York	Stock	Exchange.	Marathon's	common	stock	is	also	traded	on	the	Chicago Stock	Exchange.	Information	concerning	the	quarterly	high	and	low	sales	prices	for	the	common	stock	as	reported	in	the	consolidated	transaction	reporting	system	and the	frequency	and	amount	of	dividends	paid	during	the	last	two	years	is	set	forth	in	Financial	Statements	and	Supplementary	Data	–	Selected	Quarterly	Financial	Data.

As	of	January	31,	2008,	there	were	59,638	registered	holders	of	Marathon	common	stock.

# 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

Marathon's	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	its	dividend	policy with	respect	to	Marathon	common	stock,	the	Board	will	rely	on	the	consolidated	financial	statements	of	Marathon.	Dividends	on	Marathon	common	stock	are	limited	to legally	available	funds	of	Marathon.

# Issuer	Purchases	of	Equity	Securities

The	following	table	provides	information	about	purchases	by	Marathon	and	its	affiliated	purchaser	during	the	quarter	ended	December	31,	2007	of	equity	securities that	are	registered	by	Marathon	pursuant	to	Section	12	of	the	Securities	Exchange	Act	of	1934:

|  | (a) | (b) | (c) | (d) |
| :--- | :--- | :--- | :--- | :--- |
|  |  |  | Total | Approximate |
|  |  |  | Number | Dollar\tValue |
|  |  |  | of\tShares | of\tShares |
|  |  |  | Purchased | that\tMay\tYet |
|  |  |  | as\tPart\tof | Be |
|  |  |  | Publicly | Purchased |
|  | Total\tNumber | Average | Announced | Under\tthe |
|  | of\tShares | Price\tPaid | Plans\tor | Plans\tor |
| Period | Purchased(a)(b) | per\tShare | Programs(d) | Programs(d) |
| 10/01/07\t–\t10/31/07 | 27,708 | $57.10 | – | $2,497,064,359 |
| 11/01/07\t–\t11/30/07 | 8,730 | $58.86 | – | $2,497,064,359 |
| 12/01/07\t–\t12/31/07 | 426,422(c) | $59.39 | 385,900 | $2,474,099,898 |
| Total | 462,860 | $59.24 | 385,900 |  |
| (a) |  |  |  |  |

(a) 49,120	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	Marathon	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.	Marathon	acquired	22	shares	due	to	acquisition	share	exchanges	and	Ashland	share	transfers	pending	at	the	closing	of	the	transaction. (c) 27,818	shares	were	repurchased	in	open-market	transactions	to	satisfy	the	requirements	for	dividend	reinvestment	under	the	Marathon	Oil	Corporation	Dividend	Reinvestment	and	Direct	Stock	Purchase	Plan	(the "Dividend	Reinvestment	Plan")	by	the	administrator	of	the	Dividend	Reinvestment	Plan.	Stock	needed	to	meet	the	requirements	of	the	Dividend	Reinvestment	Plan	are	either	purchased	in	the	open	market	or issued	directly	by	Marathon.

(d) In	January	2006,	Marathon	announced	a	$2	billion	share	repurchase	program	which	was	increased	by	$500	million	in	both	January	and	May	2007	and	by	$2	billion	in	July	2007,	for	a	total	authorized	program	of $5	billion.	As	of	December	31,	2007,	58	million	split-adjusted	common	shares	had	been	acquired	at	a	cost	of	$2.520	billion,	which	includes	transaction	fees	and	commissions	that	are	not	reported	in	the	table above.

# Item	6. Selected	Financial	Data

| (In	millions,	except	per	share	data) | 2007(a) | 2006 | 2005(b) | 2004 | 2003 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Statement\tof\tIncome\tData: |  |  |  |  |  |
| Revenues(c) | $64,552 | $64,896 | $62,986 | $49,465 | $ 40,907 |
| Income\tfrom\tcontinuing\toperations | 3,948 | 4,957 | 3,006 | 1,294 | 1,010 |
| Net\tincome | 3,956 | 5,234 | 3,032 | 1,261 | 1,321 |
| Basic\tper\tshare\tdata: |  |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $5.72 | $6.92 | $4.22 | $1.92 | $1.63 |
| Net\tincome | $5.73 | $7.31 | $4.26 | $1.87 | $2.13 |
| Diluted\tper\tshare\tdata: |  |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $5.68 | $6.87 | $4.19 | $1.91 | $1.63 |
| Net\tincome | $5.69 | $7.25 | $4.22 | $1.86 | $2.13 |
| Statement\tof\tCash\tFlows\tData: |  |  |  |  |  |
| Capital\texpenditures\tfrom\tcontinuing\toperations | $4,466 | $3,433 | $2,796 | $2,141 | $1,873 |
| Dividends\tpaid | 637 | 547 | 436 | 348 | 298 |
| Dividends\tpaid\tper\tshare | $0.92 | $0.76 | $0.60 | $0.51 | $0.48 |
| Balance\tSheet\tData\tas\tof\tDecember\t31: |  |  |  |  |  |
| Total\tassets | $42,746 | $30,831 | $28,498 | $23,423 | $ 19,482 |
| Total\tlong-term\tdebt,\tincluding\tcapitalized\tleases | 6,084 | 3,061 | 3,698 | 4,057 | 4,085 |
| (a) |  |  |  |  |  |

(b) On	June	30,	2005,	Marathon	acquired	the	38	percent	ownership	interest	in	MPC	previously	held	by	Ashland,	making	it	wholly-owned	by	Marathon.	See	Note	6	to	the	consolidated	financial	statements (c) Effective	April	1,	2006,	Marathon	changed	its	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

Marathon	is	engaged	in	worldwide	exploration,	production	and	marketing	of	liquid	hydrocarbons	and	natural	gas;	mining,	extraction	and	transportation	of	bitumen from	oil	sands	deposits	in	Alberta,	Canada,	and	upgrading	of	the	bitumen	for	the	production	and	marketing	of	synthetic	crude	oil	and	by-products;	domestic	refining, marketing	and	transportation	of	crude	oil	and	petroleum	products,	primarily	in	the	Midwest,	upper	Great	Plains,	Gulf	Coast	and	southeastern	regions	of	the	United States;	and	worldwide	marketing	and	transportation	of	products	manufactured	from	natural	gas,	such	as	LNG	and	methanol,	and	development	of	other	projects	to	link stranded	natural	gas	resources	with	key	demand	areas.	Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	should	be	read	in conjunction	with	the	information	under	Business,	Risk	Factors,	Selected	Financial	Data	and	Financial	Statements	and	Supplementary	Data.

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	EGHoldings.	As	discussed	in	Note	4	to	the	consolidated	financial	statements,	effective	May	1,	2007,	we	no	longer	consolidate EGHoldings.	Our	investment	is	accounted	for	prospectively	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.	Unless	specifically	noted,	amounts	for	the	RM&T	segment	include	the	38 percent	interest	in	MPC	held	by	Ashland	prior	our	acquisition	of	that	interest	on	June	30,	2005.

# Overview

On	October	18,	2007,	we	completed	the	acquisition	of	all	the	outstanding	shares	of	Western	for	cash	and	securities	of	$5.833	billion.	Western's	debt	was	$1.063 billion	at	closing.	Western's	primary	asset	was	a	20	percent	outside-operated	interest	in	the	AOSP,	which	is	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.

Exploration	and	Production	segment	revenues	correlate	with	prevailing	prices	for	the	various	qualities	of	crude	oil	and	natural	gas	we	produce.	Higher	crude	oil prices	in	2007	primarily	reflected	increasing	global	demand	and	ongoing	concerns	about	supplies	of	crude	oil	from	oil-producing	countries.	During	2007,	the	average spot	price	per	barrel	for	West	Texas	Intermediate	("WTI"),	a	benchmark	crude	oil,	was	$72.41,	up	from	an	average	of	$66.25	in	2006,	and	ended	the	year	at	$95.98. During	2007,	the	average	spot	price	per	barrel	for	Dated	Brent	("Brent"),	an	international	benchmark	crude	oil,	was	$72.39,	up	from	an	average	of	$65.14	in	2006,	and ended	the	year	at	$96.02.	The	differential	between	WTI	and	Brent	average	prices	narrowed	to	$0.02	in	2007	from	$1.11	in	2006.	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	were	lower	in	2007	than	in	2006.	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	$0.38	per	thousand	cubic	feet	("mcf")	lower	in	2007	than the	2006	average.	Our	natural	gas	prices	in	Alaska	are	largely	contractual.	Natural	gas	sales	there	are	seasonal	in	nature,	trending	down	during	the	second	and	third quarters	of	each	year	and	increasing	during	the	fourth	and	first

quarters.	Our	other	major	natural	gas-producing	regions	are	Europe	and	Equatorial	Guinea,	where	large	portions	of	our	natural	gas	are	sold	at	contractual	prices,	making realized	prices	in	these	areas	less	volatile.	The	significant	increase	in	sales	of	natural	gas	in	Equatorial	Guinea,	at	a	fixed	price,	to	the	new	LNG	production	facility discussed	below	contributed	to	the	decrease	in	our	average	international	realized	natural	gas	prices.

For	information	on	commodity	price	risk	management,	see	Quantitative	and	Qualitative	Disclosures	about	Market	Risk.

E&P	segment	income	during	2007	was	down	14	percent	from	2006,	primarily	as	a	result	of	lower	liquid	hydrocarbon	sales	volumes	and	natural	gas	realizations	and increased	exploration	expenses,	partially	offset	by	higher	liquid	hydrocarbon	realizations	and	natural	gas	sales	volumes.

Our	oil	sands	mining	and	bitumen	upgrading	operations	were	acquired	in	October	2007	as	part	of	our	acquisition	of	Western	and	are	comprised	of	a	20	percent outside-operated	interest	in	the	AOSP,	which	includes	the	operating	Muskeg	River	mine	and	the	Scotford	upgrader,	located	in	Alberta,	Canada.	The	bitumen	production from	the	Muskeg	River	mine	is	taken	by	pipeline	to	the	Scotford	upgrader,	which	uses	hydro-conversion	technology	to	upgrade	the	bitumen	into	a	range	of	high-quality, synthetic	crude	oils.	When	the	AOSP	is	operating	at	current	capacity,	our	net	bitumen	production	is	30	mbpd,	but	operations	were	curtailed	at	the	Scotford	upgrader subsequent	to	the	Western	acquisition	date	due	to	a	mid-November	fire.	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.

Oil	Sands	Mining	segment	revenues	correlate	with	prevailing	prices	for	the	various	qualities	of	synthetic	crude	oil	we	produce	and	the	cost	of	materials	and	supplies input	during	the	upgrading	process	also	correlate	with	market	prices	for	commodities.	The	operating	cost	structure	of	the	oil	sands	mining	operations	is	predominantly fixed,	and	therefore	many	of	the	costs	incurred	when	the	AOSP	is	in	full	operation	continue	during	any	production	downtime.	This	had	a	negative	effect	on	segment income	subsequent	to	the	acquisition	date	as	a	result	of	the	downtime	associated	with	the	fire	and	maintenance	activities	discussed	above.

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.

The	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,	the	costs	of	purchased	products	and	manufacturing	expenses,	including	depreciation.	As	a	result,	our	refining	and	wholesale	marketing	gross	margin could	be	adversely	affected	by	rising	crude	oil	and	other	charge	and	blendstock	prices	that	are	not	recovered	in	the	marketplace.	The	crack	spread,	which	is	generally	a measure	of	the	difference	between	market	prices	for	gasoline	and	distillate	and	crude	oil	costs,	is	a	commonly	used	industry	indicator	of	refining	margins.	In	addition	to changes	in	the	crack	spread,	our	refining	and	wholesale	marketing	gross	margin	is	impacted	by	the	types	of	crude	oil	and	other	charge	and	blendstocks	we	process,	the selling	prices	we	realize	for	all	the	refined	products	we	sell,	the	cost	of	purchased	products,	our	level	of	manufacturing	costs	and	the	impact	of	commodity	derivative instruments	we	use	in	our	RM&T	operations	primarily	to	mitigate	price	risk	between	the	time	that	crude	oil	purchases	are	priced	and	when	they	are	actually	refined	into salable	petroleum	products.	We	process	significant	amounts	of	sour	crude	oil	which	enhances	our	profitability	compared	to	certain	of	our	competitors	as	sour	crude	oil typically	can	be	purchased	at	a	discount	to	sweet	crude	oil.	Over	the	last	three	years,	58	percent	of	the	crude	oil	throughput	at	our	refineries	has	been	sour	crude	oil.	As one	of	the	largest	U.S.	producers	of	asphalt,	our	refining	and	wholesale	marketing	gross	margin	is	also	impacted	by	the	selling	price	of	asphalt.	Sales	of	asphalt	increase during	the	highway	construction	season	in	our	market	area,	which	is	typically	in	the	second	and	third	quarters	of	each	year.	The	selling	price	of	asphalt	is	dependent	on the	cost	of	crude	oil,	the	price	of	alternative	paving	materials	and	the	level	of	construction	activity	in	both	the	private	and	public	sectors.	We	supplement	our	refining production	by	purchasing	gasolines	and	distillates	in	the	spot	market	to	resell	at	wholesale.	In	addition,	we	purchase	ethanol	for	blending	with	gasoline.	Our	refining	and wholesale	marketing	gross	margin	is	impacted	by	the	cost	of	these

purchased	products,	which	varies	with	available	supply	and	demand.	Finally,	our	refining	and	wholesale	marketing	gross	margin	is	impacted	by	changes	in manufacturing	costs	from	period	to	period,	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	refining	and	wholesale	marketing	gross	margin	has	been	historically	volatile	and	varies	with	the	level	of	economic	activity	in	our	various	marketing areas,	the	availability	of	refined	product	supply,	the	regulatory	climate,	logistical	capabilities	and	expectations	regarding	the	adequacy	of	refined	products,	ethanol	and raw	material	supplies.

Our	2007	refining	and	wholesale	marketing	gross	margin	was	the	key	driver	of	the	26	percent	decrease	in	RM&T	segment	income	when	compared	to	2006.	The average	refining	and	wholesale	marketing	gross	margin	per	gallon	decreased	to	18.48	cents	in	2007	from	22.88	cents	in	2006,	primarily	due	to	the	significant	and	rapid increases	in	crude	oil	prices	during	2007	and	lagging	wholesale	price	realizations.

Our	seven	refineries	have	an	aggregate	refining	capacity	of	1.016	mmbpd	of	crude	oil.	During	2007,	our	refineries	processed	1.010	mmbpd	of	crude	oil	and	214 mbpd	of	other	charge	and	blend	stocks.

Our	retail	marketing	gross	margin	for	gasoline	and	distillates,	which	is	the	difference	between	the	ultimate	price	paid	by	consumers	and	the	cost	of	the	refined products,	including	secondary	transportation	and	consumer	excise	taxes,	also	plays	an	important	part	in	RM&T	segment	profitability.	Factors	affecting	our	retail gasoline	and	distillate	gross	margin	include	competition,	seasonal	demand	fluctuations,	the	available	wholesale	supply,	the	level	of	economic	activity	in	our	marketing areas	and	weather	conditions	that	impact	driving	conditions.	The	gross	margin	on	merchandise	sold	at	retail	outlets	tends	to	be	less	volatile	than	the	gross	margin	from the	retail	sale	of	gasoline	and	distillates.	Factors	affecting	the	gross	margin	on	retail	merchandise	sales	include	consumer	demand	for	merchandise	items,	the	impact	of competition	and	the	level	of	economic	activity	in	our	marketing	areas.

The	profitability	of	our	pipeline	transportation	operations	is	primarily	dependent	on	the	volumes	shipped	through	the	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	driving	season,	which	extends	from	May	through September	of	each	year,	and	declines	during	the	fall	and	winter	months.	The	seasonal	pattern	for	distillates	is	the	reverse	of	this,	helping	to	level	overall	variability	on	an annual	basis.	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	production	facility	in	Equatorial	Guinea	that	commenced	operations	during	2007	is	a	key	component	of	this	strategy.	Our	integrated	gas	operations	include marketing	and	transportation	of	products	manufactured	from	natural	gas,	such	as	LNG	and	methanol,	primarily	in	the	United	States,	Europe	and	West	Africa.	Methanol spot	pricing	is	volatile	largely	because	global	methanol	demand	is	38	million	tonnes	and	any	major	unplanned	shutdown	of	or	addition	to	production	capacity	can	have	a significant	impact	on	the	supply-demand	balance.	Also	included	in	the	financial	results	of	the	Integrated	Gas	segment	are	the	costs	associated	with	ongoing	development of	integrated	gas	projects,	including	natural	gas	technology	research.

# 2007	Highlights

•	 We	acquired	Western	and,	as	a	result,	added	421	million	barrels	of	net	proved	bitumen	reserves.

•	 We	announced	the	Droshky	discovery	and	two	appraisal	sidetrack	wells	in	the	Gulf	of	Mexico	and	eight	discoveries	in	deepwater	Angola	and	continued	our Alvheim/Vilje	and	Neptune	development	projects.

•	 We	added	net	proved	liquid	hydrocarbon	and	natural	gas	reserves	of	88	million	boe,	while	producing	125	million	boe	during	2007.	Over	the	past	three	years, we	have	added	net	proved	reserves	of	516	million	boe,	excluding	dispositions	of	46	million	boe,	while	producing	383	million	boe.

•	 We	achieved	record	refinery	crude	oil	and	total	throughput	and	strengthened	our	RM&T	business	by:

¡ 	 Commencing	construction	of	the	Garyville,	Louisiana,	refinery	expansion;

¡ 	 Approving	a	heavy	oil	upgrading	and	expansion	project	at	the	Detroit,	Michigan,	refinery;	and

¡ 	 Continuing	our	investment	in	transportation	and	storage	assets	to	increase	our	ethanol	blending	capacity	throughout	our	terminal	network	and	in ethanol	production	assets	to	further	ensure	the	security	of	our	supply	of	ethanol.

•	 We	completed	construction	of	the	Equatorial	Guinea	LNG	production	facility	ahead	of	schedule	and	on	budget	and	commenced	operations.

•	 We	focused	on	total	shareholder	return	by:

¡ 	 Repurchasing	16	million	common	shares	in	2007,	bringing	the	total	repurchases	under	our	$5	billion	program	to	58	million	common	shares	through 2007	at	a	cost	of	$2.520	billion;

¡ Increasing	our	quarterly	dividend	per	share	by	20	percent	;	and

¡ 	 Completing	a	two-for-one	common	stock	split.

# Critical	Accounting	Estimates

The	preparation	of	financial	statements	in	accordance	with	generally	accepted	accounting	principles	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,	economic	and	political	conditions	change.	During	2007,	net	revisions	of	previous	estimates increased	total	proved	reserves	by	4	million	boe	(less	than	1	percent	of	the	beginning-of-the-year	reserves	estimate).	Positive	revisions	of	32	million	boe	were	partially offset	by	28	million	boe	in	negative	revisions.

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	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)."	Reserve	estimates	are reviewed	and	approved	by	members	of	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	rank	in	the	top	80	percent	of	our	total	reserves	over	a	rolling	four-year period.	The	volumes	independently	estimated	are	targeted	to	total	at	least	80	percent	of	our	total	reserves	at	the	beginning	of	the	fourth	year.	We	met	this	goal	for	the four-year	period	ended	December	31,	2007.	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	would	adjust	our	reserve	estimates	as	necessary.	This	independent third-party	reserve	estimation	process	did	not	result	in	significant	changes	to	our	reserve	estimates	in	2007,	2006	or	2005.

The	reserves	of	the	Alba	field	in	Equatorial	Guinea	comprise	39	percent	of	our	total	proved	liquid	hydrocarbon	and	natural	gas	reserves	as	of	December	31,	2007. The	reserves	of	the	next	five	largest	asset	groups	–	the	Waha	concessions	in	Libya,	the	Alvheim/Vilje	development	offshore	Norway,	the	Brae	area	complex	offshore	the United	Kingdom,	the	Oregon	Basin	field	in	the	Rocky	Mountain	area	of	the	United	States	and	the	Petronius	development	on	Viosca	Knoll	Blocks	786	and	830	in	the Gulf	of	Mexico	–	comprise	31	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	$0.66	per	barrel,	which	would	increase	pretax	income	by	approximately	$85	million	annually,	based	on	2007	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	$0.81	per	barrel and	would	result	in	a	decrease	in	pretax	income	of	approximately	$104	million	annually,	based	on	2007	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.

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	allocating	the	Western	acquisition	purchase	price	and	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,	2007	were	estimated	using	volumetric	estimation	techniques	similar	to	those	used	in estimating	liquid	hydrocarbon	and	natural	gas	reserves.	Proved	bitumen	reserves	were	estimated	at	October	18,	2007,	the	date	of	the	Western	acquisition,	based	on	the third-party	consultants'	estimate	as	of	December	31,	2006,	adjusted	for	production	through	the	acquisition	date.

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.	A	five	percent

increase	in	estimated	bitumen	reserves	would	lower	the	depreciation	and	depletion	rate	by	approximately	$0.70	per	barrel,	and	a	five	percent	decrease	in	estimated bitumen	reserves	would	increase	the	depreciation	and	depletion	rate	by	approximately	$0.77	per	barrel.

# Fair	Value	Estimates

We	are	required	to	develop	estimates	of	fair	value	to	allocate	the	purchase	prices	paid	to	acquire	businesses	to	the	assets	acquired	and	liabilities	assumed	in	those acquisitions,	to	assess	impairment	of	long-lived	assets,	goodwill	and	intangible	assets	and	to	record	non-exchange	traded	derivative	instruments.	Other	items	that	require fair	value	estimates	include	asset	retirement	obligations,	guarantee	obligations	and	stock-based	compensation.

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.	The	most	difficult	estimations	of	individual	fair	values	are	those	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.	During	2007,	we	made	a	significant	acquisition	with	an	aggregate	purchase	price	of	$5.833	billion	that	was	allocated	to	the	assets	acquired	and liabilities	assumed	based	on	their	estimated	fair	values.	See	Note	6	to	the	consolidated	financial	statements	for	information	on	this	acquisition.	We	did	not	make	any significant	acquisitions	in	2006.	As	of	December	31,	2007,	our	recorded	goodwill	was	$2.899	billion.	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	its	carrying	value.

The	fair	values	used	to	allocate	the	purchase	price	of	an	acquisition	and	to	test	goodwill	for	impairment	are	often	estimated	using	the	expected	present	value	of future	cash	flows	method,	which	requires	us	to	project	related	future	revenues	and	expenses	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	and	unpredictable.	Accordingly,	actual	results	may	differ	from	the projected	results	used	to	determine	fair	value.

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,	expansion	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.

Estimating	the	expected	future	cash	flows	from	our	oil	and	gas	producing	asset	groups	and	our	oil	sands	mining	and	bitumen	upgrading	assets	requires	assumptions about	matters	such	as	future	liquid	hydrocarbon	and	natural	gas	prices,	estimated	recoverable	quantities	of	liquid	hydrocarbons,	natural	gas	and	bitumen,	expected timing	of	production	and	the	political	environment	in	the	host	country.	An	impairment	of	any	of	our	large	oil	and	gas	producing	properties	or	our	oil	sands	mining	and bitumen	upgrading	assets	could	have	a	material	impact	on	our	consolidated	financial	condition	and	results	of	operations.

We	evaluate	our	unproved	property	investment	for	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	and/or	future	plans	to	develop	acreage	are	also	considered.	The	expected future	cash	flows	from	our	RM&T	assets	require	assumptions	about	matters	such	as	future	refined	product	prices,	future	crude	oil	and	other	feedstock	costs,	estimated remaining	lives	of	the	assets	and	future	expenditures	necessary	to	maintain	the	assets'	existing	service	potential.

Impairment	charges	have	not	been	significant,	totaling	$19	million	and	$25	million	in	2007	and	2006,	while	there	were	no	impairment	charges	in	2005.

We	record	all	derivative	instruments	at	fair	value.	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	expire	in	September	2009.	These	contracts	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	next	18	months.	Beginning	in	the	second	quarter	of	2008,	the	remaining	contract	terms	will	be	less	than	18	months	and	therefore	the	forecasted valuation	period	will	be	reduced	accordingly.	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.	In	2007,	2006	and	2005,	non-cash	losses	of	$232	million,	gains	of	$454	million	and	losses	of	$386	million	related	to	changes	in	the	fair	values	of	these contracts	were	recognized	in	income	from	operations.	These	effects	are	primarily	due	to	the	U.K.	18-month	forward	natural	gas	price	curve	strengthening	45	percent	in 2007,	weakening	44	percent	in	2006	and	strengthening	90	percent	in	2005.

# Expected	Future	Taxable	Income

We	must	estimate	our	expected	future	taxable	income	to	assess	the	realizability	of	our	deferred	income	tax	assets.	As	of	December	31,	2007,	we	reported	total deferred	tax	assets	of	$2.589	billion,	which	represented	gross	assets	of	$3.590	billion	net	of	valuation	allowances	of	$1.001	billion.

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	and	possible	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	propriety	of	releasing	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	12	years.	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.

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.

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	24	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	2007,	2006	and	2005,	as	well	as	the	obligations	and	accumulated	other	comprehensive	income	reported	on	the	balance sheets	as	of	December	31,	2007	and	2006.

Of	the	assumptions	used	to	measure	the	December	31,	2007	obligations	and	estimated	2008	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	6.3	percent	for	our	U.S.	pension	plans	and	6.6	percent	for	our other	U.S.	postretirement	benefit	plans	would	increase	pension	obligations	and	other	postretirement	benefit	plan	obligations	by	$95	million	and	$23	million	and	would increase	defined	benefit	pension	expense	and	other	postretirement	benefit	plan	expense	by	$14	million	and	$1	million.

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.	In	2005,	we	decreased	our retirement	age	assumption	by	two	years	and	also	increased	our	lump	sum	election	rate	from	90	percent	to	96	percent	based	on	changing	trends	in	our	experience.	This change	increased	our	benefit	obligations	by	$109	million.	There	were	no	plan	design	changes	in	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.

# Management's	Discussion	and	Analysis	of	Results	of	Operations

# Change	in	Accounting	for	Matching	Buy/Sell	Transactions

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.	Effective	for	contracts	entered	into	or modified	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	will	continue	to	be	reported	on	a	"gross"	basis.	This	accounting	change	had	no	effect	on	net	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.	See	Note	2	to	the consolidated	financial	statements.

Additionally,	this	accounting	change	impacts	the	comparability	of	certain	operating	statistics,	most	notably	"refining	and	wholesale	marketing	gross	margin	per gallon."	While	this	change	does	not	have	an	effect	on	the	refining	and	wholesale	marketing	gross	margin	(the	numerator	for	calculating	this	statistic),	sales	volumes	(the denominator	for	calculating	this	statistic)	recognized	after	April	1,	2006	are	less	than	the	amount	that	would	have	been	recognized	under	previous	accounting	practices because	volumes	related	to	matching	buy/sell	transactions	under	contracts	entered	into	or	modified	on	or	after	April	1,	2006	have	been	excluded.	Accordingly,	the resulting	refining	and	wholesale	marketing	gross	margin	per	gallon	statistic	will	be	higher	than	that	same	statistic	calculated	from	amounts	determined	under	previous accounting	practices.

As	a	result,	this	accounting	change	impacts	the	comparability	of	revenues,	cost	of	revenues	and	the	refining	and	wholesale	marketing	gross	margin	per	gallon	for	all periods	presented.

# Consolidated	Results	of	Operations

Revenues	for	each	of	the	last	three	years	are	summarized	in	the	following	table.

| (In	millions) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| E&P | $9,155 | $9,010 | $8,009 |
| OSM | 221 | — | — |
| RM&T | \t 56,075 | \t 55,941 | \t 56,003 |
| IG | 218 | 179 | 236 |
| Segment\trevenues | \t 65,669 | \t 65,130 | \t 64,248 |
| Elimination\tof\tintersegment\trevenues | (885) | (688) | (876) |
| Gain\t(loss)\ton\tlong-term\tU.K.\tgas\tcontracts | (232) | 454 | (386) |
| Total\trevenues | $64,552 | $64,896 | $62,986 |
| Items\tincluded\tin\tboth\trevenue\tand\tcosts\tand\texpenses: |  |  |  |
| Consumer\texcise\ttaxes\ton\tpetroleum\tproducts\tand\tmerchandise | $5,163 | $4,979 | $4,715 |
| Matching\tcrude\toil\tand\trefined\tproduct\tbuy/sell\ttransactions\tsettled\tin\tcash: |  |  |  |
| E&P | — | 16 | 123 |
| RM&T | 127 | 5,441 | \t 12,513 |
| Total\tbuy/sell\ttransactions\tincluded\tin\trevenues | $127 | $5,457 | $12,636 |

E&P	segment	revenues	increased	$145	million	in	2007	from	2006	and	$1.001	billion	in	2006	from	2005.	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	to	the	start-up	of	the	LNG	production	facility	in	Equatorial	Guinea	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.

The	2006	increase	was	primarily	in	international	revenues	due	to	higher	realized	liquid	hydrocarbon	prices	and	sales	volumes	as	illustrated	in	the	table	below.	The largest	liquid	hydrocarbon	sales	volume	increase	was	in	Libya,	where	the	first	crude	oil	sales	occurred	in	the	first	quarter	of	2006	and	where	sales	volumes	averaged	54 mbpd	in	2006,	including	a	total	of	8	mbpd	that	were	owed	to	our	account	upon	the	resumption	of	our	operations	there.	Revenues	from	domestic	operations	were	flat from	year	to	year.	An	8	percent	decrease	in	domestic	net	natural	gas	sales	volumes,	primarily	as	the	result	of	the	Camden	Hills	field	in	the	Gulf	of	Mexico	ceasing production	in	early	2006,	offset	the	benefit	of	higher	liquid	hydrocarbon	prices	in	2006.

| E&P	OPERATING	STATISTICS | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Net\tLiquid\tHydrocarbon\tSales\t(thousands\tof\tbarrels\tper\tday)(a) |  |  |  |
| United\tStates | 64 | 76 | 76 |
| Europe(b) | 33 | 35 | 36 |
| Africa(b) | 100 | 112 | 52 |
| Total\tInternational(b) | 133 | 147 | 88 |
| Worldwide\tContinuing\tOperations | 197 | 223 | 164 |
| Discontinued\tOperations(c) | — | 12 | 27 |
| WORLDWIDE | 197 | 235 | 191 |
| Net\tNatural\tGas\tSales\t(millions\tof\tcubic\tfeet\tper\tday)(d)(e) |  |  |  |
| United\tStates | 477 | 532 | 578 |
| Europe | 216 | 243 | 262 |
| Africa | 232 | 72 | 92 |
| Total\tInternational | 448 | 315 | 354 |
| WORLDWIDE | 925 | 847 | 932 |
| Total\tWorldwide\tSales\t(thousands\tof\tbarrels\tof\toil\tequivalent\tper\tday) |  |  |  |
| Continuing\tOperations | 351 | 365 | 319 |
| Discontinued\tOperations | — | 12 | 27 |
| WORLDWIDE | 351 | 377 | 346 |
| Average\tRealizations(f) |  |  |  |
| Liquid\tHydrocarbons\t(dollars\tper\tbarrel) |  |  |  |
| United\tStates | $60.15 | $54.41 | $45.41 |
| Europe | \t 70.31 | \t 64.02 | \t 52.99 |
| Africa | \t 66.09 | \t 59.83 | \t 46.27 |
| Total\tInternational | \t 67.15 | \t 60.81 | \t 49.04 |
| Worldwide\tContinuing\tOperations | \t 64.86 | \t 58.63 | \t 47.35 |
| Discontinued\tOperations | — | \t 38.38 | \t 33.47 |
| WORLDWIDE | $64.86 | $57.58 | $45.42 |
| Natural\tGas\t(dollars\tper\tthousand\tcubic\tfeet) |  |  |  |
| United\tStates | $5.73 | $5.76 | $6.42 |
| Europe | 6.53 | 6.74 | 5.70 |
| Africa | 0.25 | 0.27 | 0.25 |
| Total\tInternational | 3.28 | 5.27 | 4.28 |
| WORLDWIDE | $4.54 | $5.58 | $5.61 |
| Includes\tcrude\toil,\tcondensate\tand\tnatural\tgas\tliquids.\n(a) |  |  |  |

(a) Includes	crude	oil,	condensate	and	natural	gas	liquids. (b) 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. (c) Represents	Marathon's	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,	46	and	38	mmcfd	in	2007,	2006	and	2005.

(f) Excludes	gains	and	losses	on	traditional	derivative	instruments	and	the	unrealized	effects	of	long-term	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	and	$7	million	in	2006	and	2005.	Excluded	from	E&P	segment revenues	were	losses	of	$232	million	in	2007,	gains	of	$454	million	in	2006	and	losses	of	$386	million	in	2005	related	to	long-term	natural	gas	sales	contracts	in	the United	Kingdom	that	are	accounted	for	as	derivative	instruments.	See	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	conjuction	with	the	necessary	repairs.	The	Scotford	upgrader	returned	to	operation	in	late	December.

RM&T	segment	revenues	increased	$134	million	in	2007	from	2006	and	decreased	$62	million	in	2006	from	2005.	The	portion	of	RM&T	revenues	reported	for matching	buy/sell	transactions	decreased	$5.314	billion	and	$7.072	billion	in	the	same	periods.	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.	The	2006	increase	primarily	reflected	higher	refined	product	prices	and	sales	volumes.

Income	from	equity	method	investments	increased	$154	million	in	2007	from	2006	and	$126	million	in	2006	from	2005.	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.	Income	from	our LPG	operations,	also	in	Equatorial	Guinea,	increased	in	2006	due	to	higher	sales	volumes	as	a	result	of	the	plant	expansions	completed	in	2005.

Cost	of	revenues	increased	$6.689	billion	in	2007	from	2006	and	$4.609	billion	in	2006	from	2005.	In	both	periods	the	increases	were	primarily	in	the	RM&T segment	and	resulted	from	increases	in	acquisition	costs	of	crude	oil,	refinery	charge	and	blend	stocks	and	purchased	refined	products.	The	increases	in	both	periods were	also	impacted	by	higher	manufacturing	expenses,	primarily	planned	maintenance	projects,	or	turnarounds,	in	2007	and	higher	contract	services	and	labor	costs	in 2006.

Purchases	related	to	matching	buy/sell	transactions	decreased	$5.247	billion	in	2007	from	2006	and	$6.968	billion	in	2006	from	2005	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	and	$215	million	in	2006	from	2005.	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.	The	increase in	2006	included	higher	RM&T	depreciation	expense	primarily	as	a	result	of	the	increase	in	asset	value	recorded	for	our	acquisition	of	the	38	percent	interest	in	MPC	on June	30,	2005,	and	the	completion	of	the	Detroit	refinery	expansion	in	the	fourth	quarter	of	2005.

Selling,	general	and	administrative	expenses	increased	$99	million	in	2007	from	2006	and	$73	million	in	2006	from	2005.	The	2007	and	2006	increases	were primarily	because	personnel	and	staffing	costs	increased	throughout	the	years	as	a	result	of	variable	compensation	arrangements	and	increased	business	activity. Contingency	accruals	also	contributed	to	the	2007	increase.	Partially	offsetting	the	2006	increases	were	reductions	in	stock-based	compensation	expense.

Exploration	expenses	increased	$89	million	in	2007	from	2006	and	$148	million	in	2006	from	2005.	Exploration	expenses	related	to	dry	wells	and	other	write- offs	totaled	$233	million,	$166	million	and	$111	million	in	2007,	2006	and	2005.	In	2006,	exploration	expenses	also	included	$47	million	for	exiting	the	Cortland	and Empire	leases	in	Nova	Scotia.

Net	interest	and	other	financial	income	or	costs	reflected	$41	million	of	income	for	2007,	a	favorable	change	of	$4	million	from	2006.	Net	interest	and	other financial	income	or	costs	reflected	$37	million	of	income	for	2006,	a	favorable	change	of	$183	million	from	$146	million	of	expense	in	2005.	The	favorable	changes	in 2006	included	increased	interest	income	due	to	higher	interest	rates	and	average	cash	balances,	foreign	currency	exchange	gains,	adjustments	to	interest	on	tax	issues	and greater	capitalized	interest.	Included	in	net	interest	and	other	financial	income	or	costs	are	foreign	currency	transaction	gains	of	$2	million	and	$16	million	for	2007	and 2006,	and	losses	of	$17	million	for	2005.

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.

Minority	interest	in	income	of	MPC	was	eliminated	subsequent	to	our	acquisition	of	the	38	percent	interest	in	MPC	on	June	30,	2005.

Provision	for	income	taxes	decreased	$1.121	billion	in	2007	from	2006	and	increased	$2.308	billion	in	2006	from	2005,	primarily	due	to	the	$2.130	billion decrease	and	the	$4.259	billion	increase	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	increase	in	our	effective	income	tax	rate	in	2006	was	primarily	a	result	of	the income	taxes	related	to	our	Libya	operations,	where	the	statutory	income	tax	rate	is	in	excess	of	90	percent.	The	following	is	an	analysis	of	the	effective	income	tax rates	for	continuing	operations	for	2007,	2006	and	2005.	See	Note	11	to	the	consolidated	financial	statements.

|  | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Statutory\tU.S.\tincome\ttax\trate | 35.0% | 35.0% | 35.0% |
| Effects\tof\tforeign\toperations,\tincluding\tforeign\ttax\tcredits | 9.8 | 10.1 | (0.8) |
| State\tand\tlocal\tincome\ttaxes,\tnet\tof\tfederal\tincome\ttax\teffects | 2.0 | 1.9 | 2.8 |
| Effects\tof\tenacted\tchanges\tin\ttax\tlaws | (2.8) | (0.2) | (0.3) |
| Other\ttax\teffects | (1.6) | (2.0) | (0.4) |
| Effective\tincome\ttax\trate\tfor\tcontinuing\toperations | 42.4% | 44.8% | 36.3% |

Discontinued	operations	for	2006	and	2005	reflects	the	operations	of	our	former	Russian	oil	exploration	and	production	businesses	which	were	sold	in	June	2006. After-tax	gains	on	the	disposal	of	$8	million	and	$243	million	are	also	included	in	discontinued	operations	for	2007	and	2006.	See	Note	7	to	the	consolidated	financial statements.

Cumulative	effect	of	change	in	accounting	principle	in	2005	was	an	unfavorable	effect	of	$19	million,	net	of	taxes	of	$12	million,	representing	the	adoption	of Financial	Accounting	Standards	Board	Interpretation	("FIN")	No.	47,	"Accounting	for	Conditional	Asset	Retirement	Obligations	–	an	interpretation	of	FASB	Statement No.	143,"	as	of	December	31,	2005.

# Segment	Results

As	discussed	in	Note	7	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.

Segment	income	or	loss	for	each	of	the	last	three	years	is	summarized	and	reconciled	to	net	income	in	the	following	table.

| (In	millions) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| E&P |  |  |  |
| United\tStates | $623 | $873 | $983 |
| International | \t 1,106 | \t 1,130 | 904 |
| E&P\tsegment\tincome | \t 1,729 | \t 2,003 | \t 1,887 |
| OSM | (63) | — | — |
| RM&T | \t 2,077 | \t 2,795 | \t 1,628 |
| IG | 132 | 16 | 55 |
| Segment\tincome | \t 3,875 | \t 4,814 | \t 3,570 |
| Items\tnot\tallocated\tto\tsegments,\tnet\tof\tincome\ttaxes: |  |  |  |
| Corporate\tand\tother\tunallocated\titems | (104) | (212) | (377) |
| Gain\t(loss)\ton\tlong-term\tU.K.\tnatural\tgas\tcontracts(a) | (118) | 232 | (223) |
| Gain\ton\tforeign\tcurrency\tderivative\tinstruments | 112 | — | — |
| Deferred\tincome\ttaxes\t–\ttax\tlegislation\tchanges | 193 | 21 | 15 |
| \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 | — |
| Gain\ton\tdispositions | 8 | 274 | — |
| Loss\ton\tearly\textinguishment\tof\tdebt | (10) | (22) | — |
| Discontinued\toperations | — | 34 | 45 |
| Gain\ton\tsale\tof\tminority\tinterests\tin\tEG\tHoldings | — | — | 21 |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | — | — | (19) |
| Net\tincome | $3,956 | $5,234 | $3,032 |
| (a) |  |  |  |

(b) Other	deferred	tax	adjustments	in	2006	represent	a	benefit	recorded	for	cumulative	income	tax	basis	differences	associated	with	prior	periods.

United	States	E&P	income	decreased	$250	million,	or	29	percent,	in	2007	from	2006.	This	was	the	result	of	a	$394	million	decline	in	pretax	income,	while	the effective	income	tax	rate	remained	unchanged	at	36	percent.	The	decrease	in	pretax	income	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.

U.S.	E&P	income	decreased	$110	million	in	2006	from	2005.	This	was	the	result	of	a	$182	million	decline	in	pretax	income,	partially	offset	by	a	slight	reduction	in the	effective	income	tax	rate	from	37	percent	in	2005	to	36	percent	in	2006.	The	decrease	in	pretax	income	was	due	to	increases	in	variable	production	costs,	exploration expenses,	property	impairments	and	depreciation,	depletion	and	amortization.	Exploration	expenses	in	2006	were	$51	million	higher	than	in	2005,	with	half	of	the increase	related	to	a	Gulf	of	Mexico	exploratory	dry	well.	As	discussed	above,	U.S.	E&P	revenues	were	flat	from	2005	to	2006.

International	E&P	income	decreased	$24	million	in	2007	from	2006,	reflecting	a	decrease	in	pretax	income	of	$79	million	and	an	effective	income	tax	rate	of	62 percent	in	both	years.	The	revenue	decrease	associated	with	lower	liquid	hydrocarbon	sales	volumes	discussed	above	had	the	most	significant	impact	on	pretax	income.

International	E&P	income	increased	$226	million,	or	25	percent,	in	2006	from	2005,	reflecting	an	increase	in	pretax	income	of	$1.639	billion	and	an	increase	in	the effective	tax	rate	from	34	percent	in	2005	to	62	percent	in	2006.	The	revenue	increase	discussed	above,	primarily	related	to	higher	liquid	hydrocarbon	realizations	and higher	liquid	hydrocarbon	sales	volumes	in	Libya,	had	the	most	significant	impact	on	pretax	income.	Depreciation,	depletion	and	amortization	and	other	variable	costs increased	with	increased	production	to	partially	offset	the	revenue	increase.	Exploration	expenses	also	increased	$97	million	in	2006	compared	to	2005.	Exploration expense	related	to	dry	wells	and	other	write-offs	was	$68	million	in	2006	and	$44	million	in	2005.	Also	included	in	2006	exploration	expense	was	$47	million	for exiting	the	Cortland	and	Empire	leases	in	Nova	Scotia.	The	increase	in	the	effective	income	tax	rate	was	primarily	the	result	of	the	income	taxes	related	to	our	Libya operations,	where	the	statutory	income	tax	rate	is	in	excess	of	90	percent,	and	the	2006	increase	in	the	U.K.	supplemental	corporation	tax	rate	from	10	percent	to	20 percent.

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 $39	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.

RM&T	segment	income	increased	$1.167	billion	in	2006	from	2005,	including	the	benefit	from	the	38	percent	minority	interest	in	MPC	that	we	acquired	on June	30,	2005.	Pretax	income	increased	$1.802	billion	in	2006	from	2005.	The	pretax	earnings	reduction	related	to	the	minority	interest	was	$376	million	in	2005.	The key	driver	of	the	increase	in	RM&T	pretax	income	was	our	refining	and	wholesale	marketing	gross	margin	per	gallon	which	averaged	22.88	cents	in	2006	compared	to 15.82	cents	in	2005.	The	increase	in	the	margin	for	2006	reflected	wider	crack	spreads,	improved	refined	product	sales	realizations,	the	favorable	effects	of	our	ethanol blending	program	and	increased	refinery	throughputs.

Included	in	the	refining	and	wholesale	marketing	gross	margins	were	pretax	losses	of	$899	million	in	2007,	gains	of	$400	million	in	2006	and	losses	of	$238 million	in	2005	related	to	commodity	derivative	instruments.	For	a	more	complete	explanation	of	our	strategies	to	manage	market	risk	related	to	commodity	prices,	see Quantitative	and	Qualitative	Disclosures	about	Market	Risk.

efficiency	gains	in	the	operation	of	the	refining	units,	reflecting	the	cumulative	effect	of	regular	maintenance,	capital	improvements	and	other	process	optimization efforts.

The	following	table	includes	certain	key	operating	statistics	for	the	RM&T	segment	for	each	of	the	last	three	years.

| RM&T	OPERATING	STATISTICS | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Refining\tand\twholesale\tmarketing\tgross\tmargin\t(dollars\tper\tgallon)(a) | $0.1848 | $0.2288 | $ 0.1582 |
| Refined\tproduct\tsales\tvolumes\t(thousands\tof\tbarrels\tper\tday)(b)(c) | 1,410 | 1,425 | 1,455 |
| Matching\tbuy/sell\tvolumes\tincluded\tin\trefined\tproduct |  |  |  |
| sales\tvolumes\t(thousands\tof\tbarrels\tper\tday)(c) | — | 24 | 77 |
| (a) |  |  |  |

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

(b) Total	average	daily	volumes	of	refined	product	sales	to	wholesale,	branded	and	retail	customers.

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

IG	segment	income	increased	$116	million	in	2007	from	2006	and	decreased	$39	million	in	2006	from	2005.	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,	partially	offset	by	higher	realized	methanol	prices.	The	provision	for	income	taxes	also	increased	$15	million	in	2006.

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

# Financial	Condition

Net	property,	plant	and	equipment	as	of	the	end	of	the	last	two	years	is	summarized	in	the	following	table.

| (In	millions) | 2007 | 2006 |
| :--- | :--- | :--- |
| E&P |  |  |
| United\tStates | $4,248 | $3,636 |
| International | 5,864 | 4,879 |
| Total\tE&P | 10,112 | 8,515 |
| OSM | 6,671 | – |
| RM&T | 7,500 | 6,452 |
| IG | 31 | 1,378 |
| Corporate | 361 | 308 |
| Total | $24,675 | $16,653 |

Net	property,	plant	and	equipment	increased	$8.022	billion	in	2007	primarily	due	to	the	addition	of	the	Oil	Sands	Mining	assets	recorded	as	a	result	of	the	Western acquisition.	The	decrease	in	integrated	gas	segment	assets	is	due	to	the	deconsolidation	of	EG	Holdings	discussed	above.

# Cash	Flows

Net	cash	provided	from	operating	activities	totaled	$6.521	billion	in	2007,	compared	to	$5.488	billion	in	2006	and	$4.738	billion	in	2005.	The	$1.033	billion increase	in	2007	primarily	reflects	working	capital	changes	partially	offset	by	lower	net	income.	The	$750	million	increase	in	2006	primarily	reflects	the	impact	of higher	net	income,	partially	offset	by	contributions	of	$635	million	to	our	defined	benefit	pension	plans	and	working	capital	changes.

Net	cash	used	in	investing	activities	totaled	$8.102	billion	in	2007,	compared	with	$2.955	billion	in	2006	and	$3.127	billion	in	2005.	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) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| E&P |  |  |  |
| United\tStates | $1,354 | $1,302 | $638 |
| International | \t 1,157 | 867 | 728 |
| Total\tE&P | \t 2,511 | \t 2,169 | \t 1,366 |
| OSM | 165 | – | – |
| RM&T | \t 1,640 | 916 | 841 |
| IG | 93 | 307 | 571 |
| Corporate | 57 | 41 | 18 |
| Total | $4,466 | $3,433 | $2,796 |

The	majority	of	the	$1.033	billion	increase	in	capital	expenditures	in	2007	over	2006	was	in	our	RM&T	segment	and	primarily	related	to	the	expansion	of	our Garyville,	Louisiana	refinery.	Spending	on	E&P	projects	increased	$342	million	over	2006,	primarily	as	a	result	of	continued	work	on	the	Alvheim/Vilje	development offshore	Norway	and	exploration	activities	in	Angola	and	the	Gulf	of	Mexico.	The	decrease	in	integrated	gas	spending	from	2006	reflects	the	completion	of	the	LNG production	facility	in	Equatorial	Guinea	in	May	2007.	The	$637	million	increase	in	capital	expenditures	in	2006	over	2005	primarily	resulted	from	increased	spending	in the	E&P	segment	and	primarily	related	to	significant	acreage	acquisitions	in	the	Williston	Basin	of	North	Dakota	and	eastern	Montana	(the	Bakken	Shale	formation)	and the	Piceance	Basin	of	Colorado,	as	well	as	to	the	Alvheim/Vilje	development	and	to	the	Neptune	development	in	the	Gulf	of	Mexico.	The	$264	million	decrease	in integrated	gas	spending	from	2005	reflected	the	fact	that	the	LNG	production	facility	in	Equatorial	Guinea	was	nearing	completion	in	2006.

Acquisitions	in	2007	consist	primarily	of	the	$3.907	billion	cash	portion	of	the	Western	acquisition	purchase	price,	net	of	the	$44	million	of	Western's	cash acquired.	In	2006,	acquisitions	primarily	included	cash	payments	of	$718	million	associated	with	our	re-entry	into	Libya	and	in	2005	included	cash	payments	of	$506 million	for	the	acquisition	of	Ashland's	38	percent	ownership	interest	in	MPC.	See	Note	6	to	the	consolidated	financial	statements.

Disposal	of	assets	and	of	discontinued	operations	totaled	$137	million,	$966	million	and	$131	million	in	2007,	2006	and	2005.	Proceeds	of	$832	million	from	the disposal	of	discontinued	operations	in	2006	related	to	the	sale	of	our	Russian	exploration	and	production	businesses	in	June	2006.	See	Note	7	to	the	consolidated financial	statements.	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.

Net	cash	provided	from	financing	activities	totaled	$184	million	in	2007,	compared	with	cash	used	in	financing	activities	of	$2.581	billion	in	2006	and	$2.345 billion	in	2005.	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	during	both	2007	and	2006	were	common	stock	repurchases	under	our	share	repurchase	plan	discussed	below,	dividend payments	and	debt	repayments	including	the	early	extinguishment	of	portions	of	our	outstanding	debt.	The	most	significant	use	of	cash	in	2005	was	related	to	the repayment	of	$1.920	billion	of	debt	assumed	as	a	part	of	the	acquisition	of	Ashland's	38	percent	interest	in	MPC.

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	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,	2007,	such	reimbursements	have	totaled	$280	million.	The	$1.0	billion obligation	is	reflected	as	long-term	debt	and	the	remaining	$744	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,	2007.

# Derivative	Instruments

See	Quantitative	and	Qualitative	Disclosures	about	Market	Risk	for	a	discussion	of	derivative	instruments	and	associated	market	risk.

# Dividends	to	Stockholders

Dividends	of	$0.92	per	common	share	or	$637	million	were	paid	during	2007.	On	January	27,	2008,	our	Board	of	Directors	declared	a	dividend	of	$0.24	cents	per share	on	our	common	stock,	payable	March	10,	2008,	to	stockholders	of	record	at	the	close	of	business	on	February	20,	2008.

# Liquidity	and	Capital	Resources

Our	main	sources	of	liquidity	and	capital	resources	are	internally	generated	cash	flow	from	operations,	committed	credit	facilities	and	access	to	both	the	debt	and equity	capital	markets.	Our	ability	to	access	the	debt	capital	market	is	supported	by	our	investment	grade	credit	ratings.	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+,	Baa1,	and	BBB+.	These	ratings	were reaffirmed	in	July	2007	after	the	Western	acquisition	was	announced.	Because	of	the	alternatives	available	to	us,	including	internally	generated	cash	flow	and	potential asset	sales,	we	believe	that	our	short-term	and	long-term	liquidity	is	adequate	to	fund	operations,	including	our	capital	spending	programs,	stock	repurchase	program, repayment	of	debt	maturities	and	any	amounts	that	ultimately	may	be	paid	in	connection	with	contingencies.

We	have	a	committed	$3.0	billion	revolving	credit	facility	with	third-party	financial	institutions	terminating	in	May	2012.	At	December	31,	2007,	there	were	no borrowings	against	this	facility	and	we	had	no	commercial	paper	outstanding	under	our	U.S.	commercial	paper	program	that	is	backed	by	this	revolving	credit	facility.

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.

Our	cash-adjusted	debt-to-capital	ratio	(total	debt-minus-cash	to	total	debt-plus-equity-minus-cash)	was	22	percent	at	December	31,	2007,	compared	to	six	percent at	year-end	2006	as	shown	below.	This	includes	$498	million	of	debt	that	is	serviced	by	United	States	Steel.

| (Dollars	in	millions) | 2007 | 2006 |
| :--- | :--- | :--- |
| Long-term\tdebt\tdue\twithin\tone\tyear | $1,131 | $471 |
| Long-term\tdebt | 6,084 | 3,061 |
| Total\tdebt | $7,215 | $3,532 |
| Cash | $1,199 | $2,585 |
| Trusteed\tfunds\tfrom\trevenue\tbonds(a) | $744 | $– |
| Equity | $19,223 | $14,607 |
| Calculation: |  |  |
| Total\tdebt | $7,215 | $3,532 |
| Minus\tcash | 1,199 | 2,585 |
| Minus\ttrusteed\tfunds\tfrom\trevenue\tbonds | 744 | – |
| Total\tdebt\tminus\tcash | 5,272 | 947 |
| Total\tdebt | 7,215 | 3,532 |
| Plus\tequity | \t 19,223 | \t 14,607 |
| Minus\tcash | 1,199 | 2,585 |
| Minus\ttrusteed\tfunds\tfrom\trevenue\tbonds | 744 | – |
| Total\tdebt\tplus\tequity\tminus\tcash | $24,495 | $15,554 |
| Cash-adjusted\tdebt-to-capital\tratio | 22% | 6% |
| (a) |  |  |

(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,	2007.

During	2007	and	2006,	we	extinguished	portions	of	our	outstanding	debt	with	face	values	of	$93	million	and	$162	million.	The	debt	was	repurchased	at	a	weighted average	price	equal	to	117	percent	of	face	value	in	2007	and	122	percent	of	face	value	in	2006.	We	will	continue	to	evaluate	debt	repurchase	opportunities	as	they	arise.

A	consolidated	subsidiary,	Marathon	Oil	Canada	Corporation	(formerly	Western	Oil	Sands	Inc.),	had	a	committed	805	million	Canadian	dollar	revolving	term credit	facility	with	third-party	financial	institutions	at	December	31,	2007.	This	facility	was	in	place	prior	to	our	acquisition	of	Western,	and	had	outstanding	borrowings of	592	million	Canadian	dollars	($599	million)	at	December	31,	2007.	Marathon	Oil	Canada	Corporation	did	not	meet	certain	financial	covenants	contained	in	the facility	as	of	December	31,	2007.	In	February	2008,	we	repaid	the	outstanding	balance	and	terminated	the	facility.

As	discussed	in	more	detail	below	under	Outlook,	we	have	approved	a	capital,	investment	and	exploration	budget	of	$7.993	billion	for	2008,	which	represents	a	67 percent	increase	over	our	2007	spending.	Consistent	with	our	philosophy	of	maintaining	financial	discipline	and	flexibility,	we	have	commenced	a	review	of	our portfolio	of	assets	with	the	intent	of	monetizing	those	assets	which	are	either	mature	or	otherwise	non-strategic,	thus	allowing	us	to	re-deploy	our	capital	into	the	projects included	in	our	capital,	investment	and	exploration	budget.	We	are	in	the	early	stage	of	this	review	process,	so	we	expect	that	the	majority	of	proceeds	from	any	such asset	sales	would	be	received	in	the	second	half	of	2008.

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.

# Share	Repurchase	Program

Since	January	2006,	our	Board	of	Directors	has	authorized	a	common	share	repurchase	program	totaling	$5	billion.	As	of	December	31,	2007,	we	had	repurchased 58	million	common	shares	at	a	cost	of	$2.520	billion.	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;	however,	we	expect	to	complete	the	authorized	purchases	by	the	end	of 2009,	although	repurchases	are	likely	to	be	less	ratable	than	in	prior	years.	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.

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,	2007.

# Summary	of	Contractual	Cash	Obligations

|  |  |  | 2009- | 2011- | Later |
| :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Total | 2008 | 2010 | 2012 | Years |
| Long-term\tdebt\t(excludes\tinterest)(a)(b) | $6,947 | $1,067 | $136 | $1,664 | $4,080 |
| Sale-leaseback\tfinancing(a) | 308 | 11 | 41 | 55 | 201 |
| Capital\tlease\tobligations(a) | 193 | 68 | 37 | 35 | 53 |
| Operating\tlease\tobligations(a) | 1,063 | 165 | 267 | 183 | 448 |
| Operating\tlease\tobligations\tunder\tsublease(a) | 26 | 5 | 10 | 11 | – |
| Purchase\tobligations: |  |  |  |  |  |
| Crude\toil,\tfeedstock,\trefined\tproduct\tand\tethanol\tcontracts(c) | \t 18,434 | \t 16,713 | 604 | 593 | 524 |
| Transportation\tand\trelated\tcontracts | 1,944 | 438 | 279 | 271 | 956 |
| Contracts\tto\tacquire\tproperty,\tplant\tand\tequipment | 3,893 | 2,025 | \t 1,798 | 33 | 37 |
| LNG\tterminal\toperating\tcosts(d) | 166 | 13 | 25 | 25 | 103 |
| Service\tand\tmaterials\tcontracts(e) | 1,622 | 386 | 464 | 253 | 519 |
| Unconditional\tpurchase\tobligations(f) | 59 | 7 | 15 | 15 | 22 |
| Commitments\tfor\toil\tand\tgas\texploration\t(non-capital)(g) | 83 | 76 | 2 | 4 | 1 |
| Total\tpurchase\tobligations | \t 26,201 | \t 19,658 | \t 3,187 | \t 1,194 | 2,162 |
| Other\tlong-term\tliabilities\treported\tin\tthe\tconsolidated\tbalance\tsheet(h) | 1,970 | 110 | 362 | 241 | 1,257 |
| Total\tcontractual\tcash\tobligations(i) | $36,708 | $21,084 | $4,040 | $3,383 | $8,201 |
| (a) |  |  |  |  |  |

(b) We	anticipate	cash	payments	for	interest	of	$425	million	for	2008,	$838	million	for	2009-2010,	$740	million	for	2011-2012	and	$3.700	billion	for	the	remaining	years	for	a	total	of	$5.703	billion. (c) The	majority	of	these	contractual	obligations	as	of	December	31,	2007	relate	to	contracts	to	be	satisfied	within	the	first	180	days	of	2008.	These	contracts	include	variable	price	arrangements	and	some	contracts are	accounted	for	as	nontraditional	derivatives.

(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	is	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	2016.

(i) Includes	$544	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	–	Summary	of	Contractual	Cash	Obligations	Assumed	by	United	States	Steel.

# 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	generally	accepted	accounting	principles.	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	28	to	the consolidated	financial	statements.

We	are	a	party	to	an	agreement	that	would	require	us	to	purchase,	under	certain	circumstances,	the	interest	in	Pilot	Travel	Centers	LLC	("PTC")	not	currently owned.	This	put/call	agreement	is	described	in	Note	28	to	the	consolidated	financial	statements.

# Nonrecourse	Indebtedness	of	Investees

Certain	of	our	investees	have	incurred	indebtedness	that	we	do	not	support	through	guarantees	or	otherwise.	If	we	were	obligated	to	share	in	this	debt	on	a	pro	rata ownership	basis,	our	share	would	have	been	$522	million	as	of	December	31,	2007.	Of	this	amount,	$251	million	relates	to	PTC.	If	any	of	these	investees	default,	we have	no	obligation	to	support	the	debt.	Our	partner	in	PTC	has	guaranteed	$50	million	of	the	total	PTC	debt.

# 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	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,	2007,	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	2009	through	2033.	Accrued	interest	payable	on	these	bonds	was	$9	million	at	December	31,	2007.

•$45	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,	2007.

•$38	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,	2007.

•$26	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	of	all	obligations	of	United	States	Steel	as	general	partner	of	Clairton	1314B	Partnership,	L.P.	to	the	limited	partners.	United	States	Steel	has reported	that	it	currently	has	no	unpaid	outstanding	obligations	to	the	limited	partners.	See	Note	3	to	the	consolidated	financial	statements.

Of	the	total	$533	million,	obligations	of	$507	million	and	corresponding	receivables	from	United	States	Steel	were	recorded	on	our	consolidated	balance	sheet	as	of December	31,	2007	(current	portion—$22	million;	long-term	portion—$485	million).	The	remaining	$26	million	was	related	to	off-balance	sheet	arrangements	and contingent	liabilities	of	United	States	Steel.

The	table	below	provides	aggregated	information	on	the	portion	of	our	consolidated	obligations	to	make	future	cash	payments	under	existing	contracts	that	have been	assumed	by	United	States	Steel	as	of	December	31,	2007.

# Summary	of	Contractual	Cash	Obligations	Assumed	by	United	States	Steel

|  |  |  | 2009- | 2011- | Later |
| :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Total | 2008 | 2010 | 2012 | Years |
| Long-term\tdebt\t(excludes\tinterest)(a) | $ 415 | $– | $– | $– | $415 |
| Sale-leaseback\tfinancing\t(includes\timputed\tinterest) | 55 | 11 | 22 | 22 | – |
| Capital\tlease\tobligations | 48 | 10 | 19 | 19 | – |
| Operating\tlease\tobligations\tunder\tsublease | 26 | 5 | 10 | 11 | – |
| Total\tcontractual\tcash\tobligations\tassumed\tby\tUnited\tStates\tSteel | $ 544 | $26 | $51 | $52 | $415 |
| (a) |  |  |  |  |  |

United	States	Steel	reported	in	its	Form	10-K	for	the	year	ended	December	31,	2007,	that	it	has	restrictive	covenants	related	to	its	indebtedness	that	could	have	an adverse	effect	on	its	financial	position	and	liquidity.	Further,	United	States	Steel	reported	that	the	restrictive	nature	of	its	financial	covenants	decreased	during	2007	and that	its	management	believes	that	its	liquidity	will	be	adequate	to	satisfy	its	obligations	for	the	foreseeable	future.

# 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 marketed	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	to	our	50	percent	equity	method	investee,	PTC,	which	consist	primarily	of	refined	petroleum	products,	accounted	for	2.5	percent	or	less	of	our	total	sales revenue	for	2007,	2006	and	2005.	PTC	is	the	largest	travel	center	network	in	the	United	States	and	operates	286	travel	centers	in	the	United	States	and	Canada.	Prior	to our	acquisition	of	Ashland's	38	percent	interest	in	MPC	on	June	30,	2005,	Ashland	was	a	related	party	as	a	result	of	that	interest.	During	that	time,	we	sold	refined petroleum	products	consisting	mainly	of	petrochemicals,	base	lube	oils	and	asphalt	to	Ashland.	Our	sales	to	Ashland	accounted	for	less	than	one	percent	of	our	total	sales revenue	for	2005.	We	believe	that	these	transactions	were	conducted	under	terms	comparable	to	those	with	unrelated	parties.

# 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) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Capital | $199 | $176 | $390 |
| Compliance |  |  |  |
| Operating\tand\tmaintenance | \t 287 | \t 309 | \t 250 |
| Remediation(b) | 25 | 20 | 25 |
| Total | $511 | $505 | $665 |
| (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	four	percent	of	capital	expenditures	for	continuing	operations	in	2007,	five	percent	in	2006	and	14	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	approximately	$313	million	or	4	percent	of	capital	expenditures	in	2008.	Predictions	beyond	2008	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	$735	million	in	2009;	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	Business	–	Environmental	Matters	and	for	information	on	legal	proceedings	related	to environmental	matters,	see	Legal	Proceedings.

# Outlook

# Capital,	Investment	and	Exploration	Budget

Our	Board	of	Directors	approved	a	capital,	investment	and	exploration	budget	of	$7.993	billion	for	2008,	which	includes	budgeted	capital	expenditures	of	$7.651 billion.	This	represents	a	67	percent	increase	over	2007	spending.	The	focus	of	the	2008	budget	is	to	grow	our	refining	capacity	through	the	Garyville	refinery	expansion, further	develop	our	long-life	Canadian	oil	sands	assets,	capitalize	on	the	ownership	of	those	oil	sands	assets	by	upgrading	and	expanding	our	Detroit	refinery,	fund	our ongoing	exploration	activities	and	develop	existing	fields,	including	new	developments	in	Angola	and	the	Gulf	of	Mexico.	The	budget	includes	worldwide	production spending	of	$2.144	billion,	primarily	in	the	United	States	for	expansion	of	the	Bakken	shale	and	Piceance	Basin	resource	plays	and	development	of	the	Droshky	prospect in	the	Gulf	of	Mexico,	but	also	in	Norway	and	Angola.	The	worldwide	exploration	budget	of	$1.045	billion	includes	plans	to	drill	six	to	ten	exploration	or	appraisal wells.	It	also	includes	$150	million	related	to	our	high	bids	on	leases	from	the	October	2007	Gulf	of	Mexico	lease	sale	which	were	awarded	in	early	2008.	Other exploration	plans	include	activity	within	or	adjacent	to	our	onshore	producing	properties	in	the	United	States,	appraisal	drilling	and	pre-FEED	costs	in	Angola,	and evaluation	drilling	and	feasibility	studies	of	the	in-situ	recovery	projects	in	Canada.	The	budget	includes	$910	million	for	the	Oil	Sands	Mining	segment,	primarily	for the	Phase	1	expansion	of	the	AOSP	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	associated	infrastructure.	The	budget	includes	$3.528	billion	for	RM&T,	primarily	for	the Garyville	refinery	expansion	and	the	Detroit	refinery	heavy	oil	upgrading	and	expansion	project.	The	RM&T	budget	also	includes	increased	investments	in transportation,	logistics	and	marketing	assets.	The	Integrated	Gas	segment	budget	of	$20	million	is	substantially	lower	than	2007	because	construction	on	the	LNG production	facility	in	Equatorial	Guinea	was	completed	and	the	facility	began	operations	in	2007.	The	remaining	$346	million	is	designated	for	capitalized	interest	and corporate	activities.

This	capital,	investment	and	exploration	budget	represents	a	significant	increase	over	our	2007	spending.	Consistent	with	our	philosophy	of	maintaining	financial discipline	and	flexibility,	we	have	commenced	a	review	of	our	portfolio	of	assets	with	the	intent	of	monetizing	those	assets	which	are	either	mature	or	otherwise	non- strategic,	thus	allowing	us	to	re-deploy	our	capital	into	the	projects	included	in	our	capital,	investment	and	exploration	budget.	We	are	in	the	early	stage	of	this	review process,	so	we	expect	that	the	majority	of	proceeds	from	any	such	asset	sales	would	be	received	in	the	second	half	of	2008.

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.	The	discussion	above	also	contains	forward-looking	statements	regarding	a	review	of	our	portfolio	of	assets.	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.

We	announced	nine	discoveries	in	2007	(eight	in	deepwater	Angola	and	one	in	the	Gulf	of	Mexico).	Major	exploration	activities,	which	are	currently	underway	or under	evaluation,	include	those:

•offshore	Angola,	on	Block	31	in	which	we	hold	a	10	percent	outside-operated	interest	and	have	announced	15	discoveries,	and	on	Block	32,	in	which	we	hold a	30	percent	outside-operated	interest	and	have	announced	11	discoveries.	We	plan	to	participate	in	four	to	five	exploration	or	appraisal	wells	in	these deepwater	blocks	in	2008.	Current	plans	call	for	a	potential	development	area	in	the	northeastern	part	of	Block	31,	which	encompasses	the	Plutao,	Saturno, Venus	and	Marte	discoveries.	Additional	potential	development	areas	lie	in	the	southeast	and	middle	portions	of	the	block.	Seven	of	the	Block	32	discoveries form	our	first	potential	development	in	the	eastern	area	of	that	block.

•in	Equatorial	Guinea,	where	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;

•in	Norway,	where	we	now	own	interests	in	16	licenses	covering	over	800,000	gross	acres	offshore	and	plan	to	drill	one	or	two	exploration	wells	during	2008;

•in	the	United	Kingdom,	where	we	plan	to	participate	in	the	U.K.	Onshore	Licensing	Round	during	2008	to	secure	additional	coal	bed	methane	acreage;	and

•in	the	Gulf	of	Mexico,	where	we	plan	to	participate	in	two	to	three	exploration	wells	during	2008.

During	2007,	we	continued	to	make	progress	in	advancing	key	development	projects	that	will	help	serve	as	the	basis	for	our	production	growth	profile	in	the coming	years.	Major	development	and	production	activities	currently	underway	or	under	evaluation	include	those:

•in	the	Gulf	of	Mexico,	with	the	Neptune	development	and	the	Droshky	discovery.	The	Neptune	development,	in	which	we	own	a	30	percent	outside-operated working	interest,	is	on	target	for	first	production	by	early	2008.	Development	of	the	Droshky	discovery,	in	which	we	own	a	100	percent	working	interest,	is expected	to	be	sanctioned	during	2008,	with	first	production	as	early	as	2010	dependent	upon	delivery	of	key	equipment	and	regulatory	approvals.	Rig capacity	has	been	secured	for	Droshky	development	drilling.

•in	Norway,	where	our	Alvheim/Vilje	development	will	consist	of	an	FPSO	vessel	with	subsea	infrastructure.	The	FPSO	sailed	from	the	shipyard	in	mid- February	2008	to	undergo	testing,	after	which	it	will	proceed	offshore	for	connection	to	the	subsea	infrastructure.	First	production	is	expected	at	the	end	of the	first	quarter	of	2008,	weather	permitting,	at	which	time	six	wells	will	be	available.	Drilling	activities	will	continue	in	2008.	A	peak	net	production	rate	of 75	mboepd	is	expected	in	2008.	We	are	the	operator	of	the	Alvheim	development,	which	includes	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.	We	own	a	47	percent	outside-operated	interest	in	the nearby	Vilje	discovery.	Also,	the	Volund	discovery,	a	tie-back	to	the	Alvheim	FPSO	continues	to	make	progress	towards	first	production	in	2009.	We	own	a 65	percent	interest	in	Volund	and	serve	as	operator;

•in	Libya,	where	we	continue	to	work	with	our	partners	to	maximize	the	potential	of	this	major	asset.	We	own	a	16.33	percent	outside-operated	interest	in	the approximately	13	million	acre	Waha	concessions;

•in	Ireland,	where	the	Corrib	natural	gas	development	project	continues	and	the	operator	expects	first	production	in	2009.	We	own	a	19	percent	outside- operated	interest	in	Corrib;

•in	the	Piceance	Basin	of	Colorado,	where	we	have	two	drilling	rigs	running,	and	plan	to	increase	the	rig	count	to	four	by	the	end	of	2008,	drilling	165	wells in	the	region	over	the	next	two	years;	and

•in	the	Williston	Basin	of	North	Dakota	and	eastern	Montana	(the	Bakken	shale	formation),	where	we	have	six	rigs	running	and	plan	to	drill	approximately 350	locations	over	the	next	four	to	five	years.

With	the	Alvheim/Vilje	and	Neptune	developments	coming	online,	we	estimate	that	our	2008	liquid	hydrocarbon	and	natural	gas	sales	will	average	approximately 380	to	420	mboepd,	excluding	the	impact	of	acquisitions	and	dispositions.	Projected	liquid	hydrocarbon	and	natural	gas	sales	are	based	on	a	number	of	assumptions, including	(among	others)	pricing,	supply	and	demand	for	petroleum	products,	the	amount	of	capital	available	for	exploration	and	development,	regulatory	constraints, timing	of	commencing	production	from	new	wells,	drilling	rig	availability,	inability	or	delay	in	obtaining	necessary	government	and	third-party	approvals	and	permits, unforeseen	hazards	such	as	weather	conditions,	acts	of	war	or	terrorist	acts	and	the	government	or	military	response,	and	other	geological,	operating	and	economic considerations.	These	assumptions	may	prove	to	be	inaccurate.

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's	Phase	1	expansion	is	under	construction	and	we	expect	that	it	will	be	complete	in	late	2010.	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	Scotford	upgrader	returned	to	full	operation	in	December	2007	after	a	mid-November	fire	and	the	completion	of	maintenance	that	had	originally	been scheduled	for	the	first	quarter	of	2008	and	was	completed	in	conjunction	with	the	necessary	repairs.	We	anticipate	our	net	bitumen	production	will	be	approximately	30 mbpd	in	2008.	Projected	bitumen	production	is	based	upon	a	number	of	assumptions,	including	pricing,	supply	and	demand	for	petroleum	products,	regulatory constraints,	unforeseen	hazards	such	as	weather	conditions,	acts	of	war	or	terrorist	acts	and	government	or	military	response	thereto,	and	other	geological,	operating	and economic	considerations.

The	above	discussion	includes	forward-looking	statements	with	respect	to	the	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.

Throughout	2007,	we	remained	focused	on	our	strategy	of	leveraging	refining	and	marketing	investments	in	core	markets,	as	well	as	expanding	and	enhancing	our asset	base	while	controlling	costs.	Our	2007	average	daily	crude	oil	throughput	and	total	refinery	throughput	were	at	record	levels.

Construction	continues	on	an	expansion	of	our	Garyville,	Louisiana	refinery	with	a	total	projected	cost	of	$3.2	billion	(excluding	capitalized	interest).	This expansion	will	increase	the	refinery's	crude	oil	throughput	capacity	by	180	mbpd	and,	when	completed	in	late	2009,	will	enable	the	refinery	to	provide	an	additional 7.5	million	gallons	of	clean	transportation	fuels	to	the	market	each	day.

In	2007,	a	heavy	oil	upgrading	and	expansion	project	at	our	Detroit,	Michigan	refinery	was	approved	at	a	total	projected	cost	of	$1.9	billion	(excluding	capitalized interest).	Construction	is	expected	to	begin	in	the	first	half	of	2008,	subject	to	obtaining	the	necessary	permits	from	applicable	regulatory	agencies.

We	also	continue	our	investment	in	transportation	and	storage	assets	to	increase	our	ability	to	blend	and	distribute	ethanol.	By	mid-2008,	we	expect	to	have	the capacity	to	blend	to	an	"E-10"	level	(90	percent	gasoline	and	10	percent	ethanol)	across	our	entire	gasoline	distribution	network.

We	previously	estimated	that	we	would	spend	approximately	$400	million	over	a	four-year	period	beginning	in	2008	to	comply	with	Mobile	Source	Air	Toxics	II regulations	relating	to	benzene.	We	have	not	finalized	our	strategy	or	cost	estimates	to	comply	with	these	recently	promulgated	requirements,	but	the	cost	estimates	will increase	and	may	be	approximately	$1	billion	over	a	three-year	period	beginning	in	2008.	The	cost	estimates	have	increased	due	to	better	definition	of	the	projects needed	to	meet	the	requirements	of	the	finalized	regulations	and	updated	construction	cost	estimates.

The	above	discussion	includes	forward-looking	statements	concerning	the	planned	expansion	of	the	Garyville	refinery,	the	Detroit	refinery	heavy	oil	upgrading	and expansion	project,	our	ethanol	program	and	Mobile	Source	Air	Toxics	II	regulations	compliance	costs.	Some	factors	that	could	affect	the	Garyville	and	Detroit	projects include	necessary	government	and	third-party	approvals,	transportation	logistics,	availability	of	materials	and	labor,	unforeseen	hazards	such	as	weather	conditions, other	risks	customarily	associated	with	construction	projects	and	crude	oil	supply.	Factors	that	could	affect	our	ethanol	program	include	necessary	government	and	third- party	approvals,	availability	of	materials	and	labor,	unforeseen	hazards	such	as	weather	conditions	and	other	risks	customarily	associated	with	construction	projects.	The compliance	cost	estimates	are	subject	to	change	as	FEED	work	is	completed	in	2008.	These	factors	(among	others)	could	cause	actual	results	to	differ	materially	from those	set	forth	in	the	forward-looking	statements.

Net	worldwide	LNG	sales	volumes	are	expected	to	average	6,225	to	6,875	metric	tonnes	per	day	in	2008.	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.

In	2007	we	completed	those	portions	of	the	FEED	required	to	support	the	near-term	efforts	related	to	a	potential	second	LNG	production	facility	on	Bioko	Island, Equatorial	Guinea.	The	scope	of	the	FEED	work	for	the	potential	4.4	mmtpa	LNG	project	included	feed	gas	metering,	liquefaction,	refrigeration,	ethylene	storage,	boil- off	gas	compression,	product	transfer	to	storage	and	LNG	product	metering.	We	expect	to	make	progress	towards	an	investment	decision	in	2008.

The	above	discussion	contains	forward	looking	statements	with	respect	to	the	possible	expansion	of	the	LNG	production	facility	which	could	potentially	be	affected by	partner	approvals,	access	to	sufficient	natural	gas	volumes	through	exploration	or	commercial	negotiations	with	other	resource	owners	and	access	to	sufficient	re- gasification	capacity.	The	foregoing	factors	(among	others)	could	cause	actual	results	to	differ	materially	from	those	set	forth	in	the	forward-looking	statements.

# Accounting	Standards	Not	Yet	Adopted

In	December	2007,	the	FASB	issued	SFAS	No.	141	(Revised	2007),	"Business	Combinations."	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	noncontrolling	interest	in	the acquiree	at	their	acquisition-date	fair	values	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.	Additional	disclosures	are	also	required.	For	us,	SFAS	No.	141(R)	will	be applied	prospectively	effective	January	1,	2009.

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.	For	us,	SFAS	No.	160	will	be	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	are	currently evaluating	the	provisions	of	this	statement.

In	February	2007,	the	FASB	issued	SFAS	No.	159,	"The	Fair	Value	Option	for	Financial	Assets	and	Financial	Liabilities."	This	statement	permits	entities	to	choose to	measure	many	financial	instruments	and	certain	other	items	at	fair	value	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.	For	us,	SFAS	No.	159	is effective	January	1,	2008,	and	retrospective	application	is	not	permitted.	We	did	not	elect	the	fair	value	option	when	this	standard	became	effective.

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.	In	February	2008,	the	FASB	issued	FASB	Staff	Position	("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.	For	us,	except	for	the	nonfinancial	assets	and	liabilities	subject	to	the	one- year	deferral,	SFAS	No.	157	is	effective	January	1,	2008.	We	do	not	expect	adoption	of	this	statement	to	have	a	significant	effect	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.

Certain	long-term	natural	gas	contracts	in	the	United	Kingdom	that	are	accounted	for	as	derivative	instruments	are	excluded	from	E&P	segment	income.	For additional	information	on	these	U.K.	natural	gas	contracts,	see	Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	–	Critical Accounting	Estimates	–	Fair	Value	Estimates.

Our	OSM	segment	uses	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.

Our	RM&T	segment	uses	commodity	derivative	instruments	on	a	selective	basis,	primarily	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	or	during	the	time	that	crude	oil	inventories	are	held	before	they	are	actually	refined	into salable	petroleum	products.	To	a	lesser	extent,	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.	Our	strategies	allow	us	to	realize	acceptable	margins	for	our	various	refined products	but	at	times	may	limit	our	ability	to	take	advantage	of	certain	market	opportunities.

Additionally,	certain	contracts	in	our	RM&T	segment	involving	the	purchase	or	sale	of	commodities	are	not	considered	normal	purchases	or	normal	sales	under generally	accepted	accounting	principles	and	are	required	to	be	accounted	for	as	derivative	instruments.

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	attempted	to	qualify	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	Derivative	Positions	as	of	December	31,	2007	and	Sensitivity	Analysis

At	year	end	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,	2007,	we	had	no	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.

At	October	18,	2007,	Western	held	crude	oil	put	options	purchased	in	October	2005	for	the	three-year	period	beginning	January	1,	2007.	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,	2007,	the	following	put	and	call	options	were	outstanding:

|  | 2008 | 2009 |
| :--- | :--- | :--- |
| Option\tContract\tVolumes\t(Barrels\tPer\tDay): |  |  |
| Put\tOptions\tPurchased | \t 20,000 | \t 20,000 |
| Call\tOptions\tSold | \t 15,000 | \t 15,000 |
| Average\tExercise\tPrice\t(Dollars\tPer\tBarrel): |  |  |
| Put\tOptions | $54.25 | $50.50 |
| Call\tOptions | $94.25 | $90.50 |

At	year	end	our	RM&T	segment	held	open	derivative	contracts	in	amounts	that	were	in	line	with	normal	levels	of	activity.

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,	2007,	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.

|  | Incremental<br>Decrease	in	IFO<br>Assuming	a<br>Hypothetical<br>Price	Change	of	(a) |  |
| :--- | :--- | :--- |
| (In\tmillions) | \t\t\t\t\t\t\t\t10% | \t\t\t\t\t\t\t\t25% |
| Commodity\tderivative\tinstruments:(b) |  |  |
| Crude\toil | $1(c) | $– |
| Natural\tgas | \t\t\t\t99(c) | \t\t\t\t220(c) |
| Refined\tproducts | 22(c) | 59(c) |

(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,	2007.	Included	in the	natural	gas	impacts	above	are	$102	million	and	$229	million	for	hypothetical	price	changes	of	10	percent	and	25	percent	related	to	the	long-term	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.	We	are	also	exposed to	credit	risk	in	the	event	of	nonperformance	by	counterparties.	The	creditworthiness	of	counterparties	is	reviewed	continuously	and	master	netting	agreements	are	used	when	practical.	Changes	to	the	portfolio after	December	31,	2007,	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	2007,	from	a	low	of	15	contracts	on	April	30,	2007,	to	a	high	of	1,475	contracts	on	March	15,	2007,	and	averaged	719	for	the	year.	The number	of	net	open	contracts	for	the	RM&T	segment	varied	throughout	2007,	from	a	low	of	22	contracts	on	February	7,	2007,	to	a	high	of	31,872	contracts	on	September	24,	2007,	and	averaged	12,261	for	the year.	The	number	of	net	open	contracts	for	the	OSM	segment	varied	throughout	2007,	from	a	low	of	25,585	contracts	on	December	31,	2007	to	a	high	of	28,345	contracts	on	October	18,	2007,	the	Western acquisition	date,	and	averaged	26,965	for	the	post-acquisition	period.	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.

# Derivative	Gains	or	Losses	Included	in	Results	of	Operations

Pretax	derivative	losses	of	$15	million	in	2007	and	gains	of	$25	million	in	2006	and	$7	million	in	2005	were	included	in	E&P	segment	income	and	were	primarily related	to	derivatives	utilized	to	protect	the	value	of	natural	gas	in	storage	and	margins	on	natural	gas	purchased	for	use	in	our	marketing	activities.

Pretax	derivative	losses	of	$54	million	were	included	in	OSM	segment	income	for	2007.	These	losses	primarily	resulted	from	the	increase	in	crude	oil	prices	since the	acquisition	date	of	Western.

Pretax	derivative	gains	and	losses	included	in	RM&T	segment	income	for	each	of	the	last	three	years	are	summarized	in	the	following	table:

| (In	millions) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Strategy: |  |  |  |
| Mitigate\tprice\trisk\ton\tpurchases\tof\tcrude\toil\tand\tother\tcommodities | $(378) | $204 | $(57) |
| Mitigate\tprice\trisk\ton\tcarrying\tvalues\tof\tinventories | (511) | \t 200 | (118) |
| Other | (10) | (4) | (63) |
| Subtotal,\tnon-trading\tactivities | (899) | \t 400 | (238) |
| Trading\tactivities | (1) | 1 | (87) |
| Total\tnet\tderivative\tgains\t(losses) | $(900) | $401 | $(325) |

# 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.	We	have	entered	into	several	interest	rate	swap	agreements,	designated	as	fair	value	hedges,	which	effectively	resulted	in	an	exchange of	existing	obligations	to	pay	fixed	interest	rates	for	obligations	to	pay	floating	rates.	The	following	table	summarizes	our	interest	rate	swaps	as	of	December	31,	2007.

| (In	millions) | Fixed<br>Rate	to<br>be<br>Received | Notional<br>Amount | Swap<br>Maturity | Fair<br>Value |
| :--- | :--- | :--- | :--- | :--- |
| Floating\tRate\tto\tbe\tPaid: |  |  |  |  |
| Six-Month\tLIBOR\t+3.285% | 6.850% | $400 | 2008 | $(2) |
| Six-Month\tLIBOR\t+2.142% | 6.125% | $200 | 2012 | $(1) |

Sensitivity	analysis	of	the	projected	incremental	effect	of	a	hypothetical	10	percent	change	in	interest	rates	is	provided	in	the	following	table.

|  |  | December	31,	2007 |
| :--- | :--- | :--- |
|  |  | Incremental |
|  | Fair | Change\tin |
| (In\tmillions) | Value(b) | Fair\tValue |
| Financial\tassets\t(liabilities):(a) |  |  |
| Receivables\tfrom\tUnited\tStates\tSteel | $500\t(c) | $10(d) |
| Interest\trate\tswap\tagreements | $(3)(c) | $5(d) |
| Long-term\tdebt,\tincluding\tamounts\tdue\twithin\tone\tyear | $(7,176)(c) | $(330)(d) |
| Fair\tvalues\tof\tcash\tand\tcash\tequivalents,\treceivables,\tnotes\tpayable,\taccounts\tpayable\tand\taccrued\tinterest\tapproximate\tcarrying\tvalue\tand\tare\trelatively\tinsensitive\tto\tchanges\tin\tinterest\trates\tdue\tto\tthe\tshort-term\n(a) |  |  |

(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) See	Notes	18	and	19	to	the	consolidated	financial	statements	for	the	carrying	value	of	these	instruments.

(c) Fair	value	was	based	on	market	prices	where	available,	or	current	borrowing	rates	for	financings	with	similar	terms	and	maturities. (d) 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	long-term	debt	at	December	31,	2007.	For	interest	rate	swap agreements,	this	assumes	a	10	percent	decrease	in	the	effective	swap	rate	at	December	31,	2007.

At	December	31,	2007,	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.	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	instruments	as	of December	31,	2007.

|  |  |  | Average |  |
| :--- | :--- | :--- | :--- | :--- |
|  |  | Notional | Forward | Fair |
| (Dollars\tin\tmillions) | Period | Amount | Rate(a) | Value(b) |
| Foreign\tCurrency\tForwards: |  |  |  |  |
| Euro | January\t2008\t–\tNovember\t2008 | $31 | 1.281(c) | $4 |
| Kroner\t(Norway) | January\t2008\t–\tOctober\t2009 | $71 | 6.090(d) | $8 |
| Dollar\t(Canada) | February\t2008 | $54 | 1.007(d) | – |
| Rates\tshown\tare\tweighted\taverage\tforward\trates\tfor\tthe\tperiod.\n(a) |  |  |  |  |

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

The	aggregate	cash	flow	effect	on	foreign	currency	forward	contracts	of	a	hypothetical	10	percent	change	to	exchange	rates	at	December	31,	2007,	would	be approximately	$11	million.

During	2007,	we	entered	into	derivative	foreign	currency	instruments	with	a	notional	amount	of	$3.5	billion	to	limit	our	exposure	to	changes	in	the	Canadian	dollar exchange	rate	related	to	the	cash	portion	of	the	purchase	for	Western.	These	derivative	instruments	were	settled	on	October	17,	2007,	and	a	pretax	gain	of	$182	million was	recognized.

# 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

# 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.

Clarence	P.	Cazalot,	Jr.

President	and

Chief	Executive	Officer

Janet	F.	Clark

Executive	Vice	President

and	Chief	Financial	Officer

Michael	K.	Stewart

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,	2007.	This	evaluation	did	not	include	the	internal	control	over	financial reporting	at	Marathon	Oil	Canada	Corporation	(formerly,	Western	Oil	Sands	Inc.)	which	was	acquired	in	a	purchase	business	combination	on	October	18,	2007. Marathon	Oil	Canada	Corporation's	loss	before	income	taxes	and	total	assets	represent	$100	million	and	$8.9	billion,	respectively,	of	the	related	consolidated	financial statement	amounts	as	of	and	for	the	year	ended	December	31,	2007.

The	effectiveness	of	Marathon's	internal	control	over	financial	reporting	as	of	December	31,	2007	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,	2007	and	2006,	and	the	results	of	their	operations	and	their	cash	flows	for	each	of	the	three	years	in the	period	ended	December	31,	2007	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,	2007,	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	methods	of	accounting	for	purchases	and	sales	of	inventory	with	the	same counterparty	and	defined	benefit	pension	and	other	postretirement	plans	in	2006,	and	its	method	of	accounting	for	conditional	asset	retirement	obligations	in	2005.

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.

As	described	in	Management's	Report	on	Internal	Control	over	Financial	Reporting,	management	has	excluded	Marathon	Oil	Canada	Corporation	from	its assessment	of	internal	control	over	financial	reporting	as	of	December	31,	2007	because	it	was	acquired	by	the	Company	in	a	purchase	business	combination	on October	18,	2007.	We	have	also	excluded	Marathon	Oil	Canada	Corporation	from	our	audit	of	internal	control	over	financial	reporting.	Marathon	Oil	Canada Corporation	is	a	wholly-owned	subsidiary	whose	loss	before	income	taxes	and	total	assets	represent	$100	million	and	$8.9	billion,	respectively,	of	the	related consolidated	financial	statement	amounts	as	of	and	for	the	year	ended	December	31,	2007.

PricewaterhouseCoopers	LLP Houston,	Texas February	28,	2008

# Consolidated	Statements	of	Income

| (Dollars	in	millions,	except	per	share	data) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Revenues\tand\tother\tincome: |  |  |  |
| Sales\tand\tother\toperating\trevenues\t(including\tconsumer\texcise\ttaxes) | $62,800 | $57,973 | $48,948 |
| Revenues\tfrom\tmatching\tbuy/sell\ttransactions | 127 | 5,457 | \t 12,636 |
| Sales\tto\trelated\tparties | 1,625 | 1,466 | 1,402 |
| Income\tfrom\tequity\tmethod\tinvestments | 545 | 391 | 265 |
| Net\tgain\ton\tdisposal\tof\tassets | 36 | 77 | 57 |
| Other\tincome | 74 | 85 | 37 |
| Total\trevenues\tand\tother\tincome | \t 65,207 | \t 65,449 | \t 63,345 |
| Costs\tand\texpenses: |  |  |  |
| Cost\tof\trevenues\t(excludes\titems\tbelow) | \t 49,104 | \t 42,415 | \t 37,806 |
| Purchases\trelated\tto\tmatching\tbuy/sell\ttransactions | 149 | 5,396 | \t 12,364 |
| Purchases\tfrom\trelated\tparties | 363 | 210 | 225 |
| Consumer\texcise\ttaxes | 5,163 | 4,979 | 4,715 |
| Depreciation,\tdepletion\tand\tamortization | 1,613 | 1,518 | 1,303 |
| Selling,\tgeneral\tand\tadministrative\texpenses | 1,327 | 1,228 | 1,155 |
| Other\ttaxes | 394 | 371 | 318 |
| Exploration\texpenses | 454 | 365 | 217 |
| Total\tcosts\tand\texpenses | \t 58,567 | \t 56,482 | \t 58,103 |
| Income\tfrom\toperations | 6,640 | 8,967 | 5,242 |
| Net\tinterest\tand\tother\tfinancial\tincome\t(costs) | 41 | 37 | (146) |
| Gain\ton\tforeign\tcurrency\tderivative\tinstruments | 182 | – | – |
| Loss\ton\tearly\textinguishment\tof\tdebt | (17) | (35) | – |
| Minority\tinterests\tin\tloss\t(income)\tof: |  |  |  |
| Marathon\tPetroleum\tCompany\tLLC | – | – | (384) |
| Equatorial\tGuinea\tLNG\tHoldings\tLimited | 3 | 10 | 8 |
| Income\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | 6,849 | 8,979 | 4,720 |
| Provision\tfor\tincome\ttaxes | 2,901 | 4,022 | 1,714 |
| Income\tfrom\tcontinuing\toperations | 3,948 | 4,957 | 3,006 |
| Discontinued\toperations | 8 | 277 | 45 |
| Income\tbefore\tcumulative\teffect\tof\tchange\tin\taccounting\tprinciple | 3,956 | 5,234 | 3,051 |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | – | – | (19) |
| Net\tincome | $3,956 | $5,234 | $3,032 |
| Per\tShare\tData |  |  |  |
| Basic: |  |  |  |
| Income\tfrom\tcontinuing\toperations | $5.72 | $6.92 | $4.22 |
| Net\tincome | $5.73 | $7.31 | $4.26 |
| Diluted: |  |  |  |
| Income\tfrom\tcontinuing\toperations | $5.68 | $6.87 | $4.19 |
| Net\tincome | $5.69 | $7.25 | $4.22 |

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

# Consolidated	Balance	Sheets

| (Dollars	in	millions,	except	per	share	data) | December	31 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Assets |  |  |  |
| Current\tassets: |  |  |  |
| Cash\tand\tcash\tequivalents |  | $1,199 | $2,585 |
| Receivables,\tless\tallowance\tfor\tdoubtful\taccounts\tof\t$3\tand\t$3 |  | 5,818 | 4,114 |
| Receivables\tfrom\tUnited\tStates\tSteel |  | 22 | 32 |
| Receivables\tfrom\trelated\tparties |  | 79 | 63 |
| Inventories |  | 3,277 | 3,173 |
| Other\tcurrent\tassets |  | 192 | 129 |
| Total\tcurrent\tassets |  | \t 10,587 | \t 10,096 |
| Equity\tmethod\tinvestments |  | 2,630 | 1,539 |
| Receivables\tfrom\tUnited\tStates\tSteel |  | 485 | 498 |
| Property,\tplant\tand\tequipment,\tnet |  | \t 24,675 | \t 16,653 |
| Goodwill |  | 2,899 | 1,398 |
| Intangible\tassets,\tnet |  | 288 | 180 |
| Other\tnoncurrent\tassets |  | 1,182 | 467 |
| Total\tassets |  | $42,746 | $30,831 |
| Liabilities |  |  |  |
| Current\tliabilities: |  |  |  |
| Accounts\tpayable |  | $8,281 | $5,586 |
| Payable\tto\tUnited\tStates\tSteel |  | – | 13 |
| Payables\tto\trelated\tparties |  | 44 | 264 |
| Payroll\tand\tbenefits\tpayable |  | 417 | 409 |
| Accrued\ttaxes |  | 712 | 598 |
| Deferred\tincome\ttaxes |  | 547 | 631 |
| Accrued\tinterest |  | 128 | 89 |
| Long-term\tdebt\tdue\twithin\tone\tyear |  | 1,131 | 471 |
| Total\tcurrent\tliabilities |  | \t 11,260 | 8,061 |
| Long-term\tdebt |  | 6,084 | 3,061 |
| Deferred\tincome\ttaxes |  | 3,389 | 1,897 |
| Defined\tbenefit\tpostretirement\tplan\tobligations |  | 1,092 | 1,245 |
| Asset\tretirement\tobligations |  | 1,131 | 1,044 |
| Payable\tto\tUnited\tStates\tSteel |  | 5 | 7 |
| Deferred\tcredits\tand\tother\tliabilities |  | 562 | 391 |
| Total\tliabilities |  | \t 23,523 | \t 15,706 |
| Minority\tinterests\tin\tEquatorial\tGuinea\tLNG\tHoldings\tLimited |  | – | 518 |
| Commitments\tand\tcontingencies |  |  |  |
| Stockholders'\tEquity |  |  |  |
| Preferred\tstock\tissued\tand\toutstanding\t–\t5\tmillion\tand\tno\tshares\t(no\tpar\tvalue,\t6\tmillion\tshares\tauthorized) |  | – | – |
| Common\tstock: |  |  |  |
|  |  | 765 | 736 |
| Securities\texchangeable\tinto\tcommon\tstock\tissued\tand\toutstanding\t–\t5\tmillion\tand\tno\tshares\t(no\tpar |  |  |  |
| value,\tunlimited\tshares\tauthorized) |  | – | – |
| Held\tin\ttreasury,\tat\tcost\t–\t55\tmillion\tand\t40\tmillion\tshares |  | (2,384) | (1,638) |
| Additional\tpaid-in\tcapital |  | 6,679 | 4,784 |
| Retained\tearnings |  | \t 14,412 | \t 11,093 |
| Accumulated\tother\tcomprehensive\tloss |  | (249) | (368) |
| Total\tstockholders'\tequity |  | \t 19,223 | \t 14,607 |
| Total\tliabilities\tand\tstockholders'\tequity |  | $42,746 | $30,831 |

# Consolidated	Statements	of	Cash	Flows

| (Dollars	in	millions) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Increase\t(decrease)\tin\tcash\tand\tcash\tequivalents |  |  |  |
| Operating\tactivities |  |  |  |
| Net\tincome | $3,956 | $5,234 | $3,032 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tprovided\tfrom\toperating\tactivities: |  |  |  |
| Loss\ton\tearly\textinguishment\tof\tdebt | 17 | 35 | – |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | – | – | 19 |
| Income\tfrom\tdiscontinued\toperations | (8) | (277) | (45) |
| Deferred\tincome\ttaxes | (347) | 268 | (205) |
| Minority\tinterests\tin\tincome\t(loss)\tof\tsubsidiaries | (3) | (10) | 376 |
| Depreciation,\tdepletion\tand\tamortization | 1,613 | 1,518 | 1,303 |
| Pension\tand\tother\tpostretirement\tbenefits,\tnet | 32 | (404) | 71 |
| Exploratory\tdry\twell\tcosts\tand\tunproved\tproperty\timpairments | 233 | 166 | 111 |
| Net\tgain\ton\tdisposal\tof\tassets | (36) | (77) | (57) |
| Equity\tmethod\tinvestments,\tnet | (43) | (200) | (65) |
|  | 232 | (454) | 386 |
| Changes\tin: |  |  |  |
| Current\treceivables | (1,361) | (535) | (1,164) |
| Inventories | (90) | (133) | (150) |
| Current\taccounts\tpayable\tand\taccrued\texpenses | 2,351 | 237 | 1,065 |
| All\tother,\tnet | (25) | 50 | (22) |
| Net\tcash\tprovided\tfrom\tcontinuing\toperations | 6,521 | 5,418 | 4,655 |
| Net\tcash\tprovided\tfrom\tdiscontinued\toperations | – | 70 | 83 |
| Net\tcash\tprovided\tfrom\toperating\tactivities | 6,521 | 5,488 | 4,738 |
| Investing\tactivities |  |  |  |
| Capital\texpenditures | (4,466) | (3,433) | (2,796) |
| Acquisitions,\tnet\tof\tcash\tacquired | (3,926) | (741) | (506) |
| Disposal\tof\tassets | 137 | 134 | 131 |
| Disposal\tof\tdiscontinued\toperations | – | 832 | – |
| Proceeds\tfrom\tsale\tof\tminority\tinterests\tin\tEquatorial\tGuinea\tLNG\tHoldings\tLimited | – | – | 163 |
| Trusteed\tfunds\t–\twithdrawals | 280 | – | – |
| Restricted\tcash\t–\tdeposits | (44) | (19) | (54) |
| –\twithdrawals | 9 | 43 | 41 |
| Investments\t–\tloans\tand\tadvances | (114) | (17) | (28) |
| –\trepayments\tof\tloans\tand\treturn\tof\tcapital | 59 | 298 | 15 |
| Deconsolidation\tof\tEquatorial\tGuinea\tLNG\tHoldings\tLimited | (37) | – | – |
| Investing\tactivities\tof\tdiscontinued\toperations | – | (45) | (94) |
| All\tother,\tnet | – | (7) | 1 |
| Net\tcash\tused\tin\tinvesting\tactivities | (8,102) | (2,955) | (3,127) |
| Financing\tactivities |  |  |  |
| Commercial\tpaper\tand\tother\trevolving\tcredit\tarrangements\t–\tnet | 90 | – | – |
| Borrowings | 2,071 | – | – |
| Debt\tissuance\tcosts | (20) | – | – |
| Payment\tof\tdebt\tassumed\tin\tacquisition | – | – | (1,920) |
| Other\tdebt\trepayments | (594) | (501) | (8) |
| Issuance\tof\tcommon\tstock | 27 | 50 | 78 |
| Purchases\tof\tcommon\tstock | (822) | (1,698) | – |
| Excess\ttax\tbenefits\tfrom\tstock-based\tcompensation\tarrangements | 30 | 35 | – |
| Dividends\tpaid | (637) | (547) | (436) |
| Contributions\tfrom\tminority\tshareholders\tof\tEquatorial\tGuinea\tLNG\tHoldings\tLimited | 39 | 80 | 213 |
| Distributions\tto\tminority\tshareholder\tof\tMarathon\tPetroleum\tCompany\tLLC | – | – | (272) |
| Net\tcash\tprovided\tfrom\t(used\tin)\tfinancing\tactivities | 184 | (2,581) | (2,345) |
| Effect\tof\texchange\trate\tchanges\ton\tcash | 11 | 16 | (18) |
| Net\tdecrease\tin\tcash\tand\tcash\tequivalents | (1,386) | (32) | (752) |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tyear | 2,585 | 2,617 | 3,369 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tyear | $1,199 | $2,585 | $2,617 |

# Consolidated	Statements	of	Stockholders'	Equity

|  | Stockholders'	Equity | Stockholders'	Equity |  | Shares | Shares | Shares |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions,\texcept\tper\tshare\tdata) | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 |
| Preferred\tstock\tissued |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $– | $– | $– | – | – | – |
| Issuances | – | – | – | 5 | – | – |
| Balance\tat\tend\tof\tyear | $– | $– | $– | 5 | – | – |
| Common\tstock |  |  |  |  |  |  |
| Issued |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $736 | $734 | $694 | 736 | 734 | 693 |
| Issuances | 29 | 2 | 40 | 29 | 2 | 41 |
| Balance\tat\tend\tof\tyear | $765 | $736 | $734 | 765 | 736 | 734 |
| Securities\texchangeable\tfor\tcommon\tstock |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $– | $– | $– | – | – | – |
| Issuances | – | – | – | 5 | – | – |
| Balance\tat\tend\tof\tyear | $– | $– | $– | 5 | – | – |
| Held\tin\ttreasury |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $(1,638) | $(8) | $(1) | (40) | – | – |
| Repurchases | (845) | (1,712) | (7) | (17) | (42) | – |
| Reissuances\tfor\temployee\tstock\tplans | 99 | 82 | – | 2 | 2 | – |
| Balance\tat\tend\tof\tyear | $(2,384) | $(1,638) | $(8) | (55) | (40) | – |
|  |  |  |  | Comprehensive\tIncome | Comprehensive\tIncome |  |
|  |  |  |  | 2007 | 2006 | 2005 |
| Additional\tpaid-in\tcapital |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $4,784 | $4,744 | $3,681 |  |  |  |
| Stock\tissuances | 1,844 | (8) | 1,028 |  |  |  |
| Stock-based\tcompensation | 51 | 48 | 35 |  |  |  |
| Balance\tat\tend\tof\tyear | $6,679 | $4,784 | $4,744 |  |  |  |
| Unearned\tcompensation |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $– | $(20) | $(9) |  |  |  |
| Change\tin\taccounting\tprinciple | – | 20 | – |  |  |  |
| Changes\tduring\tyear | – | – | (11) |  |  |  |
| Balance\tat\tend\tof\tyear | $– | $– | $(20) |  |  |  |
| Retained\tearnings |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $11,093 | $6,406 | $3,810 |  |  |  |
| Net\tincome | 3,956 | 5,234 | 3,032 | $3,956 | $5,234 | $3,032 |
|  | (637) | (547) | (436) |  |  |  |
| Balance\tat\tend\tof\tyear | $14,412 | $11,093 | $6,406 |  |  |  |
| Accumulated\tother\tcomprehensive\tloss |  |  |  |  |  |  |
| Minimum\tpension\tliability\tadjustments |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $– | $(141) | $(71) |  |  |  |
| Changes\tduring\tyear,\tnet\tof\ttax\tof\t$–,\t$74\tand\t$42 | – | 114 | (70) | – | 114 | (70) |
| Reclassification\tto\tdefined\tbenefit\tpostretirement\tplans | – | 27 | – |  |  |  |
| Balance\tat\tend\tof\tyear | $– | $– | $(141) |  |  |  |
| Defined\tbenefit\tpostretirement\tplans |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $(375) | $– | $– |  |  |  |
| Actuarial\tgains,\tnet\tof\ttax\tof\t$87 | 110 | – | – | 110 | – | – |
| Prior\tservice\tcosts,\tnet\tof\ttax\tof\t$1 | 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 |  |  |  |  |  |  |
|  | $(263) | $(375) | $– |  |  |  |
| Other |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $7 | $(10) | $7 |  |  |  |
| Changes\tduring\tyear,\tnet\tof\ttax\tof\t$4,\t$9\tand\t$3 | 7 | 17 | (17) | 7 | 12 | (17) |
| Balance\tat\tend\tof\tyear | $14 | $7 | $(10) |  |  |  |
| Total\tat\tend\tof\tyear | $(249) | $(368) | $(151) |  |  |  |
| Comprehensive\tincome |  |  |  | $4,075 | $5,360 | $2,945 |
| Total\tstockholders'\tequity | $19,223 | $14,607 | $11,705 |  |  |  |

# Notes	to	Consolidated	Financial	Statements

# 1.	Summary	of	Principal	Accounting	Policies

Marathon	Oil	Corporation	("Marathon"	or	the	"Company")	is	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,	and	development	of	other	projects	to	link	stranded	natural gas	resources	with	key	demand	areas.

Principles	applied	in	consolidation	–	These	consolidated	financial	statements	include	the	accounts	of	Marathon's	majority-owned,	controlled	subsidiaries	and	variable interest	entities	("VIEs")	for	which	Marathon	is	the	primary	beneficiary.	Investments	in	entities	over	which	Marathon	has	significant	influence,	but	not	control,	are accounted	for	using	the	equity	method	of	accounting	and	are	carried	at	Marathon's	share	of	net	assets	plus	loans	and	advances.	This	includes	entities	in	which	Marathon holds	majority	ownership	but	the	minority	shareholders	have	substantive	participating	rights	in	the	investee.	Income	from	equity	method	investments	represents Marathon's	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.

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

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	functional	currency	applicable	to	foreign	operating	subsidiaries	of	Marathon	is	the	U.S.	dollar	since	cash	flows	are	denominated principally	in	U.S.	dollars.	For	these	foreign	operating	subsidiaries,	all	remeasurement	gains	and	losses	are	included	in	net	income.

Income	per	common	share	–	Basic	income	per	share	is	calculated	based	on	the	weighted	average	number	of	common	shares	outstanding,	including	securities exchangeable	into	common	shares.	Diluted	income	per	share	assumes	exercise	of	stock	options	and	warrants	and	conversion	of	convertible	debt	and	preferred	securities, provided	the	effect	is	not	antidilutive.

Segment	information	–	Marathon's	operations	consist	of	four	reportable	operating	segments:

•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	United	States;	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.

Management	has	determined	that	these	are	its	operating	segments	because	these	are	the	components	of	Marathon	(1)	that	engage	in	business	activities	from	which revenues	are	earned	and	expenses	are	incurred,	(2)	whose	operating	results	are	regularly	reviewed	by	Marathon's	chief	operating	decision	maker	("CODM")

to	make	decisions	about	resources	to	be	allocated	and	to	assess	performance	and	(3)	for	which	discrete	financial	information	is	available.	The	CODM	is	responsible	for allocating	resources	to	and	assessing	performance	of	Marathon's	operating	segments.	Information	regarding	assets	by	segment	is	not	presented	because	it	is	not	reviewed by	the	CODM.	The	CODM	is	the	manager	over	the	E&P	and	IG	segments	and	the	manager	of	the	RM&T	and	OSM	segments	reports	to	the	CODM.	The	segment managers	are	responsible	for	allocating	resources	within	the	segments,	reviewing	financial	results	of	components	within	the	segments	and	assessing	the	performance	of the	components.	The	components	within	the	segments	that	are	separately	reviewed	and	assessed	by	the	CODM	in	his	role	as	segment	manager	are	aggregable	because they	have	similar	economic	characteristics.	The	CODM	reviews	the	financial	results	of	the	RM&T	and	OSM	segments	at	the	segment	level.

Segment	income	represents	income	from	continuing	operations,	net	of	minority	interests	and	income	taxes,	attributable	to	the	operating	segments.	Marathon's 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.	Non-cash	gains	and	losses	on	two	long-term	natural	gas	sales	contracts	in	the	United Kingdom	that	are	accounted	for	as	derivative	instruments	and	certain	non-operating	or	infrequently	occurring	items	(as	determined	by	the	CODM)	also	are	not	allocated to	operating	segments.	See	the	reconciliation	of	segment	income	to	consolidated	net	income	in	Note	9.

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	collectibility	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.	Royalties	on	the production	of	oil,	natural	gas	and	bitumen	are	either	paid	in	cash	or	settled	through	the	delivery	of	volumes.	Marathon	includes	royalties	in	its	revenues	and	cost	of revenues	when	settlement	of	the	royalties	is	paid	in	cash,	while	royalties	settled	by	the	delivery	of	volumes	are	excluded	from	revenues	and	cost	of	revenues.

Marathon	follows	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.

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,	Marathon	enters	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.	The	value	of	the	purchased	volumes	rarely	equals	the	sales	value	of	the	sold volumes.	The	value	differences	between	purchases	and	sales	are	primarily	due	to	(1)	grade/quality	differentials,	(2)	location	differentials	and/or	(3)	timing	differences	in those	instances	when	the	purchase	and	sale	do	not	occur	in	the	same	month.

For	the	E&P	segment,	Marathon	enters	into	matching	buy/sell	transactions	to	reposition	crude	oil	from	one	market	center	to	another	to	maximize	the	value	received for	Marathon's	crude	oil	production.	For	the	RM&T	segment,	Marathon	enters	into	crude	oil	matching	buy/sell	transactions	to	secure	the	most	profitable	refinery	supply and	enters	into	refined	product	matching	buy/sell	transactions	to	meet	projected	customer	demand	and	to	secure	the	required	volumes	in	the	most	cost-effective	manner.

Prior	to	April	1,	2006,	Marathon	recorded	all	such	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,	Marathon	accounts	for	matching	buy/sell arrangements	entered	into	or	modified	as	exchanges	of	inventory,	except	for	those	arrangements	accounted	for	as	derivative	instruments.

A	portion	of	Marathon's	matching	buy/sell	transactions	are	"nontraditional	derivative	instruments,"	which	are	described	below.	Effective	for	contracts	entered	into or	modified	on	or	after	April	1,	2006,	the

income	effects	of	matching	buy/sell	arrangements	accounted	for	as	nontraditional	derivative	instruments	are	recognized	on	a	net	basis	as	cost	of	revenues.

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

Consumer	excise	taxes	–	Marathon	is	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	maturities	generally of	three	months	or	less.

Accounts	receivable	and	allowance	for	doubtful	accounts	–	Marathon's	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	Marathon's	proprietary	credit	card	receivables.	Marathon determines	the	allowance	based	on	historical	write-off	experience	and	the	volume	of	proprietary	credit	card	sales.	Marathon	reviews	the	allowance	quarterly	and	past- due	balances	over	180	days	are	reviewed	individually	for	collectibility.	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.

Traditional	derivative	instruments	–	Marathon	uses	derivatives	to	manage	its	exposure	to	commodity	price	risk,	interest	rate	risk	and	foreign	currency	risk. Management	has	authorized	the	use	of	futures,	forwards,	swaps	and	combinations	of	options,	including	written	or	net	written	options,	related	to	the	purchase,	production or	sale	of	crude	oil,	natural	gas,	refined	products	and	ethanol,	the	fair	value	of	certain	assets	and	liabilities,	future	interest	expense	and	certain	business	transactions denominated	in	foreign	currencies.	Changes	in	the	fair	value	of	all	traditional	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.

Amounts	reported	in	net	income	are	classified	as	revenues,	cost	of	revenues,	depreciation,	depletion	and	amortization	or	net	interest	and	other	financing	costs	or income	based	on	the	nature	of	the	underlying	transactions.

As	market	conditions	change,	Marathon	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	also	recognized	in	net	income	and	classified	as	other	income.

Nontraditional	derivative	instruments	–	Certain	contracts	involving	the	purchase	or	sale	of	commodities	are	not	considered	normal	purchases	or	normal	sales	under generally	accepted	accounting	principles	and	are	required	to	be	accounted	for	as	derivative	instruments.	Marathon	refers	to	such	contracts	as	"nontraditional	derivative instruments"	because,	unlike	traditional	derivative	instruments,	nontraditional	derivative	instruments	have	not	been	entered	into	to	manage	a	risk	exposure.	Such contracts	are	recorded	on	the	balance	sheet	at	fair	value	and	changes	in	fair	value	are	recognized	in	net	income	and	are	classified	as	either	revenues	or	cost	of	revenues.

In	the	E&P	segment,	two	long-term	natural	gas	delivery	commitment	contracts	in	the	United	Kingdom	are	classified	as	nontraditional	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.

In	the	RM&T	segment,	certain	physical	commodity	contracts	are	classified	as	nontraditional	derivative	instruments	because	certain	volumes	under	these	contracts are	physically	netted	at	particular	delivery	locations.	The	netting	process	causes	all	contracts	at	such	delivery	locations	to	be	considered	derivative	instruments.	Other physical	contracts	that	management	has	chosen	not	to	designate	as	normal	purchases	or	normal	sales,	which	can	include	contracts	that	involve	flash	title,	are	also accounted	for	as	nontraditional	derivative	instruments.

Property,	plant	and	equipment	–	Marathon	uses	the	successful	efforts	method	of	accounting	for	oil	and	gas	producing	activities.	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)	Marathon	is	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	of	producing	oil	and	natural	gas	properties	are	depreciated	and depleted	on	a	units-of-production	basis.

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.	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.

Marathon	evaluates	its	oil	and	gas	producing	properties	for	impairment	of	value	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. Marathon	evaluates	its	unproved	property	investment	and	records	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	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.

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.	Such	assets	are	reviewed	for	impairment	whenever	events	or	changes	in	circumstances	indicate	that the	carrying	amount	of	an	asset	may	not	be	recoverable.	If	the	sum	of	the	expected	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.

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.	Marathon	has	determined	that	the components	of	the	E&P	segment	have	similar	economic	characteristics	and	therefore	aggregates	the	components	into	a	single	reporting	unit.	The	OSM	segment	is comprised	of	only	one	component	and	therefore	is	a	single	reporting	unit.	The	RM&T	segment	is	composed	of	three	reporting	units:	refining	and	marketing,	pipeline transportation	and	retail	marketing.	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	expense.

Intangible	assets	–	Intangible	assets	primarily	include	technology	used	in	oil	sands	mining	operations,	retail	marketing	tradenames,	intangible	contract	rights	and marketing	branding	agreements.	Certain	of	the	marketing	tradenames	have	indefinite	lives	and	therefore	are	not	amortized,	but	rather	are	tested	for	impairment	annually and	when	events	or	changes	in	circumstances	indicate	that	the	fair	value	of	the	intangible	asset	has	been	reduced	below	carrying	value.	The	oil	sands	mining	technology is	amortized	on	a	units-of-production	basis.	The	other	intangible	assets	are	amortized	on	a	straight-line	basis	over	their	estimated	useful	lives	or	the	expected	lives	of	the related	contracts,	as	applicable,	which	range	from	2	to	22	years.	Amortized	intangible	assets	are	reviewed	for	impairment	whenever	events	or	changes	in	circumstances indicate	that	the	carrying	amount	of	an	asset	may	not	be	recoverable.	If	the	sum	of	the	expected	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.

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.	Marathon	provides	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.	For	Marathon,	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	Marathon's	international	oil	and	gas	producing	facilities	as	Marathon	currently	does	not	have	a legal	obligation	associated	with	the	retirement	of	those	facilities.

To	a	lesser	extent,	asset	retirement	obligations	also	relate	to	dismantlement	and	site	restoration	of	oil	sands	mining	facilities	and,	effective	December	31,	2005, 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	due	to	an indeterminate	settlement	date	of	the	obligation.

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	Marathon's	filings	with	the	respective	taxing	authorities.	The	realization	of	deferred	tax	assets is	assessed	periodically	based	on	several	interrelated	factors.	These	factors	include	Marathon's	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	–	Marathon	adopted	Statement	of	Financial	Accounting	Standards	("SFAS")	No.	123	(Revised	2004),	"Share-Based Payment,"	("SFAS	No.	123	(R)")	as	a	revision	of	SFAS	No.	123,	"Accounting	for	Stock-Based	Compensation,"	as	of	January	1,	2006.	Marathon	had	previously	adopted the	fair	value	method	under	SFAS	No.	123	for	grants	made,	modified	or	settled	on	or	after	January	1,	2003.

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	Marathon's	stock	price	have	the	most	significant	impact	on	the	fair	value	calculation.	Marathon	has	utilized historical	data	and	analyzed	current	information	which	reasonably	support	these	assumptions.

The	fair	value	of	Marathon's	restricted	stock	awards	and	common	stock	units	is	determined	based	on	the	fair	market	value	of	the	Company's	common	stock	on	the date	of	grant.

Effective	January	1,	2006,	Marathon's	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.

Prior	to	January	1,	2006,	Marathon	recorded	stock-based	compensation	expense	over	the	stated	vesting	period	for	stock	option	awards	that	are	subject	to	specific vesting	conditions	and	specify	(1)	that	an	employee	vests	in	the	award	upon	becoming	"retirement	eligible"	or	(2)	that	the	employee	will	continue	to	vest	in	the	award after	retirement	without	providing	any	additional	service.	Under	SFAS	No.	123	(R),	from	the	January	1,	2006	date	of	adoption,	such	compensation	cost	is	recognized immediately	for	awards	granted	to	retirement-eligible	employees	or	over	the	period	from	the	grant	date	to	the	retirement	eligibility	date	if	retirement	eligibility	will	be reached	during	the	stated	vesting	period.	See	Note	24	for	more	information	on	stock-based	compensation	expense,	stock	option	award,	stock-based	performance	award and	restricted	stock	award	activity,	valuation	assumptions	and	other	information	required	to	be	disclosed	under	SFAS	No.	123	(R).

Concentrations	of	credit	risk	–	Marathon	is	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,	Marathon	has	significant	exposures	to United	States	Steel	arising	from	the	transaction	discussed	in	Note	3.

Reclassifications	–	Certain	reclassifications	of	prior	years'	data	have	been	made	to	conform	to	2007	classifications.

# 2.	New	Accounting	Standards

FSP	No.	AUG	AIR-1	–	In	September	2006,	the	Financial	Accounting	Standards	Board	("FASB")	issued	FASB	Staff	Position	("FSP")	No.	AUG	AIR-1,	"Accounting for	Planned	Major	Maintenance	Activities."	This	FSP	prohibits	the	use	of	the	accrue-in-advance	method	of	accounting	for	planned	major	maintenance	activities	in annual	and	interim	financial	reporting	periods.	Marathon	adopted	FSP	No.	AUG	AIR-1	effective	January	1,	2007.	Prior	to	adoption,	Marathon	expensed	such	costs	in the	same	annual	period	as	incurred;	however,	estimated	annual	major	maintenance	costs	were	recognized	as	expense	throughout	the	year	on	a	pro	rata	basis.	As	such,	the adoption	of	this	FSP	has	no	impact	on	Marathon's	annual	consolidated	financial	statements.	The	FSP	has	not	been	applied	retrospectively	because	the	impact	on	the Company's	prior	interim	consolidated	financial	statements	was	not	significant.

FIN	No.	48	–	In	July	2006,	the	FASB	issued	FASB	Interpretation	("FIN")	No.	48,	"Accounting	for	Uncertainty	in	Income	Taxes	–	An	Interpretation	of	FASB Statement	No.	109."	FIN	No.	48	clarifies	the	accounting	for	uncertainty	in	income	taxes	recognized	in	an	enterprise's	financial	statements	in	accordance	with	SFAS No.	109,	"Accounting	for	Income	Taxes."	FIN	No.	48	prescribes	a	recognition	threshold	and	measurement	attribute	for	the	financial	statement	recognition	and measurement	of	a	tax	position	taken	or	expected	to	be	taken	in	a	tax	return.	The	new	standard	also	provides	guidance	on	derecognition,	classification,	interest	and penalties,	accounting	in	interim	periods,	transition	and	disclosure.	Marathon	adopted	FIN	No.	48	effective	January	1,	2007,	and	adoption	did	not	have	a	significant	effect on	its	consolidated	results	of	operations,	financial	position	or	cash	flows.	See	Note	11	for	other	disclosures	required	by	FIN	No.	48.

SFAS	No.	156	–	In	March	2006,	the	FASB	issued	SFAS	No.	156,	"Accounting	for	Servicing	of	Financial	Assets	–	An	Amendment	of	FASB	Statement	No.	140."	This statement	amends	SFAS	No.	140,	"Accounting	for	Transfers	and	Servicing	of	Financial	Assets	and	Extinguishments	of	Liabilities,"	with	respect	to	the	accounting	for separately	recognized	servicing	assets	and	servicing	liabilities.	Marathon	adopted	SFAS	No.	156	effective	January	1,	2007,	and	adoption	did	not	have	a	significant effect	on	its	consolidated	results	of	operations,	financial	position	or	cash	flows.

SFAS	No.	155	–	In	February	2006,	the	FASB	issued	SFAS	No.	155,	"Accounting	for	Certain	Hybrid	Financial	Instruments	–	An	Amendment	of	FASB	Statements No.	133	and	140."	SFAS	No.	155	simplifies	the	accounting	for	certain	hybrid	financial	instruments,	eliminates	the	interim	FASB	guidance	which	provided	that beneficial	interests	in	securitized	financial	assets	are	not	subject	to	the	provisions	of	SFAS	No.	133,	"Accounting	for	Derivative	Instruments	and	Hedging	Activities," and	eliminates	the	restriction	on	the	passive	derivative	instruments	that	a	qualifying	special-purpose	entity	may	hold.	Effective	January	1,	2007,	Marathon	adopted	the provisions	of	SFAS	No.	155	prospectively	for	all	financial	instruments	acquired	or	issued	on	or	after	January	1,	2007.	Adoption	of	this	statement	did	not	have	a significant	effect	on	Marathon's	consolidated	results	of	operations,	financial	position	or	cash	flows.

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.	Marathon	adopted	SFAS	No.	158 prospectively	as	of	December	31,	2006	and	has	recognized	the	funded	status	of	its	plans	in	the	consolidated	balance	sheets.	The	adoption	of	SFAS	No.	158	had	no impact	on	Marathon's	measurement	date	as	the	Company	has	historically	measured	the	plan	assets	and	benefit	obligations	of	its	pension	and	other	postretirement	plans as	of	December	31.	See	Note	22	for	additional	disclosures	regarding	defined	benefit	pension	and	other	postretirement	plans	required	by	SFAS	No.	158.

The	following	table	illustrates	the	incremental	effect	of	applying	SFAS	No.	158	on	individual	line	items	of	the	balance	sheet	as	of	December	31,	2006.

|  | Before |  | After |
| :--- | :--- | :--- | :--- |
|  | Application |  | Application |
|  | of\tSFAS |  | of\tSFAS |
| (In\tmillions) | No.\t158 | Adjustments | No.\t158 |
| Prepaid\tpensions | $229 | $(229) | $– |
| Equity\tmethod\tinvestments | 1,545 | (6) | 1,539 |
| Total\tassets | 31,066 | (235) | 30,831 |
| Payroll\tand\tbenefits\tpayable | $384 | $25 | $409 |
| Long-term\tdeferred\tincome\ttaxes | 2,183 | (286) | 1,897 |
| Defined\tbenefit\tpostretirement\tplan\tobligations | $870 | $375 | $1,245 |
| Deferred\tcredits\tand\tother\tliabilities | 397 | (6) | 391 |
| Total\tliabilities | 15,598 | 108 | 15,706 |
| Accumulated\tother\tcomprehensive\tloss | (25) | (343) | (368) |
| Total\tstockholders'\tequity | $14,950 | $(343) | $14,607 |

SAB	No.	108	–	In	September	2006,	the	Securities	and	Exchange	Commission	issued	Staff	Accounting	Bulletin	("SAB")	No.	108,	"Financial	Statements	–	Considering the	Effects	of	Prior	Year	Misstatements	When	Quantifying	Misstatements	in	Current	Year	Financial	Statements."	SAB	No.	108	addresses	how	a	registrant	should quantify	the	effect	of	an	error	in	the	financial	statements	for	purposes	of	assessing	materiality	and	requires	that	the	effect	be	computed	using	both	the	current	year income	statement	perspective	("rollover")	and	the	year	end	balance	sheet	perspective	("iron	curtain")	methods	for	fiscal	years	ending	after	November	15,	2006.	If	a change	in	the	method	of	quantifying	errors	is	required	under	SAB	No.	108,	this	represents	a	change	in	accounting	policy;	therefore,	if	the	use	of	both	methods	results	in	a larger,	material	misstatement	than	the	previously	applied	method,	the	financial	statements	must	be	adjusted.	SAB	No.	108	allows	the	cumulative	effect	of	such adjustments	to	be	made	to	opening	retained	earnings	upon	adoption.	Marathon	adopted	SAB	No.	108	for	the	year	ended	December	31,	2006,	and	adoption	did	not	have an	effect	on	Marathon's	consolidated	results	of	operations,	financial	position	or	cash	flows.

EITF	Issue	No.	06-03	–	In	June	2006,	the	FASB	ratified	the	consensus	reached	by	the	EITF	regarding	Issue	No.	06-03,	"How	Taxes	Collected	from	Customers	and Remitted	to	Governmental	Authorities	Should	be	Presented	in	the	Income	Statement	(That	Is,	Gross	versus	Net	Presentation)."	Included	in	the	scope	of	this	issue	are	any taxes	assessed	by	a	governmental	authority	that	are	imposed	on	and	concurrent	with	a	specific	revenue-producing	transaction	between	a	seller	and	a	customer.	The	EITF concluded	that	the	presentation	of	such	taxes	on	a	gross	basis	(included	in	revenues	and	costs)	or	a	net	basis	(excluded	from	revenues)	is	an	accounting	policy	decision that	should	be	disclosed	pursuant	to	Accounting	Principles	Board	("APB")	Opinion	No.	22,	"Disclosure	of	Accounting	Policies."	In	addition,	the	amounts	of	such	taxes reported	on	a	gross	basis	must	be	disclosed	if	those	tax	amounts	are	significant.	The	policy	disclosures	required	by	this	consensus	are	included	in	Note	1	under	the heading	"Consumer	excise	taxes"	and	the	taxes	reported	on	a	gross	basis	are	presented	separately	as	consumer	excise	taxes	in	the	consolidated	statements	of	income.

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,	Marathon	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,	which	are	discussed	below).	In a	typical	matching	buy/sell	transaction,	Marathon	enters	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,	Marathon	recorded	such	matching	buy/sell	transactions	in	both	revenues	and	cost	of	revenues	as	separate	sale	and	purchase	transactions.	Upon adoption,	these	transactions	are	accounted	for	as	exchanges	of	inventory.

The	scope	of	EITF	Issue	No.	04-13	excludes	matching	buy/sell	arrangements	that	are	accounted	for	as	derivative	instruments.	A	portion	of	Marathon's	matching buy/sell	transactions	are	"nontraditional	derivative	instruments,"	which	are	discussed	in	Note	1.	Although	the	accounting	for	nontraditional	derivative	instruments	is outside	the	scope	of	EITF	Issue	No.	04-13,	the	conclusions	reached	in	that	consensus	caused	Marathon	to	reconsider	the	guidance	in	EITF	Issue	No.	03-11,	"Reporting Realized	Gains	and	Losses	on	Derivative	Instruments	That	Are	Subject	to	FASB	Statement	No.	133	and	Not	"Held	for	Trading	Purposes"	as	Defined	in	Issue	No.	02-3." As	a	result,	effective	for	contracts	entered	into	or	modified	on	or	after	April	1,	2006,	the	effects	of	matching	buy/sell	arrangements	accounted	for	as	nontraditional derivative	instruments	are	recognized	on	a	net	basis	in	net	income	and	are	classified	as	cost	of	revenues.	Prior	to	this	change,	Marathon	recorded	these	transactions	in both	revenues	and	cost	of	revenues	as	separate	sale	and	purchase	transactions.	This	change	in	accounting	principle	is	being	applied	on	a	prospective	basis	because	it	is impracticable	to	apply	the	change	on	a	retrospective	basis.

Transactions	arising	from	matching	buy/sell	arrangements	entered	into	before	April	1,	2006	will	continue	to	be	reported	as	separate	sale	and	purchase	transactions.

The	adoption	of	EITF	Issue	No.	04-13	and	the	change	in	the	accounting	for	nontraditional	derivative	instruments	had	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.

SFAS	No.	123	(Revised	2004)	–	In	December	2004,	the	FASB	issued	SFAS	No.	123	(R),	"Share-Based	Payment,"	as	a	revision	of	SFAS	No.	123,	"Accounting	for Stock-Based	Compensation."	This	statement	requires	entities	to	measure	the	cost	of	employee	services	received	in	exchange	for	an	award	of	equity	instruments	based	on the	fair	value	of	the	award	on	the	grant	date.	That	cost	is	recognized	over	the	period	during	which	an	employee	is	required	to	provide	service	in	exchange	for	the	award, usually	the	vesting	period.	In	addition,	awards	classified	as	liabilities	are	remeasured	at	fair	value	each	reporting	period.	Marathon	had	previously	adopted	the	fair	value method	under	SFAS	No.	123	for	grants	made,	modified	or	settled	on	or	after	January	1,	2003.

SFAS	No.	123(R)	also	requires	a	company	to	calculate	the	pool	of	excess	tax	benefits	available	to	absorb	tax	deficiencies	recognized	subsequent	to	adopting	the statement.	In	November	2005,	the	FASB	issued	FSP	No.	123R-3,	"Transition	Election	Related	to	Accounting	for	the	Tax	Effects	of	Share-Based	Payment	Awards,"	to provide	an	alternative	transition	election	(the	"short-cut	method")	to	account	for	the	tax	effects	of	share-based	payment	awards	to	employees.	Marathon	elected	the	long- form	method	to	determine	its	pool	of	excess	tax	benefits	as	of	January	1,	2006.

Marathon	adopted	SFAS	No.	123(R)	as	of	January	1,	2006,	for	all	awards	granted,	modified	or	cancelled	after	adoption	and	for	the	unvested	portion	of	awards outstanding	at	January	1,	2006.	At	the	date	of	adoption,	SFAS	No.	123(R)	requires	that	an	assumed	forfeiture	rate	be	applied	to	any	unvested	awards	and	that	awards classified	as	liabilities	be	measured	at	fair	value.	Prior	to	adopting	SFAS	No.	123(R),	Marathon	recognized	forfeitures	as	they	occurred	and	applied	the	intrinsic	value method	to	awards	classified	as	liabilities.	The	adoption	did	not	have	a	significant	effect	on	Marathon's	consolidated	results	of	operations,	financial	position	or	cash flows.

SFAS	No.	151	–	Effective	January	1,	2006,	Marathon	adopted	SFAS	No.	151,	"Inventory	Costs	–	an	amendment	of	ARB	No.	43,	Chapter	4."	This	statement	requires that	items	such	as	idle	facility	expense,	excessive	spoilage,	double	freight	and	re-handling	costs	be	recognized	as	a	current-period	charge.	The	adoption	did	not	have	a significant	effect	on	Marathon's	consolidated	results	of	operations,	financial	position	or	cash	flows.

SFAS	No.	154	–	Effective	January	1,	2006,	Marathon	adopted	SFAS	No.	154,	"Accounting	Changes	and	Error	Corrections	–	A	Replacement	of	APB	Opinion	No.	20 and	FASB	Statement	No.	3."	SFAS	No.	154	requires	companies	to	recognize	(1)	voluntary	changes	in	accounting	principle	and	(2)	changes	required	by	a	new accounting	pronouncement,	when	the	pronouncement	does	not	include	specific	transition	provisions,	retrospectively	to	prior	periods'	financial	statements,	unless	it	is impracticable	to	determine	either	the	period-specific	effects	or	the	cumulative	effect	of	the	change.

FIN	No.	47	–	In	March	2005,	the	FASB	issued	FIN	No.	47,	"Accounting	for	Conditional	Asset	Retirement	Obligations	–	an	interpretation	of	FASB	Statement No.	143."	This	interpretation	clarifies	that	an	entity	is	required	to	recognize	a	liability	for	a	legal	obligation	to	perform	asset	retirement	activities	when	the	retirement	is conditional	on	a	future	event	if	the	liability's	fair	value	can	be	reasonably	estimated.	If	the	liability's	fair	value	cannot	be	reasonably	estimated,	then	the	entity	must disclose	(1)	a	description	of	the	obligation,	(2)	the	fact	that	a	liability	has	not	been	recognized	because	the	fair	value	cannot	be	reasonably	estimated	and	(3)	the	reasons why	the	fair	value	cannot	be	reasonably	estimated.	FIN	No.	47	also	clarifies	when	an	entity	would	have	sufficient	information	to	reasonably	estimate	the	fair	value	of	an asset	retirement	obligation.	Marathon	adopted	FIN	No.	47	as	of	December	31,	2005.	A	charge	of	$19	million,	net	of	taxes	of	$12	million,	related	to	adopting	FIN	No.	47 was	recognized	as	a	cumulative	effect	of	a	change	in	accounting	principle	in	2005.	At	the	time	of	adoption,	total	assets	increased	$22	million	and	total	liabilities increased	$41	million.

The	pro	forma	net	income	and	net	income	per	share	effect	as	if	FIN	No.	47	had	been	applied	during	2005	is	not	significantly	different	than	the	amounts	reported. The	total	amount	of	the	liability	for	asset	retirement	obligations	at	the	beginning	of	2005	would	have	been	$527	million	if	FIN	No.	47	had	been	applied	as	of	that	date. The	pro	forma	impact	of	the	adoption	of	FIN	No.	47	on	this	unaudited	pro	forma	amount	has	been	measured	using	the	information,	assumptions	and	interest	rates	used to	measure	the	obligation	recognized	upon	adoption	of	FIN	No.	47.

FSP	No.	FAS	19-1	–	Effective	January	1,	2005,	Marathon	adopted	FSP	No.	FAS	19-1,	"Accounting	for	Suspended	Well	Costs,"	which	amended	the	guidance	for deferred	exploratory	well	costs	in	SFAS	No.	19,	"Financial	Accounting	and	Reporting	by	Oil	and	Gas	Producing	Companies."	SFAS	No.	19	requires	costs	of	drilling exploratory	wells	to	be	capitalized	pending	determination	of	whether	the	well	has	found	proved	reserves.	When	a	classification	of	proved	reserves	cannot	yet	be	made, FSP	No.	FAS	19-1	allows	exploratory	well	costs	to	continue	to	be	capitalized	when	(1)	the	well	has	found	a	sufficient	quantity	of	reserves	to	justify	completion	as	a producing	well	and	(2)	the	enterprise	is	making	sufficient	progress	assessing	the	reserves	and	the	economic	and	operating	viability	of	the	project.	Marathon's	accounting policy	for	deferred	exploratory	well	costs	was	in	accordance	with	FSP	No.	FAS	19-1	prior	to	its	adoption.	FSP	No.	FAS	19-1	also	requires	certain	disclosures	to	be made	regarding	capitalized	exploratory	well	costs	which	are	included	in	Note	14.

# 3.	Information	about	United	States	Steel

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

Financial	Matters	Agreement	–	Marathon	and	United	States	Steel	have	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	Separation,	United	States	Steel	will	provide	for	Marathon's	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	from	Marathon,	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	is	the	sole	general	partner	of	Clairton	1314B	Partnership,	L.P.,	which	owns	certain	cokemaking	facilities	formerly	owned	by	United	States	Steel. Marathon	has	guaranteed	to	the	limited	partners	all	obligations	of	United	States	Steel	under	the	partnership	documents.	The	Financial	Matters	Agreement	requires United	States	Steel	to	use	commercially	reasonable	efforts	to	have	Marathon	released	from	its	obligations	under	this	guarantee.	United	States	Steel	may	dissolve	the partnership	under	certain	circumstances,	including	if	it	is	required	to	fund	accumulated	cash	shortfalls	of	the	partnership	in	excess	of	$150	million.	In	addition	to	the normal	commitments	of	a	general	partner,	United	States	Steel	has	indemnified	the	limited	partners	for	certain	income	tax	exposures.

The	Financial	Matters	Agreement	requires	Marathon	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	Marathon's	consent.

Tax	Sharing	Agreement	–	Marathon	and	United	States	Steel	have	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	Separation	date	and	taxes	resulting from	transactions	effected	in	connection	with	the	Separation.

In	2006	and	2005,	in	accordance	with	the	terms	of	the	Tax	Sharing	Agreement,	Marathon	paid	$35	million	and	$6	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.	Variable	Interest	Entities

Equatorial	Guinea	LNG	Holdings	Limited	("EGHoldings"),	in	which	Marathon	holds	a	60	percent	interest,	was	formed	for	the	purpose	of	constructing	and	operating	an LNG	production	facility.	During	facility	construction,	EGHoldings	was	a	VIE	that	was	consolidated	by	Marathon	because	Marathon	was	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, Marathon	no	longer	consolidates	EGHoldings,	despite	the	fact	that	the	Company	holds	majority	ownership,	because	the	minority	shareholders	have	rights	limiting Marathon's	ability	to	exercise	control	over	the	entity.	Marathon's	investment	is	accounted	for	prospectively	using	the	equity	method	of	accounting,	is	carried	at	the Company's	share	of	net	assets	plus	loans	and	advances,	which	totaled	$1.014	billion	as	of	December	31,	2007,	and	is	included	in	equity	method	investments	in	the consolidated	balance	sheet	as	of	that	date.	The	Andersons	Marathon	Ethanol	LLC,	a	joint	venture	in	which	Marathon	and	its	partner	each	hold	a	50	percent	interest	and which	was	formed	in	2006	for	the	purpose	of	constructing	and	operating	one	or	more	ethanol	production	plants,	is	a	VIE	that	is	not	consolidated.	As	of	December	31, 2007,	Marathon	had	invested	$38	million	in	The	Andersons	Marathon	Ethanol	LLC.

# 5.	Related	Party	Transactions

•Sociedad	Nacional	de	Gas	de	Guinea	Ecuatorial	("SONAGAS"),	which	has	held	a	25	percent	ownership	interest	in	EGHoldings,	since	November	14,	2006;

•	 Mitsui	&	Co.,	Ltd.	("Mitsui")	and	Marubeni	Corporation	("Marubeni"),	which	have	held	8.5	percent	and	6.5	percent	ownership	interests	in	EGHoldings since	July	25,	2005;

•	 Compania	Nacional	de	Petroleos	de	Guinea	Ecuatorial	("GEPetrol"),	which	held	a	25	percent	ownership	interest	in	EGHoldings	until	November	14,	2006;

•	 Ashland	Inc.	("Ashland"),	which	held	a	38	percent	ownership	interest	in	Marathon	Petroleum	Company	LLC	("MPC"),	a	consolidated	subsidiary,	until June	30,	2005;	and

# •Equity	method	investees.

SONAGAS,	Mitsui	and	Marubeni	ceased	being	related	parties	on	May	1,	2007,	upon	the	deconsolidation	of	EGHoldings	discussed	in	Note	4.	At	that	date,	EGHoldings became	a	related	party	as	it	became	an	equity	method	investee.

Management	believes	that	transactions	with	related	parties	were	conducted	under	terms	comparable	to	those	with	unrelated	parties.

Related	party	sales	to	Pilot	Travel	Centers	LLC	("PTC")	and	Ashland	consist	primarily	of	petroleum	products.	Revenues	from	related	parties	were	as	follows:

| (In	millions) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Equity\tmethod\tinvestees: |  |  |  |
| PTC | $1,556 | $1,420 | $1,205 |
| Centennial\tPipeline\tLLC\t("Centennial") | 27 | 28 | 47 |
| Other\tequity\tmethod\tinvestees | 42 | 18 | 18 |
| Ashland | – | – | 132 |
| Total | $1,625 | $1,466 | $1,402 |

Cash	of	$234	million	held	in	escrow	for	future	capital	contributions	from	SONAGAS	to	EGHoldings	was	classified	as	restricted	cash	by	EGHoldings	and	was included	in	other	noncurrent	assets	as	of	December	31,	2006.	As	discussed	in	Note	4,	EGHoldings	is	no	longer	consolidated	effective	May	1,	2007.

# 6.	Acquisitions

Western	Oil	Sands	Inc.	–	On	October	18,	2007,	Marathon	completed	the	acquisition	of	all	the	outstanding	shares	of	Western	Oil	Sands	Inc.	("Western")	for	cash	and securities	of	$5.833	billion.	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,	Marathon's	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.

(a) Western	shareholders	received	cash	of	3.808	billion	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	Marathon's	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	Marathon's	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	following	table	summarizes	the	estimated	fair	values	of	the	assets	and	liabilities	acquired	as	of	October	18,	2007.	Marathon	is	in	the	process	of	finalizing	the fair	value	estimates	for	certain	assets	and	liabilities;	thus	the	allocation	of	the	purchase	price	is	preliminary.

The	goodwill	arising	from	the	purchase	price	allocation	was	$1.508	billion,	of	which	$1.437	billion	was	assigned	to	the	Oil	Sands	Mining	Segment	$71	million	was assigned	to	the	E&P	segment.	None	of	the	goodwill	is	deductible	for	tax	purposes.

The	following	unaudited	pro	forma	data	is	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\t–\tbasic | $5.07 | $6.35 |
| Income\tfrom\tcontinuing\toperations\t–\tdiluted | $5.03 | $6.30 |
| Net\tincome\t–\tbasic | $5.08 | $6.72 |
| Net\tincome\t–\tdiluted | $5.04 | $6.67 |

Minority	interest	in	MPC	–	On	June	30,	2005,	Marathon	acquired	the	38	percent	ownership	interest	in	Marathon	Ashland	Petroleum	LLC	("MAP")	previously	held	by Ashland.	In	addition,	Marathon	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	effective	September	1,	2005.	The	acquisition	was	accounted	for	under	the purchase	method	of	accounting	and,	as	such,	Marathon's	results	of	operations	include	the	results	of	the	acquired	businesses	from	June	30,	2005.	The	purchase	price	is	as follows:

# (In	millions)

(a) The	MAP	Limited	Liability	Company	Agreement	was	amended	to	eliminate	the	requirement	for	MPC	to	make	quarterly	cash	distributions	to	Marathon	and	Ashland	between	the	date	the	principal	transaction agreements	were	signed	and	the	closing	of	the	acquisition.	Cash	and	MPC	accounts	receivable	above	include	$506	million	representing	Ashland's	38	percent	of	MPC's	distributable	cash	as	of	June	30,	2005.

(b) Ashland	shareholders	received	35	million	shares	valued	at	$27.23	per	share,	which	was	Marathon's	average	common	stock	price	over	the	trading	days	between	June	23	and	June	29,	2005.	The	exchange	ratio	was designed	to	provide	an	aggregate	number	of	Marathon	shares	worth	$915	million	based	on	Marathon's	average	common	stock	price	for	each	of	the	20	consecutive	trading	days	ending	with	the	third	complete trading	day	prior	to	June	30,	2005.

(c) Assumed	debt	was	repaid	on	July	1,	2005. (d) Marathon	is	entitled	to	certain	tax	deductions	related	to	businesses	previously	owned	by	Ashland.	However,	pursuant	to	the	terms	of	the	tax	matters	agreement,	Marathon	has	agreed	to	reimburse	Ashland	for	a portion	of	the	tax	benefits	associated	with	these	deductions.	This	additional	consideration	will	be	included	in	the	purchase	price	as	amounts	owed	to	Ashland	are	identified.	Additions	to	the	purchase	price	for	such amounts	were	$13	million	and	$17	million	in	2007	and	2006.

The	primary	reasons	for	the	acquisition	and	the	principal	factors	that	contributed	to	a	purchase	price	that	resulted	in	the	recognition	of	goodwill	were:

•	 Marathon	believed	the	outlook	for	the	refining	and	marketing	business	was	attractive	in	MPC's	core	areas	of	operation.	Complete	ownership	of	MPC provided	Marathon	the	opportunity	to	leverage	MPC's	access	to	premium	U.S.	markets	where	Marathon	expected	the	levels	of	demand	to	remain	high	for	the foreseeable	future;

•The	acquisition	increased	Marathon's	participation	in	the	RM&T	business	without	the	risks	commonly	associated	with	integrating	a	newly	acquired	business;

•	 MPC	provided	Marathon	with	an	increased	source	of	cash	flow	which	Marathon	believed	enhanced	the	geographical	balance	in	its	overall	risk	portfolio;

•	 Marathon	anticipated	the	transaction	would	be	accretive	to	income	per	share;

•The	acquisition	eliminated	the	timing	and	valuation	uncertainties	associated	with	the	exercise	of	the	Put/Call,	Registration	Rights	and	Standstill	Agreement entered	into	with	the	formation	of	MPC	in	1998,	as	well	as	the	associated	premium	and	discount;	and

•The	acquisition	eliminated	the	possibility	that	a	misalignment	of	Ashland's	and	Marathon's	interests,	as	co-owners	of	MPC,	could	adversely	affect	MPC's future	growth	and	financial	performance.

The	following	table	summarizes	the	estimated	fair	values	of	the	assets	acquired	and	liabilities	assumed	as	of	June	30,	2005.

The	goodwill	arising	from	the	purchase	price	allocation	was	$846	million,	which	was	assigned	to	the	RM&T	segment.	None	of	the	goodwill	is	deductible	for	tax purposes.	Of	the	$112	million	allocated	to	intangible	assets,	$49	million	was	allocated	to	retail	marketing	tradenames	with	indefinite	lives.

The	purchase	price	allocated	to	equity	method	investments	is	$230	million	higher	than	the	underlying	net	assets	of	the	investees.	This	excess	will	be	amortized	over the	expected	useful	lives	of	the	underlying	assets	except	for	$144	million	of	the	excess	related	to	goodwill.

Libya	re-entry	–	On	December	29,	2005,	Marathon,	in	conjunction	with	its	partners	in	the	former	Oasis	Group,	entered	into	an	agreement	with	the	National	Oil Corporation	of	Libya	to	return	to	its	oil	and	natural	gas	exploration	and	production	operations	in	the	Waha	concessions	in	Libya.	Marathon	holds	a	16.33	percent	interest in	the	Waha	concessions	and	was	required	to	cease	operations	there	in	1986	to	comply	with	U.S.	government	sanctions.	Over	time,	Marathon	had	written	off	all	its	assets in	Libya.	The	re-entry	terms	included	a	25-year	extension	of	the	concessions	to	2030	through	2034	and	payments	from	Marathon	of	$520	million	and	$198	million, which	were	made	in	January	and	December	2006.

The	primary	reasons	for	the	transaction	and	the	principal	factors	that	contributed	to	a	purchase	price	that	resulted	in	the	recognition	of	goodwill	include	the	fact	that the	re-entry	allows	Marathon	to	expand	its	exploration	and	production	operations	without	many	of	the	risks	commonly	associated	with	integrating	a	newly	acquired business	including	having	a	trained	workforce	in	place	that	has	maintained	operations	and	added	to	the	hydrocarbon	resource	during	the	absence	of	Marathon	and	its partners.	The	transaction	also	could	assist	Marathon	in	identifying	and	participating	in	potential	future	projects	in	Libya.

The	operational	re-entry	date	under	the	terms	of	the	agreement	was	January	1,	2006;	therefore,	Marathon's	consolidated	results	of	operations	for	2005	do	not include	any	results	from	the	operations	of	the	Waha	concessions.	The	transaction	was	accounted	for	under	the	purchase	method	of	accounting.

The	following	table	summarizes	the	estimated	fair	values	of	the	assets	acquired	and	liabilities	assumed	as	of	December	29,	2005.

The	goodwill	arising	from	the	purchase	price	allocation	was	$309	million,	which	was	assigned	to	the	E&P	segment.	None	of	the	goodwill	is	deductible	for	tax purposes.

The	following	unaudited	pro	forma	data	is	as	if	the	acquisition	of	the	minority	interest	in	MPC	and	the	re-entry	to	the	Libya	concessions	had	been	consummated	at the	beginning	of	2005.	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.

# 7.	Discontinued	Operations

On	June	2,	2006,	Marathon	sold	its	Russian	oil	exploration	and	production	businesses	in	the	Khanty-Mansiysk	region	of	western	Siberia.	Under	the	terms	of	the agreement,	Marathon	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	as	discussed	in	Note	11.	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	all	periods	presented.	Revenues	applicable	to	discontinued	operations	were	$173	million	and	$325	million	for	2006	and	2005.	Pretax	income	from discontinued	operations	was	$45	million	and	$61	million	for	2006	and	2005.

# 8.	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,	provided	the	effect	is	not	antidilutive.

|  | 2007 | 2007 | 2006 | 2006 | 2005 | 2005 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions,\texcept\tper\tshare\tdata) | Basic | Diluted | Basic | Diluted | Basic | Diluted |
| Income\tfrom\tcontinuing\toperations | $3,948 | $3,948 | $4,957 | $4,957 | $3,006 | $3,006 |
| Discontinued\toperations | 8 | 8 | 277 | 277 | 45 | 45 |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | – | – | – | – | (19) | (19) |
| Net\tincome | $3,956 | $3,956 | $5,234 | $5,234 | $3,032 | $3,032 |
| Weighted\taverage\tcommon\tshares\toutstanding | 690 | 690 | 716 | 716 | 712 | 712 |
| Effect\tof\tdilutive\tsecurities | – | 5 | – | 6 | – | 6 |
| Weighted\taverage\tcommon\tshares,\tincluding\tdilutive\teffect | 690 | 695 | 716 | 722 | 712 | 718 |
| Per\tshare:\nIncome\tfrom\tcontinuing\toperations | $5.72 | $5.68 | $6.92 | $6.87 | $4.22 | $4.19 |
| Discontinued\toperations | $0.01 | $0.01 | $0.39 | $0.38 | $0.07 | $0.06 |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | $– | $– | $– | $– | $(0.03) | $(0.03) |
| Net\tincome | $5.73 | $5.69 | $7.31 | $7.25 | $4.26 | $4.22 |

The	per	share	calculations	above	exclude	3.2	million	stock	options	in	2007	that	were	antidilutive.	There	were	no	antidilutive	stock	options	in	2006	and	2005.

# 9.	Segment	Information

As	discussed	in	Note	7,	the	Russian	businesses	that	were	sold	in	June	2006	have	been	accounted	for	as	discontinued	operations.	Segment	information	for	all presented	periods	excludes	the	amounts	for	these	Russian	operations.

As	discussed	in	Note	6,	Marathon	acquired	Western	in	October	2007.	The	acquisition	was	accounted	for	under	the	purchase	method	of	accounting	and,	as	such, Marathon's	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.

Revenues	by	product	line	were:

|  | E&amp;P | OSM | RM&amp;T | IG | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 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 | \t 9,155 | 221 | \t 56,075 | \t 218 | \t 65,669 |
| Elimination\tof\tintersegment\trevenues | (497) | (40) | (348) | – | (885) |
| Loss\ton\tlong-term\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 | \t 168 | 545 |
| Depreciation,\tdepletion\tand\tamortization(b) | 963 | 22 | 587 | 6 | 1,578 |
| Minority\tinterests\tin\tloss\tof\tsubsidiary | – | – | – | 3 | 3 |
| Income\ttax\tprovision\t(benefit)(b) | \t 2,172 | (21) | 1,183 | 24 | 3,358 |
| Capital\texpenditures(c)(d) | \t 2,511 | 165 | 1,640 | 93 | 4,409 |
| 2006 |  |  |  |  |  |
| Revenues: |  |  |  |  |  |
| Customer | $8,326 | $– | $54,471 | $179 | $62,976 |
| Intersegment(a) | 672 | – | 16 | – | 688 |
| Related\tparties | 12 | – | 1,454 | – | 1,466 |
| Segment\trevenues | \t 9,010 | – | \t 55,941 | \t 179 | \t 65,130 |
| Elimination\tof\tintersegment\trevenues | (672) | – | (16) | – | (688) |
| Gain\ton\tlong-term\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 |
| Depreciation,\tdepletion\tand\tamortization(b) | 919 | – | 558 | 9 | 1,486 |
| Minority\tinterests\tin\tloss\tof\tsubsidiary | – | – | – | 10 | 10 |
| Income\ttax\tprovision(b) | \t 2,371 | – | 1,642 | 8 | 4,021 |
| Capital\texpenditures(c)(d) | \t 2,169 | – | 916 | \t 307 | 3,392 |
| 2005 |  |  |  |  |  |
| Revenues: |  |  |  |  |  |
| Customer | $7,320 | $– | $54,414 | $236 | $61,970 |
| Intersegment(a) | 678 | – | 198 | – | 876 |
| Related\tparties | 11 | – | 1,391 | – | 1,402 |
| Segment\trevenues | \t 8,009 | – | \t 56,003 | \t 236 | \t 64,248 |
| Elimination\tof\tintersegment\trevenues | (678) | – | (198) | – | (876) |
| Loss\ton\tlong-term\tU.K.\tnatural\tgas\tcontracts | (386) | – | – | – | (386) |
| Total\trevenues | $6,945 | $– | $55,805 | $236 | $62,986 |
| Segment\tincome | $1,887 | $– | $1,628 | $55 | $3,570 |
| Income\tfrom\tequity\tmethod\tinvestments | 69 | – | 137 | 59 | 265 |
| Depreciation,\tdepletion\tand\tamortization(b) | 794 | – | 468 | 8 | 1,270 |
| Minority\tinterests\tin\t(income)\tloss\tof\tsubsidiaries(b) | – | – | (376) | 8 | (368) |
| Income\ttax\tprovision\t(benefit)(b) | \t 1,030 | – | 1,007 | (7) | 2,030 |
| Capital\texpenditures(c)(d) | \t 1,366 | – | 841 | \t 571 | 2,778 |
| (a) |  |  |  |  |  |

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

(b) Differences	between	segment	totals	and	Marathon	totals	represent	amounts	related	to	corporate	administrative	activities	and	other	unallocated	items	and	are	included	in	"Items	not	allocated	to	segments,	net	of income	taxes"	in	the	reconciliation	below.

(c) Differences	between	segment	totals	and	Marathon	totals	represent	amounts	related	to	corporate	administrative	activities.

(d) Through	April	2007,	Integrated	Gas	segment	capital	expenditures	include	EGHoldings	at	100	percent.	As	discussed	in	Note	4,	effective	May	1,	2007,	Marathon	no	longer	consolidates	EGHoldings	and	its investment	in	EGHoldings	is	accounted	for	under	the	equity	method	of	accounting;	therefore	EGHoldings'	capital	expenditures	subsequent	to	April	2007	are	not	included	in	Marathon's	capital	expenditures.

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

| (In	millions) | 2007 | 2006 |
| :--- | :--- | :--- |
| United\tStates | $13,133 | $11,365 |
| Canada | 6,980 | – |
| Equatorial\tGuinea | 2,842 | 3,186 |
| Other\tinternational | 4,393 | 3,675 |
| Total | $27,348 | $18,226 |

# 10.	Other	Items

# Net	interest	and	other	financial	income	(costs)

| (In	millions) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Interest\tand\tother\tfinancial\tincome: |  |  |  |
| Interest\tincome | $144 | $129 | $77 |
| Foreign\tcurrency\tgains\t(losses) | 2 | 16 | (17) |
| Total | 146 | 145 | 60 |
| Interest\tand\tother\tfinancing\tcosts: |  |  |  |
| Interest\tincurred(a) | 290 | 245 | 257 |
| Loss\ton\tinterest\trate\tswaps | 15 | 16 | – |
| Interest\tcapitalized | (214) | (152) | (83) |
| Net\tinterest\texpense | 91 | 109 | 174 |
| Other | 14 | (1) | 32 |
| Total | 105 | 108 | 206 |
| Net\tinterest\tand\tother\tfinancial\tincome\t(costs) | $41 | $37 | $(146) |
| (a) |  |  |  |

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

| (In	millions) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Net\tinterest\tand\tother\tfinancing\tcosts | $2 | $16 | $(17) |
| Provision\tfor\tincome\ttaxes | 18 | (22) | 24 |
| Aggregate\tforeign\tcurrency\tgains\t(losses) | $20 | $(6) | $7 |

# 11.	Income	Taxes

Income	tax	provisions	(benefits)	were:

|  | 2007 | 2007 | 2007 | 2006 | 2006 | 2006 | 2005 | 2005 | 2005 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | Current | Deferred | Total | Current | Deferred | Total | Current | Deferred | Total |
| Federal | $1,290 | $(2) | $1,288 | $1,579 | $72 | $1,651 | $1,225 | $14 | $1,239 |
| State\tand\tlocal | 184 | 22 | 206 | 230 | 30 | 260 | 171 | 12 | 183 |
| Foreign | 1,774 | (367) | \t 1,407 | 1,945 | 166 | \t 2,111 | 523 | (231) | 292 |
| Total | $3,248 | $(347) | $2,901 | $3,754 | $268 | $4,022 | $1,919 | $(205) | $1,714 |

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) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Statutory\trate\tapplied\tto\tincome\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | $2,397 | $3,143 | $1,652 |
| Effects\tof\tforeign\toperations,\tincluding\tforeign\ttax\tcredits\t(a) | 671 | 909 | (39) |
| State\tand\tlocal\tincome\ttaxes,\tnet\tof\tfederal\tincome\ttax\teffects | 134 | 170 | 134 |
| Credits\tother\tthan\tforeign\ttax\tcredits | (3) | (2) | (2) |
| Domestic\tmanufacturing\tdeduction | (64) | (47) | (39) |
| Excess\tcapital\tlosses\tgenerated | – | – | 23 |
| Effects\tof\tpartially-owned\tcompanies | (5) | (6) | (4) |
| Effects\tof\tenacted\tchanges\tin\ttax\tlaws\t(b) | (193) | (21) | (15) |
| Adjustment\tof\tprior\tyears'\tfederal\tincome\ttaxes\t(c) | (27) | (119) | 10 |
| Other | (9) | (5) | (6) |
| Provision\tfor\tincome\ttaxes | $2,901 | $4,022 | $1,714 |
| (a) |  |  |  |

(b) 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,	and	in	2005,	the	state	of	Ohio	enacted	legislation	that	phased	out	its	income-based	franchise	taxes.

(c) The	2006	adjustment	of	prior	years'	federal	income	taxes	is	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) | December	31 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Deferred\ttax\tassets: |  |  |  |
| Employee\tbenefits |  | $703 | $730 |
| Operating\tloss\tcarryforwards\t(a) |  | \t 1,596 | \t 1,016 |
| Derivative\tinstruments |  | 284 | 81 |
| Foreign\ttax\tcredits\t(b) |  | 838 | 527 |
| Other |  | 169 | 200 |
| Valuation\tallowances |  |  |  |
| Federal\t(c) |  | (29) | (19) |
| State |  | (55) | (59) |
| Foreign\t(d) |  | (917) | (611) |
| Total\tdeferred\ttax\tassets |  | \t 2,589 | \t 1,865 |
| Deferred\ttax\tliabilities: |  |  |  |
| Property,\tplant\tand\tequipment\t(e) |  | \t 4,610 | \t 2,951 |
| Inventories |  | 652 | 708 |
| Investments\tin\tsubsidiaries\tand\taffiliates |  | 987 | 552 |
| Other |  | 89 | 100 |
| Total\tdeferred\ttax\tliabilities |  | \t 6,338 | \t 4,311 |
| Net\tdeferred\ttax\tliabilities |  | $3,749 | $2,446 |
| (a) |  |  |  |

(a) At	December	31,	2007,	foreign	operating	loss	carryforwards	primarily	include	$1.214	billion	for	Norway	regular	income	tax,	$1.677	billion	for	Norway	special	petroleum	tax	and	$540	million	for	Angola	income tax.	The	Norway	and	Angola	operating	loss	carryforwards	have	no	expiration	dates.	The	remainder	of	foreign	carryforwards	are	in	several	other	foreign	jurisdictions,	the	majority	of	which	expire	in	2008	through 2020.	State	operating	loss	carryforwards	of	$765	million	expire	in	2008	through	2025.	The	state	operating	loss	carryforwards	primarily	relate	to	the	period	prior	to	the	Separation	and	are	offset	by	valuation allowances.

(b) The	Company's	expectation	regarding	its	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	Marathon's	tax	profile	in	the	years	that	such	credits	may	be	claimed.

(c) Federal	valuation	allowances	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	Marathon's	Russian	oil	exploration	and	production	businesses.	Federal	valuation	allowances	increased	$63	million	in	2005	reflecting	valuation allowances	established	for	deferred	tax	assets	generated	in	2005,	primarily	related	to	Marathon's	re-entry	into	Libya	of	$38	million	and	excess	capital	losses	related	to	certain	derivative	instruments	and	an	asset sale	of	$30	million.

(d) Foreign	valuation	allowances	increased	$306	million,	$176	million	and	$70	million	in	2007,	2006	and	2005	primarily	as	a	result	of	net	operating	loss	carryforwards	generated	in	those	years	in	Norway,	Angola	and several	other	jurisdictions. (e) Deferred	tax	liabilities	for	property,	plant,	and	equipment	increased	$1.659	billion	in	2007	primarily	due	to	a	$1.338	billion	increase	attributable	to	Marathon's	acquisition	of	Western.

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

| (In	millions) | December	31 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Assets: |  |  |  |
| Other\tcurrent\tassets |  | $2 | $4 |
| Other\tnoncurrent\tassets |  | 185 | 78 |
| Liabilities: |  |  |  |
| Current\tdeferred\tincome\ttaxes |  | 547 | 631 |
| Noncurrent\tdeferred\tincome\ttaxes |  | \t 3,389 | \t 1,897 |
| Net\tdeferred\ttax\tliabilities |  | $3,749 | $2,446 |

Marathon	is	continuously	undergoing	examination	of	its	U.S.	federal	income	tax	returns	by	the	Internal	Revenue	Service.	Such	audits	have	been	completed	through the	2003	tax	year.	The	audit	of	the	2004	and	2005	U.S.	federal	income	tax	returns	commenced	in	May	2006	and	is	ongoing.	Marathon	believes	it	has	made	adequate provision	for	federal	income	taxes	and	interest	which	may	become	payable	for	years	not	yet	settled.	Further,	Marathon	is	routinely	involved	in	U.S.	state	and	local income	tax	audits	and	foreign	jurisdiction	tax	audits.	Marathon	believes	all	other	audits	will	be	resolved	within	the	amounts	paid	and/or	provided	for	these

liabilities.	As	of	December	31,	2007,	Marathon's	income	tax	returns	remain	subject	to	examination	in	the	following	major	tax	jurisdictions	for	the	tax	years	indicated.

(a) Includes	federal,	state	and	local	jurisdictions.

Total	unrecognized	tax	benefits	were	$48	million	upon	adoption	of	FIN	No.	48	as	of	January	1,	2007,	and	were	$40	million	as	of	December	31,	2007.	If	the unrecognized	tax	benefits	as	of	December	31,	2007	were	recognized,	$29	million	would	affect	Marathon's	effective	income	tax	rate.	There	are	$23	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	2008.

The	following	table	summarizes	the	activity	in	unrecognized	tax	benefits	for	2007.

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

In	connection	with	the	adoption	of	FIN	No.	48,	Marathon	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,	Marathon recorded	such	interest	as	part	of	net	interest	and	other	financing	costs	and	such	penalties	as	selling,	general	and	administrative	expenses.	Interest	and	penalties	were	a	net $8	million	credit	to	income	for	the	year	ended	December	31,	2007.	As	of	December	31,	2007	and	2006,	$15	million	and	$17	million	of	interest	and	penalties	were accrued	related	to	income	taxes.

Pretax	income	from	continuing	operations	included	amounts	attributable	to	foreign	sources	of	$2.900	billion	in	2007,	$3.570	billion	in	2006	and	$1.061	billion	in 2005.

Undistributed	income	of	certain	consolidated	foreign	subsidiaries	at	December	31,	2007	amounted	to	$1.739	billion	for	which	no	deferred	U.S.	income	tax provision	has	been	recorded	because	Marathon	intends	to	permanently	reinvest	such	income	in	those	foreign	operations.	If	such	income	was	not	permanently	reinvested, income	tax	expense	of	$609	million	would	have	been	incurred.

# 12.	Inventories

| (In	millions) | December	31 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Liquid\thydrocarbons,\tnatural\tgas\tand\tbitumen |  | $1,203 | $1,136 |
| Refined\tproducts\tand\tmerchandise |  | \t 1,792 | \t 1,812 |
| Supplies\tand\tsundry\titems |  | 282 | 225 |
| Total\t(at\tcost) |  | $3,277 | $3,173 |

The	LIFO	method	accounted	for	89	percent	and	90	percent	of	total	inventory	value	at	December	31,	2007	and	2006.	Current	acquisition	costs	were	estimated	to	exceed the	LIFO	inventory	value	at	December	31,	2007	and	2006	by	$4.034	billion	and	$1.682	billion.

# 13.	Equity	Method	Investments

| (In	millions) | December	31 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| EGHoldings\t(a) |  | $1,014 | $– |
| Alba\tPlant\tLLC |  | 395 | 420 |
| Atlantic\tMethanol\tProduction\tCompany\tLLC |  | 245 | 257 |
| Pilot\tTravel\tCenters\tLLC |  | 493 | 510 |
| LOOP\tLLC |  | 183 | 156 |
| Other |  | 300 | 196 |
| Total |  | $2,630 | $1,539 |
| (a) |  |  |  |

(a) As	discussed	in	Note	4,	Marathon	no	longer	consolidates	EGHoldings	effective	May	1,	2007.	Marathon's	investment	is	accounted	for	prospectively	using	the	equity	method	of	accounting	and	therefore EGHoldings'	results	for	May	1,	2007	through	December	31,	2007	are	included	in	the	income	data	below.

Summarized	financial	information	of	investees	accounted	for	by	the	equity	method	of	accounting	follows:

| (In	millions) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Income\tdata\t–\tyear: |  |  |  |
| Revenues\tand\tother\tincome | $ 14,133 | $11,873 | $10,088 |
| Income\tfrom\toperations | 1,098 | 746 | 556 |
| Net\tincome | 1,038 | 710 | 474 |
| Balance\tsheet\tdata\t–\tDecember\t31: |  |  |  |
| Current\tassets | $1,279 | $817 |  |
| Noncurrent\tassets | 5,998 | 3,637 |  |
| Current\tliabilities | 1,512 | 755 |  |
| Noncurrent\tliabilities | 1,378 | 1,119 |  |

Marathon's	carrying	value	of	its	equity	method	investments	is	$356	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	$159	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	$502	million	in	2007,	$191	million	in	2006	and	$200	million	in	2005.

# 14.	Property,	Plant	and	Equipment

| (In	millions) | December	31 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Exploration\tand\tproduction |  | $21,232 | $18,894 |
| Oil\tsands\tmining\tand\tbitumen\tupgrading |  | 6,691 | – |
| Refining |  | 6,462 | 5,238 |
| Marketing |  | 2,123 | 2,015 |
| Transportation |  | 2,331 | 2,173 |
| Gas\tliquefaction\t(a) |  | 26 | 1,321 |
| Other |  | 667 | 585 |
| Total |  | $39,532 | $30,226 |
| Less\taccumulated\tdepreciation,\tdepletion\tand\tamortization |  | \t 14,857 | \t 13,573 |
| Net\tproperty,\tplant\tand\tequipment |  | $24,675 | $16,653 |
| (a) |  |  |  |

(a) Through	April	2007,	gas	liquefaction	property,	plant	and	equipment	included	EGHoldings	at	100	percent.	As	discussed	in	Note	4,	effective	May	1,	2007,	Marathon	no	longer	consolidates	EGHoldings	and	its investment	in	EGHoldings	is	accounted	for	under	the	equity	method	of	accounting;	therefore	EGHoldings'	property,	plant	and	equipment	balance	subsequent	to	April	2007	is	not	included	in	Marathon's	property, plant	and	equipment.

Property,	plant	and	equipment	includes	gross	assets	acquired	under	capital	leases	of	$74	million	and	$79	million	at	December	31,	2007	and	2006,	with	related amounts	in	accumulated	depreciation,	depletion	and	amortization	of	$13	million	and	$10	million	at	December	31,	2007	and	2006.

Deferred	exploratory	well	costs	were	as	follows:

| (Dollars	in	millions) | December	31 | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- | :--- |
| Amounts\tcapitalized\tless\tthan\tone\tyear\tafter\tcompletion\tof\tdrilling |  | $683 | $377 | $304 |
| Amounts\tcapitalized\tgreater\tthan\tone\tyear\tafter\tcompletion\tof\tdrilling |  | \t 100 | 93 | 59 |
| Total\tdeferred\texploratory\twell\tcosts |  | $783 | $470 | $363 |
| Number\tof\tprojects\twith\tcosts\tcapitalized\tgreater\tthan\tone\tyear\tafter\tcompletion\tof\tdrilling |  | 3 | 3 | 2 |

Exploratory	well	costs	capitalized	greater	than	one	year	after	completion	of	drilling	as	of	December	31,	2007	included	$46	million	for	the	Ozona	prospect	in	the Gulf	of	Mexico	that	was	primarily	incurred	in	2001	and	2002,	$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.

Marathon	is	continuing	to	evaluate	options	to	develop	the	Ozona	Prospect.	Commercial	terms	have	been	secured	that	will	allow	this	sub-sea	well	to	be	tied	back	to existing	oil	and	natural	gas	infrastructure.	We	are	actively	searching	for	a	rig	to	drill	the	planned	development	well.

The	Equatorial	Guinea	discovery	wells	are	part	of	Marathon's	long-term	LNG	strategy.	These	discoveries	will	be	developed	when	the	natural	gas	supply	from	the nearby	Alba	Field	starts	to	decline	or	additional	LNG	markets	are	entered	that	require	increased	natural	gas	supply.

Marathon	and	its	partners	are	focused	on	subsurface	evaluation	and	assessing	development	concepts	for	the	Gudrun	field	with	concept	selection	expected	in	2008.

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

(b) E&P	segment	goodwill	allocated	to	the	Russian	businesses	that	were	sold	in	June	2006	as	discussed	in	Note	7.

The	E&P	segment	tests	goodwill	for	impairment	in	the	second	quarter	of	each	year.	The	RM&T	segment	tests	goodwill	for	impairment	in	the	fourth	quarter	of	each year.	No	impairment	in	the	carrying	value	of	goodwill	has	been	identified.	The	goodwill	in	the	OSM	segment	was	acquired	in	October	2007;	therefore	no	impairment	test was	performed	in	2007.

# 16.	Intangible	Assets

# Intangible	assets	were	as	follows:

|  |  | Gross |  | Net |
| :--- | :--- | :--- | :--- | :--- |
|  |  | Carrying | Accumulated | Carrying |
| (In\tmillions) | December\t31 | Amount | Amortization | Amount |
| 2007 |  |  |  |  |
| Amortized\tintangible\tassets: |  |  |  |  |
| Oil\tsands\tmining\ttechnology |  | $105 | $– | $105 |
| Branding\tagreements |  | 58 | 22 | 36 |
| Elba\tIsland\tdelivery\trights |  | 42 | 10 | 32 |
| Other |  | 107 | 48 | 59 |
|  |  | $312 | $80 | $232 |
| Unamortized\tintangible\tassets: |  |  |  |  |
| Retail\tmarketing\ttradenames |  | $49 | $– | $49 |
| Other |  | 7 | – | 7 |
|  |  | $56 | $– | $56 |
| Total |  | $368 | $80 | $288 |
| 2006 |  |  |  |  |
| Amortized\tintangible\tassets: |  |  |  |  |
| Branding\tagreements |  | $54 | $20 | $34 |
| Elba\tIsland\tdelivery\trights |  | 42 | 8 | 34 |
| Other |  | 103 | 47 | 56 |
|  |  | $199 | $75 | $124 |
| Unamortized\tintangible\tassets: |  |  |  |  |
| Retail\tmarketing\ttradenames |  | $49 | $– | $49 |
| Other |  | 7 | – | 7 |
|  |  | $56 | $– | $56 |
| Total |  | $255 | $75 | $180 |

Derivative	instruments	are	recorded	at	fair	value.	The	fair	value	of	exchange-traded	commodity	contracts	is	based	on	market	quotes	derived	from	major	exchanges.	The fair	value	for	over-the-counter	("OTC")	commodity	contracts	is	determined	using	option-pricing	models	or	dealer	quotes.	The	fair	value	of	interest	rate	swaps	and foreign	currency	forward	contracts	is	based	on	dealer	quotes.	Marathon's	consolidated	balance	sheet	is	reported	on	a	net	basis	by	brokerage	firm,	as	permitted	by	master netting	agreements.

The	following	table	sets	forth	quantitative	information	by	category	of	derivative	instrument	at	December	31,	2007	and	2006.	These	amounts	are	reported	on	a	gross basis	by	individual	derivative	instrument.

(a) There	was	no	ineffectiveness	associated	with	fair	value	hedges	for	2007	or	2006	because	the	hedging	instruments	and	the	existing	firm	commitment	contracts	are	priced	on	the	same	underlying	index.	Derivative instruments	used	in	the	fair	value	hedges	mature	in	2008.

(b) The	contract	price	under	the	long-term	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	twelve	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	for	the	next	18	months.	The	18-month period	represents	approximately	90	percent	of	market	liquidity	in	that	region.

(c) Certain	physical	commodity	contracts	are	classified	as	nontraditional	derivative	instruments	because	certain	volumes	covered	by	these	contracts	are	physically	netted	at	particular	delivery	locations.	The	netting process	causes	all	contracts	at	such	delivery	locations	to	be	considered	derivative	instruments.	Other	physical	contracts	that	management	has	chosen	not	to	designate	as	normal	purchases	or	normal	sales,	which	can include	contracts	that	involve	flash	title,	are	also	accounted	for	as	nontraditional	derivative	instruments.

(d) The	fair	value	of	OTC	interest	rate	swaps	excludes	accrued	interest	amounts	not	yet	settled.	As	of	December	31,	2007	and	2006,	accrued	interest	was	$3	million	and	$4	million.	The	net	fair	value	of	the	OTC interest	rate	swaps	as	of	December	31,	2007	and	2006	is	included	in	long-term	debt.	See	Note	20. (e) The	changes	in	fair	value	of	cash	flow	hedges	included	no	ineffectiveness	during	2007	and	ineffectiveness	of	$3	million	during	2006	on	a	pretax	basis.

# 18.	Fair	Value	of	Financial	Instruments

The	following	table	summarizes	financial	instruments,	excluding	the	derivative	financial	instruments	in	Note	17,	by	individual	balance	sheet	line	item	at	December	31, 2007	and	2006.

|  |  |  | 2007 | 2007 | 2006 | 2006 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | Fair | Carrying | Fair | Carrying |
| (In\tmillions) | (In\tmillions) | December\t31 | Value | Amount | Value | Amount |
| Financial\tassets: |  |  |  |  |  |  |
| Cash\tand\tcash\tequivalents | Cash\tand\tcash\tequivalents |  | $1,199 | $1,199 | $2,585 | $2,585 |
| Receivables | Receivables |  | 5,897 | 5,897 | \t 4,177 | 4,177 |
| Receivables\tfrom\tUnited\tStates\tSteel | Receivables\tfrom\tUnited\tStates\tSteel |  | 500 | 507 | 533 | 530 |
| Other\tnoncurrent\tassets\t(a) | Other\tnoncurrent\tassets\t(a) |  | 1,164 | 923 | 461 | 348 |
| Total\tfinancial\tassets | Total\tfinancial\tassets |  | $8,760 | $8,526 | $7,756 | $7,640 |
| Financial\tliabilities: |  |  |  |  |  |  |
| Accounts\tpayable | Accounts\tpayable |  | $8,325 | $8,325 | $5,850 | $5,850 |
| Payables\tto\tUnited\tStates\tSteel | Payables\tto\tUnited\tStates\tSteel |  | 5 | 5 | 20 | 20 |
| Accrued\tinterest | Accrued\tinterest |  | 128 | 128 | 89 | 89 |
| Long-term\tdebt\tdue\twithin\tone\tyear\t(b) | Long-term\tdebt\tdue\twithin\tone\tyear\t(b) |  | 1,000 | 999 | 450 | 450 |
| Long-term\tdebt\t(b) | Long-term\tdebt\t(b) |  | 6,176 | 5,948 | \t 3,279 | 2,947 |
| Total\tfinancial\tliabilities | Total\tfinancial\tliabilities |  | $15,634 | $15,405 | $9,688 | $9,356 |
| (a) | Includes\ttrusteed\tfunds,\tcost\tmethod\tinvestments,\tlong-term\treceivables\tand\tdeposits. |  |  |  |  |  |

(b) Excludes	capital	leases.

The	fair	value	of	the	financial	instruments	above	is	not	necessarily	representative	of	the	amount	that	could	be	realized	or	settled,	nor	does	the	fair	value	consider	the tax	consequences	of	realization	or	settlement.	The	fair	value	of	financial	instruments	classified	as	current	assets	or	liabilities	approximates	carrying	value	due	to	the short-term	maturity	of	the	instruments.	The	fair	value	of	cost	method	investments,	long-term	receivables	and	deposits	was	based	on	discounted	cash	flows	or	other specific	instrument	analysis.	The	fair	value	of	long-term	debt	instruments	was	based	on	market	prices	where	available	or	current	borrowing	rates	available	for	financings with	similar	terms	and	maturities.	The	fair	value	of	the	receivables	from	United	States	Steel	was	estimated	using	market	prices	for	United	States	Steel	debt	assuming	the industrial	revenue	bonds	are	redeemed	on	or	before	the	tenth	anniversary	of	the	Separation	per	the	Financial	Matters	Agreement.

# 19.	Short-Term	Debt

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

# 20.	Long-Term	Debt

| (In	millions) | December	31 | 2007 | 2006 |
| :--- | :--- | :--- | :--- |
| Marathon\tOil\tCorporation: |  |  |  |
| Revolving\tcredit\tfacility\tdue\t2012(a) |  | $– | $– |
| 5.375%\tnotes\tdue\t2007 |  | – | 450 |
| 6.850%\tnotes\tdue\t2008 |  | 400 | 400 |
| 6.125%\tnotes\tdue\t2012(b) |  | 450 | 450 |
| 6.000%\tnotes\tdue\t2012(b) |  | 400 | 400 |
| 6.800%\tnotes\tdue\t2032(b) |  | 550 | 550 |
| 9.375%\tdebentures\tdue\t2012(c) |  | 87 | 123 |
| 9.125%\tdebentures\tdue\t2013(c) |  | 174 | 212 |
| 6.000%\tdebentures\tdue\t2017(b) |  | 750 | – |
| 9.375%\tdebentures\tdue\t2022(c) |  | 65 | 67 |
| 8.500%\tdebentures\tdue\t2023(c) |  | 116 | 122 |
| 8.125%\tdebentures\tdue\t2023(c) |  | 172 | 181 |
| 6.600%\tdebentures\tdue\t2037(b) |  | 750 | – |
| 4.550%\tpromissory\tnote,\tsemi-annual\tpayments\tdue\t2008\t–\t2015 |  | 544 | – |
| Series\tA\tmedium\tterm\tnotes\tdue\t2022 |  | 3 | 3 |
| and\tnotes\tdue\t2009\t–\t2033(d) |  | 439 | 439 |
| 5.125%\tobligation\trelating\tto\trevenue\tbonds\tdue\t2037(e) |  | 1,000 | – |
| Sale-leaseback\tfinancing\tdue\t2008\t–\t2012(f) |  | 45 | 60 |
| Capital\tlease\tobligation\tdue\t2008\t–\t2012(g) |  | 38 | 44 |
| Consolidated\tsubsidiaries: |  |  |  |
| Revolving\tcredit\tfacility\tdue\t2012(h) |  | 599 | – |
| 8.375%\tsecured\tnotes\tdue\t2012(b)\t(c)\t(\ti) |  | 448 | – |
| Sale-leaseback\tfinancing\tdue\t2009\t–\t2024(j) |  | 45 | – |
| Capital\tlease\tobligations\tdue\t2008\t–\t2020(j) |  | 108 | 59 |
| Total\t(k)(l) |  | 7,183 | \t 3,560 |
| Unamortized\tfair\tvalue\tdifferential\tfor\tdebt\tassumed\tin\tacquisitions |  | 47 | – |
| Unamortized\tdiscount |  | (12) | (6) |
| Fair\tvalue\tadjustments\ton\tnotes\tsubject\tto\thedging(m) |  | (3) | (22) |
| Amounts\tdue\twithin\tone\tyear |  | (1,131) | (471) |
| Long-term\tdebt\tdue\tafter\tone\tyear |  | $6,084 | $3,061 |
| (a) |  |  |  |

(a) During	2007,	Marathon	entered	into	amendments	of	its	$2.0	billion	revolving	credit	agreement	expanding	the	size	of	the	facility	to	$3.0	billion	and	extending	the	termination	date	from	May	2011	to	May	2012.	The facility	requires	a	representation	at	an	initial	borrowing	that	there	has	been	no	change	in	Marathon's	consolidated	financial	position	or	operations,	considered	as	a	whole,	that	would	materially	and	adversely	affect its	ability	to	perform	its	obligations	under	the	revolving	credit	facility.	Interest	on	the	facility	is	based	on	defined	short-term	market	rates.	During	the	term	of	the	agreement,	Marathon	is	obligated	to	pay	a	variable facility	fee	on	the	total	commitment,	which	at	December	31,	2007	was	0.08	percent.

(b) These	notes	contain	a	make-whole	provision	allowing	Marathon	the	right	to	repay	the	debt	at	a	premium	to	market	price. (c) Marathon	has	extinguished	portions	of	this	debt.	In	2007,	debt	with	a	total	face	value	of	$93	million	was	repurchased	at	a	weighted	average	price	equal	to	117	percent	of	face	value.	In	2006,	debt	with	a	total	face value	of	$162	million	was	repurchased	at	a	weighted	average	price	equal	to	122	percent	of	face	value.	The	premium	in	each	year	is	reflected	as	loss	on	early	extinguishment	of	debt	in	the	consolidated	statements of	income.

(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	Separation,	United States	Steel	will	provide	for	Marathon's	discharge	from	any	remaining	liability	under	any	of	the	assumed	industrial	revenue	bonds.

(e) During	2007,	the	Parish	of	St.	John	the	Baptist,	where	Marathon's	Garyville,	Louisiana,	refinery	is	located,	issued	these	revenue	bonds	associated	with	the	Company's	Garyville	refinery	expansion.	Marathon	is solely	obligated	to	service	the	principal	and	interest	payments	associated	with	the	bonds.	The	proceeds	from	the	bonds	were	trusteed	to	be	disbursed	to	Marathon	upon	its	request	for	reimbursement	of	expenditures related	to	the	expansion.	Through	December	31,	2007,	such	reimbursements	have	totaled	$280	million.	The	remaining	$744	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,	2007.

(f) This	sale-leaseback	financing	arrangement	relates	to	a	lease	of	a	slab	caster	at	United	States	Steel's	Fairfield	Works	facility	in	Alabama.	Marathon	is	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.	Marathon	is	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.	As	of	December	31,	2007,	Marathon	Oil	Canada	Corporation	was	not	in	compliance	with	certain	of	these	covenants	and	in	February	2008, repaid	the	outstanding	balance	and	terminated	the	facility.

(i) These	notes	are	senior	secured	notes	of	Marathon	Oil	Canada	Corporation.	As	of	December	31,	2007,	the	notes	were	secured	by	substantially	all	of	Marathon	Oil	Canada	Corporation's	assets.	In	January	2008, Marathon	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,	2007	include	$49	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,	2007	and	do	not	reflect	future	lease	obligations.

(l) In	the	event	of	a	change	in	control	of	Marathon,	as	defined	in	the	related	agreements,	debt	obligations	totaling	$1.077	billion	at	December	31,	2007,	may	be	declared	immediately	due	and	payable. (m) See	Note	17	for	information	on	interest	rate	swaps.

# 21.	Supplemental	Cash	Flow	Information

| (In	millions) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Net\tcash\tprovided\tfrom\toperating\tactivities\tfrom\tcontinuing\toperations\tincluded: |  |  |  |
| Interest\tpaid\t(net\tof\tamounts\tcapitalized) | $66 | $96 | $174 |
| Income\ttaxes\tpaid\tto\ttaxing\tauthorities | 3,283 | 4,149 | 1,528 |
| Income\ttax\tsettlements\tpaid\tto\tUnited\tStates\tSteel | 13 | 35 | 6 |
| Commercial\tpaper\tand\trevolving\tcredit\tarrangements,\tnet: |  |  |  |
| Commercial\tpaper\t–\tissuances | $12,751 | $1,321 | $3,896 |
| –\trepayments | (12,751) | (1,321) | (3,896) |
| Credit\tagreements\t–\tborrowings | 190 | – | 10 |
| –\trepayments | (100) | – | (10) |
| Total | $90 | $– | $– |
| Noncash\tinvesting\tand\tfinancing\tactivities: |  |  |  |
| Asset\tretirement\tcosts\tcapitalized,\texcluding\tacquisitions | $8 | $286 | $171 |
| Debt\tpayments\tassumed\tby\tUnited\tStates\tSteel | 21 | 24 | 44 |
| Capital\tlease\tand\tsale-leaseback\tfinancing\tobligations | 49 | 1 | 18 |
| Bond\tobligation\tassumed\tfor\ttrusteed\tfunds | 1,000 | – | – |
| Acquisitions: |  |  |  |
| Debt\tand\tother\tliabilities\tassumed | 1,541 | 26 | 4,125 |
| Common\tstock\tor\tsecurities\texchangeable\tfor\tcommon\tstock\tissued\tto\tseller | 1,910 | – | 955 |
| Receivables\ttransferred\tto\tseller | – | – | 911 |
| 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 | – | – |

# 22.	Defined	Benefit	and	Other	Postretirement	Plans

Marathon	has	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.	Marathon	adopted	SFAS No.	158,	which	applies	to	such	plans,	prospectively	as	of	December	31,	2006.

Marathon	also	has	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	Marathon's	defined	benefit	pension	and	other	postretirement	plans:

|  |  |  |  |  | Other |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  | Pension\tBenefits | Pension\tBenefits | Pension\tBenefits | Pension\tBenefits | Benefits | Benefits |
|  | 2007 | 2007 | 2006 | 2006 | 2007 | 2006 |
| (In\tmillions) | U.S. | Int'l | U.S. | Int'l |  |  |
| Change\tin\tbenefit\tobligations |  |  |  |  |  |  |
| Benefit\tobligations\tat\tJanuary\t1 | $2,077 | $381 | $2,055 | $338 | $821 | $776 |
| Service\tcost | 126 | 14 | 117 | 17 | 22 | 23 |
| Interest\tcost | 124 | 18 | 113 | 17 | 45 | 42 |
| Actuarial\tloss\t(gain) | (8) | 22 | (207)(a) | 15 | (122)(b) | 9 |
| Plan\tamendment | – | – | 117(c) | – | – | – |
| Benefits\tpaid | (176) | (9) | (118) | (6) | (30)(d) | (29)(d) |
| Benefit\tobligations\tat\tDecember\t31 | $2,143 | $426 | $2,077 | $381 | $736 | $821 |
| Change\tin\tplan\tassets |  |  |  |  |  |  |
| Fair\tvalue\tof\tplan\tassets\tat\tJanuary\t1 | $1,688 | $301 | $1,025 | $222 |  |  |
| Actual\treturn\ton\tplan\tassets | 148 | 34 | 175 | 56 |  |  |
| Employer\tcontributions | 130 | 55 | 606 | 29 |  |  |
| Benefits\tpaid\tfrom\tplan\tassets | (176) | (9) | (118) | (6) |  |  |
| Fair\tvalue\tof\tplan\tassets\tat\tDecember\t31 | $1,790 | $381 | $1,688 | $301 |  |  |
| Funded\tstatus\tof\tplans\tat\tDecember\t31 | $(353) | $ (45) | $(389) | $ (80) | $(736) | $(821) |
| Amounts\trecognized\tin\tthe\tconsolidated\tbalance\tsheet: |  |  |  |  |  |  |
| Current\tliabilities | (7) | – | (8) | (1) | (35) | (36) |
| Noncurrent\tliabilities | (346) | (45) | (381) | (79) | (701) | (785) |
| Accrued\tbenefit\tcost | $(353) | $ (45) | $(389) | (80) | $(736) | $(821) |
| Pretax\tamounts\trecognized\tin\taccumulated\tother\tcomprehensive\tincome:\t(e) |  |  |  |  |  |  |
| Net\tloss | $281 | $62 | $338 | $70 | $54 | $184 |
| Prior\tservice\tcost\t(credit) | 119 | – | 132 | – | (44) | (53) |

(a) Includes	the	impact	of	an	increase	in	the	discount	rate	to	5.80	percent	from	5.50	percent	and	demographic	assumption	changes,	which	decreased	the	obligation	by	$112	million.

(b) Includes	the	impact	of	an	increase	in	the	discount	rate	to	6.60	percent	from	5.90	percent	and	favorable	claims	experience,	which	decreased	the	obligation	by	$122	million.

(c) Includes	the	impact	of	plan	design	changes	related	to	the	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.

(d) Benefits	paid	is	net	of	$3	million	of	medicare	subsidies	received	in	both	2007	and	2006.

(e) Excludes	amounts	related	to	LOOP	LLC,	an	equity	method	investee	with	defined	benefit	pension	and	postretirement	plans	for	which	net	losses	of	$7	million	and	$6	million	are	reflected	in	accumulated	other comprehensive	income,	reflecting	Marathon's	51	percent	share.

The	accumulated	benefit	obligation	for	all	defined	benefit	pension	plans	was	$2.028	billion	and	$1.912	billion	as	of	December	31,	2007	and	2006.

The	following	summarizes	all	of	Marathon's	defined	benefit	pension	plans	that	have	accumulated	benefit	obligations	in	excess	of	plan	assets.

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	Marathon's	defined	benefit	pension	and	other	postretirement	plans.

|  | 2007 | 2007 | 2006 | 2006 | 2005 | 2005 | Other	Benefits | Other	Benefits | Other	Benefits |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | U.S. | Int'l | U.S. | Int'l | U.S. | Int'l | 2007 | 2006 | 2005 |
| Components\tof\tnet\tperiodic\tbenefit\tcost: |  |  |  |  |  |  |  |  |  |
| Service\tcost | $126 | $14 | $117 | $17 | $109 | $11 | $22 | $23 | $20 |
| Interest\tcost | 124 | 18 | 113 | 17 | \t 104 | 16 | 45 | 42 | 38 |
| Expected\treturn\ton\tplan\tassets | (135) | (19) | (103) | (15) | (83) | (12) | – | – | – |
| Amortization\t–\tnet\ttransition\tgain | – | – | – | – | (3) | – | – | – | – |
| –\tprior\tservice\tcost\t(credit) | 13 | – | 8 | – | 4 | – | (10) | (11) | (12) |
| –\tactuarial\tloss | 36 | 3 | 34 | 7 | 47 | 8 | 8 | 9 | 7 |
| Multi-employer\tand\tother\tplans | 2 | – | 2 | – | 2 | – | 3 | 3 | 3 |
| Net\tperiodic\tbenefit\tcost | $166 | $16 | $171 | $26 | $180 | $23 | $68 | $66 | $56 |

| (In	millions) | U.S. | Int'l |
| :--- | :--- | :--- |
| Increase\tin\tminimum\tliability\tincluded\tin\tother\tcomprehensive\tincome,\texcluding\ttax\teffects\tand\tminority\tinterest | $81 | $10 |

|  | Benefits |  | Other |
| :--- | :--- | :--- | :--- |
|  | 2007 | 2007 | Benefits |
| (In\tmillions) | U.S. | Int'l | 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(a) | $94 | $20 | $(55) |
| (a) |  |  |  |

(a) Excludes	net	periodic	benefit	costs	related	to	multi-employer	and	other	plans.

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	2008	are	$16	million	and	$13	million.	The	estimated	net	loss	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	2008	are	$5	million	and	$8	million.

Plan	assumptions	–	The	following	summarizes	the	assumptions	used	to	determine	the	benefit	obligations	and	net	periodic	benefit	cost	for	Marathon's	defined	benefit pension	and	other	postretirement	plans.

| 2007 | 2007 | 2006 | 2006 | 2005 | 2005 | Other	Benefits | Other	Benefits | Other	Benefits |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| U.S. | Int'l | U.S. | Int'l | U.S. | Int'l | 2007 | 2006 | 2005 |
| 6.30% | 5.80% | 5.80% | 5.20% | 5.50% | 4.70% | 6.60% | 5.90% | 5.75% |
| 4.50% | 5.15% | 4.50% | 4.75% | 4.50% | 4.55% | 4.50% | 4.50% | 4.50% |
| 5.81% | 5.20% | 5.70% | 4.70% | 5.57% | 5.30% | 5.90% | 5.75% | 5.57% |
| 8.50% | 6.45% | 8.50% | 6.07% | 8.50% | 6.87% |  |  |  |
| 4.50% | 4.75% | 4.50% | 4.55% | 4.50% | 4.60% | 4.50% | 4.50% | 4.50% |

(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.	Also,	on	June	30,	2005,	due	to	Marathon's	acquisition	of	the	minority	interest	in	MPC,	the	discount	rate	for	the	MPC pension	plan	was	decreased	to	5.25	percent	from	5.75	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.

(a) Prior	to	2006,	the	assumed	cost	trend	rate	and	the	year	that	it	would	reach	the	ultimate	trend	rate	for	prescription	drugs	were	the	same	as	those	for	other	medical	costs.

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:

# Plan	investment	policies	and	strategies

U.S.	Plans	–	The	investment	policy	reflects	the	funded	status	of	the	plans	and	Marathon's	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	and	real	estate-related	securities.	Management	of	the	plans'	assets	is	delegated	to	the	United	States	Steel	and	Carnegie Pension	Fund.	The	fund	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	–	Marathon	expects	to	make	contributions	to	the	Company's	funded	pension	plans	of	approximately	$37	million	in	2008.	Cash	contributions	to	be paid	from	the	general	assets	of	the	Company	for	the	unfunded	pension	and	postretirement	plans	are	expected	to	be	approximately	$9	million	and	$41	million	in	2008.

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.

|  |  | Pension<br>Benefits | Pension<br>Benefits | Other<br>Benefits(a) |
| :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | (In\tmillions) | U.S. | Int'l |  |
| 2008 | 2008 | $172 | $10 | $41 |
| 2009 |  | 187 | 11 | 45 |
| 2010 | 2010 | 201 | 13 | 49 |
| 2011 |  | 216 | 14 | 52 |
| 2012 | 2012 | 240 | 16 | 55 |
| 2013\tthrough\t2017 | 2013\tthrough\t2017 | \t 1,336 | \t 113 | 326 |
| (a) | Expected\tMedicare\treimbursements\tfor\t2008\tthrough\t2017\ttotal\t$69\tmillion. |  |  |  |

(a) Expected	Medicare	reimbursements	for	2008	through	2017	total	$69	million.

Other	Plan	Contributions	–	Marathon	also	contributes	to	several	defined	contribution	plans	for	eligible	employees.	Contributions	to	these	plans	totaled	$55	million	in 2007,	$47	million	in	2006	and	$39	million	in	2005.

# 23.	Asset	Retirement	Obligations

The	following	summarizes	the	changes	in	asset	retirement	obligations.

| (In	millions) | 2007 | 2006 |
| :--- | :--- | :--- |
| Asset\tretirement\tobligations\tas\tof\tJanuary\t1 | $1,044 | $711 |
| Liabilities\tincurred,\tincluding\tacquisitions | 60 | 29 |
| Liabilities\tsettled | (10) | (16) |
| Accretion\texpense\t(included\tin\tdepreciation,\tdepletion\tand\tamortization) | 61 | 43 |
| Revisions\tof\tprevious\testimates | (17) | 277 |
| Deconsolidation\tof\tEGHoldings | (4) | – |
| Asset\tretirement\tobligations\tas\tof\tDecember\t31(a) | $1,134 | $1,044 |
| (a) |  |  |

# 24.	Stock-Based	Compensation	Plans

Description	of	the	plans	–	The	Marathon	Oil	Corporation	2007	Incentive	Compensation	Plan	(the	"2007	Plan")	was	approved	by	the	Company's	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	Marathon	to	provide	equity	compensation	to	its	non-employee directors.	No	more	than	34	million	shares	of	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	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	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	and/or	be	exercisable	in accordance	with	their	original	terms	and	conditions.

# Stock-based	awards	under	the	Plan

Stock	options	–	Marathon	grants	stock	options	under	the	2007	Plan	and	previously	granted	options	under	the	2003	Plan.	Marathon's	stock	options	represent	the	right	to purchase	shares	of	common	stock	at	the	fair	market	value	of	the	common	stock	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	and/or	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,	Marathon	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,	Marathon	granted	stock-based	performance	awards	under	the	2003	Plan.	No	stock-based	performance	awards	have been	granted	under	the	2007	Plan.	Beginning	in	2005,	Marathon	discontinued	granting	stock-based	performance	awards	and	instead	now	grants	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	–	Marathon	grants	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. Marathon	also	grants	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.	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	Marathon's	transfer	agent.

Common	stock	units	–	Marathon	maintains	an	equity	compensation	program	for	its	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.

Stock-based	compensation	expense	–	Total	employee	stock-based	compensation	expense	was	$80	million,	$83	million	and	$111	million	in	2007,	2006	and	2005.	The total	related	income	tax	benefits	were	$29	million,	$31	million	and	$39	million.	In	2007	and	2006,	cash	received	upon	exercise	of	stock	option	awards	was	$27	million and	$50	million.	Tax	benefits	realized	for	deductions	during	2007	and	2006	that	were	in	excess	of	the	stock-based	compensation	expense	recorded	for	options	exercised and	other	stock-based	awards	vested	during	the	period	totaled	$30	million	and	$36	million.	Cash	settlements	of	stock	option	awards	totaled	$1	million	and	$3	million	in 2007	and	2006.

Stock	option	awards	granted	–	During	2007,	2006	and	2005,	Marathon	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:

|  | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Weighted\taverage\texercise\tprice\tper\tshare | $60.94 | $37.84 | $25.14 |
| Expected\tannual\tdividends\tper\tshare | $0.96 | $0.80 | $0.66 |
| Expected\tlife\tin\tyears | 5.0 | 5.1 | 5.5 |
| Expected\tvolatility | 27% | 28% | 28% |
| Risk-free\tinterest\trate | 4.1% | 5.0% | 3.8% |
| Weighted\taverage\tgrant\tdate\tfair\tvalue\tof\tstock\toption\tawards\tgranted | $17.24 | $10.19 | $6.15 |

Outstanding	stock-based	awards	–	The	following	is	a	summary	of	stock	option	award	activity.

| Outstanding	stock-based	awards	–	The	following	is	a	summary	of	stock	option	award	activity. |  |  |
| :--- | :--- | :--- |
|  |  | Weighted- |
|  |  | Average |
|  | Number | Exercise |
|  | of\tShares | Price |
| Outstanding\tat\tDecember\t31,\t2004 | 16,026,496 | $14.92 |
| Granted | 3,789,440 | 25.14 |
| Exercised | (7,573,656) | 14.69 |
| Canceled | (226,372) | 16.98 |
| Outstanding\tat\tDecember\t31,\t2005 | 12,015,908 | 18.26 |
| Granted | 3,203,600 | 37.84 |
| Exercised | (4,037,258) | 11.61 |
| Canceled | (191,260) | 25.71 |
| Outstanding\tat\tDecember\t31,\t2006 | 10,990,990 | 24.72 |
| Granted | 3,251,391 | 60.94 |
| Exercised | (1,756,294) | 15.32 |
| Canceled | (271,234) | 38.67 |
| Outstanding\tat\tDecember\t31,\t2007\t(a) | 12,214,853 | 34.58 |
| Of\tthe\tstock\toption\tawards\toutstanding\tas\tof\tDecember\t31,\t2007,\t3,188,623,\t8,479,560\tand\t546,670\twere\toutstanding\tunder\tthe\t2007\tPlan,\tthe\t2003\tPlan\tand\tthe\t1990\tStock\tPlan,\tincluding\t749,282\tstock\toptions\n(a) |  |  |

The	intrinsic	value	of	stock	option	awards	exercised	during	2007,	2006	and	2005	was	$64	million,	$107	million	and	$90	million.	Of	those	amounts,	$10	million, $32	million	and	$61	million	relate	to	stock	options	with	tandem	SARs.

The	following	table	presents	information	related	to	stock	option	awards	at	December	31,	2007.

|  |  | Outstanding | Outstanding | Outstanding | Outstanding | Exercisable | Exercisable |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | Weighted- |  |  |  |  |
|  |  |  | Average |  |  |  |  |
|  |  | Number | Remaining |  | Weighted- | Number | Weighted- |
|  | Range\tof\nExercise\tPrices | of\tShares\nUnder\tOption | Contractual\nLife |  | Average\nExercise\tPrice | of\tShares\nUnder\tOption | Average\nExercise\tPrice |
|  | $\t12.75–17.00 | 3,586,610 |  | 6 | $15.61 | 3,586,610 | $15.61 |
|  | $\t23.83–25.84 | 2,626,645 |  | 7 | 24.98 | 1,484,707 | 24.88 |
|  | $\t37.82–40.51 | 2,812,975 |  | 8 | 37.84 | 786,925 | 37.84 |
|  | $\t57.51–61.33 | 3,188,623 |  | 9 | 60.94 | – | – |
| Total |  | 12,214,853 |  | 8 | 34.58 | 5,858,242 | 20.95 |

As	of	December	31,	2007,	the	aggregate	intrinsic	value	of	stock	option	awards	outstanding	was	$322	million.	The	aggregate	intrinsic	value	and	weighted	average remaining	contractual	life	of	stock	option	awards	currently	exercisable	were	$234	million	and	7	years.	As	of	December	31,	2007,	the	number	of	fully-vested	stock option	awards	and	stock	option	awards	expected	to	vest	was	12,111,870.	The	weighted	average	exercise	price	and	weighted	average	remaining	contractual	life	of	these stock	option	awards	were	$34.42	and	7.7	years	and	the	aggregate	intrinsic	value	was	$321	million.	As	of	December	31,	2007,	unrecognized	compensation	cost	related	to stock	option	awards	was	$54	million,	which	is	expected	to	be	recognized	over	a	weighted	average	period	of	1.8	years.

The	following	is	a	summary	of	stock-based	performance	award	and	restricted	stock	award	activity.

|  | Stock-Based | Weighted | Restricted | Weighted |
| :--- | :--- | :--- | :--- | :--- |
|  | Performance | Average\tGrant | Stock | Average\tGrant |
|  | Awards | Date\tFair\tValue | Awards | Date\tFair\tValue |
| Unvested\tat\tDecember\t31,\t2005 | 897,200 | $14.97 | 1,971,112 | $23.97 |
| Granted | 135,696(a) | 38.41 | 437,960 | 40.45 |
| Vested | (546,896) | 19.15 | (777,194) | 20.59 |
| Forfeited | (12,000) | 16.81 | (79,580) | 26.55 |
| Unvested\tat\tDecember\t31,\t2006 | 474,000 | 16.81 | 1,552,298 | 30.21 |
| Granted | 393,420(a) | 44.13 | 572,897 | 54.97 |
| Vested | (867,420) | 29.20 | (557,096) | 28.86 |
| Forfeited | – | – | (40,268) | 34.55 |
| Unvested\tat\tDecember\t31,\t2007 | – | – | 1,527,831 | 39.87 |
| (a) |  |  |  |  |

As	of	December	31,	2007,	there	was	$37	million	of	unrecognized	compensation	cost	related	to	restricted	stock	awards	which	is	expected	to	be	recognized	over	a weighted	average	period	of	1.4	year.

# 25.	Stockholders'	Equity

Common	stock	–	On	April	25,	2007,	Marathon's	stockholders	approved	an	increase	in	the	number	of	authorized	shares	of	common	stock	from	550	million	to	1.1	billion shares,	and	the	Company's	Board	of	Directors	subsequently	declared	a	two-for-one	split	of	the	Company's	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 Oil	Corporation	common	stock	for	each	share	of	common	stock	held	as	of	the	close	of	business	on	the	record	date.	In	addition,	shares	of	common	stock	issued	or issuable	for	stock-based	awards	under	Marathon's	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	2007,	2006	and	2005,	Marathon	had	the	following	common	stock	issuances	in	addition	to	shares	issued	for	employee	stock-based	awards:

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

•	 On	June	30,	2005,	in	connection	with	the	acquisition	of	Ashland's	minority	interest	in	MPC	discussed	in	Note	6,	Marathon	distributed	35	million	shares	of its	common	stock	valued	at	$27.23	per	share	to	Ashland's	shareholders.

Marathon's	Board	of	Directors	has	authorized	the	repurchase	of	up	to	$5	billion	of	common	stock.	Purchases	under	the	program	may	be	in	either	open	market transactions,	including	block	purchases,	or	in	privately	negotiated	transactions.	The	Company	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	the	Company's	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, 2007,	the	Company	had	acquired	58	million	common	shares	at	a	cost	of	$2.520	billion	under	the	program,	including	16	million	common	shares	acquired	during	2007	at a	cost	of	$822	million	and	42	million	common	shares	acquired	during	2006	at	a	cost	of	$1.698	billion.

Securities	exchangeable	into	Marathon	common	stock	–	As	discussed	in	Note	6,	Marathon	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	shares,	securities	exchangeable	into	Marathon	common	shares (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	shares.	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,	2007	was	1.00423	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,	Marathon's	Board	of	Directors	authorized	a	class	of	voting	preferred	stock consisting	of	6	million	shares.	Upon	completion	of	the	acquisition,	Marathon	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	Marathon's	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.

Marathon	leases	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 | Obligations |
| 2008 | $79 | $170 |
| 2009 | 32 | 153 |
| 2010 | 46 | 124 |
| 2011 | 45 | 102 |
| 2012 | 45 | 92 |
| Later\tyears | 254 | 448 |
| Sublease\trentals | – | (26) |
| Total\tminimum\tlease\tpayments | $501 | $1,063 |
| Less\timputed\tinterest\tcosts | 134 |  |
| Present\tvalue\tof\tnet\tminimum\tlease\tpayments | $367 |  |

In	connection	with	past	sales	of	various	plants	and	operations,	Marathon	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, Marathon	remains	primarily	obligated	for	payments	under	these	leases.	Minimum	lease	payments	under	these	operating	lease	obligations	of	$26	million	have	been included	above	and	an	equal	amount	has	been	reported	as	sublease	rentals.

Of	the	$367	million	present	value	of	net	minimum	capital	lease	payments,	$83	million	was	related	to	obligations	assumed	by	United	States	Steel	under	the Financial	Matters	Agreement.

Operating	lease	rental	expense	was:

| (In	millions) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Minimum\trental(a) | $209 | $172 | $140 |
| Contingent\trental | 33 | 28 | 21 |
| Sublease\trentals | – | (7) | (14) |
| Net\trental\texpense | $242 | $193 | $147 |
| (a) |  |  |  |

# 27.	Sale	of	Minority	Interests	in	EGHoldings

In	connection	with	the	formation	of	EGHoldings,	GEPetrol	was	given	certain	contractual	rights	that	gave	GEPetrol	the	option	to	purchase	and	resell	a	13	percent	interest in	EGHoldings	held	by	Marathon	to	a	third	party.	On	July	25,	2005,	GEPetrol	exercised	these	rights	and	reimbursed	Marathon	for	its	actual	costs	incurred	up	to	the	date of	closing,	plus	an	additional	specified	rate	of	return.	Marathon	and	GEPetrol	entered	into	agreements	under	which	Mitsui	and	a	subsidiary	of	Marubeni	acquired	8.5 percent	and	6.5	percent	interests	in	EGHoldings.	As	part	of	these	agreements,	Marathon	sold	a	2	percent	interest	in	EGHoldings	to	Mitsui	for	its	actual	costs	incurred	up to	the	date	of	closing,	plus	a	specified	rate	of	return,	as	well	as	a	premium	and	future	consideration	based	upon	the	performance	of	EGHoldings.	Following	the transaction,	Marathon	held	a	60	percent	interest	in	EGHoldings,	GEPetrol	held	a	25	percent	interest	and	Mitsui	and	Marubeni	held	the	remaining	interests.

During	2005,	Marathon	received	net	proceeds	of	$163	million	in	connection	with	the	transactions	and	recorded	a	gain,	which	is	included	in	other	income.

# 28.	Contingencies	and	Commitments

Marathon	is	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	Marathon's	consolidated	financial	statements.	However,	management	believes	that	Marathon	will	remain	a	viable	and	competitive	enterprise even	though	it	is	possible	that	these	contingencies	could	be	resolved	unfavorably.

Environmental	matters	–	Marathon	is	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,	2007	and	2006,	accrued	liabilities	for	remediation	totaled	$108	million	and	$101	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	$66	million	at	December	31,	2007	and	2006.

On	May	11,	2001,	Marathon	entered	into	a	consent	decree	with	the	U.S.	Environmental	Protection	Agency	which	commits	the	Company	to	complete	certain agreed-upon	environmental	projects	over	an	eight-year	period	primarily	aimed	at	reducing	air	emissions	at	its	seven	refineries.	The	court	approved	this	consent	decree on	August	28,	2001.	The	total	one-time	expenditures	for	these	environmental	projects	are	estimated	to	be	approximately	$447	million	over	the	eight-year	period,	with approximately	$420	million	incurred	through	December	31,	2007.

Marathon	is	a	defendant	along	with	many	other	refining	companies	in	over	50	cases	in	12	states	alleging	methyl	tertiary-butyl	ether	("MTBE")	contamination	in groundwater.	All	of	these	cases	have	been	consolidated	in	a	multi-district	litigation	in	the	Southern	District	of	New	York	for	preliminary	proceedings.	Marathon	stopped producing	MTBE	at	its	refineries	in	October	2002.	The	potential	impact	of	these	recent	cases	and	future	potential	similar	cases	is	uncertain.	Marathon	is	engaged	in ongoing	settlement	discussions	related	to	the	majority	of	the	cases	in	which	it	is	a	defendant,	and	established	a	related	reserve	in	2007,	the	amount	of	which	is	not significant	to	Marathon's	consolidated	results	of	operations,	financial	position	or	cash	flows.

Guarantees	–	Marathon	has	provided	certain	guarantees,	direct	and	indirect,	of	the	indebtedness	of	other	companies.	Under	the	terms	of	most	of	these	guarantee arrangements,	Marathon	would	be	required	to	perform	should	the	guaranteed	party	fail	to	fulfill	its	obligations	under	the	specified	arrangements.	In	addition	to	these financial	guarantees,	Marathon	also	has	various	performance	guarantees	related	to	specific	agreements.

Guarantees	Related	to	Indebtedness	of	Equity	Method	Investees	–	Marathon	holds	interests	in	an	offshore	oil	port,	LOOP	LLC	("LOOP"),	and	a	crude	oil	pipeline system,	LOCAP	LLC	("LOCAP").	Both	LOOP	and	LOCAP	have	secured	various	project	financings	with	throughput	and	deficiency	agreements.	Under	the	agreements, Marathon	is	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.	Marathon's	maximum	potential	undiscounted	payments	under	these	agreements totaled	$183	million	as	of	December	31,	2007.

Marathon	holds	an	interest	in	a	refined	products	pipeline	through	its	investment	in	Centennial,	and	has	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.	Marathon's	maximum potential	undiscounted	payments	under	this	agreement	totaled	$70	million	as	of	December	31,	2007.

Other	Guarantees	–	Marathon	has	entered	into	other	guarantees	with	maximum	potential	undiscounted	payments	totaling	$262	million	as	of	December	31,	2007, 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	is	the	sole	general	partner	of	Clairton	1314B	Partnership,	L.P.,	which	owns	certain	cokemaking	facilities	formerly	owned	by	United	States	Steel. Marathon	has	guaranteed	to	the	limited	partners	all	obligations	of	United	States	Steel	under	the	partnership	documents	through	2012.	In	addition	to	the	commitment	to fund	operating	cash	shortfalls	of	the	partnership	discussed	in	Note	3,	United	States	Steel,	under	certain	circumstances,	is	required	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.	United	States	Steel	has	estimated	the	maximum	potential	amount of	this	indemnity	obligation,	including	interest	and	tax	gross-up,	was	approximately	$660	million	as	of	December	31,	2007.	Furthermore,	United	States	Steel	under certain	circumstances	has	indemnified	the	partnership	for	environmental	obligations.

General	Guarantees	Associated	with	Asset	Disposals	–	Over	the	years,	Marathon	has	sold	various	assets	in	the	normal	course	of	its	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	Marathon	to	perform	upon	the	occurrence	of	a	triggering	event	or	condition.	These	guarantees	and indemnifications	are	part	of	the	normal	course	of	selling	assets.	Marathon	is	not	typically	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,	2007	and	2006,	Marathon's	contract	commitments	to	acquire	property,	plant	and	equipment	totaled	$3.893	billion	and	$1.703 billion.	The	$2.190	billion	increase	is	primarily	related	to	the	Detroit,	Michigan	refinery	heavy	oil	upgrading	and	expansion	project	and	the	Garyville,	Louisiana	refinery expansion.

Agreements	with	joint	owners	–	As	part	of	the	formation	of	PTC,	MPC	and	Pilot	Corporation	("Pilot")	entered	into	a	Put/Call	and	Registration	Rights	Agreement	(the "Agreement").	The	Agreement	provides	that	any	time	after	September	1,	2008,	Pilot	will	have	the	right	to	sell	its	interest	in	PTC	to	MPC	for	an	amount	of	cash	and/or Marathon,	MPC	or	Ashland	equity	securities	equal	to	the	product	of	90	percent	(95	percent	if	paid	in	securities)	of	the	fair	market	value	of	PTC	at	the	time	multiplied	by Pilot's	percentage	interest	in	PTC.	At	any	time	after	September	1,	2011,	under	certain	conditions,	MPC	will	have	the	right	to	purchase	Pilot's	interest	in	PTC	for	an amount	of	cash	and/or	Marathon,	MPC	or	Ashland	equity	securities	equal	to	the	product	of	105	percent	(110	percent	if	paid	in	securities)	of	the	fair	market	value	of	PTC at	the	time	multiplied	by	Pilot's	percentage	interest	in	PTC.	Under	the	Agreement,	MPC	would	determine	the	form	of	consideration	to	be	paid	upon	exercise	of	the rights.

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.	Marathon	is	in	the	process	of	determining	what	impact	this	law	may	have	on	its	existing	operations	in	Equatorial	Guinea.

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.	Additional	disclosures	are	also	required.	For Marathon,	SFAS	No.	141(R)	will	be	applied	prospectively	effective	January	1,	2009.

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.	For	Marathon,	SFAS No.	160	will	be	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.	Marathon	is	currently	evaluating	the	provisions	of	this statement.

In	February	2007,	the	FASB	issued	SFAS	No.	159,	"The	Fair	Value	Option	for	Financial	Assets	and	Financial	Liabilities."	This	statement	permits	entities	to	choose to	measure	many	financial	instruments	and	certain	other	items	at	fair	value	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.	For	Marathon,	SFAS	No.	159 is	effective	January	1,	2008,	and	retrospective	application	is	not	permitted.	Marathon	did	not	elect	the	fair	value	option	when	this	standard	became	effective.

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.	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.	For	Marathon,	except	for	the	nonfinancial	assets	and	liabilities	subject	to	the	one- year	deferral,	SFAS	No.	157	is	effective	January	1,	2008.	Marathon	does	not	expect	adoption	of	this	statement	to	have	a	significant	effect	on	its	consolidated	results	of operations,	financial	position	or	cash	flows.

# Selected	Quarterly	Financial	Data	(Unaudited)

| (In	millions,	except	per	share	data) | Qtr. | Qtr. | Qtr. | Qtr. | Qtr. | Qtr. | Qtr. | 1st	Qtr. |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Revenues | $18,185 | $16,762 | $16,736 | $12,869 | $13,807 | $16,492 | $18,179 | $16,418 |
| Income\tfrom\toperations | 949 | 1,619 | 2,756 | 1,316 | 1,793 | 2,944 | 2,754 | 1,476 |
| Income\tfrom\tcontinuing\toperations | 668 | 1,021 | 1,542 | 717 | 1,079 | 1,623 | 1,484 | 771 |
| Discontinued\toperations | – | – | 8 | – | – | – | 264 | 13 |
| Net\tincome | 668 | 1,021 | 1,550 | 717 | 1,079 | 1,623 | 1,748 | 784 |
| Common\tstock\tdata |  |  |  |  |  |  |  |  |
| Net\tincome\tper\tshare: |  |  |  |  |  |  |  |  |
| –\tBasic | $0.95 | $1.50 | $2.27 | $1.04 | $1.54 | $2.28 | $2.42 | $1.07 |
| –\tDiluted | $0.94 | $1.49 | $2.25 | $1.03 | $1.53 | $2.26 | $2.40 | $1.06 |
| Dividends\tpaid\tper\tshare | $0.24 | $0.24 | $0.24 | $0.20 | $0.20 | $0.20 | $0.20 | $0.16 |
| Price\trange\tof\tcommon\tstock(a): |  |  |  |  |  |  |  |  |
| –\tLow | $53.34 | $49.24 | $59.74 | $83.43 | $71.94 | $70.73 | $69.83 | $65.24 |
| –\tHigh | $62.59 | $65.04 | $132.51 | $102.56 | $97.57 | $92.19 | $86.04 | $78.15 |
| (a) |  |  |  |  |  |  |  |  |

# Principal	Unconsolidated	Investees	(Unaudited)

|  |  | December	31,	2007 | December	31,	2007 |
| :--- | :--- | :--- | :--- |
| Company | Country | Ownership | Activity |
| Alba\tPlant\tLLC | Cayman\tIslands | 52%(a) | Liquefied\tPetroleum\tGas |
| Atlantic\tMethanol\tProduction\tCompany\tLLC | Cayman\tIslands | 45% | Methanol\tProduction |
| Centennial\tPipeline\tLLC | United\tStates | 50% | Pipeline\t&amp;\tStorage\tFacility |
| Equatorial\tGuinea\tLNG\tHoldings\tLimited | Bahamas | 60%(a) | Liquefied\tNatural\tGas |
| Kenai\tKachemak\tPipeline,\tLLC | United\tStates | 60%(a) | Natural\tGas\tTransmission |
| Kenai\tLNG\tCorporation | United\tStates | 30% | Natural\tGas\tLiquefaction |
| LOCAP\tLLC | United\tStates | 59%(a) | Pipeline\t&amp;\tStorage\tFacilities |
| LOOP\tLLC | United\tStates | 51%(a) | Offshore\tOil\tPort |
| Minnesota\tPipe\tLine\tCompany,\tLLC | United\tStates | 17% | Pipeline\tFacility |
| Muskegon\tPipeline\tLLC | United\tStates | 60%(a) | Pipeline\tFacility |
| Odyssey\tPipeline\tL.L.C. | United\tStates | 29% | Pipeline\tFacility |
| Pilot\tTravel\tCenters\tLLC | United\tStates | 50% | Travel\tCenters |
| Poseidon\tOil\tPipeline\tCompany,\tL.L.C. | United\tStates | 28% | Crude\tOil\tTransportation |
| Southcap\tPipe\tLine\tCompany | United\tStates | 22% | Crude\tOil\tTransportation |
| The\tAndersons\tClymers\tEthanol\tLLC | United\tStates | 35% | Ethanol\tProduction |
| The\tAndersons\tMarathon\tEthanol\tLLC | United\tStates | 50% | Ethanol\tProduction |
| Represents\ta\tnoncontrolling\tinterest.\n(a) |  |  |  |

(a) Represents	a	noncontrolling	interest.

# 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,	which	includes activities	in	Canada,	and	other	international	locations	outside	of	Europe	and	Africa.	Discontinued	operations	represent	Marathon's	Russian	oil	exploration	and production	businesses	that	were	sold	in	2006.

# Capitalized	Costs	and	Accumulated	Depreciation,	Depletion	and	Amortization	^(a)

|  |  |  | United |  |  | Other |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) | (In\tmillions) | December\t31 | States | Europe | Africa | Int'l | Total |
| 2007 | Capitalized\tcosts: |  |  |  |  |  |  |
| Proved\tproperties | Proved\tproperties |  | $8,325 | $8,191 | $2,108 | $60 | $18,684 |
| Unproved\tproperties | Unproved\tproperties |  | \t 1,133 | 64 | 474 | 261 | 1,932 |
|  | Suspended\texploratory\twells |  | 312 | 76 | 395 | – | 783 |
| Total | Total |  | \t 9,770 | 8,331 | \t 2,977 | 321 | \t 21,399 |
| Accumulated\tdepreciation,\tdepletion\tand\tamortization: | Accumulated\tdepreciation,\tdepletion\tand\tamortization: |  |  |  |  |  |  |
| Proved\tproperties | Proved\tproperties |  | \t 5,478 | 5,070 | 482 | 1 | \t 11,031 |
|  | Unproved\tproperties |  | 67 | 6 | 9 | 0 | 82 |
| Total | Total |  | \t 5,545 | 5,076 | 491 | 1 | \t 11,113 |
|  | Net\tcapitalized\tcosts |  | $4,225 | $3,255 | $2,486 | $ 320 | $10,286 |
| 2006 | Capitalized\tcosts: |  |  |  |  |  |  |
| Proved\tproperties | Proved\tproperties |  | $7,682 | $7,216 | $2,044 | $1 | $16,943 |
| Unproved\tproperties | Unproved\tproperties |  | 938 | 77 | 481 | 4 | 1,500 |
|  | Suspended\texploratory\twells |  | 156 | 25 | 289 | – | 470 |
| Total | Total |  | \t 8,776 | 7,318 | \t 2,814 | 5 | \t 18,913 |
| Accumulated\tdepreciation,\tdepletion\tand\tamortization: | Accumulated\tdepreciation,\tdepletion\tand\tamortization: |  |  |  |  |  |  |
| Proved\tproperties | Proved\tproperties |  | \t 5,141 | 4,771 | 412 | 1 | \t 10,325 |
|  | Unproved\tproperties |  | 42 | 1 | 9 | – | 52 |
| Total | Total |  | \t 5,183 | 4,772 | 421 | 1 | \t 10,377 |
| Net\tcapitalized\tcosts | Net\tcapitalized\tcosts |  | $3,593 | $2,546 | $2,393 | $4 | $8,536 |
| (a) | Includes\tcapitalized\tasset\tretirement\tcosts\tand\tthe\tassociated\taccumulated\tamortization. |  |  |  |  |  |  |

(a) Includes	capitalized	asset	retirement	costs	and	the	associated	accumulated	amortization.

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

|  |  | United |  |  | Other | Continuing | Discontinued |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (In\tmillions) |  | States | Europe | Africa | Int'l | Operations | Operations | Total |
| 2007 | Property\tacquisition: |  |  |  |  |  |  |  |
|  | Proved | $4 | $– | $– | $– | $4 | $– | $4 |
|  | Unproved | 142 | 1 | 1 | 315 | 459 | – | 459 |
|  | Exploration | 523 | 68 | 219 | 44 | 854 | – | 854 |
|  | Development\t(b) | 759 | 806 | 85 | – | 1,650 | – | \t 1,650 |
|  | Capitalized\tasset\tretirement\tcosts\t(c) | (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\t(b) | 603 | 607 | 40 | – | 1,250 | 43 | \t 1,293 |
|  | Capitalized\tasset\tretirement\tcosts\t(c) | 78 | 201 | 13 | 2 | 294 | 1 | 295 |
|  | Total | $1,435 | $847 | $244 | $76 | $2,602 | $46 | $2,648 |
| 2005 | Property\tacquisition: |  |  |  |  |  |  |  |
|  | Proved | $3 | $– | $390 | $– | $393 | $– | $393 |
|  | Unproved | 31 | – | 381 | – | 412 | – | 412 |
|  | Exploration | 186 | 48 | 95 | 14 | 343 | 10 | 353 |
|  | Development\t(b) | 465 | 531 | 32 | – | 1,028 | 85 | \t 1,113 |
|  | Capitalized\tasset\tretirement\tcosts\t(c) | 35 | 108 | 12 | 1 | 156 | 2 | 158 |
|  | Total | $720 | $687 | $910 | $15 | $2,332 | $97 | $2,429 |
| (a) | Includes\tcosts\tincurred\twhether\tcapitalized\tor\texpensed. |  |  |  |  |  |  |  |

(a) Includes	costs	incurred	whether	capitalized	or	expensed. (b) Includes	$23	million,	$12	million	and	$12	million	of	costs	incurred	prior	to	assignment	of	proved	reserves	in	2007,	2006	and	2005.	The	associated	reserves	were	awaiting	full	project	sanction	at	the	end	of	the applicable	year.

(c) Includes	the	effect	of	foreign	currency	fluctuations.	In	2007,	capitalized	asset	retirement	costs	decreased	in	the	United	States	primarily	as	a	result	of	lower	inflation	factors.

# 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) | (In\tmillions) | States | Europe | Africa | Int'l | Total |
| 2007 | Revenues\tand\tother\tincome: |  |  |  |  |  |
| Sales^(a) | Sales^(a) | $2,110 | $1,198 | $1,380 | $– | $ 4,688 |
| Transfers | Transfers | 299 | 60 | 1,031 | – | 1,390 |
|  | Other\tincome^(b) | 3 | – | 2 | 7 | 12 |
| Total\trevenues | Total\trevenues | 2,412 | 1,258 | 2,413 | 7 | 6,090 |
| Expenses: | Expenses: |  |  |  |  |  |
| Production\tcosts | Production\tcosts | (550) | (234) | (164) | – | (948) |
|  | Transportation\tcosts^(c) | (122) | (39) | (28) | – | (189) |
| Exploration\texpenses | Exploration\texpenses | (274) | (23) | (118) | (37) | (452) |
|  | Depreciation,\tdepletion\tand\tamortization | (486) | (278) | (130) | – | (894) |
| Administrative\texpenses | Administrative\texpenses | (56) | (11) | (6) | (34) | (107) |
| Total\texpenses | Total\texpenses | (1,488) | (585) | (446) | (71) | (2,590) |
| Other\tproduction-related\tincome^(d) | Other\tproduction-related\tincome^(d) | – | 103 | 6 | – | 109 |
| Results\tbefore\tincome\ttaxes | Results\tbefore\tincome\ttaxes | 924 | 776 | 1,973 | (64) | 3,609 |
| Income\ttax\tprovision\t(benefit) | Income\ttax\tprovision\t(benefit) | 343 | 377 | 1,368 | (24) | 2,064 |
| Results\tof\tcontinuing\toperations | Results\tof\tcontinuing\toperations | $581 | $399 | $605 | $(40) | $ 1,545 |
| Results\tof\tdiscontinued\toperations | Results\tof\tdiscontinued\toperations | $– | $– | $– | $8 | $8 |
| 2006 | Revenues\tand\tother\tincome: |  |  |  |  |  |
| Sales^(a) | Sales^(a) | $2,329 | $1,240 | $1,300 | $– | $ 4,869 |
| Transfers | Transfers | 307 | 58 | 1,168 | – | 1,533 |
| Other\tincome^(b) | Other\tincome^(b) | 3 | – | – | 46 | 49 |
| Total\trevenues | Total\trevenues | 2,639 | 1,298 | 2,468 | 46 | 6,451 |
| Expenses: | Expenses: |  |  |  |  |  |
| Production\tcosts | Production\tcosts | (512) | (207) | (126) | – | (845) |
| Transportation\tcosts^(c) | Transportation\tcosts^(c) | (124) | (44) | (33) | – | (201) |
|  | Exploration\texpenses | (169) | (29) | (91) | (73) | (362) |
| Depreciation,\tdepletion\tand\tamortization | Depreciation,\tdepletion\tand\tamortization | (458) | (281) | (127) | – | (866) |
|  | Administrative\texpenses | (41) | (10) | (6) | (36) | (93) |
| Total\texpenses | Total\texpenses | (1,304) | (571) | (383) | (109) | (2,367) |
|  | (d) |  |  |  |  |  |
| Other\tproduction-related\tincome | Other\tproduction-related\tincome | – | 73 | 1 | – | 74 |
| Results\tbefore\tincome\ttaxes | Results\tbefore\tincome\ttaxes | 1,335 | 800 | 2,086 | (63) | 4,158 |
| Income\ttax\tprovision\t(benefit) | Income\ttax\tprovision\t(benefit) | 489 | 358 | 1,457 | (4) | 2,300 |
| Results\tof\tcontinuing\toperations | Results\tof\tcontinuing\toperations | $846 | $442 | $629 | $(59) | $ 1,858 |
| Results\tof\tdiscontinued\toperations | Results\tof\tdiscontinued\toperations | $– | $– | $– | $273 | $273 |
| 2005 | Revenues\tand\tother\tincome: |  |  |  |  |  |
|  | (a) |  |  |  |  |  |
| Sales | Sales | $2,227 | $1,136 | $71 | $– | $ 3,434 |
| Transfers | Transfers | 422 | 38 | 810 | – | 1,270 |
|  | (b) |  |  |  |  |  |
|  | Other\tincome | 22 | – | – | – | 22 |
| Total\trevenues | Total\trevenues | 2,671 | 1,174 | 881 | – | 4,726 |
| Expenses: | Expenses: |  |  |  |  |  |
| Production\tcosts | Production\tcosts | (448) | (170) | (82) | (3) | (703) |
|  | (c) |  |  |  |  |  |
|  | Transportation\tcosts | (114) | (40) | (27) | – | (181) |
| Exploration\texpenses | Exploration\texpenses | (118) | (31) | (27) | (38) | (214) |
|  | Depreciation,\tdepletion\tand\tamortization | (411) | (255) | (87) | – | (753) |
| Administrative\texpenses | Administrative\texpenses | (34) | (8) | (5) | (25) | (72) |
| Total\texpenses | Total\texpenses | (1,125) | (504) | (228) | (66) | (1,923) |
|  | (d) |  |  |  |  |  |
| Other\tproduction-related\tincome | Other\tproduction-related\tincome | 2 | 44 | – | – | 46 |
| Results\tbefore\tincome\ttaxes | Results\tbefore\tincome\ttaxes | 1,548 | 714 | 653 | (66) | 2,849 |
| Income\ttax\tprovision\t(benefit) | Income\ttax\tprovision\t(benefit) | 572 | 256 | 199 | (13) | 1,014 |
| Results\tof\tcontinuing\toperations | Results\tof\tcontinuing\toperations | $976 | $458 | $454 | $(53) | $ 1,835 |
| Results\tof\tdiscontinued\toperations | Results\tof\tdiscontinued\toperations | $– | $– | $– | $42 | $42 |
| (a) |  |  |  |  |  |  |

(c) Includes	the	cost	to	prepare	and	move	liquid	hydrocarbons	and	natural	gas	to	their	points	of	sale.

(d) Includes	revenues,	net	of	associated	costs,	from	activities	that	are	an	integral	part	of	Marathon's	production	operations	which	may	include	processing	and/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) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Results\tof\tcontinuing\toperations | $1,545 | $1,858 | $1,835 |
| Items\tnot\tincluded\tin\tresults\tof\tcontinuing\toil\tand\tgas\toperations,\tnet\tof\ttax: |  |  |  |
| Marketing\tincome\tand\ttechnology\tcosts | 36 | 40 | 4 |
| Income\tfrom\tequity\tmethod\tinvestments | 154 | 135 | 52 |
| Other | (6) | 1 | (4) |
| Items\tnot\tallocated\tto\tE&amp;P\tsegment\tincome: |  |  |  |
| Gain\ton\tasset\tdisposition | – | (31) | – |
| E&amp;P\tsegment\tincome | $1,729 | $2,003 | $1,887 |

# Average	Production	Costs	(a)

|  | United |  |  | Continuing |
| :--- | :--- | :--- | :--- | :--- |
| (per\tbarrel\tof\toil\tequivalent) | States | Europe | Africa | Operations |
| 2007 | $10.46 | $10.41 | $ 3.26 | $7.56 |
| 2006 | 8.51 | 8.36 | 2.78 | 6.48 |
| 2005 | 7.11 | 6.45 | 3.33 | 6.18 |
| (a) |  |  |  |  |

(a) Computed	using	production	costs,	excluding	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 | Discontinued<br>Operations |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (Excluding\tderivative\tgains\tand\tlosses) |  |  |  |  |  |  |
| 2007 | Liquid\thydrocarbons\t(per\tbbl) | $60.15 | $70.31 | $66.09 | $64.86 | – |
|  | Natural\tgas\t(per\tmcf)\t(a) | 5.73 | 6.55 | 0.25 | 4.44 | – |
| 2006 | Liquid\thydrocarbons\t(per\tbbl) | $54.41 | $64.02 | $59.83 | $58.63 | $38.38 |
|  | Natural\tgas\t(per\tmcf)\t(a) | 5.76 | 6.78 | 0.27 | 5.52 | – |
| 2005 | Liquid\thydrocarbons\t(per\tbbl) | $45.41 | $52.99 | $46.27 | $47.35 | $33.47 |
|  | Natural\tgas\t(per\tmcf)\t(a) | 6.42 | 5.72 | 0.25 | 5.61 | – |
| (a) |  |  |  |  |  |  |

(a) Excludes	the	resale	of	purchased	natural	gas	utilized	for	reservoir	management.

# 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	Marathon's	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.

Marathon's	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.	Marathon	does	not	have	any	quantities	of	oil	and	gas	reserves	subject	to	long-term	supply agreements	with	foreign	governments	or	authorities	in	which	Marathon	acts	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 | Discontinued |
| :--- | :--- | :--- | :--- | :--- | :--- |
| (Millions\tof\tbarrels) | States | Europe | Africa(a) | Operations | Operations |
| Liquid\tHydrocarbons |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2005 | 191 | 107 | 223 | 521 | 39 |
| Purchase\tof\treserves\tin\tplace(b) | – | – | 3 | 3 | – |
| Re-entry\tto\tLibya\tconcessions | – | – | 165 | 165 | – |
| Revisions\tof\tprevious\testimates | 10 | 4 | 1 | 15 | 3 |
| Improved\trecovery | 2 | – | – | 2 | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 15 | – | – | 15 | 12 |
| Production | (28) | (13) | (19) | (60) | (10) |
| Sales\tof\treserves\tin\tplace(b) | (1) | – | – | (1) | – |
| End\tof\tyear\t–\t2005 | 189 | 98 | 373 | 660 | 44 |
| Purchase\tof\treserves\tin\tplace(b) | – | – | 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 | (28) | (13) | (41) | (82) | (4) |
| Sales\tof\treserves\tin\tplace(b) | – | – | – | – | (45) |
| End\tof\tyear\t–\t2006 | 172 | 108 | 397 | 677 | – |
| Purchase\tof\treserves\tin\tplace(b) | 2 | – | – | 2 | – |
| Revisions\tof\tprevious\testimates | 2 | 7 | (8) | 1 | – |
| Improved\trecovery | 8 | – | – | 8 | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 5 | 13 | 16 | 34 | – |
| Production | (23) | (13) | (36) | (72) | – |
| End\tof\tyear\t–\t2007 | 166 | 115 | 369 | 650 | – |
| Proved\tdeveloped\treserves: |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2005 | 171 | 41 | 147 | 359 | 27 |
| End\tof\tyear\t–\t2005 |  |  |  |  |  |

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

|  | United |  |  | Continuing | Discontinued |
| :--- | :--- | :--- | :--- | :--- | :--- |
| (Billions\tof\tcubic\tfeet) | States | Europe | Africa(a) | Operations | Operations |
| Natural\tGas |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2005 | 1,364 | 544 | 1,564 | 3,472 | – |
| Purchase\tof\treserves\tin\tplace(b) | – | – | 24 | 24 | – |
| Revisions\tof\tprevious\testimates | (78) | 18 | 298 | 238 | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 135 | 3 | – | 138 | – |
| Production(c) | (211) | (79) | (34) | (324) | – |
| Sales\tof\treserves\tin\tplace(b) | (1) | – | – | (1) | – |
| End\tof\tyear\t–\t2005 | 1,209 | 486 | 1,852 | 3,547 | – |
| Purchase\tof\treserves\tin\tplace(b) | — | 4 | 8 | 12 | – |
| Revisions\tof\tprevious\testimates | (5) | 4 | 139 | 138 | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 59 | 20 | 24 | 103 | – |
| Production(c) | (194) | (70) | (26) | (290) | – |
| End\tof\tyear\t–\t2006 | 1,069 | 444 | 1,997 | 3,510 | – |
| Purchase\tof\treserves\tin\tplace(b) | 1 | – | – | 1 | – |
| Revisions\tof\tprevious\testimates | (36) | (5) | 60 | 19 | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 148 | 4 | 88 | 240 | – |
| Production(c) | (174) | (61) | (84) | (319) | – |
| Sales\tof\treserves\tin\tplace(b) | (1) | – | – | (1) | – |
| End\tof\tyear\t–\t2007 | 1,007 | 382 | 2,061 | 3,450 | – |
| Proved\tdeveloped\treserves: |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2005 | 992 | 376 | 570 | 1,938 | – |
| End\tof\tyear\t–\t2005 | 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 | – |
| (a) |  |  |  |  |  |

(a) Consists	of	estimated	reserves	from	properties	governed	by	production	sharing	contracts. (b) The	net	positive	or	negative	balance	of	proved	reserves	acquired	or	relinquished	in	property	trades	within	the	same	geographic	area	is	reported	as	purchases	of	reserves	in	place	or	sales	of	reserves	in	place, respectively. (c) Excludes	the	resale	of	purchased	natural	gas	utilized	in	reservoir	management.

# Information	on	Proved	Bitumen	Reserves	Not	Included	Above

In	addition	to	the	liquid	hydrocarbon	and	natural	gas	proved	reserves	above,	Marathon	has	significant	interests	in	proved	bitumen	reserves	in	Canada	associated	with	the Athabasca	Oil	Sands	Project	("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.

(a) Marathon	holds	a	20	percent	outside-operated	interest	in	the	AOSP.

# 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	Marathon's	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	Marathon's	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	Marathon's	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	Marathon's	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.

| (In	millions)	December	31 | States | Europe | Africa | Total |
| :--- | :--- | :--- | :--- | :--- |
| 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 |
| 2005 |  |  |  |  |
| Future\tcash\tinflows | $17,346 | $10,007 | $18,088 | $45,441 |
| Future\tproduction,\ttransportation\tand\tadministrative\tcosts | (5,046) | (2,007) | (1,910) | (8,963) |
| Future\tdevelopment\tcosts | (853) | (1,531) | (751) | (3,135) |
| Future\tincome\ttax\texpenses | (3,738) | (3,199) | (9,687) | (16,624) |
| Future\tnet\tcash\tflows | $7,709 | $3,270 | $5,740 | $16,719 |
| 10\tpercent\tannual\tdiscount\tfor\testimated\ttiming\tof\tcash\tflows | (2,862) | (829) | (2,427) | (6,118) |
| (a) |  |  |  |  |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tproved\toil\tand\tgas\treserves | $4,847 | $2,441 | $3,313 | $10,601 |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tdiscontinued\toperations |  |  |  | $216 |

# Summary	of	Changes	in	Standardized	Measure	of	Discounted	Future	Net	Cash	Flows	Relating	to	Proved	Oil	and	Gas	Reserves

| (In	millions) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Sales\tand\ttransfers\tof\toil\tand\tgas\tproduced,\tnet\tof\tproduction,\ttransportation\tand\tadministrative\tcosts | $(4,887) | $(5,312) | $(3,754) |
| Net\tchanges\tin\tprices\tand\tproduction,\ttransportation\tand\tadministrative\tcosts\trelated\tto\tfuture\tproduction | \t 12,845 | (1,342) | 6,648 |
| Extensions,\tdiscoveries\tand\timproved\trecovery,\tless\trelated\tcosts | 1,816 | 1,290 | 700 |
| Development\tcosts\tincurred\tduring\tthe\tperiod | 1,654 | 1,251 | 1,030 |
| Changes\tin\testimated\tfuture\tdevelopment\tcosts | (1,727) | (527) | (552) |
| Revisions\tof\tprevious\tquantity\testimates | 290 | 1,319 | 820 |
| Net\tchanges\tin\tpurchases\tand\tsales\tof\tminerals\tin\tplace | 23 | 30 | 4,557 |
| Accretion\tof\tdiscount | 1,726 | 1,882 | 1,124 |
| Net\tchange\tin\tincome\ttaxes | (6,751) | (660) | (6,694) |
| Timing\tand\tother | (12) | (14) | 307 |
| Net\tchange\tfor\tthe\tyear | 4,977 | (2,083) | 4,186 |
| Beginning\tof\tyear | 8,518 | \t 10,601 | 6,415 |
| End\tof\tyear | $13,495 | $8,518 | $10,601 |
| Net\tchange\tfor\tthe\tyear\tfrom\tdiscontinued\toperations | $– | $(216) | $162 |

# Supplemental	Statistics	(Unaudited)

| (Dollars	in	millions,	except	as	noted) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| SEGMENT\tINCOME\t(LOSS) |  |  |  |
| Exploration\tand\tProduction |  |  |  |
| United\tStates | $623 | $873 | $983 |
| International | \t 1,106 | \t 1,130 | 904 |
| E&amp;P\tsegment | \t 1,729 | \t 2,003 | \t 1,887 |
| Oil\tSands\tMining | (63) | – | – |
| Refining,\tMarketing\tand\tTransportation(a) | \t 2,077 | \t 2,795 | \t 1,628 |
| Integrated\tGas | 132 | 16 | 55 |
| Segment\tincome | \t 3,875 | \t 4,814 | \t 3,570 |
| Items\tnot\tallocated\tto\tsegments,\tnet\tof\tincome\ttaxes: |  |  |  |
| Corporate\tand\tother\tunallocated\titems | (104) | (212) | (377) |
| Gain\t(loss)\ton\tlong-term\tU.K.\tnatural\tgas\tcontracts | (118) | 232 | (223) |
| Gain\ton\tforeign\tcurrency\tderivative\tinstruments | 112 | – | – |
| Deferred\tincome\ttaxes\t–\ttax\tlegislation\tchanges | 193 | 21 | 15 |
| \t\t–\tother\tadjustments(b) | – | 93 | – |
| Gain\ton\tdispositions | 8 | 274 | – |
| Loss\ton\tearly\textinguishment\tof\tdebt | (10) | (22) | – |
| Discontinued\toperations | – | 34 | 45 |
| Gain\ton\tsale\tof\tminority\tinterests\tin\tEG\tHoldings | – | – | 21 |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | – | – | (19) |
| Net\tincome | \t 3,956 | \t 5,234 | \t 3,032 |
| Net\tincome\tper\tcommon\tshare\t–\tbasic\t(in\tdollars) | $5.73 | $7.31 | $4.26 |
| \t–\tdiluted\t(in\tdollars) | $5.69 | $7.25 | $4.22 |
| CAPITAL\tEXPENDITURES |  |  |  |
| Exploration\tand\tProduction | $2,511 | $2,169 | $1,366 |
| Oil\tSands\tMining | 165 | – | – |
| Refining,\tMarketing\tand\tTransportation(a) | \t 1,640 | 916 | 841 |
| Integrated\tGas(c) | 93 | 307 | 571 |
| Discontinued\tOperations | – | 45 | 94 |
| Corporate | 57 | 41 | 18 |
| Total | $4,466 | $3,478 | $2,890 |
| EXPLORATION\tEXPENSES |  |  |  |
| United\tStates | $274 | $169 | $118 |
| International | 180 | 196 | 99 |
| Total | $454 | $365 | $217 |
| (a) |  |  |  |

(a) RM&T	segment	income	for	2005	is	net	of	$376	million	pretax	minority	interest	in	MPC.	RM&T	capital	expenditures	include	MPC	at	100	percent	for	all	periods.

(b) Other	deferred	tax	adjustments	in	2006	represent	a	benefit	recorded	for	cumulative	income	tax	basis	differences	associated	with	prior	periods. (c) Through	April	2007,	includes	EGHoldings	at	100	percent.	Effective	May	1,	2007,	Marathon	no	longer	consolidates	EGHoldings	and	its	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	Marathon's	capital	expenditures.

# Supplemental	Statistics	(Unaudited)	C	O	N	T	I	N	U	E	D

|  | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| E&amp;P\tOPERATING\tSTATISTICS |  |  |  |
| Net\tLiquid\tHydrocarbon\tSales\t(thousands\tof\tbarrels\tper\tday)(d) |  |  |  |
| United\tStates | 64 | 76 | 76 |
| Europe | 33 | 35 | 36 |
| Africa | 100 | 112 | 52 |
| Total\tInternational | 133 | 147 | 88 |
| Worldwide\tContinuing\tOperations | 197 | 223 | 164 |
| Discontinued\tOperations | – | 12 | 27 |
| Worldwide | 197 | 235 | 191 |
| Natural\tgas\tliquids\tincluded\tin\tabove | 22 | 23 | 18 |
| Net\tNatural\tGas\tSales\t(millions\tof\tcubic\tfeet\tper\tday)\t(d)(e) | – | – | – |
| United\tStates | 477 | 532 | 578 |
| Europe | 216 | 243 | 262 |
| Africa | 232 | 72 | 92 |
| Total\tInternational | 448 | 315 | 354 |
| Worldwide | 925 | 847 | 932 |
| Total\tWorldwide\tSales\t(thousands\tof\tbarrels\tof\toil\tequivalent\tper\tday) |  |  |  |
| Continuing\tOperations | 351 | 365 | 319 |
| Discontinued\tOperations | – | 12 | 27 |
| Worldwide | 351 | 377 | 346 |
| Average\tRealizations(f) |  |  |  |
| Liquid\tHydrocarbons\t(dollars\tper\tbarrel) |  |  |  |
| United\tStates | $60.15 | $54.41 | $45.41 |
| Europe | \t 70.31 | \t 64.02 | \t 52.99 |
| Africa | \t 66.09 | \t 59.83 | \t 46.27 |
| Total\tInternational | \t 67.15 | \t 60.81 | \t 49.04 |
| Worldwide\tContinuing\tOperations | \t 64.86 | \t 58.63 | \t 47.35 |
| Discontinued\tOperations | – | \t 38.38 | \t 33.47 |
| Worldwide | $64.86 | $57.58 | $45.42 |
| Natural\tGas\t(dollars\tper\tthousand\tcubic\tfeet) |  |  |  |
| United\tStates | $5.73 | $5.76 | $6.42 |
| Europe | 6.53 | 6.74 | 5.70 |
| Africa | 0.25 | 0.27 | 0.25 |
| Total\tInternational | 3.28 | 5.27 | 4.28 |
| Worldwide | $4.54 | $5.58 | $5.61 |
| Net\tProved\tReserves\tat\tyear-end\t(developed\tand\tundeveloped) |  |  |  |
| Liquid\tHydrocarbons\t(millions\tof\tbarrels) |  |  |  |
| United\tStates | 166 | 172 | 189 |
| International | 484 | 505 | 515 |
| Total | 650 | 677 | 704 |
| Developed\treserves\tas\ta\tpercentage\tof\ttotal\tnet\treserves | 72% | 84% | 86% |
| Natural\tGas\t(billions\tof\tcubic\tfeet) |  |  |  |
| United\tStates | \t 1,007 | \t 1,069 | \t 1,209 |
| International | \t 2,443 | \t 2,441 | \t 2,338 |
| Total | \t 3,450 | \t 3,510 | \t 3,547 |
| Developed\treserves\tas\ta\tpercentage\tof\ttotal\tnet\treserves | 71% | 50% | 54% |
| (d) |  |  |  |

| (Dollars	in	millions,	except	as	noted) | 2007 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| OSM\tOPERATING\tSTATISTICS |  |  |  |
| Net\tBitumen\tProduction\t(thousands\tof\tbarrels\tper\tday)(g) | 4 | – | – |
| Net\tSynthetic\tCrude\tSales\t(thousands\tof\tbarrels\tper\tday)(g) | 4 | – | – |
| Synthetic\tCrude\tAverage\tRealization\t(dollars\tper\tbarrel)(h) | $71.07 | – | – |
| Net\tProved\tBitumen\tReserves\tat\tyear-end\t(millions\tof\tbarrels) | 421 | – | – |
| RM&amp;T\tOPERATING\tSTATISTICS |  |  |  |
| Refinery\tRuns\t(thousands\tof\tbarrels\tper\tday) |  |  |  |
| Crude\toil\trefined | 1,010 | 980 | 973 |
| Other\tcharge\tand\tblend\tstocks | 214 | 234 | 205 |
| Total | 1,224 | 1,214 | 1,178 |
| Refined\tProduct\tYields\t(thousands\tof\tbarrels\tper\tday) |  |  |  |
| Gasoline | 646 | 661 | 644 |
| Distillates | 349 | 323 | 318 |
| Propane | 23 | 23 | 21 |
| Feedstocks\tand\tspecial\tproducts | 108 | 107 | 96 |
| Heavy\tfuel\toil | 27 | 26 | 28 |
| Asphalt | 86 | 89 | 85 |
| Total | 1,239 | 1,229 | 1,192 |
| Refined\tProduct\tSales\tVolumes\t(thousands\tof\tbarrels\tper\tday)(i)(j) | 1,410 | 1,425 | 1,455 |
| Matching\tbuy/sell\tvolumes\tincluded\tin\tabove(j) | – | 24 | 77 |
| Refining\tand\tWholesale\tMarketing\tGross\tMargin\t($\tper\tgallon)(k) | $0.1848 | $0.2288 | $ 0.1582 |
| Speedway\tSuperAmerica |  |  |  |
| Retail\toutlets\tat\tyear-end | 1,636 | 1,636 | 1,638 |
| Gasoline\t&amp;\tdistillates\tsales\t(millions\tof\tgallons) | 3,356 | 3,301 | 3,226 |
| Gasoline\t&amp;\tdistillates\tgross\tmargin\t(dollars\tper\tgallon) | $0.1119 | $0.1156 | $ 0.1230 |
| Merchandise\tsales | $2,796 | $2,706 | $2,531 |
| Merchandise\tgross\tmargin | $705 | $667 | $626 |
| IG\tOPERATING\tSTATISTICS |  |  |  |
| Sales\tVolumes\t(metric\ttonnes\tper\tday)(l) |  |  |  |
| LNG | 3,310 | 1,026 | 1,068 |
| Methanol | 1,308 | 905 | 1,335 |
| (g) |  |  |  |

(i) Total	average	daily	volumes	of	refined	product	sales	to	wholesale,	branded	and	retail	customers.

(j) As	a	result	of	the	change	in	accounting	for	matching	buy/sell	arrangements	on	April	1,	2006,	the	reported	sales	volumes	after	that	date	are	lower	than	the	volumes	determined	under	the	previous	accounting practices.	See	Note	2	to	the	consolidated	financial	statements.

(k) Sales	revenue	less	cost	of	refinery	inputs,	purchased	products	and	manufacturing	expenses,	including	depreciation.	As	a	result	of	the	change	in	accounting	for	matching	buy/sell	transactions	on	April	1,	2006,	the resulting	per	gallon	statistic	is	higher	after	that	date	than	the	statistic	that	would	have	been	calculated	from	amounts	determined	under	previous	accounting	practices.	See	Note	2	to	the	consolidated	financial statements.

(l) LNG	sales	volumes	include	both	consolidated	sales	and	our	share	of	the	sales	of	an	equity	method	investee.	Methanol	sales	volumes	represent	our	share	of	sales	of	an	equity	method	investee.

# Item	9. Changes	in	and	Disagreements	with	Accountants	on	Accounting	and	Financial	Disclosure

# None.

# 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	Marathon's	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	2007,	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	the	directors	of	Marathon	required	by	this	item	is	incorporated	by	reference	to	the	material	appearing	under	the	heading	"Election	of Directors"	in	Marathon's	Proxy	Statement	for	the	2008	Annual	Meeting	of	stockholders.

Marathon's	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	Marathon's	Proxy	Statement	for	the	2008	Annual	Meeting	of	Stockholders.

Marathon	has	adopted	a	Code	of	Ethics	for	Senior	Financial	Officers.	It	is	available	on	our	website	at

http://www.marathon.com/Investor_Center/Corporate_GovernanceCode_of_Ethics_for_Senior_Financial_Officers/.

See	Business	–	Executive	Officers	of	the	Registrant	for	the	names,	ages	and	titles	of	Marathon's	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,	2007,	except	for	Janet	F.	Clark	who	filed	one	Form	4	report	five	days late.	This	late	filing	related	to	52	common	shares	she	acquired	in	connection	with	our	acquisition	of	the	Class	A	shares	of	Western	Oil	Sands	Inc.	on	October	18,	2007. Under	the	plan	of	arrangement	for	the	transaction,	Ms.	Clark's	100	percent	cash	election	for	her	Class	A	shares	of	Western	stock	was	prorated	at	the	rate	of approximately	86	percent	of	cash	elected,	resulting	in	Ms.	Clark	acquiring	52	shares	of	our	common	stock.

# 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	Marathon's	Proxy	Statement	for	the	2008	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	Marathon's	Proxy Statement	for	the	2008	Annual	Meeting	of	stockholders.

# Securities	Authorized	for	Issuance	Under	Equity	Compensation	Plans

The	following	table	provides	information	as	of	December	31,	2007	with	respect	to	shares	of	Marathon's	common	stock	that	may	be	issued	under	Marathon's 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.

|  |  |  | remaining |
| :--- | :--- | :--- | :--- |
|  |  |  | available\tfor |
|  | Number\tof |  | future |
|  | securities | Weighted- | issuance |
|  | to\tbe\tissued | average | under\tequity |
|  | upon | exercise | compensation |
|  | exercise\tof | price\tof | plans |
|  | outstanding | outstanding | (excluding |
|  | options, | options, | securities |
|  | warrants | warrants | reflected\tin |
| Plan\tcategory | and\trights | and\trights(c) | column(a)) |
| Equity\tcompensation\tplans\tapproved\tby\tstockholders | 11,997,173(a) | $34.58 | 30,413,677(d) |
| Equity\tcompensation\tplans\tnot\tapproved\tby\tstockholders | 114,486(b) | N/A | – |
| Total | 12,111,659 | N/A | 30,413,677 |
| Includes\tthe\tfollowing:\n(a) |  |  |  |

•7,871,443	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	Marathon's	closing stock	price	on	December	31,	2007,	of	$60.86	per	share.;

•546,670	stock	options	outstanding	under	the	1990	Stock	Plan;

•170,055	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	3,505	and	166,550.

•58,650	restricted	stock	units	granted	to	non-officers	under	the	2007	Plan	and	outstanding	as	of	December	31,	2007;	and

•161,732	restricted	stock	units	granted	to	non-officers	under	the	2003	Plan	and	outstanding	as	of	December	31,	2007.

In	addition	to	the	awards	reported	above,	342,555	shares	and	980,644	shares	of	restricted	stock	were	issued	and	outstanding	as	of	December	31,	2007,	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) Reflects	the	shares	available	for	issuance	under	the	2007	Plan.	No	more	than	11,602,300	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	our	common	stock	on	that	date.	The	ongoing	value	of	each	common	stock	unit	equals	the	market	price	of	a	share of	our	common	stock.	When	the	non-employee	director	leaves	the	Board,	he	or	she	is	issued	actual	shares	of	our	common	stock	equal	to	the	number	of	common	stock units	in	his	or	her	account	at	that	time.

# Item	13. Certain	Relationships	and	Related	Transactions,	and	Director	Independence

Information	required	by	this	item	is	incorporated	by	reference	to	the	material	appearing	under	the	heading	"Certain	Relationships	and	Related	Person	Transactions," and	under	the	sub-heading	"Board	and	Committee	Independence"	under	the	heading	"The	Board	of	Directors	and	Governance	Matters"	in	Marathon's	Proxy	Statement for	the	2008	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	Marathon's	Proxy	Statement	for	the	2008	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.

2.8++ 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).

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.

* Filed	herewith

++ 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.

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	28,	2008	on	behalf	of the	registrant	and	in	the	capacities	indicated.

/S/				MICHAEL	K.	STEWART Michael	K.	Stewart

Executive	Vice	President	and	Chief	Financial	Officer


as of december 31 , 2007 , how much unrecognized compensation cost related to restricted stock awards is expected to be recognized in 1 year , in millions?
  a = 37 / 1.4
 answer = a